Market Protocols for SPP Integrated Marketplace
Market Protocols SPP Integrated Marketplace Revision 23.a
MAINTAINED BY Market Design
PUBLISHED: 12/16/2010 LATEST REVISION: 12/4/2014
Copyright © 2010 by Southwest Power Pool, Inc. All rights reserved.
Market Protocols for SPP Integrated Marketplace
REVISIONS Revision
Date
0.a 0.b 0.c 1.0
10/12/2010 12/16/2010 4/28/2011 4/29/2011
1.1
6/8/2011
2.0
7/12/2011
3.0
10/14/2011
4.0
11/1/2011
5.0
11/18/2011
5.1
12/1/2011
6.0 7.0 8.0
12/6/2011 1/20/2012 2/7/2012
9.0
4/13/2012
10.0
4/30/2012
10.0a FERC Compliance
2/28/2013
10.0b
3/8/2013
11.0 11.1 12.0 12.1
8/8/2012 8/31/2012 11/5/2012 11/7/2012
13.0a
3/11/2013
Version 23.a
Description of Modification Initial draft Working draft Protocols endorsed by the MOPC on January 12, 2011 Incorporation of MPRR 1 Fixed punctuation, grammar, spacing, references, page size and layout, etc. No content was changed. Incorporation of MPRR 3 Incorporation of MPRRs 6, 7, 10, 13, 14, 15, 16, 17, 19, 23, 24, 27, 31, 38 and 39 Incorporation of MPRRs 4, 11, 12, 20, 21, 22, 26, 28, 29, 30, 32, 34, 35 and 36 Incorporation of MPRR 25 Correction of MPRR 4 Version update to correct Microsoft Word generated errors and truncated language Incorporation of MPRR 33 Incorporation of MPRRs 9 and 18 Incorporation of MPRRs 40, 42 and 46 Incorporation of MPRRs 49, 53, 54, 55, 57, 58, 59, 60, 61, 66 and 67 Incorporation of MPRRs 43, 44, 47, 50, 52, 56, 63, 65 and 68 All MCRRs were added in redline (1, 2, 5, 6, 7, 8, 9, 10, 11, 12, 14, 15, 16, 17, 19, 20, 21, 22, 24, 25, 26, 27, 30, 33, 35, 36, 37, 38, 41, and 42). Fixed references, spelling, and aesthetics. Corrected units and attributes of Settlement calculations. Added MPRRs from versions 11 and 12 of these Marketplace Protocols and from the January 2013 MOPC (51, 62, 71, 72, 73, 74, 76, 77, 79, 81, 83, 84, 86, 88, 89, 90, 92, 96, 98, 99, 103, 105, 108, and 111) in redline. All changes from v11.0 have been incorporated into v13.0a. All changes from v11.1 have been incorporated into v13.0a. All changes from v12.0 have been incorporated into v13.0a. All changes from v12.1 have been incorporated into v13.0a. Incorporated MPRRs from 10.0b that were not associated with Tariff changes (62, 72, 73, 79, 81, 83, 84, and 86) as approved, black line text.
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14.0a
5/10/2013
15.0a
5/29/2013
16.0a
8/6/2013
17.0
11/22/2013
18.0
1/31/2014
18.1
2/6/2014
Implemented MPRRs 82, 87, 93, 94, 95 and 110. MPRR 91 – awaiting FERC filing. MPRR 100 – awaiting FERC filing. MPRR 113 – awaiting FERC filing. Fixed typos and aesthetics. Implemented MPRR 112. Implemented MPRR 114, 115 and 119. Incorporated MPRR 117 – awaiting FERC filing MPRR 118 – awaiting FERC filing MPRR 120 – awaiting FERC filing MPRR 121 – awaiting FERC filing MPRR 122 – awaiting FERC filing MPRR 123 – awaiting FERC filing MPRR 124 – awaiting FERC filing MPRR 125 – awaiting FERC filing MPRR 128 – awaiting FERC filing MPRR 133 – awaiting FERC filing Implemented MPRR 51, 69, 74, 76, 86, 88, 89, 90, 92, 96, 98, 99, 103, 104, 106, 108, 111, 124, 127, 129, 134, 135, 136, 137, 139, 142, 143, 146 and 147. Implemented MCRR 1, 2, 5, 6, 7, 8, 9, 10, 11, 12, 14, 15, 16, 17, 19, 20, 21, 22, 24, 25, 26, 27, 30, 35, 36, 37, 38, 41 and 42 Incorporated MPRRs Awaiting FERC approval 131, 132, 145, 149, 150 and 153 Incorporated MCRRs Awaiting FERC approval 100, 101, 102, 103, 104, 107, 109, 110, 111, 112, 114, 115, 116, 117, 118, 122, 123, 125, 127, 128, 129, 130, 132, 134 and 135 Incorporation of MCRR100 Incorporation MPRR Awaiting FERC approval 159 Implemented MPRR 117, 118, 120, 123, 125, 128, 130a, 131, 132, 145, 149, 153, 154, 156, and 158 effective 3/1/2014 SPP Staff will be revising Settlement examples to match revised calculations. Examples will be included in Appendix F once they are updated. Implemented MCRR200 effective 3/1/2014
19.0
Version 23.a
2/24/2014
Implemented MPRRs 77, 89, 113, 122, 150, 163 and 166 effective 3/1/2014
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Implemented MCRR200 effective 3/1/2014.
19.1
2/26/2014
Implemented MPRR 157, 160, 163, 165 and 167, which contain clarifications for March 1st Go-Live effective 3/1/2014. These MPRRs are pending MOPC approval. Changed the number of Regulation priority groups from 1 to 6 in section 4.4.3.3. MPRR will be created to address this change. Corrected grammatical errors.
19.1a
4/2/2014
Incorporation of MPRR 91, 101, 102, 138, 140, 141, 155 Implemented MPRR 162, 172, effective 5/13/2014.
20.a
5/13/2014
Incorporation MPRR 144, 165, Awaiting FERC filing Corrected grammatical errors.
20.b
6/4/2014
Incorporation of MPRR 80 Awaiting implementation Implemented MPRR 80 effective 3/1/2014
21
8/29/2014
Implemented MPRR 192 effective 3/1/2014 Implemented MPRRs 174 and 175 effective 8/30/2014
21.a
8/29/2014
Incorporation of MPRR 173, 178, 183, 190 Awaiting FERC Filing Incorporation of MPRR 182 Awaiting Implementation
22
11/11/2014
Implemented MPRRs 187, 188, 189, 200 and 205 effective 11/11/2014 Incorporation of MPRR 151, 191 and 206 Awaiting Implementation
22.a
11/11/2014
23.a
12/4/2014
Incorporation of MPRR 193, 194, 195, 199, 201, 202, 204 and 212 Awaiting FERC filing Implemented MPRRs 178 effective 12/5/2014
Version 23.a
Implemented MPRRs 183 effective 3/1/2014
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TABLE OF CONTENTS 1. Glossary ..................................................................................................................................32 2. Introduction ............................................................................................................................61 2.1 Purpose...............................................................................................................................62 3. SPP Integrated Marketplace Overview ...............................................................................63 3.1 Energy and Operating Reserve Markets ............................................................................63 3.2 Transmission Congestion Rights Markets .........................................................................67 4. Energy and Operating Reserve Markets Processes ............................................................75 4.1 SPP System Requirements .................................................................................................75 4.1.1 Reserve Zone Establishment ........................................................................................75 4.1.2 Forecasting ...................................................................................................................76 4.1.2.1 Short Term and Mid-Term Load Forecasting ........................................................76 4.1.2.1.1 Conforming Load .............................................................................................76 4.1.2.1.2 Non-conforming Load .....................................................................................77 4.1.2.1.3 Losses ...............................................................................................................77 4.1.2.1.4 Demand Response Adjustments ......................................................................78 4.1.2.1.5 Reserve Zone Load ..........................................................................................78 4.1.2.1.6 Load Distribution .............................................................................................78 4.1.2.2 Wind-Powered Generation Resource Output Forecasts ........................................79 4.1.2.3 Wind-Powered Generation Resource Data Requirements .....................................79 4.1.2.4 Grandfathered Wind-Powered Generation Resource Data Requirements .............82 4.1.3 Operating Reserve, Head-room and Floor-room Requirements ..................................83 4.1.3.1 Reserve Zone Requirements ..................................................................................84 4.1.3.1.1 Minimum Reserve Zone Operating Reserve Requirements ............................84 4.1.3.1.2 Maximum Reserve Zone Operating Reserve Limitations ...............................85 4.1.3.2 Head-room and Floor-room Requirements ............................................................86 4.1.3.2.1 Day-Ahead Market...........................................................................................86 4.1.3.2.2
RUC .................................................................................................................87
4.1.4 Violation Relaxation Limits .........................................................................................88 4.1.4.1 Impact of VRLs on LMPs and MCPs ....................................................................91
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4.1.4.2 Determination of VRLs..........................................................................................92 4.1.4.3 VRL Reporting.......................................................................................................93 4.1.4.3.1 Quarterly Reporting .........................................................................................93 4.1.4.3.2 Annual Reporting .............................................................................................94 4.1.5 Scarcity Pricing ............................................................................................................94 4.1.5.1 Demand Curve Interaction with VRLs ..................................................................96 4.1.6 Ramp Sharing.............................................................................................................101 4.1.7 Outage Scheduling and Reporting .............................................................................102 4.1.8 Joint Operating Agreements – Seams Coordination ..................................................102 4.1.9 Calculation of Net Benefits Test for Compensation of Demand Response Load......103 4.2 Pre-Day-Ahead Activities ................................................................................................104 4.2.1 Must-Offer Requirement ............................................................................................105 4.2.1.1 Day-Ahead Market...............................................................................................105 4.2.1.1.1
Penalty Calculation ........................................................................................108
4.2.1.2 RUC and RTBM ..................................................................................................109 4.2.2 Offer Submittal ..........................................................................................................109 4.2.2.1 Resource Offer Parameters ..................................................................................111 4.2.2.1.1 Resource Ramp Rate Interaction – Energy and Operating Reserve ..............118 4.2.2.2 Resource Status ....................................................................................................120 4.2.2.2.1 Commitment Status ........................................................................................120 4.2.2.2.2 Dispatch Status...............................................................................................120 4.2.2.3 Resource Limit Validation ...................................................................................122 4.2.2.4 Resource Commitment Parameter Relationships.................................................124 4.2.2.4.1 Start-Up and Shut-Down Times.....................................................................126 4.2.2.5 Resource Modeling ..............................................................................................127 4.2.2.5.1
Dispatchable Demand Response Resource ....................................................127
4.2.2.5.2 Block Demand Response Resource ...............................................................129 4.2.2.5.3 Combined Cycle Resource .............................................................................131 4.2.2.5.4 Jointly Owned Unit ........................................................................................133 4.2.2.5.5 Dispatchable Variable Energy Resources ......................................................137
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4.2.2.5.6 Non-Dispatchable Variable Energy Resources ..............................................139 4.2.2.5.7 External Dynamic Resource ..........................................................................140 4.2.2.5.8 Resources Pseudo-Tied Out of the SPP BAA ...............................................142 4.2.2.6 Virtual Energy Offers ..........................................................................................143 4.2.2.7 Import Interchange Transaction Offers ................................................................144 4.2.3 Bid Submittal .............................................................................................................145 4.2.3.1 Demand Bids ........................................................................................................146 4.2.3.2 Virtual Energy Bids .............................................................................................147 4.2.3.3 Export Interchange Transaction Bids...................................................................149 4.2.4 Through Interchange Transactions ............................................................................151 4.2.5 Ramp Reservation Requirements ...............................................................................152 4.2.6 Multi-Day Reliability Assessment .............................................................................153 4.2.6.1 Multi-Day Reliability Assessment Inputs ............................................................153 4.2.6.2 Multi-Day Reliability Assessment Analysis ........................................................154 4.2.6.3 Multi-Day Reliability Assessment Results ..........................................................155 4.3 Day-Ahead Activities.......................................................................................................155 4.3.1 Day-Ahead Market.....................................................................................................156 4.3.1.1 DA Market Inputs ................................................................................................156 4.3.1.2 DA Market Execution ..........................................................................................157 4.3.1.2.1 Clearing During Capacity Shortage ...............................................................160 4.3.1.2.2 Clearing During Excess Generation Conditions ............................................160 4.3.1.3 DA Market Results ..............................................................................................161 4.3.2 Day-Ahead Reliability Unit Commitment .................................................................162 4.3.2.1 Day-Ahead RUC Inputs .......................................................................................162 4.3.2.2 Day-Ahead RUC Execution .................................................................................163 4.3.2.3 Day-Ahead RUC Results .....................................................................................166 4.3.2.4 Update Current Operating Plan ............................................................................167 4.4 Operating Day Activities .................................................................................................167 4.4.1 Intra-Day Reliability Unit Commitment ....................................................................168 4.4.1.1 Intra-Day RUC Inputs ..........................................................................................169
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4.4.1.2 Intra-Day RUC Execution....................................................................................169 4.4.1.3 Intra-Day RUC Results ........................................................................................173 4.4.1.4 Update Current Operating Plan ............................................................................173 4.4.2 Real-Time Balancing Market .....................................................................................174 4.4.2.1 Managing Regulation Control Status Prior to Operating Hour ...........................174 4.4.2.2 RTBM Inputs .......................................................................................................177 4.4.2.2.1 Pre-Operating Hour Inputs:............................................................................177 4.4.2.2.2 In-Operating Hour Inputs:..............................................................................177 4.4.2.3 RTBM Execution .................................................................................................178 4.4.2.3.1 Quick-Start Resource Logic ...........................................................................180 4.4.2.3.2 Emergency Operations – Capacity Shortage .................................................180 4.4.2.3.3 Emergency Operations – Excess Generation .................................................181 4.4.2.3.4 Ensuring Reliable Operations ........................................................................182 4.4.2.4 RTBM Results .....................................................................................................182 4.4.2.5 Out-of-Merit Energy (OOME) Dispatch .............................................................183 4.4.2.5.1 Out-of-Merit Energy Dispatch for Emergency Conditions ...........................185 4.4.2.6 SPP Congestion Management ..............................................................................186 4.4.2.6.1 SPP Congestion Management under TLR Operations...................................186 4.4.2.6.2 Congestion Management - Market Flow .......................................................186 4.4.2.6.3 IDC Curtailments ...........................................................................................187 4.4.3 Energy and Operating Reserve Deployment..............................................................187 4.4.3.1 Dispatchable Variable Energy Resource Deployment .........................................188 4.4.3.2 Non-Dispatchable Variable Energy Resource Deployment ................................188 4.4.3.3 Regulation Deployment .......................................................................................189 4.4.3.4 Contingency Reserve Deployment ......................................................................191 4.4.3.5 Reserve Sharing Group Scheduling Procedures ..................................................192 4.4.3.6 Contingency Reserve Recovery ...........................................................................192 4.4.4 Energy and Operating Reserve Deployment Failure .................................................193 4.4.4.1 Uninstructed Resource Deviation ........................................................................193 4.4.4.1.1 URD Exemptions ...........................................................................................194
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4.4.4.1.2 Load Deviation Exemptions ..........................................................................195 4.4.4.2 Regulation Deployment Failure Charges .............................................................195 4.4.4.3 Contingency Reserve Deployment Failure Charges ............................................196 4.4.5 Inadvertent Management ...........................................................................................201 4.4.5.1 Inadvertent Payback Reporting ............................................................................201 4.5 Post Operating Day and Settlement Activities.................................................................202 4.5.1 Settlement Sign Conventions .....................................................................................203 4.5.2 Commercial Model ....................................................................................................204 4.5.2.1 Nodes ...................................................................................................................204 4.5.2.2 Pricing Nodes .......................................................................................................204 4.5.2.2.1 Aggregated Pricing Nodes .............................................................................204 4.5.2.3 Settlement Locations ............................................................................................205 4.5.2.3.1 Hubs Establishment .......................................................................................205 4.5.2.3.1.1 Resource Hubs ...............................................................................................205 4.5.2.3.1.2 Trading Hubs .................................................................................................206 4.5.2.4 Asset Owners .......................................................................................................206 4.5.2.5 Market Participants ..............................................................................................207 4.5.3 Bilateral Settlement Schedules ..................................................................................208 4.5.3.1 Transition Mechanism for Pre-Existing Bilateral Contracts ................................209 4.5.3.2 GFA Carve Out Schedules – Internal ..................................................................209 4.5.3.3 GFA Carve Out Schedules – External .................................................................211 4.5.3.4 GFA Carve Out Uplift .........................................................................................211 4.5.4 Calculation of LMPs, LMP Components and MCPs .................................................211 4.5.4.1 LMP Calculations and LMP Components ...........................................................212 4.5.4.1.1 Marginal Losses Component Calculation ......................................................212 4.5.4.1.2 Marginal Congestion Component Calculation...............................................213 4.5.4.1.3 Marginal Energy Component Calculation .....................................................213 4.5.4.2 MCP Calculations ................................................................................................213 4.5.5 Settlement Location LMPs and LMP Components ...................................................215 4.5.5.1 Calculation of LMP at a Market Hub Settlement Location .................................216
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4.5.5.2 Calculation of LMP at a Load APNode Settlement Location..............................217 4.5.5.3 Calculation of LMP at an External Interface Settlement Location ......................218 4.5.6 Precision and Rounding .............................................................................................218 4.5.7 FERC Electric Quarterly Reporting ...........................................................................219 4.5.8 Day-Ahead Market Settlement ..................................................................................223 4.5.8.1 Day-Ahead Asset Energy Amount.......................................................................227 4.5.8.2 Day-Ahead Non-Asset Energy Amount ..............................................................231 4.5.8.3 Day-Ahead Virtual Energy Amount ....................................................................235 4.5.8.4 Day-Ahead Regulation-Up Service Amount .......................................................238 4.5.8.5 Day-Ahead Regulation-Down Service Amount ..................................................242 4.5.8.6 Day-Ahead Spinning Reserve Amount ................................................................246 4.5.8.7 Day-Ahead Supplemental Reserve Amount ........................................................250 4.5.8.8 Day-Ahead Regulation-Up Service Distribution Amount ...................................254 4.5.8.9 Day-Ahead Regulation-Down Service Distribution Amount ..............................262 4.5.8.10 Day-Ahead Spinning Reserve Distribution Amount ...........................................269 4.5.8.11 Day-Ahead Supplemental Reserve Distribution Amount ....................................275 4.5.8.12 Day-Ahead Make-Whole-Payment Amount........................................................284 4.5.8.13 Day-Ahead Make-Whole-Payment Distribution Amount ...................................299 4.5.8.14 Transmission Congestion Rights Funding Amount .............................................303 4.5.8.15 Transmission Congestion Rights Daily Uplift Amount .......................................305 4.5.8.16 Transmission Congestion Rights Monthly Payback Amount ..............................309 4.5.8.17 Transmission Congestion Rights Annual Payback Amount ................................313 4.5.8.18 Transmission Congestion Rights Annual Closeout Amount ...............................315 4.5.8.19 Day-Ahead Over-Collected Losses Distribution Amount ...................................318 4.5.8.20 Day-Ahead Virtual Energy Transaction Fee Amount .........................................327 4.5.8.21 Day-Ahead Demand Reduction Amount .............................................................329 4.5.8.22 Day-Ahead Demand Reduction Distribution Amount .........................................333 4.5.8.23 Day-Ahead Grandfathered Agreement Carve-Out Daily Amount ......................337 4.5.8.24 Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount .................340 4.5.8.25 Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount ....................342
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4.5.8.26 GFA Carve Out Distribution Daily Amount ........................................................345 4.5.8.27 GFA Carve Out Distribution Monthly Amount ...................................................350 4.5.8.28 GFA Carve Out Distribution Yearly Amount ......................................................354 4.5.9 Real-Time Balancing Market Settlement...................................................................358 4.5.9.1 Real-Time Asset Energy Amount ........................................................................369 4.5.9.2 Real-Time Non-Asset Energy Amount ................................................................382 4.5.9.3 Real-Time Virtual Energy Amount .....................................................................388 4.5.9.4 Real-Time Regulation-Up Service Amount.........................................................391 4.5.9.5 Real-Time Regulation-Down Service Amount ....................................................400 4.5.9.6 Real-Time Spinning Reserve Amount .................................................................408 4.5.9.7 Real-Time Supplemental Reserve Amount .........................................................412 4.5.9.8 RUC Make-Whole-Payment Amount ..................................................................416 4.5.9.9 Real-Time Out-Of-Merit Amount........................................................................454 4.5.9.10 RUC Make-Whole-Payment Distribution Amount .............................................465 4.5.9.11 Real-Time Regulation-Up Service Distribution Amount ....................................485 4.5.9.12 Real-Time Regulation-Down Service Distribution Amount ...............................489 4.5.9.13 Real-Time Spinning Reserve Distribution Amount .............................................492 4.5.9.14 Real-Time Supplemental Reserve Distribution Amount .....................................494 4.5.9.15 Real-Time Regulation Service Non-Performance Amount .................................496 4.5.9.16 Real-Time Regulation Non-Performance Distribution Amount ..........................502 4.5.9.17 Real-Time Contingency Reserve Deployment Failure Amount ..........................504 4.5.9.18 Real-Time Contingency Reserve Deployment Failure Distribution Amount......512 4.5.9.19 Real-Time Regulation Service Deployment Adjustment Amount ......................515 4.5.9.20 Over-Collected Losses Distribution Amount.......................................................523 4.5.9.21 Real-Time Joint Operating Agreement Amount ..................................................536 4.5.9.22 Real-Time Reserve Sharing Group Amount ........................................................538 4.5.9.23 Real-Time Reserve Sharing Group Distribution Amount ...................................542 4.5.9.24 Real-Time Demand Reduction Amount ..............................................................544 4.5.9.25 Real-Time Demand Reduction Distribution Amount ..........................................548 4.5.9.26 Real-Time Pseudo-Tie Congestion Amount ........................................................552
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4.5.9.27 Real-Time Pseudo-Tie Losses Amount ...............................................................555 4.5.9.28 Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount .....558 4.5.9.29 Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount.567 4.5.10 ARR and TCR Auction Settlement ............................................................................576 4.5.10.1 Transmission Congestion Rights Auction Transaction Amount .........................577 4.5.10.2 Auction Revenue Rights Funding Amount ..........................................................581 4.5.10.3 Auction Revenue Rights Uplift Amount..............................................................584 4.5.10.4 Auction Revenue Rights Monthly Payback Amount ...........................................587 4.5.10.5 Auction Revenue Rights Annual Payback Amount .............................................590 4.5.10.6 Auction Revenue Rights Annual Closeout Amount ............................................592 4.5.11 Miscellaneous Amount ..............................................................................................594 4.5.12 Revenue Neutrality Uplift Distribution Amount .......................................................597 4.5.13 Settlement Statement Process ....................................................................................611 4.5.13.1 Meter Data Submittal ...........................................................................................611 4.5.13.2 Daily Settlement Statement..................................................................................611 4.5.13.3 Settlement Statement Access ...............................................................................612 4.5.13.4 Initial Settlement Statements ...............................................................................612 4.5.13.5 Final Settlement Statements .................................................................................612 4.5.13.6 Resettlement Statements ......................................................................................613 4.5.13.7 Settlement Timeline .............................................................................................614 4.5.14 Settlement Invoice .....................................................................................................616 4.5.14.1 Timing and Content of Invoice ............................................................................617 4.5.14.2 Invoice Calendar ..................................................................................................618 4.5.14.3 Holiday Invoice Calendar ....................................................................................618 4.5.15 Disputes......................................................................................................................619 4.5.15.1 Dispute Submission Timeline ..............................................................................622 4.5.15.2 SPP Dispute Processing .......................................................................................622 4.5.15.2.1 Dispute Status ................................................................................................623 4.5.16 Invoice Payment Process ...........................................................................................624 4.5.16.1 Overview of Payment Process .............................................................................624
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4.5.16.2 Invoice Payments Due SPP ..................................................................................624 4.5.16.3 SPP Payments to Invoice Recipients ...................................................................625 4.5.17 Billing Determinant Anomalies .................................................................................625 5. Transmission Congestion Rights Markets Process ...........................................................627 5.1 Annual LTCR/ARR Verification Process ........................................................................631 5.1.1 Transmission Service Verification .............................................................................631 5.1.1.1 TSR Modification for Resource Specific Source Points......................................634 5.1.2 Candidate LTCRs/ARRs ............................................................................................635 5.1.3 ARR Nomination Cap ................................................................................................637 5.2 Annual LTCR Allocation Process ...................................................................................637 5.2.1 LTCR Surrender.........................................................................................................638 5.2.2 Candidate LTCR Simultaneous Feasibility for LSEs ................................................638 5.2.3 Annual LTCR Available for LSEs .............................................................................640 5.2.4 Candidate LTCR Simultaneous Feasibility for Non-LSEs ........................................640 5.2.5 Annual LTCR Available for Non-LSEs ....................................................................642 5.2.6 LTCR Selections and Awards ....................................................................................642 5.3 Annual ARR Allocation Process .....................................................................................643 5.3.1 ARR Nominations......................................................................................................644 5.3.2 ARR Allocation .........................................................................................................645 5.3.3 Simultaneous Feasibility ............................................................................................647 5.3.4 Annual ARR Awards .................................................................................................648 5.4 Annual TCR Auction .......................................................................................................649 5.4.1 TCR Bid and Offer Submittal ....................................................................................650 5.4.2 Annual TCR Auction Process ....................................................................................651 5.4.3 Annual TCR Auction Clearing and Simultaneous Feasibility ...................................652 5.4.4 Annual TCR Awards..................................................................................................652 5.5 Monthly ARR Allocation Process ...................................................................................653 5.5.1 Monthly ARR Transmission Service Verification .....................................................654 5.5.2 Monthly ARR Nominations .......................................................................................654 5.5.3 Simultaneous Feasibility ............................................................................................655
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5.5.4 Monthly ARR Awards ...............................................................................................656 5.6 Monthly TCR Auction Processes.....................................................................................656 5.6.1 TCR Bid and Offer Submittal ....................................................................................657 5.6.2 Monthly TCR Auction Process ..................................................................................658 5.6.3 Monthly TCR Auction Clearing and Simultaneous Feasibility .................................659 5.6.4 Monthly TCR Awards................................................................................................660 5.7 ARR Allocation/TCR Auction Settlements .....................................................................660 5.8 TCR Secondary Market ...................................................................................................661 5.9 Interim TCR Markets Schedule .......................................................................................662 6. Market Registration.............................................................................................................664 6.1 Registration of Resources ................................................................................................666 6.1.1 Responsibilities of the Resource Asset Owner ..........................................................666 6.1.2 Energy Production Prior to Completion of Market Registration ...............................667 6.1.3 Common Bus .............................................................................................................667 6.1.4 Dispatchable Demand Response Resource ................................................................668 6.1.5 Block Demand Response Resource ...........................................................................668 6.1.6 Jointly Owned Resource ............................................................................................668 6.1.6.1 Individual Resource Option .................................................................................669 6.1.6.2 Combined Resource Option .................................................................................669 6.1.7 Combined Cycle Resource .........................................................................................670 6.1.8 Dispatchable Variable Energy Resource ...................................................................675 6.1.9 Non-Dispatchable Variable Energy Resource ...........................................................676 6.1.10 Resources External to the SPP BA ............................................................................676 6.1.10.1 External Dynamic Resources ...............................................................................676 6.1.10.2 Resources External to the SPP BA Pseudo-Tying In...........................................677 6.1.10.3 Resources Internal to the SPP BA Pseudo-Tying Out .........................................677 6.1.11 Operating Reserve Certification ................................................................................678 6.1.11.1 Spin Qualified Resources .....................................................................................678 6.1.11.2 Supplemental Qualified Resources ......................................................................679 6.1.11.3 Regulation Qualified Resources ..........................................................................681
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6.1.11.3.1 Regulation Testing Procedures ......................................................................681 6.1.11.3.2 Regulation Testing Scoring............................................................................683 6.1.11.3.3 Regulation Qualified Resource Compliance Rating ......................................685 6.1.12 Resource Auxiliary Load Modeling...........................................................................685 6.2 Registration of Load ........................................................................................................686 6.2.1 Responsibilities of the Load.......................................................................................687 6.2.2 Non-Conforming Load...............................................................................................687 6.2.3 Demand Response Load Asset...................................................................................687 6.2.4 Dispatchable Demand Response Load Settlement Location .....................................687 6.2.5 Block Demand Response Load Settlement Location.................................................687 6.2.6 Loads External to the SPP BA Pseudo-Tying In .......................................................688 6.2.7 Loads Internal to the SPP BA Pseudo-Tying Out ......................................................688 6.2.8 Loads Transfers Relating to Bilateral Contracts ........................................................689 6.3 Registration of Meter Agent ............................................................................................689 6.4 Network and Commercial Model Updates ......................................................................689 6.5 Registration of External Participants in the Reserve Sharing Group ...............................691 6.6 TCR/ARR Related Network and Commercial Model Updates .......................................691 7. Market System Outage and Error Handling.....................................................................693 7.1 Market System Outages ...................................................................................................693 7.1.1 Day-Ahead Market System Outages ..........................................................................693 7.1.2 SPP-Wide Real-Time Balancing Market System Outages ........................................694 7.1.3 Islanded Real-Time Balancing Market System Outages ...........................................694 7.2 Procedures for Correcting LMPs and/or MCPs Resulting From Market Software and Data Input Errors ......................................................................................................................695 7.2.1 Procedure for Evaluating and Correcting Market Software and Data Input Errors ...695 7.2.2 Procedures for Revising Prices in Response to Market Software and Data Input Errors695 7.2.2.1 Notice to Market Participants and the Public ......................................................695 7.2.2.2 Price Corrections Identified After the End of the Notice Period .........................696 7.2.2.3 Process for Recalculating DA Market Cleared Amounts and Prices ...................696 7.2.2.4 Process for Recalculating RTBM Prices..............................................................696 7.2.2.5 Compensatory Payments to Market Participants .................................................697
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7.2.3 Disputes and Resettlement Provisions .......................................................................697 8. Market Monitoring and Mitigation....................................................................................698 8.1 Market Monitoring Plan ...................................................................................................698 8.1.1 Purpose and Objective ...............................................................................................698 8.1.2 Resolution of Conflicts ..............................................................................................699 8.1.3 Independent Market Monitor .....................................................................................699 8.1.3.1 Staffing and Resources ........................................................................................699 8.1.3.2 Relationships and Notifications ...........................................................................699 8.1.3.3 Standards of Conduct ...........................................................................................700 8.1.4 Market Monitoring .....................................................................................................700 8.1.4.1 Markets to be Monitored ......................................................................................700 8.1.4.2 Monitoring Activities ...........................................................................................701 8.1.4.3 Instances of Market Power...................................................................................702 8.1.4.4 Market Participant Behavior Warranting Possible Mitigation.............................703 8.1.5 Inquiries .....................................................................................................................703 8.1.5.1 Requests ...............................................................................................................703 8.1.5.2 Conducting Inquiries ............................................................................................704 8.1.5.3 Reporting..............................................................................................................704 8.1.6 Compliance and Corrective Actions ..........................................................................705 8.1.6.1 Compliance ..........................................................................................................705 8.1.6.2 Corrective Actions for Market Design .................................................................705 8.1.7 Reporting....................................................................................................................706 8.1.7.1 Annual State of the Market Report ......................................................................706 8.1.7.2 Monthly, Quarterly and Annual Metrics Reports ................................................707 8.1.7.3 Communication of Market Monitoring Reports ..................................................707 8.1.7.4 Other Reports .......................................................................................................707 8.1.8 Performance Indices, Metrics and Screens ................................................................707 8.1.8.1 Development ........................................................................................................708 8.1.9 Referrals to the Commission ......................................................................................708 8.1.10 Market Manipulation .................................................................................................708
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8.1.11 Monitoring for Potential Transmission Market Power Activities..............................708 8.1.12 Data Access, Collection and Retention ......................................................................709 8.1.12.1 Confidentiality .....................................................................................................709 8.1.12.2 Access to SPP Data and Information ...................................................................710 8.1.12.3 Access to Market Participant Data and Information ............................................710 8.1.12.4 Data Created by the Market Monitor ...................................................................712 8.1.13 Miscellaneous Provisions...........................................................................................712 8.1.13.1 Rights and Remedies............................................................................................712 8.1.13.2 Disputes................................................................................................................712 8.1.13.3 Review of Market Monitor ..................................................................................712 8.2 Market Power Mitigation and Monitoring .......................................................................712 8.2.1 Purpose and Objectives ..............................................................................................712 8.2.2 Economic Withholding ..............................................................................................713 8.2.2.1 Mitigate Only in the Presence of Local Market Power........................................713 8.2.2.2 Mitigation Measures ............................................................................................713 8.2.2.3 Mitigation Measures for Energy Offer Curves ....................................................714 8.2.2.4 Mitigation Measures for Start-Up and No-Load Offers ......................................716 8.2.2.5 Mitigation Measures for Operating Reserve Offers.............................................718 8.2.2.6 Mitigation Measures for Transition State Offers .................................................721 8.2.2.7 Local Market Power Test .....................................................................................722 8.2.2.7.1 Frequently Constrained Areas........................................................................722 8.2.2.8 Additional Mitigation Measures for Resource Offer Parameters ........................723 8.2.2.9 Market Impact Test ..............................................................................................725 8.2.2.10 Mitigated Offer Development Guidelines ...........................................................725 8.2.2.11 Participant Requested Mitigation Exceptions ......................................................726 8.2.3 Uneconomic Production.............................................................................................727 8.2.4 Measures and Mitigation for Virtual Energy Bids and Offers ...................................728 8.2.4.1 Metric and Threshold Specifications ...................................................................728 8.2.4.2 Excessive Divergence and Mitigation Measures .................................................728 8.2.5 Offer Caps and Floors ................................................................................................728
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8.2.6 Physical Withholding .................................................................................................729 8.2.6.1 Thresholds for Identifying Physical Withholding of Resource Capacity ............730 8.2.6.2 Thresholds for Identifying Physical Withholding of Transmission Facilities .....731 8.2.6.3 Sanctions for Physical Withholding.....................................................................731 8.2.7 Sanctions for Noncompliance with the Day-Ahead Market Must Offer Requirement731 8.2.8 Maintenance and Implementation of the Mitigation Protocols..................................732 9. Protocol Revision Request Process .....................................................................................733 9.1 Submission of a Protocol Revision Request ....................................................................733 9.2 Protocol Revision Procedure............................................................................................733 9.2.1 Review and Posting of Protocol Revision Requests ..................................................735 9.2.2 Comments on a PRR ..................................................................................................736 9.2.3 Impact Analysis .........................................................................................................736 9.2.4 Market Working Group Review and Action ..............................................................737 9.2.5 Operations Reliability Working Group Review ........................................................738 9.2.6 Regional Tariff Working Group Review ...................................................................738 9.2.7 Market and Operations Policy Committee Action .....................................................739 9.2.8 SPP Board of Directors Review and Action ..............................................................739 9.2.9 Withdrawal of Protocol Revision Request .................................................................740 9.2.10 Expedited Review Requests .......................................................................................740 9.2.11 Urgent Action Requests .............................................................................................740 9.2.12 Appeal of Decision ....................................................................................................741 10. Market Process and System Change Process ....................................................................742 10.1 Root Cause Analysis ........................................................................................................744 Appendix A – Registration Portal ............................................................................................745 Appendix B - XML Specifications ............................................................................................746 Appendix C - Meter Technical Protocols.................................................................................747 1. Scope......................................................................................................................................748 2. Purpose..................................................................................................................................748 3. Definitions .............................................................................................................................748 4. Applicable Standards...........................................................................................................748
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5. General ..................................................................................................................................749 5.1 Introduction ......................................................................................................................749 5.2 Existing Facilities.............................................................................................................749 5.3 Physical Location of Meter ..............................................................................................749 5.4 Metering of Net Interchange ............................................................................................749 5.5 Metering for Resources ....................................................................................................749 5.6 Metering for Loads ..........................................................................................................750 5.7 Measurement Quantity Verification ................................................................................750 5.8 Measurement Governance ...............................................................................................750 6. Timing Standard ..................................................................................................................750 6.1 Remote Terminal Unit (RTU) Freeze Contact or Signal .................................................750 6.2 Accumulators / Register Values.......................................................................................750 6.3 Accuracy - Meter .............................................................................................................750 6.4 Accuracy – EMS/RTU .....................................................................................................751 7. Meters....................................................................................................................................751 7.1 Measurement Quantities ..................................................................................................751 7.2 Measurement Configuration ............................................................................................751 7.3 Accuracy ..........................................................................................................................752 7.4 Testing..............................................................................................................................752 7.4.1 Testing Equipment .....................................................................................................752 7.4.2 Acceptance Testing ....................................................................................................752 7.4.3 In-Service Testing ......................................................................................................752 7.4.4 Verification Records and Retention ...........................................................................753 7.5 Real Time Metering .........................................................................................................753 7.5.1 General .......................................................................................................................753 7.5.2 Measurement Configuration ......................................................................................754 7.5.3 Accuracy ....................................................................................................................754 7.5.4 Testing........................................................................................................................754 7.5.4.1 Testing Equipment ...............................................................................................754 7.5.4.2 Acceptance Testing ..............................................................................................755
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7.5.4.3 Operating Conditions ...........................................................................................755 7.5.4.4 Output Characteristics ..........................................................................................755 7.5.4.5 In Service Testing ................................................................................................755 7.5.4.6 Verification Records and Retention .....................................................................756 7.6 New Current and Voltage Sensing Technologies ............................................................756 7.7 Current Transformers .......................................................................................................756 7.7.1 Nameplate ..................................................................................................................756 7.7.2 Polarity .......................................................................................................................757 7.7.3 Burden Testing ...........................................................................................................757 7.7.4 Paralleling ..................................................................................................................757 7.8 Coupling Capacitor Voltage Transformers ......................................................................758 7.8.1 General .......................................................................................................................758 7.8.2 Nameplate ..................................................................................................................758 7.8.3 Polarity .......................................................................................................................759 7.8.4 Burden ........................................................................................................................759 7.9 Wire Wound Voltage Transformers.................................................................................759 7.9.1 Nameplate ..................................................................................................................759 7.9.2 Polarity .......................................................................................................................759 7.9.3 Burden ........................................................................................................................760 7.10 Ancillary Devices.............................................................................................................760 7.10.1 Wiring ........................................................................................................................760 7.10.1.1 Phase Wiring ........................................................................................................760 7.10.1.2 Neutral Returns ....................................................................................................760 7.10.1.3 Induced Voltage on Wiring..................................................................................761 7.10.1.4 Fusing ...................................................................................................................761 7.10.1.5 Test Switches .......................................................................................................761 7.11 Metering Site Procedures .................................................................................................761 7.11.1 General .......................................................................................................................761 7.11.2 Site Verification Procedure ........................................................................................762 7.11.3 Periodic Test Procedure .............................................................................................762
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7.12 Node Loss Compensation ................................................................................................764 7.12.1 General .......................................................................................................................764 7.12.2 Methods for Compensation ........................................................................................765 7.12.2.1 Flat Percentage Adjustment .................................................................................765 7.12.2.2 Engineered Adjustment with Assumptions..........................................................766 7.12.2.3 Engineered Adjustment ........................................................................................766 7.12.3 Node Loss Compensation Variables and Calculations ..............................................766 7.12.3.1 Transformer Test Data .........................................................................................766 7.12.3.2 Calculating data not supplied with Transformer Test Data .................................767 7.12.3.3 Transmission line losses ......................................................................................767 7.12.3.4 Secondary line losses ...........................................................................................768 7.13 Record Retention .............................................................................................................769 Appendix D - Settlement Metering Data Management Protocols .........................................770 1. Scope......................................................................................................................................771 2. Purpose..................................................................................................................................771 3. Definitions .............................................................................................................................771 4. Market Participants .............................................................................................................771 4.1 Responsibilities ................................................................................................................771 4.2 Meter Agent(s) Designation .............................................................................................771 5. Meter Agent ..........................................................................................................................772 6. Data Format .........................................................................................................................772 6.1 Unit of Measure ...............................................................................................................772 6.2 Sign Convention of Data ..................................................................................................773 6.3 Meter Technical Standards ..............................................................................................773 6.4 Data Submission Standards..............................................................................................773 7. Settlement Meter Data Types .............................................................................................773 7.1 Resource Metering ...........................................................................................................774 7.1.1 Joint Owned Unit (JOU) Generation .........................................................................774 7.1.2 Generation Loss Compensation .................................................................................774 7.2 Load Metering..................................................................................................................774
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7.2.1 General .......................................................................................................................774 7.2.2 Load Loss Compensation ...........................................................................................774 7.2.3 Residual Load ............................................................................................................775 7.3 Hourly Metered Interchange ............................................................................................775 7.3.1 Substitution for Missing Data ....................................................................................776 8. Settlement Location Anatomy ............................................................................................776 8.1 General .............................................................................................................................776 8.2 Making of a Settlement Location .....................................................................................776 8.2.1 Resource and Load Settlement Locations ..................................................................777 8.2.2 Overview of Settlement Area Load Settlement Locations ........................................778 9. Loss Compensation ..............................................................................................................779 9.1 General .............................................................................................................................779 9.2 Loss Compensation Examples .........................................................................................779 9.2.1 Loss Compensation to Node when Meter is on Distribution System ........................780 9.2.2 Loss Compensation to Node when Meter and Node at Different Location ...............782 9.3 Meter Data Exchange and Submission ............................................................................783 9.3.1 Actual Meter Data (Idata) ..........................................................................................783 9.3.2 Alternate Settlement Meter Data ...............................................................................784 10. Data Source and Estimating ...............................................................................................784 10.1 Actual Meter Data (Idata – Actual) .................................................................................784 10.1.1 Primary Data Sources ................................................................................................785 10.1.2 Backup Data Sources .................................................................................................785 10.2 Estimated Meter Data (Idata – Estimated) .......................................................................785 10.2.1 Estimation Methods ...................................................................................................785 10.2.2 Replacing Estimated Meter Data ...............................................................................786 11. Verification Meter SL Values .............................................................................................786 11.1 Data Types and Verification Methods .............................................................................786 11.1.1 Telemetered Pulses via Remote Terminal Unit (RTU)..............................................787 11.1.2 Register Transfer via Other Communication Options ...............................................787 11.1.3 Interval Data Recorder Collection System (IDRCS) .................................................787
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11.1.4 Inter Control Center Protocol (ICCP) Data ...............................................................787 11.1.5 Alternate Data for Verification ..................................................................................788 11.2 Periodicity of Verification ...............................................................................................788 11.2.1 Telemetered Pulses via Remote Terminal Unit (RTU)..............................................788 11.2.2 Other Data Transfers ..................................................................................................788 11.3 Verification Uncovers Discrepancy .................................................................................788 11.3.1 Identify the Cause for the Discrepancy ......................................................................788 11.3.2 Impact to Settlement Location Values Submitted .....................................................789 11.3.2.1 Settlement Data Values Correct ...........................................................................789 11.3.2.2 Settlement Data Values Incorrect ........................................................................789 11.3.2.2.1 Requirement for Resubmission ......................................................................789 11.3.2.2.2 Good Utility Business Practices/Contractual Requirements ..........................789 12. Real Time Data Reporting to SPP Balancing Authority ..................................................789 13. Record Retention .................................................................................................................790 Appendix E - Network and Commercial Model Update Timing ...........................................791 Appendix F - Settlement Examples ..........................................................................................818 1. Introduction ..........................................................................................................................819 1.1 Purpose.............................................................................................................................819 1.2 Definition of Terms..........................................................................................................819 1.3 Outstanding Issues/Assumptions .....................................................................................821 2. Market Model .......................................................................................................................822 2.1 Commercial Model ..........................................................................................................822 2.1.1 Financial Entities and Relationships ..........................................................................822 2.1.2 Network Entities and Relationships ...........................................................................824 2.2 Transactional Legend .......................................................................................................825 Appendix G - Mitigated Offer Development Guidelines ........................................................826 1. Introduction ..........................................................................................................................827 1.1 About These Guidelines ...................................................................................................827 1.2 Intended Audience ...........................................................................................................827 1.3 What is in this Manual? ...................................................................................................827
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1.4 Mitigated Offer Task Force .............................................................................................828 1.5 Purpose.............................................................................................................................828 1.6 Mitigated Offer Methodology Approval Process ............................................................828 2. Policies for All Resource Types ..........................................................................................829 2.1 Heat Rates ........................................................................................................................829 2.1.1 Heat Content of Fuel ..................................................................................................830 2.1.2 Heat Rate Curves .......................................................................................................830 2.2 Performance Factors ........................................................................................................831 2.2.1 Engineering Judgment in Performance Factors .........................................................832 2.2.2 Calculation Methods of Performance Factors............................................................832 2.2.3 “Like” Resources for Performance Factors ...............................................................833 2.3 Fuel Cost Policies ............................................................................................................833 2.3.1 Modifications to Fuel Cost Policies ...........................................................................834 2.3.2 Fuel Cost Calculation .................................................................................................835 2.3.3 Total Fuel Related Costs ............................................................................................835 2.3.4 Types of Fuel Costs ...................................................................................................836 2.3.5 Emission Allowances .................................................................................................836 2.3.6 Variable Fuel Transportation Equipment...................................................................837 2.4 Total Variable Operation and Maintenance Cost.............................................................838 2.4.1 Escalation Index .........................................................................................................838 2.4.2 Maintenance Period ...................................................................................................839 2.4.3 Average VOM Cost ...................................................................................................840 2.5 Mitigated Energy Offer Curve .........................................................................................841 2.6 Mitigated Start- Up Offer.................................................................................................842 2.6.1 Start- Up Offer Definitions ........................................................................................842 2.7 Mitigated No Load Offer .................................................................................................843 2.7.1 No-Load Definitions ..................................................................................................843 2.7.2 No-Load Fuel .............................................................................................................843 2.8 Mitigated Spinning Reserve Offer ...................................................................................844 2.9 Mitigated Supplemental Reserve Offer ...........................................................................844
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2.10 Mitigated Regulation-Up and Regulation-Down Service Offers.....................................845 2.10.1 Uncompensated Costs: ...............................................................................................845 2.10.2 Cost Increase due to Heat Rate increase during non-steady state:.............................847 2.10.3 Cost increase in Variable Operations and Maintenance: ...........................................847 3. Nuclear Unit Guidelines ......................................................................................................851 3.1 Nuclear Heat Rate ............................................................................................................851 3.2 Performance Factor ..........................................................................................................851 3.3 Fuel Cost ..........................................................................................................................851 3.3.1 Basic Nuclear Fuel Cost.............................................................................................851 3.3.2 Total Fuel-Related Costs for Nuclear Units...............................................................852 3.4 Mitigated Start-Up Offer..................................................................................................852 3.4.1 Hot Start Cost.............................................................................................................852 3.4.2 Intermediate Start Cost ..............................................................................................852 3.4.3 Cold Start Cost ...........................................................................................................853 3.4.4 Additional Components Applied to Hot, Intermediate and Cold Start-Up Costs ......853 3.5 Mitigated No Load Offer .................................................................................................854 3.6 VOM Cost ........................................................................................................................854 3.6.1 Configuration Addition VOM Adder.........................................................................854 3.6.2 Calculation of the Configuration Addition VOM Adder: ..........................................854 3.6.3 Reductions in Total VOM Costs:...............................................................................855 3.7 Mitigated Spinning Reserve Offer ...................................................................................855 3.8 Mitigated Supplemental Reserve Offer ...........................................................................855 3.9 Mitigated Regulation Offers ............................................................................................855 4. Fossil Steam Unit Guidelines ..............................................................................................855 4.1 Heat Rate ..........................................................................................................................856 4.2 Performance Factor ..........................................................................................................856 4.3 Fuel Cost ..........................................................................................................................856 4.4 Hot Start Cost, Intermediate Start Cost, and Cold Start cost ...........................................856 4.4.1 Hot Start Cost.............................................................................................................857 4.4.2 Intermediate Start Cost ..............................................................................................857
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4.4.3 Cold Start Cost ...........................................................................................................858 4.5 Mitigated No Load Offer .................................................................................................859 4.6 VOM Cost ........................................................................................................................859 4.6.1 Configuration Addition VOM Adder.........................................................................859 4.6.2 Calculation of the Configuration Addition VOM Adder ...........................................860 4.6.3 Reductions in Total VOM Costs ................................................................................860 4.7 Mitigated Spinning Reserve Offer ...................................................................................860 4.8 Mitigated Supplemental Reserve Offer ...........................................................................860 4.9 Regulation ........................................................................................................................861 5. Combined Cycle (CC) Guidelines.......................................................................................861 5.1 Heat Rate ..........................................................................................................................861 5.2 Performance Factors ........................................................................................................861 5.3 Fuel Cost ..........................................................................................................................861 5.4 Mitigated Start-Up Offer..................................................................................................861 5.5 Mitigated Transition State Offer ......................................................................................863 5.6 Mitigated No Load Offer .................................................................................................863 5.7 VOM Cost ........................................................................................................................863 5.8 Mitigated Spinning Reserve Offer ...................................................................................863 5.9 Mitigated Supplemental Reserve Offer ...........................................................................863 5.10 Mitigated Regulation Offers ............................................................................................864 6. Combustion Turbine (CT) and Reciprocating Engine Guidelines ..................................864 6.1 Combustion Turbine and Reciprocating Engine Heat Rate .............................................864 6.2 Performance Factor ..........................................................................................................864 6.3 Fuel Cost ..........................................................................................................................865 6.3.1 Combustion Turbine other Fuel-Related Costs..........................................................865 6.4 Energy Offer Curve for Quick Start.................................................................................865 6.5 Mitigated Start-Up Offer..................................................................................................866 6.6 Mitigated No Load Offer for CTs ....................................................................................866 6.7 VOM Cost ........................................................................................................................866 6.8 Mitigated Spinning Reserve Offer ...................................................................................866
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6.9 Mitigated Supplemental Reserve Offer ...........................................................................867 6.10 Mitigated Regulation Offers ............................................................................................867 7. Hydro Guidelines .................................................................................................................868 7.1 Pumping Efficiency (Pumped Hydro Only) ....................................................................868 7.2 Performance Factors ........................................................................................................869 7.3 Fuel Cost ..........................................................................................................................869 7.3.1 Total Energy Input Related Costs for Pumped Storage Hydro Plant Generation ......870 7.4 Mitigated Start-Up Offer..................................................................................................870 7.5 Mitigated No Load Offer .................................................................................................870 7.6 VOM Cost ........................................................................................................................870 7.7 Spinning Reserve: Hydro Unit Costs ...............................................................................870 7.8 Mitigated Supplemental Reserve Offer ...........................................................................871 7.9 Mitigated Regulation Offers ............................................................................................871 8. Demand Response Guidelines .............................................................................................871 8.1 Demand Response Resource (DRR) Cost for Behind the Meter Generation ..................872 8.2 DRR Cost for Demand Reduction ...................................................................................872 8.3 DRR Start-Up Cost ..........................................................................................................872 8.4 DRR Cost to Provide Spinning and/or Supplemental Reserves ......................................872 8.5 DRR Cost to Provide Regulation .....................................................................................872 9. Wind Guidelines ...................................................................................................................873 9.1 Fuel Cost ..........................................................................................................................873 9.2 Mitigated Start-Up Offer..................................................................................................873 9.3 Mitigated No Load Offer .................................................................................................873 9.4 VOM ................................................................................................................................873 10. Solar Guidelines ...................................................................................................................873 10.1 Fuel Cost ..........................................................................................................................873 10.2 Mitigated Start-Up Offer..................................................................................................874 10.3 Mitigated No Load Offer .................................................................................................874 10.4 VOM ................................................................................................................................874 11. Energy Market Opportunity Cost Guidelines ...................................................................874
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11.1 Basis for Opportunity Cost to be Included in Mitigated Offers.......................................874 11.1.1
Environmental Run-hour Restriction .........................................................................874
11.1.2
Physical Equipment Limitations ................................................................................874
11.1.3
Non-Regulatory Opportunity Cost: Fuel Limitations ................................................875
11.2 Calculation Method ..........................................................................................................875 11.2.1
Overview of the Opportunity Cost Calculation .........................................................876
11.2.2
Daily Opportunity Cost Calculation ..........................................................................876
11.2.2.1 Step 1: Forecast Hourly Resource LMPs .............................................................876 11.2.2.2 Step 2: Calculate the price-cost margin for each hour of the day ........................877 11.2.2.3 Step 3: Determine the Opportunity Cost Component ..........................................878 11.2.3
Long Term Opportunity Cost Calculation .................................................................878
11.2.3.1 Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPs ........878 11.2.3.2 Step 2: Derive Historical Monthly LMP Basis Differential between the Resource Settlement Location and the SPP Real-Time Marginal Energy Component of LMP .....................................................................................................................880 11.2.3.3 Step 3: Derive hourly volatility scalars to incorporate hourly volatility into the LMP forecast........................................................................................................883 11.2.3.4 Step 4: Create three sets of hourly forecasted Resource Settlement Location values ...................................................................................................................885 11.2.3.5 Step 5: Create a daily fuel volatility scalar ..........................................................886 11.2.3.6 Step 6: Create three daily delivered fuel forecasts ...............................................888 11.2.3.7 Step 7: Create Resource(s) cost for each of the three forecasts ...........................890 11.2.3.8 Step 8: Calculate the margin for every hour in the three hourly forecasts ..........892 11.2.3.9 Step 9: Determine the opportunity cost component .............................................894 11.2.4
Short Term Opportunity Cost Calculation .................................................................895
11.2.4.1 Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPs ........895 11.2.4.2 Step 2: Derive Historical Monthly LMP Basis Differential between the Resource Settlement Location and the SPP Real Time Marginal Energy Component of LMP897 11.2.4.3 Step 3: Derive hourly volatility scalars to incorporate hourly volatility into the LMP forecast........................................................................................................901 11.2.4.4 Step 4: Create three sets of hourly forecasted Resource LMPs ...........................902 11.2.4.5 Step 5: Fuel Price .................................................................................................904
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11.2.4.6 Step 6: Create generating unit’s cost for each of the three forecasts ...................905 11.2.4.7 Step 7: Calculate the margin for every hour in the three hourly forecasts ..........907 11.2.4.8 Step 8: Determine the opportunity cost adder......................................................909 Appendix G – Attachment A. No Load Calculation Examples .............................................911 A.1 No-Load Fuel ...................................................................................................................911 A.2 Typical Steam Unit Example ...........................................................................................911 A.3 Typical Combustion Turbine Example ............................................................................915 B.1 No-Load Cost Adjustments..............................................................................................919 B.2 Combustion Turbine Zero No-Load Example .................................................................924
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List of Exhibits: Exhibit 2-1: Document Relationships........................................................................................ 61 Exhibit 3-1: Overview of Key Energy and Operating Reserve Market Functions ............... 64 Exhibit 3-2: Energy and Operating Reserve Markets Processes Timeline ........................... 67 Exhibit 3-3: Overview of TCR Markets Structure .................................................................. 73 Exhibit 3-4: LTCR/ARR Allocation/TCR Auction Processes Timeline ................................ 74 Exhibit 4-1: VRL Values ............................................................................................................ 89 Exhibit 4-2: VRL and Demand Curve Interaction .................................................................. 97 Exhibit 4-3: Ramp Sharing Example ...................................................................................... 101 Exhibit 4-4: Pre Day-Ahead Activities Timeline .................................................................... 105 Exhibit 4-5: Energy Offer Curve Development ..................................................................... 113 Exhibit 4-6: Resource Limit Relationships ............................................................................. 123 Exhibit 4-7: Resource Commitment Parameter Relationships ............................................ 125 Exhibit 4-8: Calculated DDR Output ..................................................................................... 128 Exhibit 4-9: Virtual Energy Offer Curve Development ........................................................ 144 Exhibit 4-10: Demand Bid Curve Development ..................................................................... 147 Exhibit 4-11: Virtual Energy Bid Curve Development ......................................................... 149 Exhibit 4-12: Day-Ahead Activities Timeline ......................................................................... 155 Exhibit 4-13: Operating Day Activities Timeline ................................................................... 167 Exhibit 4-14: SCED Quick-Start Resource Logic .................................................................. 180 Exhibit 4-15: AGC System Control Status ............................................................................. 190 Exhibit 4-16: Contingency Reserve Deployment Compliance Measurement – Test 1 ....... 196 Exhibit 4-17: Contingency Reserve Deployment Compliance Measurement – Test 2 ....... 198 Exhibit 4-18: Contingency Reserve Deployment Compliance Measurement – Test 3 ....... 199 Exhibit 4-19: Contingency Reserve Deployment Compliance Measurement – Test 4 ....... 200 Exhibit 4-20: Post Operating Day Activities Timeline .......................................................... 202 Exhibit 4-21: Example of Commercial Model Relationships ................................................ 207 Exhibit 4-22: Input Data Precision and Rounding Assumptions ......................................... 219 Exhibit 4-23: FERC EQR Reporting Billing Determinants .................................................. 220 Exhibit 4-24: Meter Profiling Example................................................................................... 358
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Exhibit 4-25: RUC Make-Whole Payment Eligibility Period – Multiple Operating Days 417 Exhibit 4-26: Settlements Timeline – Non Holiday Example ............................................... 615 Exhibit 4-27: Settlements Timeline –Holiday Example......................................................... 616 Exhibit 4-28: Contents of Notice Dispute Form ..................................................................... 620 Exhibit 5-1: LTCR/ARR Allocation and TCR Auction Processes Timeline ....................... 628 Exhibit 5-2: TCR Auction Processes Summary ..................................................................... 629 Exhibit 5-3: Annual ARR Allocation Process Timeline ....................................................... 644 Exhibit 5-4: Candidate ARR Nomination for NITS .............................................................. 646 Exhibit 5-5: Annual TCR Auction Processes Timeline ........................................................ 649 Exhibit 5-6: Monthly TCR Auction Processes Timeline ....................................................... 657 Exhibit 5-7: Interim Process Detail Calendar ........................................................................ 662 Exhibit 6-1: Commercial Model and Network Element Relationships................................ 665 Exhibit 6-2: Combined Cycle Configuration Enabled Start/Shutdown Capability ........... 672 Exhibit 6-3: Combined Cycle Configuration Transition Cost Matrix ................................. 673 Exhibit 6-4: Combined Cycle Configuration Capability Array ........................................... 674 Exhibit 6-5: Combined Cycle Configuration Group Definition ........................................... 674 Exhibit 6-6: Combined Cycle Configuration Group Definition ........................................... 674 Exhibit 6-7: Regulation Testing Procedure ............................................................................ 683 Exhibit 6-8: Model Update Timeline ....................................................................................... 689 Exhibit 6-9: TCR Related Model Update Timeline ............................................................... 691 Exhibit 9-1: Process Flow Chart for Protocol Revision Requests ........................................ 734
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Glossary
1.
Actual Regulation-Down Mileage The sum of the absolute values of actual movements by a Resource with cleared Regulation-Down Service MW in response to Regulation DeploymentAs defined in the SPP Tariff.
Comment [MPRR204.1]: MPRR204 Awaiting FERC filing
Actual Regulation-Up Mileage The sum of the absolute values of actual movements by a Resource with cleared Regulation-Up Service MW in response to Regulation DeploymentAs defined in the SPP Comment [MPRR102.2]: MPRR102 Awaiting implementation. #ER13-1748
Tariff.
Comment [MPRR204.3]: MPRR204 Awaiting FERC filing
Aggregate Price Node (APNode) A collection of Price Nodes (PNodes) whose prices are averaged with a defined weighting component to determine an aggregate price. Asset Owner An owner of any combination of: (1) registered physical assets (Resource, load, Import Interchange Transaction, Export Interchange Transaction, Through Interchange Transaction), (2) Transmission Congestion Rights or (3) any combination of financial assets (Virtual Energy Offer, Virtual Energy Bid, Bilateral Settlement Schedules) within the SPP Balancing Authority Area. Auction Clearing Price (ACP) The prices generated at each source and sink Settlement Location in each round of the Annual TCR Auction and Monthly TCR Auction based upon the TCR Offers and Bids submitted. Auction Revenue Right (ARR) As defined in Attachment AE of the Tariff.A financial right, awarded during the annual ARR allocation process and/or monthly ARR allocation process, that entitles the holder to a share of the auction revenues generated in the applicable Transmission Congestion Rights (TCR) auction(s) and/or entitles the holder to self-covert the ARRs into TCRs. ARR Nomination Cap
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As defined in Attachment AE of the Tariff.The maximum total amount of ARRs that an Eligible Entity may nominate in each month and season in the annual ARR allocation process and the monthly incremental ARR allocation process. Balancing Authority As defined in the SPP Tariff. Balancing Authority Area As defined in the SPP Tariff. Bilateral Settlement Schedule As defined in Attachment AE of the SPP Tariff. Bid A commitment to pay a specific maximum price for a quantity of Energy or TCRs such as a Demand Bid, Virtual Energy Bid an Export Interchange Transaction Bid and/or a TCR Bid. Block Demand Response Load Settlement Location As defined in the Tariff. Block Demand Response Resource A controllable load, including controllable load of an aggregator of retail customers, that is not a Dispatchable Resource that can reduce the withdrawal of Energy from the transmission grid when directed by SPP. Central Prevailing Time (CPT) Clock time for the season of a year, i.e. Central Standard Time and Central Daylight Time. Commercial Model A representation of the attributes of and the relationships between Market Participants, Asset Owners, Resource and load assets and Pricing Nodes for use in the Energy and Operating Reserve Markets, and Transmission Congestion Rights Markets. Commitment Status A parameter submitted as part of a Resource Offer that specifies the option under which the Resource is to be committed.
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Commit Time The time specified by SPP or a local Transmission Operator in a commit order at which a Resource should be synchronized and at or above Minimum Economic Capacity Operating Limit. Common Bus A single bus to which two or more Resources that are owned by the same Asset Owner are connected in an electrically equivalent manner where such Resources may be treated as interchangeable for certain compliance monitoring purposes. Congestion Management Event (CME) An event during which constraints are activated in RTBM in order to re-dispatch the system to reduce the impact of SPP Market Flow on a Coordinated Flowgate or Reciprocal Coordinated Flowgate or in order to redispatch the system to remove projected limit violation on flowgates other than a Coordinated Flowgate or Reciprocal Coordinated Flowgate. This event may entail a parallel issuance of TLR. Contingency Reserve As defined in the SPP Tariff. Contingency Reserve Deployment Instruction An instruction issued by SPP to Resources cleared for Contingency Reserve in the RealTime Balancing Market to deploy a specific MW quantity of Contingency Reserve, rounded to one decimal place, as communicated as a component of the Setpoint Instructions. Contingency Reserve Deployment Period The time period following the issuance of a Contingency Reserve Deployment Instruction within which a Resource has to deploy Contingency Reserve which is set at ten (10) minutes. Contingency Reserve Ramp Rate A curve specifying MW/minute ramp rates that are used to determine a Resource’s maximum Spinning Reserve quantities or on-line Supplemental Reserve quantities. Control Status
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A parameter communicated electronically to SPP by a Market Participant at any time during an Operating Hour indicating a Resource’s ability to follow Setpoint Instructions. Current Operating Plan SPP’s internal hourly Resource commitment schedule for the Operating Day resulting from the various Day-Ahead Market and Day-Ahead Reliability Unit Commitment processes and updated, as required, during the Intra-Day RUC process that is used as input into the Real-Time Balancing Market. DA Market Commitment Period The contiguous period of time between a Resource’s DA Market Commit Time and DA Market De-Commit Time. Day-Ahead The time period starting at 0001 and ending at 2400 on the day prior to the Operating Day. Day-Ahead Market (DA Market) The financially binding market for Energy and Operating Reserve that is conducted on the day prior to the Operating Day. Day-Ahead Reliability Unit Commitment (Day-Ahead RUC) The process performed by SPP following the close of the DA Market and prior to the Operating day to assess resource and operating reserve adequacy for the Operating Day, commit and/or de-commit Resources as necessary, and communicate commitment or decommitment of Resources to the appropriate Market Participants as necessary. De-Commit Time The time specified by SPP or a local Transmission Operator in a de-commit order at which a Resource should begin de-synchronization procedures. Demand Bid A proposal by a Market Participant associated with a physical load to purchase a fixed or price sensitive-amount of Energy at a specified location and period of time in the DayAhead Market. Demand Bid Curve As defined in the SPP Tariff.
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Demand Curve A series of quantity/price points used to set Operating Reserve Market Clearing Prices when there is a supply shortage of Operating Reserve and to set LMPs when there is shortage of capacity to meet Energy requirements. Demand Response Load A measurable load that is capable of being reduced at the instruction of the SPP operator and subsequently increased at the instruction of the SPP operator that is identified in the registration of a Dispatchable Demand Response Resource or a Block Demand Response Resource. Demand Response Resource A Dispatchable Demand Response Resource or a Block Demand Response Resource. Designated Resource As defined in the SPP Tariff. Desired Dispatch A MW value calculated from a Resource’s RTBM Energy Offer Curve that represents the point at which the Resource’s incremental Energy offer first exceeds the Resource’s RTBM LMP. Dispatch Instruction (DI) The communicated Resource target energy MW output level at the end of the Dispatch Interval, rounded to one decimal place. Dispatch Interval The period of time for which SPP issues Dispatch Instructions for Energy and clears Operating Reserve in the Real-Time Balancing Market. The Dispatch Interval is currently 5 minutes. Dispatch Status A parameter submitted as part of a Resource Offer that specifies the option under which the Resource is to be dispatched once the Resource has been committed and becomes a Synchronized Resource. Dispatchable Demand Response Load Settlement Location
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As defined in the Tariff. Dispatchable Demand Response Resource A controllable load, including behind-the-meter generation, that is a Dispatchable Resource that can reduce the withdrawal of Energy from the transmission grid when directed by SPP. Dispatchable Resource A Resource for which an Energy Offer Curve has been submitted and that is available for dispatch by SPP on a Dispatch Interval basis. Dispatchable Variable Energy Resource A Variable Energy Resource that is capable of being incrementally dispatched down by the Transmission Provider. Electric Industry Registry (EIR) The Electric Industry Registry serves as a central repository of information that is required for commercial interactions. Electrical Node (ENode) A physical node represented in the Network Model where electrical equipment and components are connected. Eligible Entity A Transmission Customer or Market Participant that is eligible to nominate ARRs during the annual allocation process. Emergency As defined as Emergency Condition in the SPP Tariff. Energy An amount of electricity that is Bid or Offered, produced, purchased, consumed, sold or transmitted over a period of time, which is measured or calculated in megawatt hours (MWh). Energy and Operating Reserve Markets The Day-Ahead Market and Real-Time Balancing Market.
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Energy Management System (EMS) The software system used by SPP for the real-time acquisition of operating data and operations. Energy Offer Curve A set of price/quantity pairs that represents the offer to provide Energy from a Resource. Excess Regulation-Down Mileage Settled Regulation-Down mileage that exceeds the amount of Expected Regulation-Down Mileage. Excess Regulation-Up Mileage Settled Regulation-Up mileage that exceeds the amount of Expected Regulation-Up Mileage. Expected Regulation-Down Mileage Regulation-Down mileage included as part of the market clearing that is equal to the amount of Regulation-Down cleared multiplied by the Regulation-Down Mileage Factor. Expected Regulation-Up Mileage Regulation-Up mileage included as part of the market clearing that is equal to the amount of Regulation-Up cleared multiplied by the Regulation-Down Mileage Factor. Export Interchange Transaction A Market Participant schedule for exporting Energy out of the SPP Balancing Authority Area. Export Interchange Transaction Bid A proposal by a Market Participant to purchase a fixed or price-sensitive amount of Energy in the Day-Ahead Market or a fixed amount of Energy in the Real-Time Balancing Market for delivery outside of the SPP Balancing Authority Area at a specified External Interface and period of time. External Interface A Settlement Location representing a physical interconnection point(s) between the SPP Balancing Authority Area and an External Balancing Authority Area.
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Firm Point-to-Point ARR Nomination Cap (“FPTP ARR Nomination Cap”) As defined in Attachment AE of the Tariff.The maximum total amount of FPTP Candidate ARRs that an Eligible Entity may nominate in each month and season in the annual ARR allocation process and/or the monthly ARR allocation process.
Comment [MPRR138.9]: MPRR138 Awaiting FERC Approval. #ER14-2553
Firm Point-to-Point Candidate ARR (“FPTP Candidate ARR”) As defined in Attachment AE of the Tariff.All or portion of the MW quantity of a confirmed Firm Point-To-Point Transmission Service Reservation (TSR) that the holder of the TSR can nominate for conversion into an ARR in the ARR allocation process.
Comment [MPRR138.10]: MPRR138 Awaiting FERC Approval. #ER14-2553
Firm Point-to-Point Candidate LTCR (“FPTP Candidate LTCR”) Comment [MPRR138.11]: MPRR138 Awaiting FERC Approval. #ER14-2553
As defined in Attachment AE of the Tariff. Firm Point-to-Point Transmission Service As defined in the SPP Tariff. Floor-room As defined in the SPP Tariff. GFA Carve Out As defined in the SPP Tariff. GFA Carve Out Schedule As defined in the SPP Tariff. GFA Responsible Entity As defined in the SPP Tariff.
GFA Firm Point-to-Point ARR Nomination Cap (“GFA FPTP ARR Nomination Cap”) As defined in Attachment AE of the Tariff.The maximum total amount of GFA FPTP Candidate ARRs that an Eligible Entity may nominate in each month and season in the annual ARR allocation process and/or the monthly ARR allocation process. GFA Firm Point-to-Point Candidate ARR (“GFA FPTP Candidate ARR”) As defined in Attachment AE of the Tariff.All or a portion of the MW quantity of the transmission service component of a Grandfathered Agreement (GFA) providing service
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equivalent to Firm Point-to-Point Transmission Service, as defined in the SPP Tariff, verified prior to the start of the annual ARR allocation process, that the applicable Eligible Entity can nominate for conversion into an ARR in the annual ARR allocation process.
Comment [MPRR138.13]: MPRR138 Awaiting FERC Approval. #ER14-2553
GFA Firm Point-to-Point Candidate LTCR (“GFA FPTP Candidate LTCR”) Comment [MPRR138.14]: MPRR138 Awaiting FERC Approval. #ER14-2553
As defined in Attachment AE of the Tariff. GFA NITS ARR Nomination Cap As defined in Attachment AE of the Tariff.The maximum total amount of GFA NITS Candidate ARRs that an Eligible Entity may nominate in each month and season in the annual ARR allocation process and the monthly ARR allocation process.
Comment [MPRR138.15]: MPRR138 Awaiting FERC Approval. #ER14-2553
GFA NITS Candidate ARR As defined in Attachment AE of the Tariff.All or a portion of the MW quantity of the transmission service component of a Grandfathered Agreement (GFA) providing service equivalent to Network Integration Transmission Service, as defined in the SPP Tariff, verified prior to the start of the annual ARR allocation process, that the applicable Eligible Entity can nominate for conversion into an ARR in the ARR allocation process.
Comment [MPRR138.16]: MPRR138 Awaiting FERC Approval. #ER14-2553
GFA NITS Candidate LTCR Comment [MPRR138.17]: MPRR138 Awaiting FERC Approval. #ER14-2553
As defined in Attachment AE of the Tariff. Grandfathered Agreement (GFA) As defined as Grandfathered Agreements or Transactions in the SPP Tariff. Group Minimum Run Time
Comment [MPRR101.18]: MPRR101 awaiting FERC filing
As defined in Attachment AE of the SPP Tariff Head-room As defined in the SPP Tariff. Hub A Settlement Location consisting of an aggregation of Price Nodes developed for financial and trading purposes.
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Import Interchange Transaction A Market Participant schedule for importing Energy into the SPP Balancing Authority Area. Import Interchange Transaction Offer A proposal by a Market Participant to purchase a fixed or price-sensitive amount of Energy in the Day-Ahead Market or a fixed amount of Energy in the Real-Time Balancing Market for delivery into the SPP Balancing Authority Area at a specified External Interface and period of time. Instructed Regulation-Down Mileage The sum of the absolute values of instructed movements to a Resource with cleared Regulation-Down Service through Regulation Deployment instructionsAs defined in the SPP Tariff.
Comment [MPRR204.19]: MPRR204 Awaiting FERC filing
Instructed Regulation-Up Mileage The sum of the absolute values of instructed movements to a Resource with cleared Regulation-Up Service through Regulation Deployment instructionsAs defined in the SPP Tariff. Interchange Transaction
Comment [MPRR204.20]: MPRR204 Awaiting FERC filing Comment [MPRR102.21]: MPRR102 Awaiting implementation. #ER13-1748
Any Energy transaction that is crossing the boundary of the SPP Balancing Authority Area and requires checkout with one or more external Balancing Authority Areas. This includes any Import Interchange Transaction, Export Interchange Transaction and/or Through Interchange Transaction. Intra-Day Reliability Unit Commitment (Intra-Day RUC) The process performed by SPP following the completion of the DA RUC and throughout the Operating day to assess Resource and Operating Reserve adequacy for the Operating Day, commit and/or de-commit Resources as necessary, and communicate commitment or de-commitment of Resources to the appropriate Market Participants as necessary. Jointly Owned Resource A Resource that is owned by more than one Asset Owner. Load Serving Entity (LSE) Comment [MPRR138.22]: MPRR138 Awaiting FERC Approval. #ER14-2553
As defined in Attachment AE of the Tariff.
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Local Emergency Condition As defined in the SPP Tariff Local Reliability Issue As defined in the SPP Tariff. Locational Marginal Price (LMP) The market clearing price for Energy at a given Price Node which is equivalent to the marginal cost of serving demand at the Price Node while meeting SPP Operating Reserve requirements. Long-Term Congestion Right (LTCR) Comment [MPRR138.23]: MPRR138 Awaiting FERC Approval. #ER14-2553
As defined in Attachment AE of the Tariff. Loss Pool As defined in the SPP Tariff. Manual Dispatch Instruction A dispatch instruction created outside of the normal RTBM SCED Dispatch Instruction solution to address a system reliability condition that could not be resolved by the RTBM SCED. Market Clearing Price (MCP) The price used for settlements of an Operating Reserve product in each Reserve Zone. A separate price is calculated for Regulation-Up Service, Expected Regulation-Up Mileage, Regulation-Down Service, Expected Regulation-Down Mileage, Spinning Reserve and Supplemental Reserve. Market Flow The impact on transmission system flowgate flows resulting from an operational entity’s Resources serving market load within a defined market footprint. Market Hub A Resource Hub or Trading Hub. Market Participant As defined in the SPP Tariff.
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Maximum Daily Energy The maximum amount of Energy, in MWh, that is available to be produced in an Operating Day from a particular Resource. Maximum Daily Starts The maximum number of times a Resource can be started within an Operating Day. Maximum Economic Capacity Operating Limit An economic MW level at or below a Resource’s Maximum Normal Capacity Operating Limit used for constraining Energy dispatch and Contingency Reserve clearing during normal system conditions. Maximum Emergency Capacity Operating Limit The maximum MW level at which a Resource other than a Block Demand Response Resource may operate under Emergency system conditions. Maximum Emergency Capacity Run Time The maximum length of time a Resource can operate above its Maximum Normal Capacity Operating Limit up to its Maximum Emergency Capacity Operating Limit. Maximum Normal Capacity Operating Limit The maximum MW level at which a Resource may operate continuously. Maximum Quick-Start Response Limit The maximum amount of Supplemental Reserve that can be provided by a Quick-Start Resource from an off-line state. Maximum Regulation Capacity Operating Limit The maximum MW level at which a Regulation Qualified Resource, a Regulation-Up Qualified Resource or a Regulation-Down Qualified Resource may operate while providing Regulation Deployment. Maximum Run Time The maximum length of time a Resource can run from the time the Resource is synchronized to the time the Resource is off-line.
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Maximum Weekly Starts The maximum number of times a Resource can be started within a rolling seven-day period. Megawatt (MW) A measurement unit of the instantaneous demand for energy. Meter Data Submittal Location One or more Meter Settlement Locations for which meter data is submitted to SPP by the Meter Agent for settlement purposes. Meter Settlement Location The effective point at which a Market Participant’s registered load and Resources interchange energy with the Real-Time Balancing Market. Metering Parties All parties, identified in a transmission service agreement, that have a vested interest in the accuracy of the meter data. Mid-Term Load Forecast A Settlement Area Load forecast developed by SPP on a rolling hourly basis for the next seven days for input into Reliability Unit Commitment. Minimum Down Time The minimum length of time required following desynchronization that a Resource must remain off-line prior to a subsequent synchronization. Minimum Economic Capacity Operating Limit A MW level at or above a Resource’s Minimum Normal Capacity Operating Limit used for energy dispatch at a minimum level during normal operating conditions. Minimum Emergency Capacity Operating Limit The minimum MW level at which a Resource other than a Block Demand Response Resource may operate under Emergency system conditions.
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Minimum Emergency Capacity Run Time The maximum length of time a Resource can operate below its Minimum Normal Capacity Operating Limit down to its Minimum Emergency Capacity Operating Limit. Minimum Normal Capacity Operating Limit The minimum MW level at which a Resource may operate continuously. Minimum Regulation Capacity Operating Limit The minimum MW level at which a Regulation Qualified Resource, a Regulation-Up Qualified Resource or a Regulation-Down Qualified Resource may operate while providing Regulation Deployment. Minimum Run Time The minimum length of time a Resource must run from the time the Resource is put online to the time the Resource is shut down. Min-To-Off Time The time for a Resource to de-synchronize from the grid starting from the Resource’s Minimum Economic Capacity Operating Limit. Mitigated Energy Offer Curve A set of price/quantity pairs that represents the mitigated energy offer, where such offers are developed in accordance with guidelines detailed in Appendix G, to provide Energy from a Resource. Mitigated No-Load Offer The mitigated compensation request in a Mitigated Resource Offer, where such compensation offers are developed in accordance with guidelines detailed in Appendix G, in dollars, by a Market Participant representing the hourly fee for operating a synchronized Resource at zero (0) MW output.
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Mitigated Regulation-Down Mileage Offer The mitigated offer, where such offers are developed in accordance with guidelines detailed in Appendix G, at which a Regulation Qualified Resource or a Regulation-Down Qualified Resource offers sell Expected Regulation-Down in dollars per MW. Mitigated Regulation-Up Mileage Offer
Comment [MPRR102.27]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.28]: MPRR102 Awaiting implementation. #ER13-1748
The mitigated offer, where such offers are developed in accordance with guidelines detailed in Appendix G, at which a Regulation Qualified Resource or a Regulation-Up Qualified Resource offers to sell Expected Regulation-Up in dollars per MW.
Comment [MPRR102.29]: MPRR102 Awaiting implementation. #ER13-1748
Mitigated Resource Offer For a Resource, the combination of its Mitigated Start-Up Offer, Mitigated No-Load Offer, Mitigated Energy Offer Curve, Mitigated Regulation-Up Offer, Mitigated Regulation-Down Offer, Mitigated Regulation-Up Mileage Offer, Mitigated RegulationDown Mileage Offer,Mitigated Spinning Reserve Offer, and Mitigated Supplemental Reserve Offer, and Mitigated Transition State Offer. The Mitigated Resource Offer Parameters are developed in accordance with guidelines detailed in Appendix G and are intended to capture the incremental cost, including the appropriate application of opportunity costs, of providing each service to the SPP Energy and Operating Reserve Markets.
Comment [MPRR102.30]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR101.31]: MPRR101 awaiting FERC filing
Mitigated Spinning Reserve Offer The mitigated offer, where such offers are developed in accordance with guidelines detailed in Appendix G, at which a Spin Qualified Resource offers to sell Spinning Reserve in dollars per MW. Mitigated Transition State Offer Comment [MPRR101.32]: MPRR101 awaiting FERC filing
As defined in Attachment AE of the SPP Tariff. Mitigated Start-Up Offer
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The mitigated compensation request in a Mitigated Resource Offer, where such compensation offers are developed in accordance with guidelines detailed in Appendix G, required by a Market Participant for bringing an off-line Resource on-line or for reducing consumption of a Dispatchable Demand Response Resource or Block Demand Response Resource. Mitigated Supplemental Reserve Offer The mitigated offer, where such offers are developed in accordance with guidelines detailed in Appendix G, at which a Supplemental Qualified Resource offers to sell Supplemental Reserve in dollars per MW. Multi-Day Reliability Assessment The process performed prior to the Operating Day to assess resource adequacy for the Operating Day, commit Resources with long Start-Up Times that cannot be considered as part of the DA Market or Day-Ahead RUC, and communicate commitment of such Resources as necessary. Net Actual Interchange The algebraic sum of all metered interchange over all interconnections between two physically adjacent Balancing Authority Areas. Net Benefits Test As defined in the SPP Tariff. Net Scheduled Interchange The algebraic sum of all Interchange Transactions between Balancing Authorities for a given period or instant in time. Network Integration Transmission Service (NITS) As defined in the SPP Tariff. Network Model A representation of the transmission, generation, and load elements of the interconnected SPP Transmission System and the transmission systems of other regions in the Eastern Interconnection.
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NITS ARR Nomination Cap As defined in Attachment AE of the Tariff.The maximum total amount of NITS Candidate ARRs an Eligible Entity may nominate in each month and season in the annual ARR allocation process and/or the monthly ARR allocation process.
Comment [MPRR138.33]: MPRR138 Awaiting FERC Approval. #ER14-2553
NITS Candidate ARR As defined in Attachment AE of the Tariff. The MW quantity associated with firm NITS that the holder of the NITS can nominate for conversion into an ARR, subject to the NITS ARR Nomination Cap, in the annual ARR allocation process and the monthly ARR allocation process.
Comment [MPRR138.34]: MPRR138 Awaiting FERC Approval. #ER14-2553
NITS Candidate LTCR Comment [MPRR138.35]: MPRR138 Awaiting FERC Approval. #ER14-2553
As defined in Attachment AE of the Tariff. Node A specific ENode for which a settlement price is calculated. No-Load Offer The compensation request in a Resource Offer, in dollars, by a Market Participant representing the hourly fee for operating a synchronized Resource at zero (0) MW output. For a generating unit, No-Load Offers are generally representative of the fuel expense required to maintain synchronous speed at zero (0) MW output (i.e. the resource is operating under a “no load” condition). For a Dispatchable Demand Response Resource or Block Demand Response Resource, No-Load Offers are generally representative of a combination of the fuel expense required to maintain synchronous speed at zero (0) MW output for behind the meter generation (i.e. the resource is operating under a “no load” condition) and/or ongoing hourly costs associated with manufacturing process changes associated with a reduction in load consumption. Non-Dispatchable Variable Energy Resource A Variable Energy Resource that is not capable of being incrementally dispatched down by the Transmission Provider. Offer A commitment to sell (i) a quantity of Energy at a specific minimum price such as a Resource Offer, a Virtual Energy Offer and/or an Import Interchange Transaction Offer,
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or (ii) a quantity of Transmission Congestion Rights at a specific minimum price, where such quantities may be submitted in 0.1 MW increments. Off-Peak As defined under Schedule 1 of the SPP Tariff. On-Peak As defined under Schedule 1 of the SPP Tariff. Operating Day A daily period beginning at midnight. Operating Hour A 60-minute period of time during the Operating Day corresponding to a clock hour typically expressed as hour-ending. Operating Reserve Resource capacity held in reserve for Resource contingencies and NERC control performance compliance which includes the following products: Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve. Operating Reserve Only Resource A Resource that cannot be cleared or dispatched for Energy that is qualified to provide any or all of the Operating Reserve products: Regulation-Up Service, Regulation-Down Service, Spinning Reserve, or Supplemental Reserve. Operating Tolerance The MW range of actual Resource output above and below the Resource’s average Setpoint Instruction over the Dispatch Interval where the Resource will not be subject to charges associated with Uninstructed Resource Deviation.
Comment [MPRR102.36]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.37]: MPRR102 Awaiting implementation. #ER13-1748
Parallel Flow Flow on the Transmission System not scheduled with SPP caused by entities external to the SPP Market Footprint. (Also known as loop flow.) Plant Minimum Run Time Comment [MPRR101.38]: MPRR101 awaiting FERC filing
As defined in Attachment AE of the SPP Tariff.
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Portal Internet interface between SPP and its Members. Post-Operating Day The time period starting with the day immediately following the Operating Day. Power Transfer Distribution Factor (PTDF) The percentage of power transfer flowing through a facility or set of facilities (flowgate) for a particular transfer when there are no contingencies Pre-Day-Ahead The time period starting six days prior to Day-Ahead and ending midnight on the day prior to Day-Ahead. Price Node (PNode) A single node in the Commercial Model that has a one-to-one relationship to an ENode where Locational Marginal Prices are calculated. Quick-Start Resource A Resource that can be started, synchronized and inject Energy within ten minutes of SPP notification. Ramp-Rate-Down A curve specifying MW/minute ramp rates applicable between Resource operating ranges that is used to dispatch Resources in the down direction. Ramp-Rate-Up A curve specifying MW/minute ramp rates applicable between Resource operating ranges that is used to dispatch Resources in the up direction. Real-Time The continuous time period during which the RTBM is operated. Real-Time Balancing Market (RTBM) The market operated by SPP continuously in real-time to balance the system through deployment of Energy and to clear Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve.
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Reference Bus The location on the SPP Transmission System relative to which all mathematical quantities, including shift factors and penalty factors relating to physical operation, will be calculated. Regulation Deployment The utilization of Regulation-Up Service and/or Regulation-Down Service through Automatic Generation Control (AGC) equipment to automatically and continuously adjust Resource output to balance the SPP Balancing Authority Area in accordance with NERC control performance criteria.
Comment [MPRR102.39]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.40]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.41]: MPRR102 Awaiting implementation. #ER13-1748
Regulation-Down As defined in the SPP Tariff. Regulation-Down Offer The price at which a Regulation Qualified Resource or a Regulation-Down Qualified Resource has agreed to sell Regulation-Down in dollars per MW. Regulation-Down Mileage Factor A factor determined through historical Regulation Deployment analysis that represents the ratio of cleared Regulation-Down to the observed Regulation-Down mileage created in response to Regulation Deployment instructions. The Regulation-Down Mileage Factor shall initially be set equal to 1.0As defined in the SPP Tariff.
Comment [MPRR204.42]: MPRR204 Awaiting FERC filing
Regulation-Down Mileage Offer The price at which a Regulation Qualified Resource or a Regulation-Down Qualified Resource has agreed to sell Expected Regulation-Down Mileage.
Comment [MPRR102.43]: MPRR102 Awaiting implementation. #ER13-1748
Regulation-Down Qualified Resource A Resource that has met the requirements to be eligible to submit Regulation-Down Offers and Regulation-Down Mileage Offers into the Energy and Operating Reserve Markets but has not met the requirements to be eligible to submit Regulation-Up Offers and Regulation-Up Mileage Offers into the Energy and Operating Reserve Markets. Regulation-Down Service The provision of Actual Regulation-Down Mileage associated with cleared RegulationDown Service MW in response to Regulation Deployment instructions.
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Regulation-Down Service Offer The sum of (i) a Resource’s Regulation-Down Offer and (ii) that Resource’s RegulationDown Mileage Offer multiplied by the Regulation-Down Mileage Factor.
Comment [MPRR102.46]: MPRR102 Awaiting implementation. #ER13-1748
Regulation Mileage Operating Tolerance The allowable percentage deviation below a Resource’s Instructed Regulation-Up Mileage and/or Instructed Regulation-Down Mileage over the Dispatch Interval where the Resource will settle based upon Instructed Regulation-Up Mileage and/or Instructed Regulation-Down Mileage versus Actual Regulation-Up and/or Actual Regulation-Down Mileage. Such percentage shall initially be set to 5%.
Comment [MPRR102.47]: MPRR102 Awaiting implementation. #ER13-1748
Regulation Qualified Resource A Resource that has met the requirements to be eligible to submit Regulation-Up Offers Regulation-Up Mileage Offers, Regulation-Down Offers and Regulation-Down Mileage Offers into the Energy and Operating Reserve Markets. Regulation Ramp Rate A curve specifying MW/minute ramp rates that are used to determine a Resource’s maximum Regulation-Up Service and/or Regulation-Down Service quantities. Regulation Response Time
Comment [MPRR102.48]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.49]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.50]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.51]: MPRR102 Awaiting implementation. #ER13-1748
The maximum amount of time allowed for a Resource to move its output from zero Regulation Deployment to the full amount of Regulation-Up cleared or to move from zero Regulation Deployment to the full amount of Regulation-Down cleared. Regulation-Up As defined in the SPP Tariff. Regulation-Up Mileage Factor A factor determined through historical Regulation Deployment analysis that represents the ratio of cleared Regulation-Up to the Instructed Regulation-Up Mileage created in response to Regulation Deployment instructions. The Regulation-Up Mileage Factor shall initially be set equal to 1.0As defined in the SPP Tariff.
Comment [MPRR204.52]: MPRR204 Awaiting FERC filing
Regulation-Up Mileage Offer The price at which a Regulation Qualified Resource or a Regulation-Up Qualified Resource has agreed to sell Expected Regulation-Up Mileage.
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Regulation-Up Offer The price at which a Regulation Qualified Resource or a Regulation-Up Qualified Resource has agreed to sell Regulation-Up in dollars per MW. Regulation-Up Qualified Resource A Resource that has met the requirements to be eligible to submit Regulation-Up Offers and Regulation-Up Mileage Offers into the Energy and Operating Reserve Markets but has not met the requirements to be eligible to submit Regulation-Down Offers and Regulation-Down Mileage Offers into the Energy and Operating Reserve Markets.
Comment [MPRR102.54]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.55]: MPRR102 Awaiting implementation. #ER13-1748
Regulation-Up Service The provision of Actual Regulation-Up Mileage associated with cleared Regulation-Up Service MW in response to Regulation Deployment instructions. Regulation-Up Service Offer The sum of (i) a Resource’s Regulation-Up Offer and (ii) that Resource’s Regulation-Up Mileage Offer multiplied by the Regulation-Up Mileage Factor Reported Load As defined in the SPP Tariff. Reserved Capacity The reservation MW between a specified source and sink associated with SPP Transmission Service. Reserve Sharing Event A request for assistance to deploy Contingency Reserve by any Reserve Sharing Group (RSG) member following the sudden loss of a Resource. Reserve Sharing Group As defined in the SPP Tariff. Reserve Shutdown An SPP approved Resource shutdown that is requested by a Market Participant for the purposes of making the Resource unavailable for SPP commitment and dispatch due to reasons other than to perform maintenance or to repair equipment. Reserve Zone
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A zone containing a specific group of Price Nodes for which a minimum and maximum Operating Reserve requirement is established. Resident Load As defined in the SPP Tariff. Resource As defined in the SPP Tariff. Resource Hub A Settlement Location consisting of an aggregation of Resource Price Nodes developed for financial and trading purposes. Resource Offer For a Resource, the combination of its Start-Up Offer, No-Load Offer, Energy Offer Curve, Transition State Offer, Regulation-Up Service Offer, Regulation-Down Service Offer, Spinning Reserve Offer and Supplemental Reserve Offer. Resource-to-Load Distribution Factor The simulated impact of incremental power output from a specific Resource (“source”) on the loading of a specific flowgate based on delivery to a representation of the locational weighting of all loads within all Settlement Locations (“sink”). Reliability Unit Commitment (RUC) The process performed by SPP to assess resource and operating reserve adequacy for the Operating Day, commit and/or de-commit resource as necessary, and communicate commitment or de-commitment of Resources to the appropriate Market Participants as necessary. RUC Commitment Period The contiguous period of time between a Resource’s RUC Commit Time and RUC DeCommit Time.
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Scarcity Price The MCP and LMP price levels determined through the use of Demand Curves when there is insufficient Operating Reserve available to meet the Operating Reserve requirement. Security Constrained Economic Dispatch (SCED) An algorithm capable of clearing, dispatching, and pricing Energy and Operating Reserve on a co-optimized basis that minimizes overall cost while enforcing multiple security constraints. Security Constrained Unit Commitment (SCUC) An algorithm capable of committing Resources to supply Energy and/or Operating Reserve on a co-optimized basis that minimizes capacity costs while enforcing multiple security constraints. Setpoint Instruction The real-time desired MW output signal calculated for a specific Resource, rounded to one decimal place, by SPP’s control system on a specified periodicity that is equal to the current Dispatch Instruction plus the Regulation Deployment instruction (which may be positive or negative) plus an adjustment to the Dispatch Instruction for Energy to account for Contingency Reserve Deployment Instructions. The Setpoint Instruction represents the desired output level of the Resource and assumes that the Resource can attain this output instantaneously (i.e. infinite ramp rate). Settlement Area As defined in Attachment AE of the Tariff Settlement Determinant Report A daily report of interval input, intermediate calculation and settlement result data with full Settlement Location and transactional detail which is generated for each Asset Owner and Operating Day settled, either on an Initial, Final or Resettlement basis. Separate reports are available for 1) 5-minute data and 2) hourly and daily data. Settlement Invoice A weekly summary of the SPP Integrated Marketplace net daily charges and credits by Asset Owner and Operating Day which is generated for each Market Participant and contains data for all of the Operating Days settled, either on an Initial, Final or
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Resettlement basis, during the invoice period. For each Operating Day only the net amounts (current total less previously invoiced - if a Final or Resettlement) contribute to the invoice amounts. Settlement Location A location defined for the purpose of commercial operations and settlement. A Settlement Location is the location of finest granularity for calculation of Day-Ahead Market and Real-Time Balancing Market settlements. Settlement Statement A daily summary of the SPP Integrated Marketplace total daily charges and credits by charge type and Operating Day which is generated for each Asset Owner and contains data for all of the Operating Days settled, either on an Initial, Final or Resettlement basis, on a single settlement execution day. For each Operating Day the current, previous and net amounts are included on the statement. Shadow Price A price for a commodity that measures the marginal value of this commodity, that is, the rate at which system costs could be decreased or increased by slightly increasing or decreasing, respectively, the amount of the commodity being made available. For example, the shadow price associated with a transmission constraint is equal to the change in total system production cost produced through re-dispatching the system when incrementally relaxing that transmission line limit. Short-Term Load Forecast A Settlement Area Load forecast developed by SPP on a rolling 5-minute basis for the next 120 Dispatch Intervals for input into the Real-Time Balancing Market. Spinning Reserve As defined in the SPP Tariff. Spinning Reserve Offer The price at which a Spin Qualified Resource has agreed to sell Spinning Reserve in dollars per MW. Spin Qualified Resource
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A Resource that has met the requirements to be eligible to submit Spinning Reserve Offers into the Energy and Operating Reserve Markets. SPP Holidays New Year's Day, President's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, Day After Thanksgiving, Christmas Eve, Christmas Day. SPP Integrated Marketplace The Energy and Operating Reserve Markets and the Transmission Congestion Rights Markets. SPP Region As defined in the SPP Tariff. Start-Up Offer The compensation required by a Market Participant for bringing an off-line Resource on-line or for reducing consumption of a Dispatchable Demand Response Resource or Block Demand Response Resource. Start-Up Offers are generally representative of the out of pocket cost that a Market Participant incurs in starting up a generating unit from an off-line state through Minimum Economic Capacity Operating Limit. For Dispatchable Demand Response Resources and Block Demand Response Resources, Start-Up Offers are generally representative of a combination of out-of-pocket costs that a Market Participant incurs in starting up a behind-the-meter generating unit and/or out-of-pocket costs associated with preparing for manufacturing process changes in preparation for reducing load consumption. State Estimator The computer software used to estimate the properties of the electric system based on a sample of system measurements based on current system conditions. Start-Up Time The time required to start a Resource and reach the Minimum Economic Capacity Operating Limit following receipt of a start-up order from SPP. Supplemental Qualified Resource A Resource that has met the requirements to be eligible to submit Supplemental Reserve Offers into the Energy and Operating Reserve Markets.
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Supplemental Reserve As defined in the SPP Tariff. Supplemental Reserve Offer The price at which a Supplemental Qualified Resource has agreed to sell Supplemental Reserve in dollars per MW. Sync-To-Min Time The time for a Resource’s output to reach Minimum Economic Capacity Operating Limit following synchronization to the grid. Synchronized Resource A Resource that is electrically connected to the grid as evidenced by the closing of the Resource circuit breaker. Through Interchange Transaction A Market Participant schedule submitted between two External Interfaces for use in the DA Market or RTBM for moving Energy through the SPP Balancing Authority Area. Trading Hub A Settlement Location consisting of an aggregation of Price Nodes developed for financial and trading purposes. Transition State Offer As defined in Attachment AE of the SPP Tariff. Transition State Time Comment [MPRR101.61]: MPRR101 awaiting FERC filing
As defined in Attachment AE of the SPP Tariff. Transmission Congestion Right (TCR) As defined in Attachment AE of the Tariff.A financial right that entitles the holder to a share of the congestion revenue collected in the Day-Ahead Market.
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Transmission Congestion Rights Markets As defined in Attachment AE of the Tariff.The Auction Revenue Rights annual and monthly allocation processes and the annual and monthly Transmission Congestion Rights auctions.
Comment [MPRR138.63]: MPRR138 Awaiting FERC Approval. #ER14-2553
Transmission Loading Relief (TLR) The NERC prescribed method for relieving congestion on Coordinated Flowgates and Reciprocal Coordinated Flowgates through reductions in tagged flow and Market Flow associated with these flowgates. Turn-Around Ramp Rate Factor A Resource Offer parameter with a value between 0.01 and 1.00, inclusive, that is used as a multiplier to limit a Resources Ramp-Rate-Up or Ramp-Rate-Down parameter in the RTBM. Uninstructed Resource Deviation (URD) The average MW amount of actual Resource output in a Dispatch Interval above or below the Resource’s average Setpoint Instruction in the Dispatch Interval. Unused Regulation-Down Mileage The amount by which settled Regulation-Down mileage is less than the amount of Expected Regulation-Down Mileage. Unused Regulation-Up Mileage The amount by which settled Regulation-Up mileage is less than the amount of Expected Regulation-Up Mileage. Variable Energy Bid Curve As defined in the SPP Tariff. Variable Energy Resource A device for the production of electricity that is characterized by an energy source that: (1) is renewable; (2) cannot be stored by the facility owner or operator; and (3) has variability that is beyond the control of the facility owner or operator. Virtual Energy Bid
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A proposal by a Market Participant to purchase Energy at a specified price, Settlement Location and period of time in the Day-Ahead Market that is not associated with a physical Load. Virtual Energy Offer A proposal by a Market Participant to sell Energy at a specified price, Settlement Location and period of time in the Day-Ahead Market that is not associated with a physical Resource.
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Introduction
2.
SPP Market Protocols complement the Governing Documents, as defined in Exhibit 2-1, through documentation of detailed procedures that implement their provisions. Exhibit 2-1 shows how the Market Protocols interact with the Governing Documents and business practices related to the transmission markets. Exhibit 2-1: Document Relationships
GOVERNING DOCUMENTS
TARIFF
BY-LAWS
Establishes services to be provided and rights and obligations of the parties pursuant to those services
Establishes Organizational Framework, structure and purposes
MEMBERSHIP AGREEMENT
(Members Committee/BOD) (RTWG/MOPC/BOD)
SPP CRITERIA
Establishes obligations of SPP and Members pursuant to membership
Rules to promote and protect system reliability that members are obligated to follow
(Members Committee/BOD)
(ORWG/TWG/MOPC/BOD)
BUSINESS PRACTICES/PROTOCOLS Detailed procedures that implement the provisions of the Governing Documents
OATT BUSINESS PRACTICES MANUAL
MARKET PROTOCOLS Detailed procedures that implement the provisions of the Governing Documents relating to Energy and Operating Reserve Market Operations, TCR Markets, Settlement and Market Mitigation
Detailed procedures that implement the provisions of the Governing Documents relating to Transmission Markets (BPWG/MOPC)
(MWG/SUG/MOPC)
RTWG – Regional Tariff Working Group BOD – SPP Board of Directors TWG – Transmission Working Group
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MOPC – Market and Operations Policy Committee ORWG - Operating Reliability Working Group BPWG – Business Practices Working Group
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Market Protocols for SPP Integrated Marketplace MWG – Market Working Group
2.1
SUG – Settlement Users Group
Purpose
The Market Protocols developed by SPP provide background information, guidelines, business rules, and processes for the operation and administration of the SPP Integrated Marketplace and the Reliability Unit Commitment processes, including market settlements, billing, and accounting requirements.
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SPP Integrated Marketplace Overview
3.
As a Regional Transmission Organization, SPP is mandated by the Federal Energy Regulatory Commission to ensure reliable supplies of power, adequate transmission infrastructure, and competitive wholesale prices of electricity. In order to ensure reliable operations and competitive wholesale electricity prices, SPP operates and administers Energy and Operating Reserve Markets and Transmission Congestion Rights Markets. The SPP Integrated Marketplace does not supersede any Market Participants’ obligations with respect to any other capacity or ancillary service obligations. The responsibilities in regards to capacity adequacy, reserves, and other reliability-based concerns do not change as a result of this market.
3.1
Energy and Operating Reserve Markets
The Energy and Operating Reserve Markets processes include mandatory Market Participant participation in:
a price-based Day-Ahead Market (DA Market) with Transmission Congestion Rights providing the hedge against transmission congestion costs in the DA Market,
a price-based Real-Time Balancing Market (RTBM) and
all Reliability Unit Commitment (RUC) processes.
The DA Market provides Market Participants with the ability to submit offers to sell Energy, Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve and/or to submit bids to purchase Energy. The RTBM provides Market Participants with the ability to submit offers to sell Energy, Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve. Energy and Operating Reserve Markets operations will “simultaneously” or “jointly” optimize Resource Offers for Energy and Operating Reserve in the Security Constrained Unit Commitment (SCUC) and Security Constrained Economic Dispatch (SCED) algorithms. The objective function of joint optimization will be the minimization of the total production costs in the DA Market and the RTBM for energy and operating reserve products to meet the requirements. Procurement of Operating Reserve (Regulation-Up Service, Regulation Down Service, Spinning Reserve, and Supplemental Reserve) will not be decoupled from the procurement of Energy from Resources capable of providing both Energy and Operating Reserve. Resources selected to provide Operating Reserve will receive opportunity cost payments when appropriate which are included in the Market Clearing Prices for each product. The simultaneous optimization logic considers various permutations of unit commitment, and the joint dispatch of Energy and Operating Reserve,
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Comment [MPRR102.69]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.70]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
arriving to a solution that results in the least overall production cost subject to reliability constraints. The simultaneous optimization logic also allows product substitution of Operating Reserve if economically efficient, i.e., the logic utilizes a higher quality product offer to fill a lower quality product demand if and when such selection would reduce the overall production cost compared to if each product were cleared separately. The RUC processes are reliability based and are needed to ensure that the physical unit commitment produced from the DA Market is sufficient to meet SPP projected capacity needs during the Operating Day. Exhibit 3-1 provides an overview of the key Energy and Operating Reserve Market functions. Exhibit 3-1: Overview of Key Energy and Operating Reserve Market Functions DA Market Offers (Energy and Operating Reserve), Bids, Operating Reserve Requirements
Day-Ahead Market (DA Market)
RTBM Offers, Load Forecast, Operating Reserve Requirements
DA Market Commitment
DA Market Commitment, Cleared Energy and Operating Reserve (MW and Price) (hourly)
Reliability Unit Commitment (RUC)
DA Market & Net RTBM Settlements
Resource and Load Meter Data
RTBM Offers, Load Forecast, Operating Reserve Requirements
RUC Commitment
Real-Time Balancing Market (RTBM)
Dispatch Instruction, cleared Operating Reserve (MW and Price) (5 minute)
Dispatch Instruction, cleared Operating Reserve (MW) (5 minute)
EMS
TCR Markets
Key features of the Day-Ahead Market include: (1)
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Financially binding market in which all cleared supply and demand is settled with a minimum mandatory offer requirement for physical Resources that are not on a planned or forced outage or Reserve Shutdown that is equal to a Market Participant’s expected daily peak Resident Load plus its estimated Operating Reserve obligation;
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(2)
Bilateral Settlement Schedules for Energy and Operating Reserve accommodate internal physical bilateral transactions by removing their impact from the DA Market settlement;
(3)
Physical supply offers, virtual supply offers, physical demand bids and virtual demand bids are accommodated;
(4)
DA Market clearing is performed for Energy, Regulation-Up Service, RegulationDown Service, Spinning Reserve and Supplemental Reserve on a least cost, cooptimized basis and accounts for each Resource’s marginal system losses, congestion, and Energy cost to minimize the overall production cost;
(5)
All physical supply cleared for Operating Reserve products cleared are paid at the applicable Reserve Zone Market Clearing Price for the Operating Reserve product;
(6)
All Energy supply cleared is paid at the Settlement Location DA Market Locational Marginal Price and all Energy demand cleared is charged at the Settlement Location DA Market Locational Marginal Price producing an over collection due to congestion (congestion revenues) and marginal losses (marginal loss revenues);
(7)
TCR holders are paid (or charged) for the TCR MW at the difference between the DA Market Marginal Congestion Component at the TCR sink and the DA Market Marginal Congestion Component at the TCR source using the congestion revenues;
(8)
Losses are settled financially through the LMP settlement process. Any over collection of marginal loss revenues are credited to Asset Owners with net Energy withdrawals in proportion to the amount of marginal loss revenue collected from that Asset Owner;
(9)
SPP committed Resources are assured recovery of their Start-Up Offer, No-Load Offer and actual incremental Energy costs as defined in the Energy Offer Curve subject to certain eligibility criteria; and
(10) Operating Reserve procurement costs are allocated and collected on a Reserve Zone basis. Key features of the RUC processes and Real-Time Balancing Market include: (1)
For the RUC, it is mandatory that Market Participants submit offers for all of their Resources that are not on a planned, forced or otherwise approved outage;
(2)
Bilateral Settlement Schedules for Energy and Operating Reserve accommodate internal physical bilateral transactions by removing their impact from the RTBM
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settlement (Bilateral Settlement Schedules to not have any impact on the RUC processes); (3)
The RTBM operates on a 5-minute basis and calculates Dispatch Instructions for Energy and clears Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve on a least cost, co-optimized basis and accounts for each Resource’s marginal system losses, congestion, and Energy cost to minimize the overall production cost;
(4)
Cleared Operating Reserve product settlement is performed on a 5-minute basis. Charges and credits are calculated as the difference between the RTBM Operating Reserve MW cleared and the DA Market Operating Reserve MW cleared amount multiplied by the applicable Reserve Zone Operating Reserve Market Clearing Price;
(5)
Resource settlement is performed on a 5-minute basis. Energy charges and credits are calculated as the difference between the Resource actual output and the Resource DA Market cleared MW amount multiplied by the Settlement Location RTBM Locational Marginal Price;
(6)
Load settlement is performed on a 5-minute basis. Energy charges and credits are calculated as the difference between the load actual consumption and the load DA Market cleared MW amount multiplied by the Settlement Location RTBM Locational Marginal Price;
(7)
Import, Export and Through Interchange Transaction settlement is performed on a 5minute basis. Charges and credits are calculated as the difference between the real-time scheduled MW amount and the DA Market cleared MW amount multiplied by the RTBM Locational Marginal Price of the appropriate External Interface Settlement Location;
(8)
Losses are settled financially through the LMP settlement process. Any over collection or under collection of marginal loss revenues are credited/charged to Asset Owners with net Energy withdrawals in proportion to the amount of marginal loss revenue collected from that Asset Owner.
(9)
SPP committed Resources are assured recovery of their Start-Up Offer, No-Load Offer and actual incremental Energy costs as defined in the Energy Offer Curve subject to certain eligibility criteria;
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(10) Charges are imposed on Market Participants for failure to deploy Energy, regulation and Contingency Reserve as instructed; and (11) Operating Reserve procurement costs, net of penalty revenues received for regulation and Contingency Reserve deployment failure, are collected from Market Participants on a real-time load ratio share basis. Exhibit 3-2 provides a timeline-based illustration of the sequencing and interaction of the key Energy and Operating Reserve Market functions for a representative Operating Day (1/31). Exhibit 3-2: Energy and Operating Reserve Markets Processes Timeline
1/29 - 1/31 RUC
1/24 - 1/29 Pre Day-Ahead 1/24
1/25
1/26
1/27
1/28
1/29
1/30
1/31
1/23
1/31 Offer and Bid Submittal 1/24 - 1/30
1/30 - 1/30 DAM
1/31 - 1/31 RTBM – Every 5 Minutes
1/30 - 1/30 Day-Ahead
1/31 - 1/31 Operating Day 1/31
1/30
2/1 Begin Settlement Process
2/8 Issue Initial Daily Statement (daily)
RUC as needed 1/31 - 1/31
2/17 Issue Weekly Invoice (weekly)
RUC 1/30 - 1/31
1/31
3/19 Issue Final Daily Statement
2/1 - 3/31 Post Operating Day 2
3
1/23
3.2
3/20
Transmission Congestion Rights Markets
The structure of the TCR Markets includes annual nomination and allocation of Long-Term Congestion Rights (LTCRs) to Eligible Entities and annual and monthly nomination and allocation of Auction Revenue Rights (ARRs) to Eligible Entities followed by annual and
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Market Protocols for SPP Integrated Marketplace
monthly TCR Auctions. Eligible Entities for ARRs include Transmission Customers with firm SPP transmission service and entities with firm non-SPP transmission service (commonly referred to as a “grandfathered agreement or GFA”) into, out of, within or through the SPP Region that have identified such service during the annual LTCR/ARR verification process. Eligible Entities for LTCRs include Transmission Customers with qualifying firm SPP transmission service and entities with qualifying firm non-SPP transmission service (commonly referred to as a “grandfathered agreement or GFA”) into, out of, within and through the SPP Region that have identified such qualifying service during the annual LTCR/ARR verification process. Entities with firm non-SPP transmission service (GFA) must agree between the parties as to which party is eligible to nominate LTCRs and/or ARRs. Additionally, Eligible Entities may request NITS, GFA NITS, FPTP and/or GFA FPTP Candidate ARRs for firm transmission service confirmed following completion of the annual TCR auction. Key features of the annual LTCR allocation process include: (1)
Eligible Entities are awarded LTCRs that apply to the entire TCR year. Load Serving Entities (LSEs) are awarded LTCRs prior to consideration of LTCR awards for Eligible Entities that are not LSEs. Candidate LTCRs are only associated with eligible long-term firm transmission service with rollover rights ;
(2)
All Candidate LTCRs are modeled in order to determine simultaneous feasibility of the Candidate LTCRs. LTCRs are only awarded up to the selected amount of simultaneously feasible Candidate LTCRs;
(3)
(a)
Candidate LTCRs are evaluated for simultaneous feasibility for flows in the prevailing direction only with no simultaneous consideration of LTCR flows in the opposite direction (i.e. counterflow is not considered in the feasibility analysis);
(b)
50% of the SPP transmission system capability is available for allocation;
Awarded LTCRs are of the obligation type which means that the TCRs associated with the awarded LTCR could result in a payment or charge to the TCR holder in the DayAhead Market settlement of TCRs; (a)
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Once awarded, the awarded LTCRs are guaranteed in subsequent years as long as the associated long-term firm SPP transmission service reservation remains in effect;
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(b) (4)
Awarded LTCRs may be surrendered in subsequent years at the Market Participant's request;
Awarded LTCRs are initially ARRs which will automatically be self-directly converted to TCRs prior to the annual ARR allocation for the current allocation year.in the annual ARR allocation process.
Key features of the annual ARR allocation process include:
Comment [MPRR171.82]: MPRR171 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.83]: MPRR138 Awaiting FERC Approval. #ER14-2553
(1)
Eligible Entities nominate candidate ARRs separately for On-Peak and Off-Peak periods each month and season of the annual period in a three-round process;
(2)
Nominated candidate ARRs are awarded up to the amount that is simultaneously feasible;
(1)
Awarded ARRs are of the obligation type which means that the awarded ARR could result in a payment or charge to the ARR holder;
(3)
Comment [MPRR171.81]: MPRR171 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.84]: MPRR138 Awaiting FERC Approval. #ER14-2553
100% of the SPP transmission system capability is available for allocation; (a)
All awarded LTCRs are directly converted to TCRs and are accounted for prior to assessing nominated ARR feasibility;
(a)(b) Awarded ARRs are of the obligation type which means that the awarded ARR could result in a payment or charge to the ARR holder. Awarded LTCRs are converted to ARRs and included in the total ARR awards for settlement purposes; (3)(4) Holders of ARRs receive positive or negative revenue resulting from the annual and monthly TCR auctions, including those ARRs that were self-converted to TCRs. ARRs associated with LTCRs are automatically self-converted into TCRs for settlement purposes. Positive auction revenue results when the sink Auction Clearing Price (ACP) is greater than the source ACP for a given ARR. Negative revenue results when the sink ACP is less than the source ACP, in other words, a counterflow ARR. (a)
(b)
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For the annual TCR auction, the amount of ARRs eligible to receive auction revenues is equal to the greater of ARRs self-converted to TCRs or the amount of ARRs awarded multiplied by the following percentages: June – 100%; July through September, 90%; and Fall, Winter, Spring – 60%. For the monthly TCR auction for the months of July through September, the amount of ARRs eligible to receive auction revenues is equal to the amount of ARRs awarded in the monthlyincremental ARR allocation process plus: the lesser
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Comment [MPRR171.88]: MPRR171 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.89]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.90]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.91]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.92]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
of (i) 10% of the annual ARR award or (ii) the difference between the annual ARR award and the amount of self-converted TCRs in the annual TCR auction; (c)
For the monthly TCR auction for the months of October through May, the amount of ARRs eligible to receive auction revenues is equal to the amount of ARRs awarded in the monthly incremental ARR allocation process plus: the lesser of (i) 40% of the annual ARR award or (ii) the difference between the annual ARR award and the amount of self-converted TCRs in the annual TCR auction.
Comment [MPRR138.93]: MPRR138 Awaiting FERC Approval. #ER14-2553
Key features of the annual TCR auction include: (1)
Any Market Participant that meets the applicable credit requirements may submit TCR Bids to purchase and/or TCR Offers to sell (for which the entity is the owner of record) separately for On-Peak and Off-Peak periods in the annual TCR auction for each month and season in the annual period; (a)
ARRs resulting from LTCRs are automatically self-converted into TCRs prior to auction clearing and are modeled as fixed injections/withdrawals. These TCRs directly converted from LTCRs may be offered for sale in the annual or monthly TCR auction process;
(1)(2) TCRs are of the obligation type which means that the awarded TCR could result in a payment or charge to the TCR holder in the DA Market settlement; (2)(3) The annual TCR auction is a single round process for the month of June that makes 100% of the available SPP transmission system capability available, is a single round process for the months of July, August and September that makes 90% of the available SPP transmission system capability available and is a single round process for the Fall, Winter and Spring seasons that makes 60% of the available SPP transmission system capability available; (4)
Market Participants who have TCR bids cleared in the annual TCR auction will be charged (or get paid in the case of a counter-flow TCR) based on the amount of TCR MWs cleared and the annual TCR auction clearing prices associated with the source and sink of the purchased offered TCR; and
(3)(5) Market Participants who have TCR offers cleared in the annual TCR auction will be paid (or get charged in the case of a counter-flow TCR) based on the amount of TCR MWs cleared and the annual TCR auction clearing prices associated with the source and sink of the TCR sold;
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Comment [MPRR138.99]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR171.100]: MPRR171 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.101]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.102]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
(4)(6) Market Participants holding ARRs not associated with LTCRs may self-convert their ARRs into TCRs for the applicable period subject to simultaneous feasibility. TCRs from self-converted ARRs, including TCRs self-converted from ARRs associated with LTCRs, are included as awarded TCRs. Key features of the monthly incremental ARR allocation include: (1)
(2)(1) SPP verifies new firm transmission service reservations the request and performs a monthly incremental ARR allocation process beginning five days prior to the applicable monthly TCR auction process.
(b)
(c)
(d)
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Eligible Entities may nominate candidate ARRs from their verified NITS Incremental Candidate ARRs not to exceed the difference between their NITS ARR Nomination Cap and those ARRs awarded in the annual ARR allocation process from nominated NITS Candidate ARRs in the annual ARR allocation process; Eligible Entities may nominate candidate ARRs from their verified FPTP Incremental Candidate ARRs not to exceed the difference between their FPTP ARR Nomination Cap and those ARRs awarded in the annual ARR allocation processesfrom nominated FPTP Candidate ARRs in the annual ARR allocation process; Eligible Entities may nominate candidate ARRs from their verified GFA NITS Incremental Candidate ARRs not to exceed the difference between their GFA NITS ARR Nomination Cap and those ARRs awarded from nominated GFA NITS Candidate ARRs in the annual ARR allocation process; Eligible Entities may nominate candidate ARRs from their verified GFA FPTP Incremental Candidate ARRs not to exceed the difference between their GFA FPTP ARR Nomination Cap and those ARRs awarded from nominated GFA FPTP Candidate ARRs in the annual ARR allocation process;
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Eligible Entities must submit a request to SPP specifying the NITS Incremental Candidate ARRs, GFA NITS Incremental Candidate ARRs, FPTP Incremental Candidate ARRs and/or GFA FPTP Incremental Candidate ARRs desired that are associated with the confirmed firm transmission service and the request must be submitted ten days prior to the start of the applicable monthly TCR auction process to be eligible to participate in the upcoming monthly TCR auction;
(a)
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Market Protocols for SPP Integrated Marketplace
(e)
Nominated candidate ARRs are awarded up to the amount that is simultaneously feasible;
(f)
All TCRs previously awarded in the Annual TCR Auction Process and all remaining ARRs not accounted for in the Annual TCR Auction Process for the applicable month are modeled as fixed injections at the specified sources and fixed withdrawals at the specified sinks prior to assessing nominated incremental candidate ARR feasibility.
(3)(2) Awarded incremental ARRs are of the obligation type which means that the awarded incremental ARR could result in a payment or charge to the ARR holder; and (4)(3)
100% of the SPP transmission system capability is available for allocation.
(1)
The monthly TCR auction process allows any Market Participants that have met the applicable credit requirements to submit TCR Bids to purchase additional TCRs or TCR Offers to sell currently held TCRs in a single-round process for the months of July, August and September and in a two-round process for the months of October through May;
(2)
100% of the SPP transmission system capability is made available; and
(3)
Market Participants may self-convert their remaining ARRs (including ARRs remaining from the annual TCR auction process and ARRs awarded in the monthly incremental ARR allocation process) into TCRs for the applicable period subject to simultaneous feasibility.
Exhibit 3-3 provides an overview of the TCR Markets structure.
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Comment [MPRR138.129]: MPRR138 Awaiting FERC Approval. #ER14-2553
Key features of the monthly TCRARR auction include:
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Exhibit 3-3: Overview of TCR Markets Structure
TCs identify and confirm NITS and Firm PTP
TCs Nominate Annual ARRs
MPs Submit Bids to Buy TCRs
Verification
Annual ARR Awards
Annual TCR Auction
Receive Annual and Monthly Auction Revenue
Annual ARR Award MW
TCs Nominate Incremental ARRs
MPs Submit Bids to Buy TCRs and Offers to Sell TCRs
Incremental ARR Awards
Monthly TCR Auction
Receive Cleared Bids Pay Monthly Auction Cleared Offers are Paid Revenue
TCR Market Settlements
Incremental ARR Award MW
Cleared Bids Pay Cleared Offers are Paid
DA Market Settlements
The TCR Markets are operated in parallel with the timeline depicted in Exhibit 3-2 to ensure the Market Participants are able to obtain TCRs prior to DA Market operation. A representative timeline for the TCR Market processes is shown in Exhibit 3-4.
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Comment [MPRR138.131]: MPRR138 Awaiting FERC Approval. #ER14-2553
Exhibit 3-4: LTCR/ARR Allocation/TCR Auction Processes Timeline
4/5 - 4/23 Annual ARR 5/3 - 5/23 Allocation 3/10 - 3/28 Annual Annual LTCR TCR Auction Allocation
6/1 - 9/30 Annual ARR Awards And TCR Auction Awards by Month On-Peak and Off-Peak
10/1 - 5/31 Annual ARR Awards And TCR Auction Awards by Season On-Peak and Off-Peak
6/1 - 5/31 Annual LTCR Awards
12/15 - 5/31 LTCR/ARR Allocation / TCR Auctions 1
2
3
4
5
6
7
8
9
10
11
12
1
12/15
MP Verification of Transmission Entitlements 2/3 - 3/4
2
3
4
5 5/31
TCR Monthly Auction for July Repeats for Each Month 6/8 - 6/18
Monthly TCR Auction Awards Month to Month On-Peak and Off-Peak 7/1 - 5/31
5/25 - 6/5 Monthly ARR Allocation and Awards. Repeats Each Month
The Energy and Operating Reserve Markets processes are described in detail in Section 4 and the TCR Markets processes are described in detail in Section 5.
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Energy and Operating Reserve Markets Processes
4.
Energy and Operating Reserve Markets processes consist of activities beginning six days prior to the DA Market (Pre-Day-Ahead), activities the day prior to the Operating Day (Day-Ahead), activities during the Operating Day (Operating Day) and activities following the end of the Operating Day (Post Operating Day). All time referenced throughout this Section 4 is Central Prevailing Time (CPT). A detailed description of the activities in each of these four periods and key market design elements for the Energy and Operating Reserve Markets functions depicted in Exhibit 3-1 are provided in the following subsections.
4.1
SPP System Requirements
Prior to and in parallel with the Energy and Operating Reserve Markets processes, SPP performs several related activities as follows.
4.1.1
Reserve Zone Establishment
SPP establishes Reserve Zones to ensure the deliverability of cleared Operating Reserve throughout the SPP Balancing Authority Area. (1)
SPP identifies the need for Reserve Zones within the SPP BAA through Reserve Zone studies that identify constrained areas within the SPP BAA which may require a minimum amount of Operating Reserve procurement within that zone or may be limited to a maximum amount of Operating Reserve procurement within that zone to ensure system-wide procurement of Operating Reserve is deliverable when deployed.
(2)
Reserve Zone Studies will be conducted semi-annually and made effective by December 1 and June 1 of each year. Normal transmission system topology will be used for the study along with selected, approved long-term outages. All generation resources and loads in the market footprint will be evaluated.
(3)
In order to ensure deliverability of reserves, the most likely constrained transmission facilities must be identified. Monitored constraints will be identified through analysis of historical congestion activity, planned transmission and generation outages, and forecasted system demands and generation.
(4)
Once a final set of transmission constraints is identified, PNodes, including PNodes contained in an APNode associated with an EDR, are grouped based on similar impact on all of the remaining transmission constraints. The groups of PNodes represent the Reserve
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Zones. Each PNode, and APNodes associated with an EDR, will be placed into exactly
one Reserve Zone. (5)
Reserve Zones may be added or reconfigured between semiannual updates to address significant changes in system conditions that would cause adverse reliability impacts absent the Reserve Zone addition or reconfiguration. Any resulting changes made to the Reserve Zones will be communicated to the Market Participants no less than two (2) business days prior to becoming effective.
4.1.2
Forecasting
4.1.2.1
Short Term and Mid-Term Load Forecasting
SPP develops Short-Term Load Forecasts and Mid-Term Load Forecasts for each Settlement Area. The Short-Term Load Forecast produces values on a rolling 5-minute basis for input into the RTBM. The Mid-Term Load Forecast produces hourly values for the next hour through seven (7) days and is used in all of the RUC processes. Load forecasts are derived through a combination of conforming load and non-conforming load forecasts for each Settlement Area as described under Sections 4.1.2.1.1 and 4.1.2.1.2. The Settlement Area short-term and mid-term forecasts are then summed up to SPP Balancing Authority Area short-term and mid-term forecasts. These forecasts include an estimate of losses that must be removed, as described under Section 4.1.2.1.3, prior to execution of the Market applications in order for the dispatch to reflect losses appropriately under the marginal losses approach. Once the estimated losses have been removed, both the Mid-Term Load Forecast and the Short-Term Load Forecast is distributed to the PNode level for modeling purposes for use in the RUC and RTBM processes respectively as described under Section 4.1.2.1.6. The DA Market relies on bid-in demand so these load forecasts are not used in that process. 4.1.2.1.1
Conforming Load
Conforming load is load that changes in a reasonably predictable, uniform ratio that is environmentally driven (i. e. changes in temperature as) as opposed to process driven (i. e. large industrial or irrigation processes). SPP uses a load forecasting tool to produce the mid-term and short-term load forecasts for conforming load within each Settlement Area. The load forecasting tool use historical actual conforming load values as well as temperature, wind speed, dew point
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and any other environmental variables determined necessary to accurately forecast the conforming load within each Settlement Area. 4.1.2.1.2
Non-conforming Load
Non-Conforming Load, as described in Section 6.2.2, is more process driven and needs to be separated from the load forecast application because it does not follow a predictable pattern. Load associated with stored energy devices such as pumped storage hydro or compressed air Resources shall be considered a Non-Conforming Load. Market Participants with registered Non-Conforming Load shall submit hourly load forecasts of Non-Conforming Load consumption to SPP by 1700 hours Day-Ahead for the Operating Day and for six (6) days following the Operating Day. Once the initial submission is received at or before 1700 hours, Market Participants are allowed to submit hourly load forecasts of Non-Conforming Load after 1700 hours up to thirty minutes before the Operating Hour. Market Participants are encouraged to submit a forecast of each registered Non-Conforming Load for two (2) hours following the current interval for each 15-minute interval that the forecast deviates from the hourly profile. If the 15-minute forecast is unavailable, SPP shall interpolate using the submitted hourly NonConforming Load forecast. Market Participants shall also submit a forecast on a 5-minute rolling 15-minute ahead basis. The submitted Non-Conforming Load will be added to the conforming load forecasts to create the total Settlement Area forecast. Market Participants are required to submit actual Non-Conforming Load data for each Non-Conforming Load for which metering is available or estimates of Non-Conforming Load for which metering is not available (submitted forecast value can be used as actual). 4.1.2.1.3
Losses
Both the short-term and the mid-term load forecasts for each Settlement Area are originally calculated including an estimate of losses. To allow for the correct dispatch using a marginal losses approach, the losses estimates from the original forecasts must be removed before distributing the forecast load to the loads at the individual PNodes. For the RTBM, loss estimates are determined based on State Estimator solutions. SPP determines the Settlement Area loss percentage for each Settlement Area by dividing the solved losses of the Settlement Area by the total load plus losses of the Settlement Area from the most recent valid solution. SPP then multiplies the Short-Term Load Forecast of the Settlement Area by (1 – Settlement Area loss percentage) to obtain the Settlement Area load forecast without estimated losses for use in the RTBM study.
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For each RUC execution, SPP estimates the future system operating conditions and a power flow study is used to determine loss estimates. Using the estimated future system operating conditions, SPP determines the Settlement Area loss percentage with an approach similar to the RTBM approach: for each area, dividing the study solution losses of the Settlement Area by the total load plus losses of the Settlement Area in the solution. SPP then multiplies (1 – Settlement Area loss percentage) by the Mid-Term Load Forecast of the Settlement Area to obtain the Settlement Area load forecast without estimated losses for use in the RUC study. 4.1.2.1.4
Demand Response Adjustments
In developing the Short-Term Load Forecast, SPP will perform a gross-up adjustment in realtime for deployed Demand Response Resources (DRR) in order to continue to forecast the total load to be served by the RTBM. SPP will gross-up the Settlement Area actual real-time load received via SCADA by adding the real-time DRR output to the Settlement Area actual load where the DRR resides. The DRR output, in this case, is the estimated DRR output as calculated pursuant to Section 4.2.2.4.1. 4.1.2.1.5
Reserve Zone Load
Using the PNode load forecasts developed under Section 4.1.2.1.6, SPP sums up the load forecasts at each PNode in a Reserve Zone to determine the amount of load within the Reserve Zone for input into the study models used to establish the daily Reserve Zone minimum and maximum Operating Reserve requirements. Additionally, SPP will calculate each Asset Owner’s forecast load within each Reserve Zone and SPP will then use this Asset Owner load forecast to estimate each Asset Owner’s Operating Reserve obligation within each Reserve Zone. 4.1.2.1.6
Load Distribution
SPP uses historical hourly load consumption patterns at each PNode within each Settlement Area, as determined by the State Estimator from a reference day, to allocate the Settlement Area Mid-term Load Forecast down to the PNode level within each Settlement Area for all RUC processes. The reference day used for each Settlement Area will be determined by SPP Operations Staff who are also responsible for load forecasting. By default the reference day will be the same day of the week seven (7) days prior but SPP has the discretion to choose a different reference day if more appropriate due to holidays, dramatic weather pattern changes or other factors as appropriate.
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For the DA Market, bid-in demand at each Settlement Location will be distributed using the same weighting used for the RUC process. For the RTBM, the Short-term Load Forecast will be distributed to each PNode weighted by the load at each PNode from the latest State Estimator solution. 4.1.2.2
Wind-Powered Generation Resource Output Forecasts
SPP produces and updates an hourly Wind-powered Generation Resource (WGR) forecast that provides a rolling 48-hour hourly forecast of wind production potential from each WGR that is expected to exceed the WGR actual output 50% of the time (50% probability of exeedance forecast). This process uses a physical modeling technique that incorporates the relationships of the WGRs to wind speed, topography, atmospheric conditions, actual WGR output, and other variables that influence WGR production. The updated WGR forecasts for each hour are used as inputs into each RUC process. SPP also produces and updates an hourly SPP Total Wind Power Forecast (TWPF) providing a probability distribution of the hourly production potential from all wind-powered in SPP for each of the next 48 hours. SPP produces the WGR and TWPF forecasts using the information described in section 4.1.2.3. WGR Generator Interconnection Customers with a Generator Interconnection Agreement that was effective prior to July 16, 2013, will be grandfathered in as detailed in section 4.1.2.4. This is in addition to the Availability and Actual Output data required of all generation Resources. SPP shall make available the WGR forecasts to Market Participants and their designated agents for their specific WGRs, subject to any applicable confidentiality protections. In addition, SPP shall provide all Market Participants with the TWPF. Historical data shall be immediately available for seven (7) calendar days. 4.1.2.3
Wind-Powered Generation Resource Data Requirements
(A) A Generator Interconnection Customer for a WGR must provide applicable and accurate static information to SPP using a spreadsheet based template as defined by SPP. The Market Participant registering the Resource shall provide SPP with current contact information for the wind farm Owner and Operator through the Model Change Submission Tool (MCST). When the parties agree, the Market Participant may submit the data on the Generator Interconnection Customer’s behalf. WGR static data must be updated at least once every five (5) years or as needed.
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(1)
Geographical Data – One set of coordinates is required for the wind farm site and the met tower/nacelle anemometer. The placement of the met tower/nacelle anemometer should be within 10 miles from the wind farm site. The height of met tower/nacelle anemometer should be within 10 meters of the wind farm’s turbine hub height. If more than one set of coordinates will be provided for the wind farm and its met towers/nacelle anemometers, an email can be sent to
[email protected]. (a)
(b)
Wind Farm (i)
Latitude – Latitude of the resource location. The value should be entered in the decimal form of degrees. The value should be between 30 and 50 degrees and rounded to four digits. The value should represent the latitude at the mid-point of the wind farm.
(ii)
Longitude – Longitude of the resource location. The value should be entered in the decimal form of degrees. The value should be between -85 and -110 degrees and rounded to four digits. The value should represent the longitude at the mid-point of the wind farm.
Met Tower/Nacelle Anemometer (i)
Latitude – Latitude of the met tower/nacelle anemometer. The value should be entered in the decimal form of degrees. The value should be between 30 and 50 degrees and rounded to four digits.
(ii)
Longitude – Longitude of the met tower/nacelle anemometer. The value should be entered in the decimal form of degrees. The value should be between -85 and -110 degrees and rounded to four digits.
(iii) Height – Height of the met tower/nacelle anemometer. The value should be entered in meters (m) above ground level. (2)
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Turbine Data – Turbine data characterizes the wind farm. If there is more than one manufacturer, model, etc., provide the most dominant data among the wind farm site. (a)
Manufacturer – Manufacture of the wind turbine.
(b)
Model – Model of the wind turbine. Provide any prefixes and suffixes if available.
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(3)
(4)
(c)
Turbines – The number of turbines at the wind farm
(d)
Capacity – The nameplate capacity of each turbine
(e)
Hub Height – Height of the center of the turbine hub in meters (m) above ground level
(f)
Rotor Diameter – Diameter of the rotor blades of the turbine in meters (m)
(g)
Temperature Range of Operation – Temperature range of operation. The value should be entered in degree Celsius (C). The value should reflect the turbine temperature range of operation.
ICCP Object ID – The ICCP object IDs that the Generator Interconnection Customer will use to send ICCP data for a WGR (a)
Wind Speed
(b)
Wind Direction
(c)
Temperature
(d)
Pressure
(e)
Relative Humidity
(f)
Real Time Turbine Availability
Contact Information – 24x7 contact information (a)
Wind Farm Owner
(b)
Wind Farm Operator
(B) A Generator Interconnection Customer for a WGR must provide Real Time data through ICCP. When the parties agree, the Market Participant may submit the data on the Generator Interconnection Customer’s behalf. (1)
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Weather Data – A snapshot of the instantaneous value at the wind resource site is requested at a periodicity of every 60 seconds or faster. (a)
Wind Speed – Telemetered wind speed measured in meters per second (m/s) taken directly from the specified met tower/nacelle anemometer.
(b)
Wind Direction – Telemetered wind direction measured in compass heading degrees (1 – 360) taken directly from the specified met tower/nacelle anemometer.
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(2)
(c)
Temperature – Telemetered temperature measured in degrees Celsius (C) taken directly from the specified met tower/nacelle anemometer.
(d)
Pressure – Telemetered barometric pressure measured in kilopascals (kPa) taken directly from the specified met tower/nacelle anemometer.
(e)
Relative Humidity – Telemetered relative humidity measured in percent (%) taken directly from the specified met tower/nacelle anemometer.
Real-Time Turbine Availability – Number of turbines at the wind resource site that are able to generate power as a percentage (%) of the installed nameplate capacity of the site. A snapshot of the instantaneous availability at the wind resource site is requested at a periodicity of every 60 seconds or faster.
(C) A Generator Interconnection Customer for a WGR must provide Planned and Forced Outage and Availability data though the Control Room Operations Window (CROW). When the parties agree, the Market Participant may submit the data on the Generator Interconnection Customer’s behalf. (1)
Outage – Any planned or forced outage, where all turbines at the wind farm site are out of service or not operational, shall be added to CROW as an outage with the best approximation of the in-service date.
(2)
Availability – Provide the planned hourly wind farm MW capability due to maintenance and any known power curve de-rate for the next 7 days. The threshold to submit, or update, availability reduction from nameplate capacity is 10% or 10MW whichever is smaller.
4.1.2.4
Grandfathered Wind-Powered Generation Resource Data Requirements
(A) A Generator Interconnection Customer for a WGR must provide applicable and accurate static information as identified in section 4.1.2.3(A) to SPP using a spreadsheet based template as defined by SPP. The Market Participant shall provide SPP with current contact information for the wind farm Owner and Operator though the Model Change Submission Tool (MCST). When the parties agree, the Market Participant may submit the data on the Generator Interconnection Customer’s behalf. WGR static data must be updated at least once every five (5) years or as needed.
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(B) When available and voluntarily submitted, SPP will accept Real-Time data such as identified in section 4.1.2.3(B) above through ICCP from a Generator Interconnection Customer or the Market Participant. (C) A Generator Interconnection Customer for a WGR must provide Planned and Forced Outage and Availability data though the Control Room Operations Window (CROW). When the parties agree, the Market Participant may submit the data on the Generator Interconnection Customer’s behalf. (1)
Outage – Any planned or forced outage, where all turbines at the wind farm site are out of service or not operational, shall be added to CROW as an outage with the best approximation of the in-service date.
(2)
Availability – Provide the planned hourly wind farm MW capability due to maintenance and any known power curve de-rate for the next 7 days. The threshold to submit, or update, availability reduction from nameplate capacity is 20% or 20MW whichever is smaller. SPP highly recommends submitting or updating availability information in 10% or 10MW step sizes, but it is not required.
4.1.3
Operating Reserve, Head-room and Floor-room Requirements
SPP calculates the amount of Operating Reserve required for the Operating Day, on both a system-wide basis and a Reserve Zone basis, to comply with the reliability requirements specified in the SPP Criteria. Additionally, SPP calculates the amount of Head-room and Floorroom required for the Operating Day to ensure that unit commitment is sufficient to reliably serve load in real-time while maintaining the Operating Reserve requirements. SPP calculates the hourly Regulation-Up, Regulation-Down, Contingency Reserve, Head-room and Floor-room requirements on an SPP BAA basis and calculates minimum Operating Reserve requirements and maximum Operating Reserve limitations for each Reserve Zone. (1)
SPP BAA Contingency Reserve requirements are set consistent with SPP Criteria and may vary on an hourly basis.
(2)
SPP BAA Regulation-Up and Regulation-Down requirements are set to ensure compliance with NERC control performance requirements and are based upon a percentage of forecasted load, adjusted up or down to account for resource output variability, and may vary on an hourly basis.
(3)
SPP BAA Head-room and Floor-room requirements are set to ensure that expected variations between real-time instantaneous load and the average load and variations
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between real-time variable resource output and projected variable resource output cleared in the Day-Ahead Market and the projected average load used in the RUC unit commitment processes can be reliably served in real-time while simultaneously maintaining the SPP BAA Operating Reserve requirements (4)
The SPP BAA requirements, minimum Reserve Zone Operating Reserve requirements and maximum Reserve Zone Operating Reserve limitations are calculated and posted no later than 7:00 AM Day-Ahead. At this time, SPP will also communicate each Asset Owner’s estimated Operating Reserve obligations in each Reserve Zone using the BAA Mid-Term Load Forecast and the Asset Owner load forecasts developed by SPP under Section 4.1.2.1.5.
(5)
These Operating Reserve requirements and limitations are used by SPP as inputs into the DA Market and RTBM clearing and RUC processes. (a)
(6)
SPP may increase Operating Reserve requirements for use in RTBM clearing and RUC processes above the requirements used in the DA Market clearing, including changes to Reserve Zone minimums and maximums, as required to meet increases in reliability requirements caused by changes in system conditions.
Reserve Zone minimum Operating Reserve requirements and maximum Operating Reserve limitations are determined through reserve zone studies prior to the DA Market. Reserve zone studies are performed as described under Section 4.1.3.1.
4.1.3.1
Reserve Zone Requirements
Reserve Zone studies are performed on a daily basis to determine each Reserve Zone’s minimum and maximum Operating Reserve requirements. A base case is produced using RTBM Resource Offer data to produce a Resource commitment and dispatch with all applicable transmission constraints activated. Using this base case, Reserve Zone studies are performed as follows. 4.1.3.1.1
Minimum Reserve Zone Operating Reserve Requirements
Using this base case commitment and dispatch, the loss of the largest Resource is simulated for each Reserve Zone and the unused physical import capability is assessed. Operating Reserve being supplied to a Reserve Zone from outside of the SPP BA as described under Section 4.2.2.5.7 is included in this evaluation;
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(1)
Power Transfer Distribution Factor (PTDF) interface flowgates for the import/export study will use appropriate ratings that do not reflect additional protection for transmission contingencies.
(2)
If unused physical import capability, including capability set aside to protect against instability, uncontrolled separation, or cascading outages equals or exceeds the largest Resource MW, then Reserve Zone minimum is equal to zero.
(3)
If unused physical import capability, including capability set aside to protect against instability, uncontrolled separation, or cascading outages is less than the largest Resource MW, then the Reserve Zone minimum Operating Reserve requirement is equal to the lesser of; 1) the difference between the largest Resource MW and unused physical import capability; or 2) the difference between the Reserve Zone load and physical import capability.
(4)
The Reserve Zone minimum Operating Reserve requirement can be met through clearing of the most economic combination of Regulation-Up, Spinning Reserve and Supplemental Reserve that is available on Resources located within the Reserve Zone. (a)
4.1.3.1.2
SPP may set specific Regulation-Up and/or Spinning Reserve minimum requirements for each Reserve Zone, as needed, to address reliability issues that can only be alleviated through carrying synchronized reserves. In such cases, SPP will include these minimum Regulation-Up and/or Spinning Reserve requirements when posting the Operating Reserve requirements by 0700 Day-Ahead.
Maximum Reserve Zone Operating Reserve Limitations
Using the base case commitment and dispatch, simulate the loss of the largest Resource in one Reserve Zone and assess the export capability in remaining Reserve Zones. Operating Reserve being supplied to a Reserve Zone from outside of the SPP BA as described under Section 4.2.2.5.7 is included in this evaluation. (1)
Aggregate and proxy PTDF flowgates for the import/export study will use appropriate ratings that do not reflect additional protection for transmission contingencies.
(2)
A Reserve Zone maximum Operating Reserve limitation would be equal to the incremental export capability of the Reserve Zone without violating any system operating limits.
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(3)
The Reserve Zone maximum Operating Reserve limitation can be met through clearing of the most economic combination of Regulation-Up Service, Spinning Reserve and Contingency Reserve that is available on Resources located within the Reserve Zone.
4.1.3.2
Head-room and Floor-room Requirements
For Day-Ahead Market and RUC which use hourly load granularity, intra-hour Head-room and Floor-room requirements represent the needed real-time online capacity to address load changes within the Operating Hour and variations between real-time variable resource output and projected variable resource output. For example, during morning load pickup, the end-of-hour capacity requirements may be much greater than the average hourly energy represented by the cleared demand in the Day-Ahead Market or the load forecast used in the RUC processes. Additionally, the load forecast or generation forecast for a variable resource can be off due to uncertainties inherent in these load and generation forecasts. If Resources were committed only for the average hourly load, the online capacity at the end of the morning load pickup hour may be insufficient to support reliable real time operations. SPP calculates the required Head-room and Floor-room requirements for both the Day-Ahead Market and the RUC processes as follows. SPP may include up to 0% of the calculated Head-room and Floor-room requirements as an input into the Day-Ahead Market and may include 100% of the calculated Head-room and Floor-room requirements in all RUC processes. 4.1.3.2.1
Day-Ahead Market
SPP estimates the hourly Head-room and Floor-room requirements to be included in the DayAhead Market using SPP’s Mid-Term Load Forecast and expected real-time instantaneous load values for the Operating Day including a factor for load forecast and variable resource output uncertainty. SPP’s Mid-Term Load Forecast represents the expected average load in an Operating Hour. For Head-room and Floor-room requirement calculations, the instantaneous load is assumed to be equal to the expected average load at the midpoint of the Operating Hour and ramp linearly from this point to the expected average load at the midpoint of the neighboring Operating Hours. Because this assumption will not always be accurate, especially in Operating Hours in which an instantaneous peak load or an instantaneous minimum load trough occurs, and due to load forecast and variable resource output uncertainty, SPP requires an amount of Headroom and Floor-room requirements. (1)
The Head-room requirement for the current Operating Hour is set equal to the maximum of: (i) the difference between the expected instantaneous load at the beginning of the
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Operating Hour and expected average load in the Operating Hour; (ii) the difference between the expected instantaneous load at the end of the Operating Hour and the expected average load in the Operating Hour; or (iii) the minimum Head-room requirement. SPP may reduce the Head-room requirement calculated above as operational experience dictates and/or to account for differences between offered DayAhead Market Resources and those available in the RUC processes. (2) The Floor-room requirement for the current Operating Hour is set equal to the maximum of: (i) the difference between the expected average load in the Operating Hour and the expected instantaneous load at the beginning of the Operating Hour; (ii) the difference between the expected average load in the Operating Hour and the expected instantaneous load at the end of the Operating Hour; or (iii) the minimum Floor-room requirement. SPP may reduce the Floor-room requirement calculated above as operational experience dictates and/or to account for differences between offered Day-Ahead Market Resources and those available in the RUC processes. The expected instantaneous load at the beginning of the Operating Hour is estimated as the load forecast value at the point at which a straight line drawn from the midpoint of the previous Operating Hour’s expected average load to the midpoint of the current Operating Hour’s expected average load crosses the beginning of the current Operating Hour. The expected instantaneous load at the end of the Operating Hour is estimated as the load forecast value at the point at which a straight line drawn from the midpoint of the current Operating Hour’s expected average load to the midpoint the next Operating Hour’s expected average load crosses the end of the current Operating Hour. The minimum Head-room and Floor-room requirements will be determined by SPP based upon operating experience. The Head-room and Floor-room requirements will be reviewed by the Market Working Group quarterly and may be refined over time based upon the relationship between SPP Mid-Term Load Forecast average loads and observed instantaneous load values. 4.1.3.2.2
RUC
For all RUC processes, SPP estimates the hourly Head-room and Floor-room requirements to be included in the RUC analyses using the most current Mid-Term Load Forecast and expected realtime instantaneous load values for the Operating Day using the same methodology as described under Section 4.1.3.2.1 for the Day-Ahead Market.
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4.1.4
Violation Relaxation Limits
The DA Market, RUC processes and RTBM SCED enforce a number of operating constraints in developing the co-optimized market solution. In certain situations, attempting to enforce all constraints may result in a solution that is not feasible at a Shadow Price less than an appropriately priced Violation Relaxation Limit. In such cases, SPP must apply Violation Relaxation Limits (VRLs) in SCED. There are five categories of constraints and associated VRLs: (1) Resource Capacity Constraints; (2) Resource Ramp Constraint; (3) Global Power Balance Constraint; (4) Operating Constraint (which include PNode, Manual, Watch List, flowgate and Real-Time Contingency Analysis (RTCA) Constraints) and (5) Spinning Reserve requirement constraint. A higher VRL value is an indication of the relative priority for enforcing the constraint type. For example, the VRL value assigned to a ramp rate limit exceeds that assigned to a flowgate limit indicating that the flowgate constraint should be relaxed before the ramp rate constraint. If the VRL with the lowest value will not allow SCED to balance the market’s energy obligations, a higher VRL will be applied. In the case of the Operating Constraint VRLs, the values limit the cost of the dispatch needed to balance system injections and withdrawals by capping the Shadow Price depending upon the level of the violation. Similarly, the Spinning Reserve Constraint VRL limits the costs of redispatch need to meet the Spinning Reserve requirement by capping the Spinning Reserve Shadow Price. Exhibit 4-1 provides a summary of the current VRL values by constraint type.
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Constraint Type (1) Resource Capacity
(2) Global Power Balance (3) Resource Ramp (4a) Operating Constraint not subject to Market-to-Market coordination
Exhibit 4-1: VRL Values Description The minimum and maximum MW dispatchable output of a resource as indicated in a Resource Offer. Energy needed to balance resources and load. The ramp capability of a resource as indicated in the resource plan. A MW limit that can be imposed on SPP related to MW flow across a market node, a manually-identified transmission constraint, a Watch List transmission constraint, a flowgate constraint, or a transmission constraint identified by SPP’s real-time contingency analysis.
VRL [$/MW] 100,000
50,000 5,000 $500 when the loading is greater than 100% and less than or equal to 101% at each network constraint at each Operating Constraint.
Comment [MPRR193.133]: MPRR193 Awaiting FERC filing
$750 when the loading is greater than 101% and less than or equal to 102% at each network constraint $1,000 when the loading is greater than 102% and less than or equal to 103% at each network constraint $1,250 when the loading is greater than 103% and less than or equal to 104% at each network constraint $1,500 when the loading is greater than 104% at each network constraint (4b) Operating Constraint subject to Market-to-Market coordination
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A MW limit that can be imposed on SPP related to MW flow across a market node, a manually-identified transmission constraint, a Watch List transmission constraint, a flowgate
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MISO’s Shadow Price as further defined in Section 3.1 of the SPP-MISO JOA
Comment [MPRR193.134]: MPRR193 Awaiting FERC filing
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Constraint Type
(5) Spinning Reserve Constraint
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Description constraint, or a transmission constraint identified by SPP’s real-time contingency analysis. A MW value representing the Spinning Reserve requirement
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VRL [$/MW]
$200
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VRLs and associated values are intended to achieve the following objectives: (1) Mitigate the occurrence of price excursions or other extreme prices; (2) Remove the portion of a loading violation attributed to market flow on a flowgate within 30 minutes of the start of a VRL violation; (3) Mitigate the regulation burden placed on the Resources providing regulation services; (4) Limit contribution to CPS violations; and (5) Minimize the need for Manual Dispatch Instructions. 4.1.4.1
Impact of VRLs on LMPs and MCPs
The applicable VRLs impact the calculation of LMPs in the following manner: (1)
When a Resource Capacity, Global Power Balance, Resource Ramp, or Operating Constraint is reached but not exceeded, it is referred to as “binding.” In this state, VRLs are not applicable and LMPs are calculated through the normal SCED solution;
(2)
When an Operating Constraint is exceeded and can’t be resolved at a Shadow Price less than or equal to the applicable Operating Constraint VRL, the constraint is relaxed so that SCED can solve (i.e. the limit is increased by the amount of the violation). The VRL values applied by SCED in this case act as a cap on the Shadow Price on the applicable Operating Constraint and do have a direct impact on the resulting LMPs. LMPs are determined by the relaxed SCED solution; (a)
For example, assume Flowgate A has a 100 MW limit and SCED is redispatching to correct a limit violation. The SCED Shadow Price on Flowgate A reaches $1500/MW at which point the SCED calculated flow on Flowgate A is 107 MW. At this point, SCED will stop trying to re-dispatch to meet the 100 MW limit, the limit is then increased (“relaxed”) to 107 MW, and SCED concludes its solution using the new limit. The Shadow Price on Flowgate A is calculated based on this new 107 MW limit and will be approximately equal to $1500/MW. LMPs are calculated using the marginal resources of this relaxed SCED solution.
(b)
Further to the example in (a) above and assuming that the recalculated Shadow Price is equal to $1495/MW, applying the equations for calculation of LMP as described under Section 4.5.3.2 (LMP = MEC + MCC + MLC) for Node X: Assume:
MEC = $20/MWh Shift Factor for Node X on Flowgate A is (-5%) MLC = 0
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MCC = Shadow Price * Shift Factor Then: Node X LMP = $20/MWh - ($1495/MWh * -.05) = $94.75/MWh. (3)
When a Resource Ramp Constraint for Energy in the up direction is exceeded and can’t be resolved and there is no capacity shortage causing Scarcity Pricing to be initiated as described under Section 4.1.5, LMPs are set equal to the highest Resource Offer for Energy as specified in the Energy Offer Curve that cleared in the DA Market or that was dispatched in the RTBM and MCPs are set by reducing the Operating Reserve requirement to match available Operating Reserve. Under capacity shortage conditions, LMPs and MCPs are set by the Operating Reserve Demand Curve as described under Section 4.1.5; and
(4)
When a Resource Ramp Constraint for Energy in the down direction is exceeded and can’t be resolved and there is no excess generation condition causing Scarcity Pricing to be initiated as described under Section 4.1.5, LMPs are set equal to the lowest Resource Offer for Energy as specified in the Energy Offer Curve that cleared in the DA Market or that was dispatched in the RTBM and MCPs are set based upon the submitted Resource Offers. Under excess generation conditions, LMPs and MCPs are set by the RegulationDown Demand Curve as described under Section 4.1.5.
(5)
When a Spinning Constraint is exceeded and can’t be resolved at a Shadow Price less than or equal to the Spinning Reserve Constraint VRL, the constraint is relaxed so that SCED can solve (i.e. the Spinning Reserve requirement is reduced by the amount of the violation). The VRL values applied by SCED in this case act as a cap on the Shadow Price of the Spinning Reserve constraint and do have a direct impact on the calculation of the Spinning Reserve MCPs. LMPs and MCPs are determined by the relaxed SCED solution.
4.1.4.2
Determination of VRLs
Each year by November 1, VRLs and their associated values shall be reviewed and approved by the MOPC based on recommendations received from ORWG and MWG. Any changes to the VRLs or associated values must be approved for filing by the Board of Directors and approved by FERC prior to their implementation. The most recent FERC approved VRLs and their associated values shall be posted on the SPP OASIS website. SPP shall post the following information on the SPP OASIS website on at least a monthly basis within 15 days of the last day of the month:
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(1)
The number of times that VRL values were applied by SCED during the month, and associated detail regarding the VRL type and value for each incident;
(2)
The value of each LMP in excess of the safety net offer cap or below zero (0) during the month;
(3)
The number and duration of each incident where a VRL was employed with respect to the same flowgate for two or more consecutive intervals;
(4)
If SPP was unable to achieve the market flow relief required by the IDC, the constraint that was violated, the deployment interval(s) during which the violation occurred, the MW amount of the violation, and the Min and Max LMP during the violation period;
(5)
The assessment of regulation requirement from application of a VRL;
(6)
The number of CPS violations coincident with the application of a VRL;
(7)
The number and magnitude of Manual Dispatch Instructions issued coincident with the application of a VRL.
4.1.4.3
VRL Reporting
By August 1st each year, SPP will provide analysis as well as a set of proposed VRLs and associated values to the ORWG and MWG. ORWG and MWG will then recommend a set of proposed VRLs and associated values to the MOPC. 4.1.4.3.1
Quarterly Reporting
SPP shall report the following information to the ORWG and the MWG on a quarterly basis in the month following the end of the quarter: (1)
A summary report and supporting detailed data identifying:
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(a)
Number of times, each month, the application of VRL was required to provide a market solution;
(b)
VRL type and value;
(c)
Amount of the limiting condition;
(d)
Amount exceeding the limit;
(e)
Resulting shadow prices for each incident;
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(f)
Number and duration of each incident where a VRL was employed with respect to the same flowgate for six or more consecutive intervals;
(g)
Number and magnitude of Manual dispatch instructions issued coincident with the application of a VRL; and
(2) An assessment of how effective the VRLs have been at achieving the stated objectives. 4.1.4.3.2
Annual Reporting
Each year by August 1st, SPP shall produce a report with supporting documentation that will analyze the effectiveness of VRLs and associated values on reliability and prices. The report shall include a sensitivity analysis of the existing VRL and associated values and examine impacts of raising or lowering the associated values. If changes are warranted, SPP shall recommend changes to the ORWG and the MWG for consideration.
4.1.5 (1)
Scarcity Pricing SPP uses Demand Curves to set Market Clearing Prices in both the DA Market and RTBM during times of capacity shortages (“Scarcity Pricing”), either on a Reserve Zone basis or system-wide basis. Capacity shortages do not include shortages of Operating Reserve relating to insufficient ramping capability and Scarcity Pricing triggered under this situation may be mitigated through the use of ramp sharing as described below under Section 4.1.6 and ultimately mitigated through constraint relaxation as described under Section 4.1.4.1(3). There are three sets of Demand Curves that apply on a system-wide basis and a Reserve Zone basis: (1) Operating Reserve; (2) Regulation-Up Service; and (3) Regulation-Down Service. The Scarcity Pricing levels associated with each of these Demand Curves are as follows: (a)
Operating Reserve – The sum of the Safety-Net Energy Offer Cap and the Contingency Reserve Offer Cap as specified under Section 8.2.5;
(b)
Regulation-Up Service – The sum of the Regulation-Up Service Offer Cap and the Contingency Reserve Offer Cap as specified under Section 8.2.5; and
(c) (2)
Regulation-Down Service - The sum of the Regulation-Down Service Offer Cap and the Contingency Reserve Offer Cap as specified under Section 8.2.5.
Capacity is required by Energy, Regulation-Up Service, Spinning Reserve and Supplemental Reserve and Operating Reserve product pricing rules (“price cascading”) require that the Regulation-Up Service MCP be greater than or equal to Spinning Reserve
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Market Protocols for SPP Integrated Marketplace
MCP and that the Spinning Reserve MCP be greater than or equal to the Supplemental Reserve MCP on both a system-wide basis and Reserve Zone basis. Therefore, any shortage in capacity to meet Energy, Regulation-Up and Contingency Reserve requirements will be reflected in the pricing of all of these products. (a)
(3)
For example, if we assume that there is a 50 MW shortage of Supplemental Reserve, the Supplemental Reserve MCP would be set to $1100/MW and the Spinning Reserve MCP, Regulation-Up Service MCP and the Energy LMP would also reflect the impacts of this $1100/MW price. The Energy LMP is increased by the Operating Reserve shortage price of $1100/MW if the cost of serving an incremental MW of energy worsens the Operating Reserve capacity shortage condition (i.e. Operating Reserve Demand Curve is included in the LMP calculation), otherwise it is not.
The system-wide Regulation-Up Service and Regulation-Down Service Demand Curve prices are designed to reflect pricing signals that are commensurate with a shortage in Regulation-Up Service or Regulation-Down Service capability, not shortages in capacity (i.e. there may be sufficient capacity available to meet the Regulation-Up requirement but there is simply not enough Regulation Qualified Resources and Regulation-Up Qualified Resources available). A shortage of Regulation-Up Service capability will invoke Regulation-Up Service Scarcity Pricing. A shortage of Regulation-Down Service capability will invoke Regulation-Down Service Scarcity Pricing. (a)
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In cases where there is no Operating Reserve capacity shortage, Energy LMPs will not be impacted by the Operating Reserve Demand Curve since there is no shortage of capacity, only Regulation-Up capability or Regulation-Down capability.
(b)
If a Regulation-Up capability shortage also contributes to an Operating Reserve capacity shortage (i.e. if Contingency Reserve is depleted for the purposes of meeting Energy requirements), Regulation-Up MCPs will be impacted by both the Regulation-Up Demand Curve price and Operating Reserve Demand Curve price.
(c)
If a Regulation-Down capability shortage is caused by an excess generation emergency situation as described under Sections 4.3.1.2.2 and 4.4.2.3.3, Regulation-Down MCPs will be impacted by the Regulation-Down Demand Curve.
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Comment [MPRR102.144]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.145]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.146]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.147]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.148]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.149]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.150]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.151]: MPRR102 Awaiting implementation. #ER13-1748
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(4)
If there is a Reserve Zone Operating Reserve shortage that occurs simultaneously with a system-wide Operating Reserve shortage and there is no system-wide Regulation-Up capability shortage, both the system-wide Operating Reserve Demand Curve and Reserve Zone Operating Reserve Demand Curves will be applied (i.e. the system-wide and zonal Operating Reserve Demand Curves are additive) in the calculation of Supplemental Reserve MCPs for the Reserve Zone(s) with Operating Reserve shortage (which will also impact Spinning Reserve and Regulation-Up MCPs due to the price cascading rules described under Section 4.5.4.2).
(5)
If there is a Reserve Zone Operating Reserve shortage that occurs simultaneously with a system-wide Operating Reserve shortage and a system-wide Regulation-Up capability shortage, the system-wide Operating Reserve Demand Curve, the system-wide Regulation-Up Demand Curve and the Reserve Zone Operating Reserve Demand Curves will be applied (i.e. the system-wide and zonal Demand Curves are additive) in the calculation of Regulation-Up MCPs for the Reserve Zone(s) with Operating Reserve shortage.
(6)
If there is insufficient capacity to meet Energy requirements on a system-wide basis, Energy requirements are reduced to meet available capacity and LMPs are calculated normally which will include the impacts of both the system-wide Operating Reserve Demand Curve and system-wide Regulation-Up Demand Curve.
4.1.5.1
Demand Curve Interaction with VRLs
During capacity shortage conditions, both LMPs and MCPs are impacted by prices set by Demand Curves. Additionally, LMPs may also be impacted by VRLs as described under Section 4.1.4. Exhibit 4-2 below shows the impacts to LMPs and MCPs under varying system conditions caused by the applicable of VRLs and Demand Curves.
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Exhibit 4-2: VRL and Demand Curve Interaction Scenarios: A:
No Capacity Shortage
B:
System-Wide Regulation-Up Shortage, No Operating Reserve Shortage
C:
System-wide Operating Reserve Capacity Shortage, No Regulation-Up Shortage
D:
System-wide Operating Reserve Capacity Shortage and System-Wide Regulation-Up Shortage
E:
System-Wide Operating Reserve Capacity Shortage, System-Wide Regulation-Up Shortage and Reserve Zone Operating Reserve Shortage
F:
Energy Capacity Shortage and No Reserve Zone Operating Reserve Shortage Non-Binding Operating Constraint VRL
Binding Operating Constraint (OC) VRL
Scenario LMP Impact
MCP Impact
LMP Impact
MCP Impact
A
Set economically by Resource Offers.
Set economically by Resource Offers.
Set economically by relaxing the Transmission Constraint associated with the Operating Constraint VRL.
Set economically by Resource Offers.
B
Set economically by Resource Offers.
Regulation-Up MCP >= Regulation-Up Demand Curve price. Contingency Reserve MCPs set economically by Resource Offers.
Set economically by relaxing the Transmission Constraint associated with the Operating Constraint VRL and includes associated OC VRL price impacts.
Regulation-Up MCP >= Regulation-Up Demand Curve price. Contingency Reserve MCPs set economically by Resource Offers.
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Non-Binding Operating Constraint VRL
Binding Operating Constraint (OC) VRL
Scenario LMP Impact
MCP Impact
C
Set economically by Resource Offers and Operating Reserve Demand Curve price impact.
MCP set at Operating Reserve Demand Curve price.
LMPs calculated by relaxing the Transmission Constraint associated with the Operating Constraint VRL. Operating Demand Curve price included in LMP calculation.
MCP set at Operating Reserve Demand Curve price.
D
Set either (i) economically by Resource Offers plus Operating Reserve Demand Curve price impact if Contingency Reserve has not been depleted or (ii) economically by Resource Offers and price impacts of both Operating Reserve Demand Curve and Regulation-Up Demand Curve if Contingency Reserve has been depleted to meet Energy requirements.
Supplemental Reserve MCP set at Operating Reserve Demand Curve price. Spinning Reserve MCP >= Operating Reserve Demand Curve price. Regulation-Up MCP >= sum of Operating Reserve Demand Curve price and RegulationUp Demand Curve price.
Set economically by relaxing the Transmission Constraint associated with the Operating Constraint VRL and includes associated OC VRL price impacts and (i) Operating Reserve Demand Curve price impact also included in LMP if Contingency Reserve has not been depleted or (ii) sum of Operating Reserve Demand Curve price and Regulation-Up Demand Curve price also included in LMP if Contingency Reserve has been depleted to meet Energy requirements.
Supplemental Reserve MCP set at Operating Reserve Demand Curve price. Spinning Reserve MCP >= Operating Reserve Demand Curve price. Regulation-Up MCP >= sum of Operating Reserve Demand Curve price and Regulation-Up Demand Curve price.
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LMP Impact
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Non-Binding Operating Constraint VRL
Binding Operating Constraint (OC) VRL
Scenario LMP Impact E
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System-Wide LMPs set as described above for Scenario D. LMPs in binding Reserve Zone will also reflect the Reserve Zone Operating Reserve Demand Curve price impact.
MCP Impact
LMP Impact
MCP Impact
System-Wide MCPs set as described above for Scenario D and MCPs in binding Reserve Zone will also reflect the Reserve Zone Operating Reserve Demand Curve price.
System-Wide LMPs Set economically by relaxing the Transmission Constraint associated with the Operating Constraint VRL and includes associated OC VRL price impacts and will also include Demand Curve price impacts as described above for Scenario D. LMPs in binding Reserve Zone will also reflect impacts of the Reserve Zone Operating Reserve Demand Curve price.
System-Wide MCPs set as described above for Scenario D and MCPs in binding Reserve Zone will also reflect the Reserve Zone Operating Reserve Demand Curve price.
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Non-Binding Operating Constraint VRL
Binding Operating Constraint (OC) VRL
Scenario LMP Impact F
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System-Wide LMPs set economically by Resource Offers will reflect the price impacts of both Operating Reserve Demand Curve price and Regulation-Up Demand Curve price.
MCP Impact
LMP Impact
MCP Impact
System-Wide Supplemental Reserve MCP set at Operating Reserve Demand Curve price. System-Wide Spinning Reserve MCP >= Operating Reserve Demand Curve price. System-Wide Regulation-Up MCP >= sum of Operating Reserve Demand Curve price and RegulationUp Demand Curve price.
System-Wide LMPs set economically by Resource Offers on the basis of Energy requirements being relaxed to meet available capacity. LMPs will reflect the price impacts of both of Operating Reserve Demand Curve price and Regulation-Up Demand Curve price.
System-Wide Supplemental Reserve MCP set at Operating Reserve Demand Curve price. System-Wide Spinning Reserve MCP >= Operating Reserve Demand Curve price. System-Wide Regulation-Up MCP >= sum of Operating Reserve Demand Curve price and Regulation-Up Demand Curve price.
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4.1.6
Ramp Sharing
To reduce instances when ramping deficiencies across Hours in the DA Market or Dispatch Intervals in the RTBM initiate unjustified Scarcity Pricing (i.e. Scarcity Pricing should only be initiated when there is a capacity shortage) ramp sharing may be applied to clear sufficient amounts of Energy, Regulation-Up Service and Spinning Reserve to meet the requirements. This is accomplished through the use of tuning parameters within the SCED model that will allow sharing of ramp ranging from no sharing of ramp to 100% sharing of ramp between Energy and Regulation-Up Service and/or Energy and Spinning Reserve. SPP will update these tuning parameters from time to time based upon historical system performance. If ramp sharing is applied, it shall remain effective for all hours in the Day-Ahead Market, Reliability Unit Commitment, and Real-Time Balancing Market. SPP will not implement ramp sharing in the RTBM that will result in the inability to meet applicable NERC reliability standards and control performance requirements. For example, if SPP institutes 20% ramp sharing between Energy and Spinning Reserve, this means that the effective remaining Ramp Rate available for Spinning Reserve clearing is divided by (1 – 20%) which may result in Spinning Reserve being cleared that is not 100% deployable. Example: Energy Ramp Rate = 10MW/min Contingency Reserve Ramp Rate = 10 MW/Min 20 % Ramp sharing As shown above the Energy Ramp Rate is 10 MW/min. Assuming Energy clears at 30 MW, Energy occupies 30MW/5min or 6MW/min of the 10MW/min ramp rate available for Spinning Reserve clearing. The remaining effective Ramp Rate available for Spinning Reserve clearing is 10 MW/min – 6 MW/min =4 MW/min which means 40 MWs of Spinning Reserve could be cleared (4MW/min * 10 min = 40 MW) with no ramp sharing. With 20% ramp sharing, the amount of Spinning Reserve that could be cleared is increased by dividing 40 MW by (1- 20%). This means based on 20% ramp sharing, we can actually clear up to 40 MW / (0.8) or 50 MW of Spin. Exhibit 4-3: Ramp Sharing Example
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4.1.7
Outage Scheduling and Reporting
SPP is responsible for approving the scheduling of maintenance on all transmission facilities making up the Transmission System and for coordinating with Resource Asset Owners, as appropriate, to schedule maintenance on generation facilities. The roles and responsibilities of SPP and Market Participants regarding submittal of requested transmission and generation outages through the outage scheduler tool, evaluation and approval of requests and reporting of generator forced outages through the outage scheduler tool is described in the SPP Criteria. Additionally, as described under Section 4.2.2.2.1, an outage must be recorded using the outage scheduler tool in order to select an “Outage” Commitment Status. Outages approved and recorded using the outage scheduler tool will override any other commitment status submitted by the Market Participant.
4.1.8
Joint Operating Agreements – Seams Coordination
Joint Operating Agreements (JOAs) are arrangements between SPP and adjacent Balancing Authorities that enable one BA on an hourly basis to request the other to re-dispatch to relieve, or make available, additional transmission flowgate capacity for use by the requesting BA. There are hours when it may be more economical for a bordering BA to make additional flowgate capacity available than it is for that BA to re-dispatch its own Resources. This capability is available in the DA Market, RUC processes and RTBM. The cost incurred to re-dispatch is paid
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for by the BA that utilized the additional capacity. For both the DA Market and RTBM, the costs incurred are calculated in accordance with the formula in the JOA. Any funds received or paid by SPP for seams coordination are distributed or collected through the Revenue Neutrality Uplift charge type as described under Section 4.5.12.
4.1.9
Calculation of Net Benefits Test for Compensation of Demand Response Load
SPP shall identify each month the price on a supply curve, representative of economic conditions expected for that month, at which the benefits of dispatching Demand Response Load exceed the costs of the load reductions to other loads (“Net Benefits Threshold”). In formulaic terms, the Net Benefit Threshold is deemed to be realized at the price point on the supply curve where the market price (“P”) change attributable to the dispatching Demand Response Load times the MWh consumed is greater than the new market price (after dispatching Demand Response Load) times the Demand Response Load, as set forth in the following formula: (Delta P x MWh consumed) > (P NEW x Demand Response Load) where Delta P = P before Demand Response Load is dispatched minus P NEW. SPP shall update and post the Net Benefits Test results and analysis for a calendar month no later than the 15th day of the preceding calendar month. The Net Benefits Threshold shall be calculated using the following steps: Step 1: Retrieve historical energy imbalance service market offers for the peak hour of each day from the same calendar month (of the prior calendar year) for which the calculation is being performed. Step 2: Adjust a portion of each prior-year offer representing the typical share of fuel costs in energy offers in the SPP Region for changes in fuel prices based on the ratio of the reference month spot price to the study month forward price. For such purpose; natural gas shall be priced at the Henry Hub price; number 2 oil shall be priced at the Gulf Coast price; and coal shall be priced at the Powder River Basin price. Step 3: Combine the offers to create an hourly supply curve for each daily peak hour in the period. Step 4: Smooth each supply curve by fitting the following function to the raw data using a nonlinear, least-squares regression: P(MW) = A + B * MW + C * MW2 + D * MW3 + e(E*MW+F)
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where P(MW) is the historical energy imbalance service market offer price in $/MWh, and MW is cumulative capacity. A through F are the parameters to be estimated. Step 5: Compute the price elasticity of the smoothed supply curves at each MW point, finding the threshold price for each supply curve at which elasticity falls below one for the duration of the curve. Step 6: Compute the average of the threshold prices identified in Step 5. This is the Net Benefits Threshold for the month.
4.2
Pre-Day-Ahead Activities
SPP and Market Participant activities during Pre-Day-Ahead begin seven (7) days prior to the Operating Day with Market Participant Offer and Bid submittal and end with the Multi-Day Reliability Assessment process that considers Resources with long lead times for potential commitment for use in both the DA Market and RTBM. Exhibit 4-4 provides a representative overall timeline of Pre-Day-Ahead activities.
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Exhibit 4-4: Pre Day-Ahead Activities Timeline
2/1 Begin Settlement Process
2
3
1/23
3/31 1/29 - 1/31 SPP performs Multi-Day RUC Process
1/25 - 1/31 SPP Mid-Term Load Forecast
1/24 - 1/29 Pre-Day-Ahead 1/24
1/25
1/26
1/27
1/28
1/29
1/23
1/30
1/31 1/31
MPs submit DA Offers and Bids 1/24 - 1/30
MPs submit RT Offers 1/24 - 1/30
A description of each of the functions identified in the Pre Day-Ahead timeline, other than the SPP Mid-Term Load Forecast process which is described under Section 4.1.2, is provided in the following subsections.
4.2.1
Must-Offer Requirement
Market Participants are required to offer available Resources to the Day-Ahead Market, RUC, and RTBM as described in this section below. 4.2.1.1
Day-Ahead Market
(A) Each Market Participant with registered load must satisfy the must offer obligation for each Asset Owner associated with that registered load as set forth in Section 4.2.1.1 based on the following criteria: (1)
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A Market Participant’s load for an Asset Owner for purposes of this section shall be equal to the Market Participant’s maximum hourly Reported Load for that Asset Owner for the Operating Day. When an Asset Owner selling power under a bilateral
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contract has registered the load of the Asset Owner that is buying power under the bilateral contract as described under Section 6.2.8, the buyer’s Reported Load shall be reduced by the amount of the buyer’s load registered by the seller and the seller’s Reported Load shall be increased by the amount of the buyer’s load registered by the seller. (2)
A Market Participant’s daily Operating Reserve obligation for an Asset Owner shall be equal to the sum of that Market Participant’s maximum daily Regulation-Up Service, Regulation-Down Service and Contingency Reserve obligation for that Asset Owner as calculated by SPP as described in Section 4.1.3(4).
(3)
Resources submitted with a Commitment Status of Market, Self or Reliability may be used to satisfy this requirement.
(4)
A load-serving Market Participant’s net resource capacity, for an Asset Owner for purposes of this section shall include: (a)
Offered capacity by Resources identified in (3) above less the Operating Reserve obligation identified in (2) above; and
(b)
Firm Power purchases less the Firm Power sales, except that, if the seller has registered the buyer’s load associated with a firm power sale, such firm power sale shall not act to increase the buyer’s net resource capacity or act to reduce the seller’s net resource capacity. (i)
For purposes of this Section 4.2.1.1, firm power purchases and firm power sales shall mean sales and purchases that are deliverable with service comparable to Firm Point-To-Point Transmission Service or Firm Network Integration Transmission Service with the supplier assuming the obligation to provide both capacity and energy. Additionally, firm power purchases shall include an Asset Owner’s share of a Jointly Owned Unit to the extent that such shares have not been registered as separate Resources either under the JOU Individual Resource Option or the JOU Combined Resource Option as described under Section 4.2.2.5.4. In order to verify firm power
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purchases and firm power sales, supporting documentation must be provided to the Market Monitor upon request. Market Participants have the option to input information regarding firm power purchases and firm power sales into the Market Monitor website.
If no
information is input into this website, the Market Monitor will contact the Market Participant for that information. The Market Monitor may confirm the firm purchase or sale with the counterparty and will include the transacted MWs to calculate net resource capacity for both purchaser and seller. If one of the parties dispute the firm purchase or sale to the Market Monitor, then the firm purchase or sale will not be used in the calculation of either the purchaser’s or seller’s net resource capacity. (B) A Market Participant’s compliance with the must-offer obligation for an Asset Owner is as follows: (1)
A Market Participant that has offered all of its available Resources for an Asset Owner with a Commitment Status of Market, Self, or Reliability for an hour of the Operating Day is deemed to be compliant with the must-offer requirement for that Asset Owner for that hour regardless of its maximum hourly Reported Load and/or Operating Reserve obligation. (a)
A Market Participant that does not have any registered Resources for an Asset Owner has met the must-offer requirement for that Asset Owner because it does not have any Resources with a Commitment Status of Not Participating for that Asset Owner.
(2)
A Market Participant that does not meet the condition described in (B)(1) above for an Asset Owner for an hour of the Operating Day, but has net resource capacity for that Asset Owner for that hour greater than or equal to 90% of its load for that Asset Owner, as described in (A)(1) above, is deemed to be compliant with the must-offer requirement for that Asset Owner for that hour.
(3)
To the extent a Market Participant does not meet the conditions for an Asset Owner described in either Section (B)(1) and (2), the Market Participant shall be deemed noncompliant with the must-offer requirement for that Asset Owner for that hour
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and will be assessed a penalty for that Asset Owner for that hour as described in Section 4.2.1.1.1. (4)
Resources used as the source of a GFA Carve Out must be offered, if available, with a sufficient capacity to cover the GFA Carve Out Schedule. GFA Carve Out treatment is only available to the extent that the Resources are offered into the DA Market using a Commitment Status of Market, Self or Reliability. To the extent the source is external, an Import Interchange Transaction must be submitted in the DA Market with a sufficient capacity to cover the GFA Carve Out Schedule.
(C) The Market Monitor shall monitor a Market Participant’s load, Operating Reserve obligation, offered Resources and net resource capacity, for an Asset Owner for each hour of the Operating Day to determine whether the Market Participant has complied with the must offer obligation for that Asset Owner set forth in Section 4.2.1.1 B. 4.2.1.1.1
Penalty Calculation
For each hour of the Operating Day that a Market Participant is found to be noncompliant as determined by the conditions set forth in Sections 4.2.1.1 B, that Market Participant shall be assessed a penalty. The penalty amount and the distribution of penalty revenues shall be determined as follows: (1)
An Asset Owner’s penalty amount in each hour is calculated by multiplying the Asset Owner’s Must-Offer Penalty MW by the maximum of zero or the Asset Owner’s MustOffer Penalty LMP for that hour. (a) Asset Owner Must-Offer Penalty MW is equal to the minimum of (i) the Asset Owner Shortage MW or (ii) the Asset Owner Not Offered MW; (i) Asset Owner Shortage MW is calculated as the difference between: (1) 90% of the Market Participant’s load for an Asset Owner as described in 4.2.1.1A.(1); and (2) The Market Participant’s net resource capacity for an Asset Owner as described in 4.2.1.1 A(3). (ii) Asset Owner Not Offered MW is calculated as the sum of the reference levels for the Maximum Economic Capability Operating Limit, as determined by the process in Section 8.2.2.8, less derate MW amounts approved and recorded in the outage scheduler tool for the Market
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(2)
Participant’s Resources for that Asset Owner with a Commitment Status of Not Participating. (b) The Must-Offer Penalty LMP is calculated as the weighted average of the DayAhead LMP for the Market Participant’s Resources for that Asset Owner with a Commitment Status of Not Participating, where the weights for the calculation are the corresponding Not Offered MWs. In any hour in which must-offer penalty revenues are collected, such revenues shall be distributed to Market Participants for an Asset Owner on a pro-rata basis for that Asset Owner’s Resources that were offered in compliance with the must-offer requirement in Section 4.2.1.1. The pro-rata share shall be equal to the ratio of (i) each compliant Asset Owner load, as described in 4.2.1.1 for that hour to (ii) the sum of all compliant Asset Owner loads for that hour.
4.2.1.2
RUC and RTBM
For the RUC and RTBM, Market Participants must submit Resource Offers for all Resources, for each product for which it is qualified, to the extent these Resources are available (e.g. not on forced outage, planned outage, or Reserve Shutdown). Market Participants must include in their Resource Offers the full amount of physical capacity available as reflected in the Resource’s submitted Maximum Normal Capacity Operating Limit and Maximum Emergency Capacity Operating Limit.
4.2.2
Offer Submittal
Beginning seven days prior to the Operating Day, Market Participants may begin to submit Offers for use in the DA Market and Offers for use in the RTBM. DA Market Offers may be updated up to 1100 hours Day-Ahead and RTBM Offers may be updated 30 minutes prior to each Operating Hour. The following business rules apply to Offer submittal: (1)
Offers submitted for use in the DA Market are submitted independent from the Offers submitted for use in the RTBM; (a) If a Resource is cleared for Regulation-Up Service and/or Regulation-Down Service in the Day-Ahead Market, the RTBM Offers for Regulation-Up Mileage and/or Regulation-Down Mileage for that Resource mustare set equal those submitted for use in the Day-Ahead Market for that Resource.
(2)
Market Participants have the option of specifying that the Offers submitted for use in the DA Market also apply in the RTBM;
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(a)
If this option is selected and a Resource has a Commitment Status of “Not Participating” the submission will be rejected.
(3)
Submitted Resource Offers roll forward hour to hour until changed within each respective market (DA Market and RTBM);
(4)
Market Participants may submit separate Resource Offers parametersmay be submitted that vary for each hour of the Operating Day except for those Offer parameters categorized relating to unit commitment, as identified as Daily Unit Commitment Parameters under Section 4.2.2.1, for which Market Participants shall submit as a single value is submitted that rolls forward in each hour to hour until updatedchanged;
Comment [MPRR191.159]: MPRR191 Awaiting implementation Comment [MPRR191.160]: MPRR191 Awaiting implementation Comment [MPRR191.161]: MPRR191 Awaiting implementation Comment [MPRR191.162]: MPRR191 Awaiting implementation Comment [MPRR191.163]: MPRR191 Awaiting implementation Comment [MPRR191.164]: MPRR191 Awaiting implementation Comment [MPRR191.165]: MPRR191 Awaiting implementation
(5)
Offers submitted for use in the RTBM are also used in the RUC processes;
Comment [MPRR191.166]: MPRR191 Awaiting implementation
(6)
Resource Offers may only be submitted at Resource Settlement Locations only, Import Interchange Transaction Offers may only be submitted at External Interface Settlement Locations only; Virtual Energy Offers may be submitted at any Settlement Location, including a Hub;
Comment [MPRR191.167]: MPRR191 Awaiting implementation
Resource Offers for Regulation-Up and Regulation-Up Mileage may only be submitted for Regulation Qualified Resources and Regulation-Up Qualified Resources only. Resource Offers for Regulation-Down and Regulation-Down Mileage may only be submitted for Regulation Qualified Resources and Regulation-Down Qualified Resources only. Resource Offers for Spinning Reserve may only be submitted for Spin Qualified Resources only. Resource Offers for Supplemental Reserve may be submitted for either a Spin Qualified Resources or a and Supplemental Qualified Resources. If a Spinning Reserve Offer is submitted for a Resource, and a Resource Offer for Supplemental Reserve is not submitted, then the Supplemental Reserve Offer is set equal to zero. Resource qualifications are verified by SPP as part of the registration process as follows;
Comment [MPRR195.170]: MPRR195 Awaiting FERC filing
(7)
(a)
A Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource must pass a specific regulation test as described under Section 6.1.11.3 that verifies: (i)
The Resource has the necessary equipment installed to be able to respond to Automatic Generation Control on a 4-second basis, including telemetering that can be scanned and updated on a 2-second basis; and
Comment [MPRR191.168]: MPRR191 Awaiting implementation Comment [MPRR195.169]: MPRR195 Awaiting FERC filing
Comment [MPRR195.171]: MPRR195 Awaiting FERC filing Comment [MPRR195.172]: MPRR195 Awaiting FERC filing Comment [MPRR102.173]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR195.174]: MPRR195 Awaiting FERC filing Comment [MPRR195.175]: MPRR195 Awaiting FERC filing Comment [MPRR102.176]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR195.177]: MPRR195 Awaiting FERC filing Comment [MPRR195.178]: MPRR195 Awaiting FERC filing Comment [MPRR195.179]: MPRR195 Awaiting FERC filing Comment [MPRR195.180]: MPRR195 Awaiting FERC filing Comment [MPRR195.181]: MPRR195 Awaiting FERC filing Comment [MPRR195.182]: MPRR195 Awaiting FERC filing Comment [MPRR195.183]: MPRR195 Awaiting FERC filing
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(ii)
(b)
A Spin Qualified Resource must: (i)
(ii) (c)
(8)
The Resource is capable of deploying 100% of cleared Regulation-Up or cleared Regulation-Down within the Regulation Response Time for a continuous duration of 60 minutes.
Self-Certify as described under Section 6.1.11.1 that the Resource is capable of deploying 100% of cleared Spinning Reserve and/or cleared online Supplemental Reserve within the Contingency Reserve Deployment Period for a continuous duration of 60 minutes; and
Comment [MPRR195.185]: MPRR195 Awaiting FERC filing
Provide telemetered output data that can be scanned every 10 seconds.
A Supplemental Qualified Resource must: (i)
Self-certify as described under Section 6.1.11.2 that the Resource is capable of deploying 100% of cleared Supplemental Reserve from an offline state within the Contingency Reserve Deployment Period for a continuous duration of 60 minutes.
(ii)
Provide telemetered output data that can be scanned every 10 seconds.
Resource Offers consisting of Start-Up Offer, No-Load Offer, Energy Offer Curve, Regulation-Up Offer, Regulation-Up Mileage Offer, Regulation-Down Offer, Regulation-Down Mileage Offer, Spinning Reserve Offer and Supplemental Reserve Offer are limited by the offer caps and floors specified under Section 8.2.5.
4.2.2.1
Comment [MPRR195.184]: MPRR195 Awaiting FERC filing
Comment [MPRR102.186]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.187]: MPRR102 Awaiting implementation. #ER13-1748
Resource Offer Parameters
The following Resource Offer parameters must be submitted to constitute a valid offer for use in either the DA Market or RTBM: (1)
Resource Name (as specified during Market Registration and cannot be changed as part of Resource Offer submittal);
(2)
Start-Up Offer ($/Start, Hot, Intermediate and Cold – Daily Unit Commitment Parameter)1;
1
For Market Participants that have registered a JOU under the Combined Resource Option (see Section 6.1.6.2), this value must be submitted by or on behalf of the designated Asset Owner and represents the value for the entire Physical JOU Resource. See Section 4.2.2.5.4).
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(3)
Mitigated Start-Up Offer ($/Start, Hot, Intermediate and Cold – Daily Unit Commitment Parameter) 1; 1
(4)
No-Load Offer ($/Hour) ;
(5)
Mitigated No-Load Offer ($/Hour) 1;
(6)
Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically nondecreasing $/MWh, increasing MW and slope or block option);
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(a)
Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs.
(b)
The price of all MWhs below the first pricing point MWh is equal to the first pricing point price. The price of all MWhs above the last pricing point MWh is equal to the last pricing point price.
(c)
Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-5 illustrates Energy Offer Curves developed from submitted price/MWh pairs for both the slope and block options.
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Exhibit 4-5: Energy Offer Curve Development Energy Offer Curve Submitted Data 90.00
$/MWh 20.00 40.00 60.00 80.00
80.00 70.00
Block BlockOption Option
60.00 $/MWh
MW 100 200 400 500
50.00 40.00
Slope SlopeOption Option
30.00 20.00 10.00 0.00 0
100
200
300
400
500
600
MW
(7)
Mitigated Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically non-decreasing $/MWh, increasing MW and slope or block option); (a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs. (8) Regulation-Up Offer ($/MW); (9) Mitigated Regulation-Up offer ($/MW); (10) Regulation-Up Mileage Offer ($/MW) – Note that if Regulation-Up Offer is less than zero then Regulation-Up Mileage Offer must be equal to zero; Comment [MPRR102.192]: MPRR102 Awaiting implementation. #ER13-1748
(9)(11) Mitigated Regulation-Up Mileage Offer ($/MW); (10)(12) Regulation-Down Offer ($/MW); (13) Mitigated Regulation-Down Offer ($/MW); (14) Regulation-Down Mileage Offer ($/MW) - Note that if Regulation-Down Offer is less than zero then Regulation-Down Mileage Offer must be equal to zero; (11)(15)
Mitigated Regulation-Down Mileage Offer ($/MW);
(12)(16) (13)(17) (14)(18)
Spinning Reserve Offer ($/MW); Mitigated Spinning Reserve Offer ($/MW); Supplemental Reserve Offer ($/MW);
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(15)(19) Mitigated Supplemental Reserve Offer ($/MW) (16)(20) Sync-To-Min Time (hours:minutes – Daily Unit Commitment Parameter)1; (17)(21) Min-To-Off Time (hours:minutes – Daily Unit Commitment Parameter)1; (18)(22) Start-Up Time (hours:minutes, Hot, Intermediate, Cold – Hourly Unit Commitment Parameter)1; (19)(23) Hot to Intermediate Time (hours:minutes– Daily Unit Commitment Parameter)1; (20)(24) Hot to Cold Time (hours:minutes– Daily Unit Commitment Parameter)1; (21)(25) Maximum Daily Starts (Daily Unit Commitment Parameter)1; (22)(26) Maximum Weekly Starts – rolling 7-day (Daily Unit Commitment Parameter)1; (23)(27) Maximum Daily Energy (MWh – Daily Unit Commitment Parameter)1; (a) For enforcement of the Maximum Daily Energy constraint, cleared Regulation-Up and cleared Contingency Reserve will decrement the Resource’s total Maximum Daily Energy by 50% of the cleared product. (b) For enforcement of the Maximum Daily Energy constraint, cleared RegulationDown will increment the Resource’s total Maximum Daily Energy allowed by 0% of the cleared product. (28) Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter)1; (29) Group Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter) - Only applicable to combined cycle Resources that have registered under the option described under Section 6.1.7(4); (24)(30) Plant Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter) Only applicable to combined cycle Resources that have registered under the option described under Section 6.1.7(4); (25)(31) Maximum Run Time (hours:minutes– Daily Unit Commitment Parameter)1; (26)(32) Minimum Down Time (hours:minutes– Daily Unit Commitment Parameter)1; (27)(33) Minimum Emergency Capacity Operating Limit (MW); (28)(34) Minimum Emergency Capacity Run Time (hours:minutes – Operations Information); (29)(35) Minimum Normal Capacity Operating Limit (MW); (30)(36) Minimum Economic Capacity Operating Limit (MW); (31)(37) Minimum Regulation Capacity Operating Limit (MW); (32)(38) Maximum Regulation Capacity Operating Limit (MW); (33)(39) Maximum Economic Capacity Operating Limit (MW); (34)(40) Maximum Normal Capacity Operating Limit (MW); (35)(41) Maximum Emergency Capacity Operating Limit (MW);
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...
Comment [MPRR101.216]: MPRR101
...
Comment [MPRR191.217]: MPRR191
...
Comment [MPRR191.218]: MPRR191
...
Comment [MPRR191.219]: MPRR191
...
Comment [MPRR191.220]: MPRR191
...
Market Protocols for SPP Integrated Marketplace
(36)(42) Maximum Emergency Capacity Run Time (hours:minutes – Operations Information); (37)(43) Maximum Quick-Start Response Limit (MW, this represents the maximum amount of Supplemental Reserve that may be supplied by an off-line Quick-Start Resource)1; (38)(44) Ramp-Rate-Up (curve, MW/Minute - for use when the Resource is not selected for Regulation-Up and/or Regulation-Down clearing and dispatched in the up direction). Ramp-Rate-Up submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10); (a)
Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Up will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Up in Block 1 will apply back to the actual measured MW.
(b)
Block 1 Ramp Rate Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1.
(c)
Block 1 Ramp Rate Emergency – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1 during an Emergency.
(d)
Breakpoint Limit n – Resource MW output at which Ramp-Rate-Up changes from previous segment values to segment n values.
(e)
Block n Ramp-Rate-Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to the Breakpoint Limit n
(f)
Block n Ramp-Rate-Up Emergency – Rate at which Resource can change output upward in MW/min at output levels greater than the Breakpoint Limit n and less than Breakpoint Limit n+1 during an Emergency.
(39)(45) Ramp-Rate-Down (curve, MW/Minute - for use when the Resource is not selected for Regulation-Up Service and/or Regulation-Down Service clearing and dispatched in the Down direction). Ramp-Rate-Down submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);
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(a)
Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Down will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Down in Block 1 will apply back to the actual measured MW.
(b)
Block 1 Ramp Rate Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1.
(c)
Block 1 Ramp-Rate-Down Emergency – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1 during an Emergency.
(d)
Breakpoint Limit n – Resource MW output at which Ramp-Rate-Down changes from previous segment values to segment n values.
(e)
Block n Ramp-Rate-Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to the Breakpoint Limit n.
(f)
Block n Ramp-Rate-Down Emergency – Rate at which Resource can change output downward in MW/min at output levels greater than the Breakpoint Limit n and less than Breakpoint Limit n+1 during an Emergency
(40)(46) Turn-Around Ramp Rate Factor (a value between 0.01 and 1.00). A Resource’s ramping direction in the next Dispatch Interval is compared against its ramping direction in the current Dispatch Interval. If these two ramping directions are different, then the Turn-Around Ramp Rate Factor is applied to the Dispatch Instruction in the next Dispatch Interval, except in circumstances where the Resource is selected as available to be cleared for Regulation or the Resource is being sent an OOME instruction. The ramping direction in the current Dispatch Interval is based on the actual output at the beginning of the current Dispatch Interval compared to the Dispatch Instruction at the end of the current Dispatch Interval. The direction of the next Dispatch Interval is determined by considering the actual output and ramp capability of the Resource at the time of the solution and comparing it to the next Dispatch Instruction; (41)(47) Regulation Ramp Rate (curve, MW/Minute - for use when the Resource is selected for Regulation-Up Service and/or Regulation Down Service clearing). Regulation Ramp Rate submittal is through a segmented profile as follows. Each profile
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will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10); (a)
Breakpoint Limit 1 – Resource MW output at which segment 1 Regulation Ramp Rate will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Regulation Ramp Rate in Block 1 will apply back to the actual measured MW.
(b)
Block 1 Regulation Ramp Rate – Rate at which a Resource on Automatic Generation Control can change output in the up and down direction in MW/min at output levels greater than or equal to Breakpoint Limit 1.
(c)
Breakpoint Limit n – Resource MW output at which Regulation Ramp Rate changes from previous segment values to segment n values.
(d)
Block n Regulation Ramp Rate – Rate at which Resource on Automatic Generation Control can change output in the up and down direction in MW/min at output levels greater than or equal to the Breakpoint Limit n.
(42)(48) Contingency Reserve Ramp Rate (curve, MW/Minute). Contingency Reserve Ramp Rate submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);
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(a)
Breakpoint Limit 1 – Resource MW output at which segment 1 Contingency Reserve Ramp Rate will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Contingency Reserve Ramp Rate in Block 1 will apply back to the actual measured MW.
(b)
Block 1 Contingency Reserve Ramp Rate – Rate at which a Resource not on Automatic Generation Control can change output in the up direction in MW/min when deploying Contingency Reserve at output levels greater than or equal to Breakpoint Limit 1.
(c)
Breakpoint Limit n – Resource MW output at which Contingency Reserve Ramp Rate changes from previous segment values to segment n values.
(d)
Block n Contingency Reserve Ramp Rate – Rate at which Resource not on Automatic Generation Control can change output in the up direction in MW/min when deploying Contingency Reserve at output levels greater than or equal to the Breakpoint Limit n.
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(49) Resource Status (see Section 4.2.2.2); and (50) Transition State Offer (Only applicable to combined cycle Resource. See Section 4.2.2.5.3(4)); (51) Mitigated Transition State Offer (Only applicable to combined cycle Resource; (43)(52) Transition State Time (Only applicable to combined cycle Resource. See Section 4.2.2.5.3(4)); and (44)(53) JOU Ownership Percent Share (Daily Unit Commitment Parameter)2. 4.2.2.1.1
Resource Ramp Rate Interaction – Energy and Operating Reserve
Comment [MPRR101.225]: MPRR101 awaiting FERC filing Comment [MPRR191.226]: MPRR191 Awaiting implementation Comment [MPRR191.227]: MPRR191 Awaiting implementation
The following ramp rate use assumptions apply to the clearing of Energy and Operating Reserve in the Day-Ahead Market and to the dispatch of Energy and clearing of Operating Reserve in the RTBM. The examples provided below assume that there is no ramp sharing between Energy and Operating Reserve products (see Section 4.1.6 for ramp sharing description). (1)
If a Resource has not been selected as clearable for either Regulation-Up Service and/or Regulation-Down Service, the Resource’s Ramp-Rate-Up is used to clear Energy in the up direction in the Day-Ahead Market and dispatch Energy in the up direction in the RTBM. The combination of that Resource’s Ramp-Rate-Up and Contingency Reserve Ramp Rate is used to clear Contingency Reserve in the Day-Ahead Market and RTBM. In the RTBM, the Turn-Around Ramp Rate Factor is applied to the Resource’s RampRate-Up and the Contingency Reserve Ramp Rate as described in Section 4.2.2.1. (a) For example, assuming in the RTBM that Resource A has a single Ramp-Rate-Up value that is equal to 5 MW/Min, a single Contingency Reserve Ramp Rate value of 8 MW/Min, and the previous RTBM Energy dispatch target was upward, the maximum amount of positive change in Energy clearing/dispatch is 25 MW (5 MW/Min times 5 minutes) and the maximum amount of Contingency Reserve that can clear on that Resource is 80 MW (8 MW/Min times 10 minutes). If we assume that the change in Energy clearing/dispatch on that Resource is 25 MW, then a maximum of 30 MWs of Contingency Reserve could be cleared on that Resource. Alternatively, if we assume that the change in Energy clearing/dispatch
2
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%.
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on that Resource is 0 MW, then a maximum of 80 MW of Contingency Reserve could be cleared on that Resource. (2)
(3)
If a Resource has not been selected as clearable for either Regulation-Up Service and/or Regulation-Down Service, the Resource’s Ramp-Rate-Down is used to clear Energy in the down direction in the Day-Ahead Market and dispatch Energy in the down direction in the RTBM. In the RTBM, the Turn-Around Ramp Rate Factor is applied to the Resource’s Ramp-Rate-Down as described in Section 4.2.2.1. For the Day-Ahead Market, the Resource’s Turn-Around Ramp Rate Factor does not apply (Contingency Reserve Ramp Rate is used). Referring to the example above, any dispatch of Energy in the down direction would allow up to 80 MWs of Contingency Reserve to be cleared on the Resource.
Comment [MPRR102.230]: MPRR102 Awaiting implementation. #ER13-1748
If a Resource has been selected as clearable for Regulation-Up Service and/or Regulation-Down Service, that Resource’s Regulation Ramp Rate is used in both the up and down direction to clear Energy, Regulation-Up Service and/or Regulation-Down Service in the Day-Ahead Market and to dispatch Energy and to clear Regulation-Up Service and/or Regulation-Down Service in the RTBM. That Resource’s Regulation Ramp Rate is used in combination with that Resource’s Contingency Reserve Ramp Rate to clear Contingency Reserve in the Day-Ahead Market and RTBM.
Comment [MPRR102.232]: MPRR102 Awaiting implementation. #ER13-1748
(a) For example, assuming in the RTBM that Resource A has a single Regulation Ramp Rate value that is equal to 4 MW/Min and a Contingency Reserve Ramp Rate of 8 MW/Min, the maximum amount of Regulation-Up Service plus the change in Energy clearing/dispatch is 20 MW (4 MW/Min times 5 minutes) and the maximum amount of Contingency Reserve that can clear on that Resource is 80 MW (8 MW/Min times 10 minutes). If we assume that Regulation-Up Service cleared at 10 MW and the change in Energy clearing/dispatch on that Resource is 10 MW, then a maximum of 40 MWs of Contingency Reserve could be cleared on that Resource. Alternatively, if we assume that the Regulation-Up Service clearing and the change in Energy clearing/dispatch on that Resource is 0 MW, then a maximum of 80 MW of Contingency Reserve could be cleared on that Resource. (4)
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In addition to the Energy clearing/dispatch limits and Operating Reserve clearing limits calculated using applicable ramp rates as described above, Energy clearing/dispatch and Operating Reserve clearing on a Resource is also subject to limitation based upon that Resource’s operational capacity limits.
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Comment [MPRR102.233]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.234]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.235]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.236]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.237]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.238]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.239]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.240]: MPRR102 Awaiting implementation. #ER13-1748
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4.2.2.2
Resource Status
In addition to the Resource Offer parameters specified under Section 4.2.2.1, Market Participants must also specify a Resource Commitment Status and a Resource Dispatch Status as part of the Resource Offer. The Commitment Status selection indicates to SPP how the Resource should be considered for unit commitment and may be specified separately for use in either the DA Market, RTBM or both unless otherwise noted below. For Resources opting for the JOU modeling described under Section 4.2.2.5.4, this value must be submitted by or on behalf of the designated Asset Owner specified during market registration and represents the Commitment Status for the entire Physical JOU Resource. The Dispatch Status selection is submitted for each product and indicates to SPP how the Resource may be dispatched once it is committed. The Dispatch Status may be specified for use in either the DA Market, RTBM or both unless otherwise noted below. If the Resource is on an approved outage as described under Section 4.1.7, the commitment status will default to outage and the Resource will not be available for commitment or dispatch during the outage period. Valid Commitment Status and Dispatch Status selections are: 4.2.2.2.1
Commitment Status
(1)
Market – The Resource is available for SPP economic commitment if it is off-line;
(2)
Self – The Market Participant is committing the Resource and SPP should include it as committed in either the DA Market and/or RUC as specified;
(3)
Reliability – The Resource is off-line and is only available for commitment by SPP if there is an anticipated reliability issue;
(4)
Outage – The Resource is unavailable due to a planned, forced, maintenance or other approved outage. The outage must be documented using the outage scheduler tool described under Section 4.1.7.
(5)
Not Participating – The Resource is otherwise available but has elected not to participate in the DA Market. This option is not available for use for RTBM Offers. (a)
4.2.2.2.2
A Commitment Status of Not Participating does not automatically prevent a Resource from being cleared for offline Supplemental Reserve.
Dispatch Status
There is a Dispatch Status for each product (Energy, Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve) as follows:
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(1)
(2)
Energy (a)
Market – The Resource is available for SPP economic dispatch if committed;
(b)
Not Qualified – The Resource is not qualified to be dispatched to provide Energy. This status is only valid for only a Demand Response Resource or External Dynamic Resource that is not available for Energy dispatch but is available to be deployed cleared for Regulation-Up Service, Regulation-Down Service and/or Contingency Reserve. Use of the Not Qualified Status is required for an External Dynamic Resource in the Eastern Interconnection. Resources with this submitted Energy Dispatch Status are not subject to the charges and credits calculated under Section 4.5.9.19 or the deviation calculations under Sections 4.5.9.10(1)(a.5) and 4.5.9.10(1)(a.7).
Comment [MPRR195.243]: MPRR195 Awaiting FERC filing Comment [MPRR195.244]: MPRR195 Awaiting FERC filing Comment [MPRR102.245]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.246]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.247]: MPRR102 Awaiting implementation. #ER13-1748
Operating Reserve (separate status for each product) (a)
Market – The Resource is available to clear the Operating Reserve product based on submitted Operating Reserve Offers; (i)
(b)
Comment [MPRR195.248]: MPRR195 Awaiting FERC filing
Fixed - Market Participant is fixing the Operating Reserve product clearing at the specified MW level. The minimum level is 100 KW (0.1 MW); (i)
SPP may clear the Operating Reserve product above the fixed MW based on submitted Operating Reserve Offers and may only clear below the fixed MW amount during an Emergency condition.
(ii)
The fixed Operating Reserve MW will be reducedrejected if the fixed MW violates any of the Resource Offer parameters such that the affected Resource Offer parameters are no longer violated.
Comment [MPRR195.249]: MPRR195 Awaiting FERC filing
For Supplemental Reserve, this status may be submitted for Supplemental Qualified Resources only and will apply to either (1) on-line Supplemental Reserve if the Resource has been committed or (2) off-line Supplemental Reserve if the Resource has not been committed.
Comment [MPRR195.251]: MPRR195 Awaiting FERC filing
(iii)
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For Supplemental Reserve, this status is valid for only off-line Supplemental Reserve being supplied from a Quick-Start Resource. For on-line Supplemental Reserve, if Spinning Reserve Dispatch Status is submitted as “Market”, then Dispatch Status for on-line Supplemental Reserve is automatically set to “Market” unless a Dispatch Status of Fixed has been submitted as described under Subsection (b)(iii).
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Comment [MPRR195.252]: MPRR195 Awaiting FERC filing Comment [MPRR195.253]: MPRR195 Awaiting FERC filing
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(c)
4.2.2.3
Not Qualified – The Market Participant may specify that a Resource that was qualified in registration, except as described under (iii) below, to provide one or more Operating Reserve products is no longer qualified to supply that product due to a temporary technical and/or physical limitation or if the Resource is a QuickStart Resource that is a Supplemental Qualified Resource and the Resource has submitted a Commitment Status of Not Participating. (i)
For Supplemental Reserve, this status is applicable for only off-line Supplemental Reserve being supplied from a Quick-Start Resource and may be submitted if a Commitment Status of Not Participating has been submitted in order to prevent the clearing of offline Supplemental Reserve in the Day-Ahead Market.
(ii)
For on-line Supplemental, if Spinning Reserve Dispatch Status is submitted as “Not Qualified”, then Dispatch Status for on-line Supplemental Reserve is automatically set to “Not Qualified”.
(i)(iii)
For Resources that are Spin Qualified Resources that are not Supplemental Qualified Resources, a Supplemental Reserve Dispatch Status of “Not Qualified” must be submitted and will only apply to off-line Supplemental Reserve.
Resource Limit Validation
Resource limits submitted as part of the Resource Offer must pass the following validation rules. Otherwise, the Resource Offer will be rejected. (1)
A Resource’s Minimum Economic Capacity Operating Limit must be greater than or equal to the Resource’s Minimum Emergency Capacity Operating Limit;
(2)
A Resource’s Minimum Regulation Capacity Operating Limit must be greater than or equal to the Resource’s Minimum Economic Capacity Operating Limit;
(3)
A Resource’s Maximum Regulation Capacity Operating Limit must be greater than or equal to the Resource’s Minimum Regulation Capacity Operating Limit;
(4)
A Resource’s Maximum Economic Capacity Operating Limit must be greater than or equal to the Resource’s Maximum Regulation Capacity Operating Limit; and
(5)
A Resource’s Maximum Emergency Capacity Operating Limit must be greater than or equal to the Resource’s Maximum Economic Capacity Operating Limit.
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Exhibit 4-6 shows typical valid limit relationships.
Exhibit 4-6: Resource Limit Relationships MW Maximum Emergency Capacity Operating Limit
Maximum Economic Capacity Operating Limit Maximum Regulation Capacity Operating Limit
Minimum Regulation Capacity Operating Limit
Minimum Emergency Capacity Operating Limit
Minimum Economic Capacity Operating Limit
Off-Line
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4.2.2.4
Resource Commitment Parameter Relationships
When developing the time-related Resource Offer parameters relating to Resource commitment, Market Participants should assume the relationships shown in Exhibit 4-7. (1)
(2)
(3)
(4)
A Resources’ physical minimum run time begins when the Resource is synchronized. After the amount of time defined by physical minimum run time, the Resource can be desynchronized. For SCUC modeling purposes, Minimum Run Time should be submitted as the physical minimum run time described above minus the Sync-To-Min Time and the Min-To-Off Time. A Resource’s physical maximum run time begins when the Resource is synchronized. After the amount of time defined by the physical maximum run time, the Resource must be de-synchronized. For SCUC modeling purposes, Maximum Run Time should be submitted as the physical maximum run time described above minus the Sync-To-Min Time and the Min-To-Off Time. A Resource’s physical minimum down time begins at the point in time when a Resource is de-synchronized. After the amount of time defined by physical minimum down time, following de-synchronization, the Resource can begin synchronizing to the grid again. For SCUC modeling purposes, the submitted Minimum Down Time should be equal to the physical minimum down time described above. Sync-To-Min Time and Min-To-Off Time are automatically added to the submitted Minimum Down Time and that value is used in SCUC. As a part of its Start-Up Offer, a Market Participant must submit a hot, intermediate, and cold start-up price per start. Two temporal parameters that are submitted in the Resource Offer define which of these three prices will be used: (i) Hot-to-Cold Time and (ii) Hotto-Intermediate Time. (a) A Resource’s physical hot-to-intermediate time represents the amount of time between Resource de-synchronization and the next synchronization during which the Resource Hot Start-Up Offer will apply. For SCUC modeling purposes, the submitted Hot-to-Intermediate Time should be equal to the sum of the physical hot-to-intermediate time, the Sync-To-Min Time and the Min-To-Off Time for that Resource. If the Resource is committed in less than the Hot-to-Intermediate Time after its previous De-Commit Time, then the hot start-up price will be used in the Resource Offer. For example, if the physical hot-to-intermediate time is 4 hours, the Sync-To-Min Time is 1 hour and the Min-To-Off Time is 1 hour, the
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(b)
(c)
submitted Hot-To-Intermediate Time should be 6 hours. If the Resource’s DeCommit Time is 10:00 AM, the Hot Start-Up Offer would apply for Resource commitments between 10:00 AM and 4:00 PM. A Resource’s physical hot-to-cold time represents the amount of time between Resource de-synchronization and the next synchronization during which the Resource Cold Start-Up Offer will apply. For SCUC modeling purposes, the submitted Hot-to-Cold Time should be equal to the sum of the physical hot-tocold time, the Sync-To-Min Time and the Min-To-Off Time for that Resource. If the Resource is committed in greater than or equal to the Hot-to-Intermediate Time and less than the amount of time defined by Hot-to-Cold Time after its previous De-Commit Time, then the intermediate start-up price will be used in the Resource Offer. For example, if the physical hot-to-cold time is 8 hours, the Sync-To-Min Time is 1 hour and the Min-To-Off Time is 1 hour, the submitted Hot-To-Cold Time should be 10 hours. If the Resource’s De-Commit Time is 10:00 AM, the Cold Start-Up Offer would apply for Resource commitments after 8:00 PM. If the Resource is committed in greater than or equal to Hot-to-Cold Time after its previous De-Commit Time, then the cold start-up price will be used in the Resource Offer. Using the above Hot-To-Intermediate Time and Hot-To-Cold Time examples, if the Resource’s De-Commit Time 10:00 AM, the Intermediate Start-Up Offer would apply for Resource commitments between 4:00 PM and 8:00 PM.
Exhibit 4-7: Resource Commitment Parameter Relationships
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Commit Time
Minimum Run Time
De-Commit Time
Commit Commit Commit Time Time Time Maximum Run Time
Minimum Down Time
Sync-To Min Time
Min-ToOff Time
Hot-to-Cold Time
Hot-to-Intermediate Time Start-up order issued by SPP
4.2.2.4.1
Start-Up and Shut-Down Times
A Market Participant must submit, as part of a Resource Offer, a Sync-To-Min Time and a MinTo-Off Time. These times will be used by SPP as follows: (1)
To calculate the minimum time between commitments as described under Section 4.2.2.4 above;
(2)
To determine a Day-Ahead Market committed Resource’s eligibility for Start-Up Offer recovery as described under Section 4.5.8.12;
(3)
To determine a RUC committed Resource’s eligibility for Start-Up Offer recovery as described under Section 4.5.9.8; and
(4)
For information purposes to monitor a Resource’s progress during start-up and shut-down mode.
During start-up and shut-down, Market Participants should place their Resource’s in “Manual” Control Status. Based on the submitted Sync-To-Min and Min-To-Off Times, SPP will monitor progress and may contact a Market Participant if the Resource remains in “Manual” Control Status beyond the submitted Sync-To-Min and/or Min-To-Off Times in order to verify the Market Participants intent.
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4.2.2.5
Resource Modeling
The Offer parameters specified under Sections 4.2.2.1 and 4.2.2.2 may be submitted for all Resource types with the understanding that some parameters may be optional for certain types of Resources. Special Resource modeling rules for such Resources are described for specific Resource types as follows: 4.2.2.5.1
Dispatchable Demand Response Resource
The following special modeling rules apply to a DDR Resource. (1)
A DDR Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind-the-meter generator that is dispatchable on a 5-minute basis;
(2)
A DDR Resource is modeled in the Commercial Model the same as any other Resource with a defined Settlement Location and associated PNode or APNode that corresponds to the associated Demand Response Load PNode or APNode definition;
(3)
A DDR Resource is also included in the SPP Network Model as a generator;
(4)
A DDR Resource must have a corresponding Demand Response Load (DRL);
(5)
The Demand Response Load for a DDR Resource must have telemetering installed;
(6)
The Market Participant must submit the real-time value of the Demand Response Load to SPP via SCADA on a 10-second basis;
(7)
A DDR Resource may select one of two options for reporting of the actual DDR Resource output: Submitted Resource Production Option or the Calculated Resource Production Option. (a)
Submitted Resource Production Option - For DDR Resources that are utilizing strictly behind-the-meter Generation to provide the response or DDR Resources where the retail provider is offering the Resource under an agreed upon Retail Tariff provision that includes near real-time measurement and verification terms, the amount of the response provided may be sent directly to SPP via ICCP and will represent the real-time resource production. (i)
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The Market Participant must determine the real-time resource production and submit the value to SPP via SCADA on a 10-second basis.
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(ii) (b)
After-the-fact integrated meter values will be submitted directly by the Meter Agent for the DDR Resource.
Calculated Resource Production Option - SPP will calculate the real-time resource output for operational dispatch and actual Resource output for settlements. (i)
(ii)
Market Participants must submit Aa baseline hourly load profile must be submitted for the DRL prior to the hour for which the DDR Resource has been committed that represents the forecast consumption for the hour assuming no load reduction. Such hourly baseline shall be submitted and calculated in accordance with Attachment AE to the Tariff. In addition, SPP may adjust the submitted hourly baseline as described in Attachment AE to the Tariff. At the start of the Operating Hour for which a DDR Resource is committed, SPP will take a snapshot of the SCADA demand MW consumption of the Demand Response Load.
(iii) The Real-Time Resource output for operational dispatch in the Dispatch Interval will be calculated as the maximum of zero or the difference between (1) and (2) below. If the baseline hourly load profile of the DRL was not submitted, the snapshot of the DRL SCADA will be used for the value in (1).
Comment [MPRR144.257]: MPRR144 Awaiting FERC filing
Comment [MPRR144.258]: MPRR144 Awaiting FERC filing
Comment [MPRR144.259]: MPRR144 Awaiting FERC filing
Comment [MPRR144.260]: MPRR144 Awaiting FERC filing
(1) the The Mminimum of the baseline hourly load profile of the DRL submitted under (i) above (Hourly Load Profile of the DRL, or the Ssnapshot of the DRL SCADA demand MW consumption described in (ii) above. interval prior to Deployment) and
Comment [MPRR144.261]: MPRR144 Awaiting FERC filing
(2) the The Real-Time SCADA value for the DRL.
Comment [MPRR144.263]: MPRR144 Awaiting FERC filing
(iii)(iv) The actual Resource output for use in settlements in the Dispatch Interval will be calculated as described under Section 4.5.9.1. Exhibit 4-8 shows how a DDR Resource’s Real-Time output for operational dispatch would be calculated within an Operating Hour using the Calculated Resource Production Option. Exhibit 4-8: Calculated DDR Output
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Interval
1 2 3 4 5 6 7 8 9 10 11 12
4.2.2.5.2
Net Telemetered Value of DRL (1) 38 40 42 33 32 30 22 24 16 25 23 30
Hourly Load Profile (2)
Telemetered Value prior to Deployment (3)
DDR Resource Production (4) = Min(2,3) – (1)
70 70 70 70 70 70 70 70 70 70 70 70
68 68 68 68 68 68 68 68 68 68 68 68
30 28 26 35 36 38 46 44 52 43 45 38
Block Demand Response Resource
The following special modeling rules apply to a BDR Resource. (1)
A BDR Resource is a special type of Resource created to model demand reduction that is not dispatchable on a 5-minute basis but can be committed and dispatched in hourly blocks;
(2)
A BDR Resource is modeled in the Commercial Model the same as any other Resource with a defined Settlement Location and associated PNode or APNode that corresponds to the associated Demand Response Load PNode or APNode definition;
(3)
A BDR Resource is not included in the SPP Network Model as a Resource;
(4)
A BDR Resource must also have a corresponding Demand Response Load (DRL);
(5)
The DRL must have telemetering installed and have the real-time Load consumption at the DRL sent to SPP SCADA via ICCP on a 10-second scan rate;
(6)
All BDR Resources will use the Calculated Resource Production Option to determine the amount of Real-Time Resource Production and Actual Resource Production. Therefore, the following information requirements apply: (a)
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Market Participants must submit An a baseline hourly load profile must be submitted for the DRL prior to the hour for which the BDR Resource has been committed that represents the forecast DRL consumption for the hour assuming no load reduction. Such hourly baseline shall be submitted and calculated in
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accordance with Attachment AE to the Tariff. In addition, SPP may adjust the submitted hourly baseline as described in Attachment AE to the Tariff.; (b)
(c)
The interval prior to the first interval for which a BDR Resource is committed and deployed, SPP will take a snapshot of the SCADAState Estimator demand MW consumption of the DRL; The Real-Time Resource output for operational dispatch in the Dispatch Interval will be calculated as the maximum of zero or the difference between (i) and (ii) below. If the baseline hourly load profile of the DRL was not submitted, the snapshot of the DRL SCADA will be used for the value in (i) below. i. 1) Tthe Mminimum of the baseline (Hourly hourly Load load Profile profile of the DRL as submitted under (a) above or the, Snapshot snapshot of the DRL SCADA demand MW consumption as described under (b) above interval prior to Deployment) and
(c)(d) The actual Resource output for use in settlements in the Dispatch Interval will be calculated as described under Section 4.5.9.1. There are also operational differences that apply to BDR Resources as follows:
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(a)
A BDR Resource will only use two operating limits: Minimum Economic Capacity Operating Limit and Maximum Economic Capacity Operating Limit. The Minimum Economic Capacity Operating Limit represents the MW amount of demand reduction associated with the first price block identified in the Energy Offer Curve. The Maximum Economic Capacity Limit will represent the maximum amount of demand reduction that can be achieved.
(b)
In the RTBM, if the BDR Resource is committed and dispatched in the DA Market or RUC, the BDR Resource Minimum Economic Capacity Operating Limit will be increased to match the dispatched amount and either Spinning Reserve or Supplemental Reserve will be allowed to clear above minimum output if the BDR Resource is a Spin Qualified Resource. Spinning Reserve clearing will be based upon submitted Ramp-Rate Up curve for the BDR Resource, the submitted Spinning Reserve Offer, the Supplemental Reserve Offer and the BDR Resource’s Maximum Economic Capacity Operating Limit.
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Comment [MPRR144.269]: MPRR144 Awaiting FERC filing Comment [MPRR144.270]: MPRR144 Awaiting FERC filing Comment [MPRR144.271]: MPRR144 Awaiting FERC filing Comment [MPRR144.272]: MPRR144 Awaiting FERC filing
i.ii. 2) tThe Real-Time SCADA value for the DRL.
(7)
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(c)
4.2.2.5.3
Other than the restriction on submittal of operating limits as stated in (a) above, a BDR Resource may submit Offers that include any of the Offer parameters listed under Sections 4.2.2.1 and 4.2.2.2.
Combined Cycle Resource
Combined Cycle cycle modeling will be accommodated as follows for Resources registered as a Combined combined Cycle cycle Resource. Market Participants that jointly own a Combined combined Cycle 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 combined Cycle cycle Resource. Market Participants will have to select from one of the threefour following options regarding submitting Resource Offers for their registered Combined combined Cycle cycle Resources which will need to be declared during asset registration as described under Section 6.1.7: (a)(1) A Resource Offer may be submitted for a single aggregate Combined combined Cycle 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 combined Cycle cycle Resource will be committed, dispatched and settled the same as any other Resource; or
Comment [MPRR101.275]: MPRR101 awaiting FERC filing Comment [MPRR101.276]: MPRR101 awaiting FERC filing Comment [MPRR101.277]: MPRR101 awaiting FERC filing Comment [MPRR101.278]: MPRR101 awaiting FERC filing Comment [MPRR101.279]: MPRR101 awaiting FERC filing Comment [MPRR101.280]: MPRR101 awaiting FERC filing Formatted: Outline numbered + Level: 1 + Numbering Style: 1, 2, 3, … + Start at: 1 + Alignment: Left + Aligned at: 0.13" + Indent at: 0.5" Comment [MPRR101.281]: MPRR101 awaiting FERC filing Comment [MPRR101.282]: MPRR101 awaiting FERC filing
(b)(2) A Resource Offer may be submitted for each Combined combined Cycle 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
Comment [MPRR101.283]: MPRR101 awaiting FERC filing
(3)
Comment [MPRR101.284]: MPRR101 awaiting FERC filing
(4)
A Resource Offer may be submitted for each pseudo Combined combined Cycle cycle Resource, where each pseudo Combined combined Cycle cycle Resource will represent the combination of one combustion turbine and a portion of the steam turbine. Under this option, each pseudo Combined combined Cycle cycle Resource must be capable of being committed and dispatched independently the same as any other Resource and each pseudo Combined combined Cycle cycle Resource will be settled the same as any other Resource. A Resource Offer may be submitted for each combined cycle Resource configuration, where each configuration is defined during market registration.
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(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:
(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
(c)
Transition State Offers and Transition State Times are only valid for moving from one configuration to another once the Resource becomes a Synchronized Resource.
(d)
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.
(e)
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.
(f)
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.
(g)
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-
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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. (a)(h) 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. 4.2.2.5.4
Jointly Owned Unit
Jointly Owned Unit (JOU) owners may elect to model their individual ownership shares as separate Resources using either the Individual Resource Option or the Combined Resource Option as specified during market registration as described under Section 6.1.6. Otherwise, the Resource is modeled like any other single Resource with an associated single Asset Owner. Resource offers may be submitted for each Asset Owner’s JOU ownership (“JOU Share Resource”) the same as any other Resource subject to the following Resource Offer validation rules and exceptions. (1)
(2)
As part of market registration, the following offer parameters representing the ownership and physical characteristics of the entire JOU (“Physical JOU Resource”) must be submitted either by or on behalf of the Asset Owner identified at registration (“designated Asset Owner”): (a)
JOU maximum physical capacity operating limit;
(b)
JOU minimum physical capacity operating limit;
(c)
maximum physical 10-minute response from an off-line state (if a Quick-Start Resource); and
(d)
JOU Ownership Percent Share by Asset Owner (Default value. May be updated as part of DA Market and RTBM Offer. Only required if registered under Combined Resource Option).
The following Offer parameters as submitted by or on behalf of each Asset Owner for its JOU Share Resource must meet the following criteria in order to be accepted as valid offers, otherwise, all Offers related to the Physical JOU Resource will revert to the last valid offer;
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(a)
The sum of the Maximum Emergency Capacity Operating Limits of each JOU Share Resource associated with the Physical JOU Resource must be less than or equal to the Physical JOU Resource maximum physical capacity operating limit; and
(b)
The sum of the Minimum Emergency Capacity Operating Limits of each JOU Share Resource associated with the Physical JOU Resource must be greater than or equal to the Physical JOU Resource minimum physical capacity operating limit;
(3)
Commitment of individual JOU Share Resources that have registered under the Individual Resource Option will be evaluated by SCUC based on the individually submitted Offers for each JOU Share Resource;
(4)
Commitment of JOU Share Resources that have registered under the Combined Resource option will be evaluated by SCUC based on a combination of the individually submitted Offers for each JOU Share Resource and the Offer parameters submitted by or on behalf of the designated Asset Owner that apply to the entire Physical JOU Resource (see Section 4.2.2.1 for footnoted parameters to be submitted by or on behalf of the designated Asset Owner and Section 4.2.2.2 regarding Commitment Status) given the additional constraint that if one of the JOU Resources is committed, all JOU Share Resources associated with the Physical JOU Resource must be committed. This rule also applies to clearing of Supplemental Reserve from off-line Quick-Start Resources. Prior to evaluation by SCUC, each JOU Share Resource associated with the Physical JOU Resource is assigned the following unit commitment parameters as submitted by or on behalf of the designated Asset Owner:
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(a)
The Start-Up Offer of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated by multiplying the Start-Up Offer submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share and this value will be used for make-whole-payment calculation purposes;
(b)
The Mitigated Start-Up Offer of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated by multiplying the Mitigated Start-Up Offer submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share and this value will be used for makewhole-payment calculation purposes;
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(c)
The No-Load Offer of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated by multiplying the No-Load Offer submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share and this value will be used for make-whole-payment calculation purposes;
(d)
The Mitigated No-Load Offer of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated by multiplying the Mitigated No-Load Offer submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share and this value will be used for makewhole-payment calculation purposes;
(e)
The Sync-To-Min Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Sync-To-Min Time submitted for the Physical JOU Resource;
(f)
The Min-To-Off Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Min-To-Off Time submitted for the Physical JOU Resource;
(g)
The Start-Up Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Start-Up Time submitted for the Physical JOU Resource;
(h)
The Hot to Intermediate Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Hot to Intermediate Time submitted for the Physical JOU Resource;
(i)
The Hot to Cold Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Hot to Cold Time submitted for the Physical JOU Resource;
(j)
The Maximum Daily Starts of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Maximum Daily Starts submitted for the Physical JOU Resource;
(k)
The Maximum Weekly Starts of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Maximum Weekly Starts submitted for the Physical JOU Resource;
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(l)
The Maximum Daily Energy of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated by multiplying the Maximum Daily Energy submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share;
(m) The Minimum Run Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Minimum Run Time submitted for the Physical JOU Resource;
(5)
(n)
The Minimum Down Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Minimum Down Time submitted for the Physical JOU Resource;
(o)
The Maximum Run Time of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Maximum Run Time submitted for the Physical JOU Resource;
(p)
The Maximum Quick-Start Response Limit of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated by multiplying the Maximum Quick-Start Response Limit submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share; and
(q)
The Commitment Status of each Asset Owner’s JOU Share Resource associated with the Physical JOU Resource is set equal to the Commitment Status submitted for the Physical JOU Resource.
If committed, each JOU Share Resource will be considered separately for the purposes of dispatch, Operating Reserve clearing and settlement and the Physical JOU Resource will receive an aggregate Setpoint Instruction for the purposes of Energy and Operating Reserve deployment;
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(a)
If a JOU Share Resource is committed by SPP in the DA Market, that JOU Share Resource is cleared for Energy based on the submitted Energy Offer Curve and Ramp Rate and is cleared for Operating Reserve based on the submitted Operating Reserve Offers and Ramp Rate;
(b)
Each JOU Share Resource committed by SPP in the DA Market is eligible to receive a DA Market make-whole payment under the same eligibility rules as any other Resource as described under Section 4.5.8.12;
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(c)
In the RTBM, each JOU Share Resource is dispatched for Energy based on the submitted Energy Offer Curve, Ramp-Rate-Up and Ramp-Rate-Down and is cleared for Operating Reserve based on the submitted Operating Reserve Offers, Ramp-Rate-Up and Ramp-Rate-Down. SPP sends to each Asset Owner it’s independent Dispatch Instruction, Setpoint Instruction, and cleared amount(s) of Operating Reserve for its individual JOU Share Resource. SPP will also, for information purposes, send to the JOU Operating Owner each Asset Owner’s independent Dispatch Instructions and the sum of these independent Dispatch Instructions, and each Asset Owner’s independent Setpoint Instructions and the sum of the Asset Owner’s independent Setpoint Instructions The SPP provided Setpoint Instruction(s) for each JOU Share and the actual output submitted for each JOU Asset Owner(s) as submitted by respective Meter Agent(s) shall be used for monitoring according to (ii) below and for settlements.
(6)
(i)
If a JOU Share Resource is committed by SPP in any RUC process, that individual JOU Share Resource is eligible to receive a RUC make-whole payment under the same eligibility rules as any other Resource as described under Section 4.5.9.8.
(ii)
Each JOU Share Resource will be subject to charges associated with Uninstructed Resource Deviation that exceeds the JOU Share Resource Operating Tolerance as described under Sections 4.5.9.8 and 4.5.9.10, Regulation deployment failure charges as described under Section 4.5.9.15 and Contingency Reserve deployment failure charges as described under Section 4.5.9.17, under the same eligibility rules as any other Resource.
The Meter Agent(s) assigned to the Physical JOU Resource must account for all physical Energy produced and properly reflect this Energy in each individual JOU Share Resource meter data submittal.
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
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(2)
(3)
(4)
(5)
Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected; For DVERs with an Emergency Maximum Capacity Operating Limit of less than 200MW, 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 20% of the DVER’s Emergency Maximum Capacity Operating Limit; 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; 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;
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
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(c)
SPP’s output forecast for that DVER if the Emergency Maximum Capacity Operating Limit: (i) Was not submitted in the DVER Offer; or (ii) Was not updated in the Offer during the Operating Hour prior to the Operating Hour in which the Resource limit would apply but before the lead time described in Section 4.2.2; or (iii) Exceeds the maximum physical rating of the DVER that was submitted at market registration.
Such maximum operating limit continues to be set as described above until such time that the Resource’s Dispatch Instruction is equal to the maximum operating limit, after which, the DVER’s maximum operating limit is calculated as described under (4)(a) above. 4.2.2.5.6
Non-Dispatchable Variable Energy Resources
The following rules apply to Resources registered as Non-Dispatchable Variable Energy Resources (“NDVER”): (1) The Minimum Emergency Capacity Operating Limit, Minimum Economic Operating Capacity Limit and Minimum Normal Capacity Operating Limit submitted as part of the Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected; (2) For the RUC processes, the maximum operating limit shall be as submitted in the Resource Offer, except that, for wind powered NDVERs, the lesser of the Resource Offer or SPP’s wind output forecast for that Resource shall be used to set the maximum operating limit; (a) NDVERs for which SPP is calculating an output forecast are not eligible to receive RUC make whole payments as described under Section 4.5.9.8. (3)
For the Real-Time Balancing Market, the Resource’s Energy Offer Curve shall not apply and offer prices shall be assumed equal to zero for the purposes of calculating production costs relating to RUC make-whole payments and cost allocation thereof under Sections 4.5.9.8 and 4.5.9.10. The Resource must operate within Setpoint Instructions. The Setpoint Instructions will be an echo of actual SCADA output as updated every ten seconds. For NDVERs, the Control Status Mode is not required. If it is not provided, it will be set to Manual
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4.2.2.5.7
External Dynamic Resource
Any external Resource, not pseudo-tied, or external fleet of resources that will be participating in the Energy and Operating Reserve Markets will be modeled and registered as an External Dynamic Resource (“EDR”). EDRs in the Eastern Interconnection are not permitted to offer Energy but may elect to fix their Energy output through the use of a Dynamic Schedule. EDRs associated with DC Ties may only be modeled and registered as an EDR if the DC tie is continuously dispatchable across zero. Dead bands are not supported. The following specific rules pertain to EDRs: (1)
An EDR may represent an external entity’s resource or fleet of resources: (a)
Within the Eastern Interconnect for the offering of Operating Reserve only or;
(b)
Offer Energy and/or Operating Reserve sourcing from other Interconnections using a DC tie;
(2)
The EDR will be assigned to the Reserve Zone within SPP, that is represented by the PNode or APNode associated with the EDR;
(3)
For Market Participants with EDRs offering Energy, Regulation-Up Service and/or Contingency Reserve into the SPP Integrated Marketplace from sources external to the SPP BA, a Firm Transmission Service Reservation is required from source BA to the SPP BA, which must be used for scheduling a Dynamic Schedule representing the services provided by the EDR.
Comment [MPRR102.289]: MPRR102 Awaiting implementation. #ER13-1748
For Market Participants with EDRs offering Regulation-Down Service into the SPP Integrated Marketplace from sources external to the SPP BA, a Firm Transmission Service Reservation is required from the SPP BA to the sink BA which must be used for scheduling a Dynamic Schedule representing the Regulation-Down service Service provided by the EDR unless the EDR has an associated Dynamic Schedule for Energy in an amount greater than or equal to the amount of Regulation-Down service Service provided as described under (5) below. The linkage of the EDR to the associated Dynamic Schedule must be specified during market registration as described under Section 6.1.10.1;
Comment [MPRR102.290]: MPRR102 Awaiting implementation. #ER13-1748
(4)
A Market Participant must use the following commit status for a EDR: (a)
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For the DA Market, a Market Participant may select “Self”, “Not Participating” or “Outage” or;
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(b) (5)
A Market Participant must offer an EDR that is not associated with a DC tie with an energy dispatch status of “Not-Qualified”; (a)
(6)
(7)
For the RTBM, a Market Participant must select “Self”, if available, otherwise “Outage”
An EDR not associated with a DC Tie may fix an energy clearing amount utilizing a Dynamic Schedule. Below are the following rules that apply: (i)
The MW profile amount submitted via the dynamic schedule will be treated like a fixed interchange schedule by the DA Market and RTBM.
(ii)
The maximum amount of Regulation-Down Service allowed for the EDR to offer will be limited to the fixed energy amount associated with the dynamic schedule.
The following resource offer parameters as described under Section 4.2.2.1 are not valid for an EDR that is not associated with a DC Tie: (a) all offer parameters labeled as Daily Unit Commitment Parameter or Hourly Unit Commitment Parameter; (b) Energy Offer Curve, Ramp-Rate-Up and Ramp-Rate-Down. For an EDR associated with a DC tie, the same restrictions apply except that if this EDR is available for Energy dispatch, it must submit an Energy Offer Curve, Ramp-Rate-Up and Ramp Rate Down;
Comment [MPRR102.293]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR191.294]: MPRR191 Awaiting implementation Comment [MPRR191.295]: MPRR191 Awaiting implementation
Market Participants must submit an Eco Min and Eco Max for the EDRs. These limits will be used for the Normal Min and Normal Max, Emergency Min and Emergency Max and Regulation Min and Regulation Max; (a) If the Dynamic Schedule associated with the EDR with a fixed energy amount is curtailed, the MP must update the Eco Max for the EDR.
(8)
If the EDR offers with a minimum less than zero, then a Dynamic Schedule must be created sourcing from the SPP BA to the Sink BA. Similarly, if the EDR offers with a maximum greater than zero, then a Dynamic Schedule must be created from the Source BA to the SPP BA.
(9)
The TSR profile on the Dynamic Schedule must be greater than or equal to the maximum operating limits of the EDR. (i)
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If the EDR minimum is less than zero, then the TSR profile must be equal to or greater than to the absolute value of the minimum. (The EDR is cleared for Regulation Down Service in the direction of the external BA).
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(ii)
If the EDR maximum is greater than zero, then the TSR profile must be equal to or greater than the maximum. (The EDR is cleared for Regulation-Up Service and/or Regulation-Down Service in the direction of the SPP BA).
(10) The EDR Dynamic Schedule will be excluded for settlement purposes. The host Market Participant is responsible for updating the profile on the Dynamic Schedule to comply with NERC standard INT-004-2; (11) The Market Participant will send a Control Status and the MW response of the EDR via ICCP the same as any other Resource; and (12) All settlements will be based on the actual output value of the EDR as submitted by the MP’s Meter Agent, the same as any other Resource. 4.2.2.5.8
Resources Pseudo-Tied Out of the SPP BAA
The following rules apply to Resources physically located within the SPP BAA that have pseudo-tied out of the SPP BA: (1) The Resource must be registered as described under Section 6.1.10.2; (2) For the DA Market, RUC, and RTBM processes, none of the requirements and options relating to Resource Offer parameters described under Section 4.2.2.1 shall apply (3) For the RTBM, the Resource output will be included in the current RTBM analysis as an echo of actual output, and the Resource will be charged for marginal losses and congestion costs between the Resource PNode and the applicable External Interface Settlement Location as described under Sections 4.5.9.26 and 4.5.9.27. (4) If the pseudo-tie associated with the Resource becomes reduced or unavailable due to reliability issues within the SPP Balancing Authority or associated external Balancing Authority, the Resource associated with the pseudo-tie must immediately limit its output to the available pseudo-tie capability after receiving notification from the affected Balancing Authority of the reduced capability. A Market Participant shall not generate any energy in excess of the pseudo-tie capability after receiving such notification and shall not be compensated for such energy in the Integrated Marketplace.
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4.2.2.6
Virtual Energy Offers
Virtual Energy Offers are supported in the DA Market only. Virtual Energy Offers are purely financial, only apply to Energy and are not associated with a physical Resource asset. The following rules apply to Virtual Energy Offer submittal. (1)
A Virtual Energy Offer can be submitted by a Market Participant at any Settlement Location;
(2)
A Market Participant may submit a single Virtual Energy Offer for each Asset Owner at any Settlement Location for a particular Hour in the form of a Virtual Energy Offer Curve (MW, $/MWh, up to ten (10) price/quantity pairs and slope or block option). The submitted MW values must be increasing and the submitted $/MWh values must be monotonically non-decreasing. A Virtual Energy Offer will clear when the price at the applicable Settlement Location is greater than or equal to the specified curve price for that Operating Hour. The highest MW quantity submitted in the Virtual Energy Offer Curve representing the maximum MW amount that can be cleared. The minimum MW amount that can be cleared is equal to zero; (a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs. (b) If the LMP is less than the lowest $/MWh submitted in the curve, then the cleared MWs will be zero. (c) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-9 illustrates Virtual Energy Offer curves developed from submitted price/MWh pairs for both the slope and block options.
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Exhibit 4-9: Virtual Energy Offer Curve Development Virtual Energy Offer Curve Submitted Data 90.00
$/MWh 20.00 40.00 60.00 80.00
80.00 70.00
BlockOption Option Block
60.00 $/MWh
MW 100 200 400 500
50.00 40.00
Slope Option Option Slope
30.00 20.00 10.00 0.00 0
100
200
300
400
500
600
MW
(3)
Each Virtual Energy Offer must specify a start and stop Hour within the applicable Operating Day;
(4)
Virtual Energy Offers are subject to a transaction fee as described under Section 4.5.8.20.
4.2.2.7
Import Interchange Transaction Offers
Market Participants may submit Offers to sell Energy coming from outside of the SPP Balancing Authority Area for use in the DA Market and/or RTBM using Market Import Service as defined in the Interchange Scheduling Reference Manual. A Market Participant must reserve Market Import Service prior to submittal of the Offer in accordance with the procedures specified in the SPP OATT Business Practices. The following rules apply to Import Interchange Transaction Offer submittal. Additional detail regarding scheduling of Import Interchange Transactions can be found in the Interchange Scheduling Reference Manual. (1)
The MW amount of Import Interchange Transactions will be limited on a Dispatch Interval basis by the amount of SPP system ramping capability available. Market Participants must use the SPP ramp reservation system as described under Section 4.2.5 to ensure there is sufficient ramp to accommodate their transaction;
(2)
Import Interchange Transaction Offers will be submitted via E-tag and Real-Time Operations Scheduling System (RTOSS) as described under the SPP OATT Business
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Practices. Additional fields will be available through E-tagging to identify transaction type and to submit price-based information as necessary; (3)
Three types of Import Interchange Transaction Offers will be supported: Fixed, Dispatchable and Up-To-Transmission Usage Charge or ‘Up-to-TUC”.
4.2.3
(a)
A Fixed Offer is a specified MW that will be cleared regardless of the price at the External Interface Settlement Location (Source GCA specified on E-tag). If the Fixed Import Interchange Transaction is submitted for use in the DA Market, it will be cleared in the DA Market and automatically roll forward as a fixed schedule for use in RUC and the RTBM. If specified for use in the RTBM only, the Fixed Import Interchange Transaction will be considered a fixed schedule for the RUC processes and RTBM.
(b)
A Dispatchable Offer specifies both a MW amount and a minimum $/MWh price that the Market Participant must be paid if the transaction clears the DA Market. Dispatchable Offers are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a fixed schedule for use in RUC and the RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
(c)
An Up-To-TUC Offer specifies both a MW amount and the maximum amount of congestion cost and marginal loss cost, in $/MWh, between the specified E-tag Source and Sink Settlement Location the Market Participant is willing to pay if the transaction clears the DA Market. Up-To-TUC Offers are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a fixed schedule for use in the RUC and RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
Bid Submittal
Beginning seven (7) days prior to the Operating Day, Market Participants are expected to begin submitting Demand Bids and Virtual Energy Bids for the purchase of Energy in the DA Market and/or Export Interchange Transaction Bids for the purchase of Energy in the DA Market or RTBM. The following business rules apply to Bid submittal: (1)
Bid submittal other than for a fixed Export Interchange Transaction Bid does not apply to any of the RUC processes or the RTBM;
(2)
Submitted Bids do not roll forward hour to hour;
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(3)
(4) (5)
Demand Bids may only be submitted at Load Settlement Locations, Export Interchange Transaction Bids may only be submitted at External Interface Settlement Locations; Virtual Energy Bids may be submitted at any Settlement Location, including a Hub; Bid submittal for use in the DA Market is voluntary. Bid submittal associated with a load pseudo-tied out of the SPP BA is not permitted.
4.2.3.1
Demand Bids
Only Market Participants with registered load assets may submit Demand Bids for use in the DA Market. Demand Bids are associated with physical load assets. The following rules apply to Demand Bid submittal: (1)
A Market Participant can only submit Demand Bids for the registered load Settlement Location of the Asset Owner(s);
(2)
A Market Participant is not permitted to submit a Demand Bid for a load asset pseudotied out of the SPP BA.
(3)
Two types of Demand Bids will be supported: Fixed and Price Sensitive; (a)
A Fixed Demand Bid is a specified MW that will be cleared in the DA Market regardless of the price at the Load Settlement Location based on the start and stop time submitted for the applicable Operating Day.
(b)
A price sensitive Demand Bid is specified as a Demand Bid Curve (MW, $/MWh, up to 10 price/quantity pairs and slope or block option). The submitted MW values must be increasing and the submitted $/MWh values must be monotonically non-increasing. A price sensitive Demand Bid will clear when the price at the applicable Load Settlement Location is less than or equal to the specified curve price for that Operating Hour. The maximum MW amount that can be cleared is equal to the highest MW quantity submitted in the Demand Bid Curve. The minimum MW amount that can be cleared is equal to zero. The price of all MWhs below the lowest MW amount submitted is equal to the first pricing point price. (i)
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Block and slope pairs may not coexist. The price sensitive Demand Bid in effect for any given period of time must be comprised of all block or all slope price/quantity pairs.
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(ii)
If the LMP is greater than the highest $/MWh submitted in the curve, then the cleared MWs will be zero.
(iii)
Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-10 illustrates Demand Bid Curves developed from submitted price/MWh pairs for both the slope and block options. Exhibit 4-10: Demand Bid Curve Development
Demand Bid Curve Submitted Data 140.00
$/MW 120.00 100.00 80.00 60.00 40.00 20.00
120.00
Slope Option 100.00 $/MW
MW 50 100 200 400 500 550
80.00 60.00 40.00
Block Option
20.00
0.00 0
100
200
300
400
500
600
MW
4.2.3.2
Virtual Energy Bids
Virtual Energy Bids are supported in the DA Market only. Virtual Energy Bids are purely financial in nature, only apply to Energy and are not associated with a physical Load asset. The follow rules apply to Virtual Energy Bid submittal. (1)
A Virtual Energy Bid can be submitted at any Settlement Location;
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(2)
A Market Participant may submit a single Virtual Energy Bid for each Asset Owner at any Settlement Location for a particular Hour in the form of a Virtual Energy Bid Curve (MW, $/MWh, up to 10 price/quantity pairs and slope or block option). The submitted MW values must be increasing and the submitted $/MWh values must be monotonically non-increasing. A Virtual Energy Bid will clear when the price at the applicable Settlement Location is less than or equal to the specified curve price for that Operating Hour. The maximum MW amount that can be cleared is equal to the highest MW quantity submitted in the Virtual Energy Bid Curve. The minimum MW amount that can be cleared is equal to zero. The price of all MWhs below the lowest MW amount submitted is equal to the first pricing point price; (a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs. (b) If the LMP is greater than the highest $/MWh submitted in the curve, then the cleared MWs will be zero. (c) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-11 illustrates Virtual Energy Bid Curves developed from submitted price/MWh pairs for both the slope and block options.
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Exhibit 4-11: Virtual Energy Bid Curve Development Virtual Energy Bid Curve Submitted Data 140.00
$/MWh 120.00 100.00 80.00 60.00 40.00 20.00
120.00
Slope Option
100.00 $/MWh
MW 50 100 200 400 500 550
80.00 60.00 40.00
Block Option 20.00
0.00 0
100
200
300
400
500
600
MW
(3)
Each Virtual Energy Bid must specify a start and stop Hour within the applicable Operating Day;
(4)
Virtual Energy Bids are subject to a transaction fee as described under Section 4.5.8.20.
4.2.3.3
Export Interchange Transaction Bids
Market Participants may submit bids to purchase Energy from the DA Market for sale outside of the SPP Balancing Authority Area. A Market Participant must reserve transmission service prior to submittal of the Bid in accordance with the procedures specified in the SPP OATT Business Practices. Additional detail regarding scheduling of Export Interchange Transactions can be found in the Interchange Scheduling Reference Manual. The following rules apply to Export Interchange Transaction Bid submittal. (1)
The MW amount of Export Interchange Transactions will be limited on a Dispatch Interval basis by the amount of SPP system ramping capability available. Market Participants must use the SPP ramp reservation system as described under Section 4.2.5 to ensure there is sufficient ramp to accommodate their transaction;
(2)
Export Interchange Transaction Bids will be submitted via E-tag and RTOSS. Additional fields will be available through E-tagging to submit price-based information as necessary;
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(3)
(4)
Three types of Export Interchange Transaction Bids will be supported: Dispatchable and Up-To-TUC;
Fixed,
(a)
A Fixed Bid is a specified MW that will be cleared regardless of the price at the External Interface Settlement Location (Sink LCA specified on E-tag). If the Fixed Export Interchange Transaction is submitted for use in the DA Market, it will be cleared in the DA Market and automatically roll forward as a fixed schedule for use in RUC and the RTBM. If specified for use in the RTBM only, the Fixed Export Interchange Transaction will be considered a fixed schedule for the RUC processes and RTBM.
(b)
A Dispatchable Bid specifies both a MW amount and a maximum $/MWh price that the Market Participant is willing to pay if the transaction clears the DA Market. Dispatchable Bids are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a Fixed schedule for use in RUC and the RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
(c)
An Up-To-TUC Bid specifies both a MW amount and the maximum amount of congestion cost and marginal loss cost, in $/MWh, between the specified E-tag Source and Sink Settlement Location the Market Participant is willing to pay if the transaction clears the DA Market. Up-To-TUC Bids are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a Fixed schedule for use in the RUC and RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
Export Interchange Transaction Bids are eligible to supply Supplemental Reserve subject to meeting the follow eligibility requirements:
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(a)
The Market Participant must notify SPP as part of their E-Tag of their intent to supply Supplemental Reserve with an Export Interchange Transaction Bid no later than 5:00 AM Day-Ahead;
(b)
The Export Interchange Transaction Bid must be fixed and submitted for use in the DA Market;
(c)
The Export Interchange Transaction must be fully recallable within a 10-minute period for the amount of Supplemental Reserve specified;
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4.2.4
(d)
An Export Interchange Transaction Bid may reduce the Market Participant’s Supplemental Reserve obligation. The reduction to Market Participant’s Supplemental Reserve obligation will be the lesser of (i) the reduction in the system requirement based on the delivery of reserve energy, provided by the curtailment of the export schedule as determined by SPP; or (ii) the Market Participant’s Supplemental Reserve obligation. The reduction, if applied, will be proportional to the Market Participant’s zonal Supplemental Reserve obligation;
(e)
Supplemental Reserve supplied by an Export Interchange Transaction in excess of the Market Participant’s Supplemental Reserve obligation within the Reserve Zone will not be eligible for payment.
(f)
Provision of Supplemental Reserve from an Export Interchange Transaction Bid is limited to Export Interchange Transactions associated to DC tie-lines.
Through Interchange Transactions
Energy scheduled through the SPP Balancing Authority Area will be settled in the DA Market, RTBM or both. A Market Participant must reserve transmission service prior to submittal of the schedule in accordance with the procedures specified in the SPP OATT Business Practices in an amount sufficient to cover the request. Additional detail regarding scheduling of Through Interchange Transactions can be found in the Interchange Scheduling Reference Manual. (1)
Through Interchange Transactions will be submitted via E-tag and RTOSS;
(2)
Two types of Through Interchange Transactions will be supported: Fixed and Up-ToTUC;
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(a)
A Fixed Through Interchange Transaction is a specified MW that will be cleared regardless of the price at either of the External Interface Settlement Locations (Source GCA and Sink LCA specified on E-Tag). If submitted for use in the DA Market, a Fixed Through Interchange Transaction will automatically roll forward as a Fixed schedule for use in RUC and the RTBM. If submitted for use in the RTBM, the Fixed Through Interchange Transaction will clear in the RTBM and will be considered a fixed schedule for use in any RUC Processes.
(b)
An Up-To-TUC Through Interchange Transaction specifies both a MW amount and the maximum amount of congestion cost and marginal loss cost, in $/MWh, between the specified E-Tag Source GCA and Sink LCA Settlement Location the Market Participant is willing to pay if the transaction clears the DA Market. Up-
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To-TUC Through Interchange Transactions are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a Fixed schedule for use in the RUC and RTBM. Any adjustment to the schedule in the RTBM would be settled as a deviation from the DA Market.
4.2.5
Ramp Reservation Requirements
SPP uses a ramp reservation system to limit schedule changes to an amount equal to or less than the available ramp capability. The ramp reservation system allows SPP to ensure that sufficient ramp is available before the schedules created under Sections 4.2.2.7 and 4.2.3.3 are approved. SPP determines a limit for the net amount of schedule change into or out of the SPP BA for any 10 minute period based on projected available ramping capability and updates these limits on an ongoing basis. SPP will not approve schedules that violate this limit. Market Participants may optionally submit requests to reserve ramping capability. A ramp reservation can be made to “hold” ramp room while Market Participants complete their scheduling responsibilities. Ramp reservations are then associated on the Tag when the Market Participant submits the schedule. The ramp reservation is validated against the submitted Tag to ensure the energy profile and path matches. If a Market Participant does not submit a specific request, the ramp reservation system will automatically generate a ramp reservation when the schedule is submitted, if there is sufficient ramp capability available. The follow business rules apply to submittal and approval of ramp reservation requests. Additional detail regarding ramp reservations can be found in the Interchange Scheduling Reference Manual. (1)
(2)
There are two time periods during which Market Participants can submit requests to reserve ramping capability: (a)
Up to 1100 hours on the day prior to the Operating Day in order to reserve ramping capability for import or export transactions that clear in the DA Market. Any unused reserved ramping capability is made available for use in import and/or export scheduling in the RTBM for the Operating Day.
(b)
Beginning at 1100 hours on the day prior to the Operating Day, ramp reservation requests may be submitted for import and/or export scheduling in the RTBM for the Operating Day, up to 30 minutes prior to the Operating Hour.
Market Participant ramp reservation requests are evaluated and granted on a first come, first served basis;
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(3)
Market Participants may be required to shift their schedule requests in order to get their ramp reservation requests approved. If the Market Participant shifts their schedule up to one hour in either direction, they are not required to purchase additional transmission;
(4)
If a Market Participant chooses to fix their ramp violation by extending the duration of the transaction, they do not have to purchase additional transmission if the total MWh capacity of the transmission request is not exceeded;
(5)
Market Participants may submit one or more schedules associated with one or more approved ramp reservations, such that the sum of the submitted schedule MWhs do not exceed the MWhs of approved ramp on that path. Any approved ramp reservations for a path in excess of the associated schedules is released for use in the RUC processes and RTBM;
(6)
SPP updates available ramping capability on a five (5) minute basis.
4.2.6
Multi-Day Reliability Assessment
The Multi-Day Reliability Assessment identifies Resources which must be given start-up orders well in advance of an Operating Day. Each day, SPP performs a Multi-Day Reliability Assessment for at least three days prior to the Operating Day, to assess capacity adequacy for each Operating Day. The purpose of the Multi-Day Reliability Assessment is to evaluate the need to issue start-up instructions for Resources that cannot be committed in the DA RUC process because of a long lead time (“Long-Lead-Time Resource”). The Multi-Day Reliability Assessment consists of four steps: (1) process inputs; (2) perform resource adequacy assessment; (3) evaluate results; and (4) issue commitment orders. 4.2.6.1
Multi-Day Reliability Assessment Inputs
Inputs to the Multi-Day Reliability Assessment process will consist of: (1)
RTBM Resource Offers;
(2)
Estimated Fixed Export Interchange Transaction Bids;
(3)
Estimated Fixed Import Interchange Transaction Offers;
(4)
Estimated SPP Operating Reserve requirements (system-wide and Reserve Zone min and max) based on historical requirements;
(5)
SPP Mid-Term Load Forecast (MTLF) as described under Section 4.1.2.1;
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(6)
Wind Resource output forecast as described under Section 4.1.2.2;
(7)
Transmission System topology with approved Transmission System outages; and
(8)
Resource outages.
4.2.6.2
Multi-Day Reliability Assessment Analysis
Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day as follows: (1)
SPP calculates an SPP system requirement for each hour of the Operating Day as the sum of (a) Mid-Term Load Forecast, (b) Fixed Interchange Transaction Bids, (c) RegulationUp requirement and (d) the Contingency Reserve requirement in each hour reduced by the Wind Resource output forecast;
(2)
SPP then calculates available Resource capacity in each hour as the sum of (a) Maximum Emergency Capacity Operating Limit for Resources other than Long-Lead-Time Resources that are not on an approved SPP outage as submitted as part of the Resource Offer and (b) Fixed Import Interchange Transaction Offers;
(3)
For each hour of the Operating Day, SPP then compares the values calculated under (1) above and (2) above. If in any hour of the Operating Day, the values calculated under (1) above exceed the values calculated under (2) above, SPP will commit available LongLead-Time Resources on an economic basis to eliminate the deficiency as follows: (a)
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For each available Long-Lead Time Resource, SPP calculates a commitment cost in dollars that is equal to: (i)
The sum of 1) the Resources Start-Up Offer, 2) the Resource’s No-Load Offer multiplied by the greater of the Resource’s Minimum Run Time (in Hours) or the number of hours the Resource would be committed ignoring the Minimum Run Time, and 3) the Resources average cost to operate at Minimum Economic Capacity Operating Limit, as calculated from the Resource’s Energy Offer Curve, multiplied by the greater of the Resource’s Minimum Run Time (in Hours) or the number of hours the Resource would be committed ignoring the Minimum Run Time.
(ii)
SPP then creates a merit order list starting with the least cost Resource bases upon the commitment cost calculated in (i) above. SPP then selects Resources for commitment in merit order until sufficient capacity is
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committed to relieve the anticipated capacity shortage with the objective of minimizing the total capacity committed to meet the anticipated shortage at the lowest overall commitment cost. Such manual commitments shall be selected by the SPP in a non-discriminatory manner, which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. (4)
SPP may also commit Resources to address Transmission System related reliability problems. Such manual commitments shall be selected by the SPP in a nondiscriminatory manner, which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff
4.2.6.3
Multi-Day Reliability Assessment Results
SPP staff communicates these start-up orders to the affected Market Participants. At the time of this notification, the submitted Offers become binding and the selected Resource(s) Offers are included in the DA Market with a Commitment Status similar to Self-commit. Unlike SelfCommitted Resources, however, the Multi-day Reliability Assessment committed Resources will be eligible for DA Market make-whole payment guarantees as described under Section 4.5.8.12.
4.3
Day-Ahead Activities
Day-Ahead activities begin 24 hours prior to the Operating Day and consist of the DA Market and Day-Ahead RUC processes. Exhibit 4-12 provides a representative overall timeline of DayAhead activities. The times specified in the timeline are the times associated with normal operating conditions. SPP may delay these times to account for unforeseen circumstances and, under such circumstances, SPP will notify Market Participants of any such timing delays. Exhibit 4-12: Day-Ahead Activities Timeline
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00:00 - 11:00 MPs submit Offers and Bids
11:00 DA Market closes 16:00 SPP posts DA Market results
20:00 SPP communicates RUC results to affected MPs
1/30 - 1/30 Day-Ahead 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 12:00 AM
11:59 PM
SPP Posts Operating Reserve Requirements 07:00
SPP performs DA Market process 11:00 - 16:00 SPP performs Day-Ahead RUC process 17:00 - 20:00
A detailed description of the DA Market and Day-Ahead RUC processes is provided in the following subsections.
4.3.1
Day-Ahead Market
The DA Market process begins with the submittal of new Offers and Bids, or updates to the Offers and Bids submitted in Pre-Day-Ahead, for use in the DA Market clearing. Energy clearing is based upon the Offers and Bids submitted. Operating Reserve clearing is based upon the Offers submitted to meet the SPP Operating Reserve requirement. Market Participants must submit final Offers and Bids no later than 1100 hours Day-Ahead. Immediately following the close of the DA Market at 1100 hours Day-Ahead, SPP begins the process of clearing the DA Market and completes the process by 1600 hours. DA Market operations consist of three steps: (1) process DA Market inputs; (2) DA Market execution and (3) DA Market results. Each of these steps is described in the following subsections. 4.3.1.1
DA Market Inputs
Inputs to the DA Market algorithm consist of: (1)
DA Market Offers and Bids as submitted by Market Participants prior to 1100 hours DayAhead; (a)
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(b)
For Virtual Energy Bids and/or Virtual Energy Offers submitted at a Market Hub Settlement Location and confirmed Interchange Transactions submitted at an External Interface, SPP uses a common set of weighting factors to distribute the Bid and/or Offer MWs down to PNodes included in the Market Hub or External Interface for modeling purposes. These weighting factors are determined by SPP at the time the Trading Hub or External Interface is created and are not dependent upon historical injections/withdrawals. Resource Hub weighting factors are determined by SPP after coordinating with the requesting Market Participant.
(2)
Resource Offers for long lead time Resources selected by SPP for commitment during the Operating Day during the Multi-Day Reliability Assessment process;
(3)
Through Interchange Transactions as submitted by Market Participants and confirmed prior to 1100 hours Day-Ahead;
(4)
SPP Operating Reserve requirements (system-wide and Reserve Zone min and max);
(5)
SPP Head-room and Floor-room requirements;
(6)
SPP Transmission System topology consistent with Network Model in place for current Operating Day, including adjustments to RCF firm flow entitlements if applicable;
(7)
Transmission System outages;
(8)
Parallel Flow forecasts; and
(9)
Resource outages.
4.3.1.2
DA Market Execution
SPP clears the Day-Ahead Market for each hour of the upcoming Operating Day based on the inputs described above. A simultaneous co-optimization methodology, utilizing the SCUC and SCED algorithms is employed to simultaneously perform the following tasks: (1)
Commit offered Resources, Import Interchange Transaction Offers and Virtual Energy Offers using the SCUC algorithm to meet the Demand Bids, Virtual Energy Bids, Export Interchange Transactions Bids, Head-room requirements, Floor-room requirements and Operating Reserve requirements at least cost throughout the projected upcoming Operating Day while respecting Resource operating constraints and transmission constraints;
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(a)
(b)
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The DA Market SCUC algorithm will initially consider commitment of Resources with a Commit Status of Market and Self, including Resources committed in the Multi-Day Reliability Assessment process, only including capacity up to the Resources’ Maximum Economic Capacity Operating Limit (or Maximum Regulation Capacity Operating Limit if selected for Regulation-Up Service and/or Regulation-Down Service) and down to the Resources Minimum Economic Capacity Operating Limit (or Minimum Regulation Capacity Operating Limit if selected for Regulation-Down Service and/or Regulation-Up Service). In addition, combined cycle Resources modeled as described under Section 4.2.2.5.3(4) are not eligible for regulation selection in any hour in which they are transitioning from one configuration to another. (i)
If this capacity is not sufficient to meet the fixed Demand Bids, fixed Export Interchange Transaction Bids, Head-room requirements and Operating Reserve requirements on a system-wide basis, the DA Market SCUC algorithm will, in priority order: (1) curtail non-firm fixed Export Interchange Transaction Bids until the capacity shortage is eliminated; (2) incorporate capacity up to Resources’ Maximum Emergency Capacity Operating Limit and/or commit Resources’ with a Commit Status of Reliability on an economic basis until the capacity shortage is eliminated while attempting to maintain the Regulation-Up requirement to the extent possible.
(ii)
If there is a capacity surplus on a system-wide basis calculated as the sum of Self-Committed capacity at minimum output, fixed Import Interchange Transaction Offers, Floor-room requirement and the Regulation-Down requirement that is in excess of the sum of Fixed Demand Bids and fixed Export Interchange Transaction Bids, the DA Market SCUC algorithm will, in priority order (1) curtail non-firm fixed Import Interchange Transaction Offers until the capacity surplus is eliminated; (2) incorporate capacity down to Resources’ Minimum Emergency Capacity Operating Limit on an economic basis until the capacity surplus is eliminated while attempting to maintain the Regulation-Down requirement to the extent possible.
To the extent that a particular reliability issue cannot be directly addressed within the DA Market SCUC algorithm as described under subsection (i) and (ii) above,
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SPP may manually commit Resources to alleviate such reliability issues. SPP will re-run the DA Market SCUC algorithm after such manual commitments, time permitting, and will notify the Market Participants that units were manually committed. The SCED algorithm will be run based on the manual commitment to produce a final market solution. (2)
Using the commitment results from the SCUC, clear Resource Offers and Import Interchange Transaction Offers to meet Demand Bids, Virtual Energy Bids, Export Interchange Transaction Bids and Operating Reserve requirements at minimum cost for each hour of the upcoming Operating Day using the SCED algorithm while respecting Resource operating constraints and transmission constraints. (a)
The SCED algorithm includes marginal loss sensitivity factors which approximate the change in marginal system losses for a change in Energy dispatch. Inclusion of these factors further optimizes the Energy dispatch and reduces overall production costs.
(b)
In certain situations, enforcing constraints may result in a solution that is not feasible at a Shadow Price less than an appropriately priced VRL. In such cases, SPP must apply Violation Relaxation Limits (VRLs) in SCED as described under Section 4.1.4.
(c)
To ensure rational pricing of cleared Operating Reserve products, the SCED algorithm will include product substitution logic as follows: (i)
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Any Regulation-Up Offers remaining once the Regulation-Up Requirement requirement is satisfied may be used to meet Contingency Reserve requirements if Regulation-Up Offer is more economic or is are required to meet the overall Operating Contingency Reserve requirement;
(ii)
Any Spinning Reserve Offers remaining once the Spinning Reserve Requirement is satisfied may be used to meet Supplemental Reserve requirements if Spinning Reserve Offer is more economic or is required to meet the overall Operating Reserve requirement;
(iii)
The product substitution logic ensures that the MCP for Regulation-Up Service is always greater than or equal to the Spinning Reserve MCP and that the Spinning Reserve MCP is always greater than or equal to the Supplemental Reserve MCP.
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Comment [MPRR102.307]: MPRR102 Awaiting implementation. #ER13-1748
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(d)
To ensure that Market Participants are indifferent as to whether they are cleared for Energy or Operating Reserve, the co-optimization logic will provide through the Shadow Price calculation Market Clearing Prices for Operating Reserve that include any lost opportunity costs incurred as a result of Operating Reserve clearing.
(d)(e) Combined cycle Resources modeled as described under Section 4.2.2.5.3(4) with Transition Times greater than 30 minutes are not eligible to clear Contingency Reserve in any hour in which they are transitioning from one configuration to another. 4.3.1.2.1
Clearing During Capacity Shortage
(1)
If there is an Operating Reserve shortage in any hour, Scarcity Pricing will be invoked as described under Section 4.1.5;
(2)
If there is a shortage of capacity to meet the fixed Demand Bids and fixed firm Export Interchange Transactions in any hour, the SCED algorithm will reduce the fixed Demand Bids and fixed firm Export Interchange Transactions on a pro-rata reduction basis based on the fixed MW amounts to match the available capacity and Scarcity Pricing will be invoked as described under Section 4.1.5;
(3)
Ramp sharing is applied to ensure, to the extent possible, that short-term ramping deficiencies from hour to hour do not initiate unjustified Scarcity Pricing (i.e. Scarcity Pricing should only be initiated when there is a capacity shortage) as described under Section 4.1.5;
(4)
If there is a transmission constraint that cannot be relieved due to a shortage of capacity in any hour, the SCED algorithm will clear the bid-in demands on a pro-rata basis based upon the impact on relieving the constraint;
4.3.1.2.2 (a)
Clearing During Excess Generation Conditions
If the sum of Minimum Emergency Capacity Operating Limits on self-committed Resources plus the Regulation-Down requirement is in excess of the cleared bid-in demands in any hour, the SCED algorithm will reduce Resources on a pro-rata reduction basis such that the resulting sum of minimum limits matches the bid-in demand. (a)
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LMPs will be set by the Offers prices associated with Energy down to the Minimum Emergency Capacity Operating Limit to the extent that the Regulation-
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Down requirement can be maintained. If the actions under 4.3.1.2 (1)(a)(ii) above create a Regulation-Down Service shortage during any Hour either on a systemwide basis or Reserve Zone basis, the MCPs for Regulation-Down Service will reflect Scarcity Prices and LMPs will reflect negative Scarcity Prices as described under Section 4.1.5. 4.3.1.3
Comment [MPRR102.309]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.310]: MPRR102 Awaiting implementation. #ER13-1748
DA Market Results
No later than 1600 hours Day-Ahead, SPP electronically communicates the DA Market results for each hour of the Operating Day to Market Participants. The following results are communicated to each Market Participant that relates only to that Market Participant: (1)
Cleared Resource Offers for Energy, Regulation-Up Service, Regulation-Down Service, Spinning Reserve and/or Supplemental Reserve, in MW; (a)
Cleared Offers for Energy associated with Resource Offers represent a physical Resource commitment schedule that forms the basis for the Current Operating Plan for the upcoming Operating Day. Market Participants should consider Resource commitment schedules resulting from SPP commitment of Resources with a Commit Status of “Market” or “Reliability as SPP start-up orders and shutdown orders.
(b)
Resources committed by SPP in the DA Market with a Commit Status of “Market” or “Reliability” are guaranteed to receive DA Market revenues that are at least equal to the DA Market Resource Offer costs for the associated cleared amount of Energy, Regulation-Up, Regulation-Down Spinning Reserve and/or Supplemental Reserve. See Section 4.5.8.12 for additional details.
(2)
Cleared Virtual Energy Offers, in MW;
(3)
Cleared Import Interchange Transaction Offers, in MW;
(4)
Cleared Demand Bids, in MW;
(5)
Cleared Virtual Energy Bids, in MW;
(6)
Cleared Export Interchange Transaction Bids, in MW;
(7)
Cleared Through Interchange Transactions, in MW.
The following results are communicated to all Market Participants:
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(1)
Locational Marginal Prices (LMPs) for each Settlement Location, the Marginal Energy Component (MEC) of LMP, the Marginal Congestion Component (MCC) of LMP for each Settlement Location and the Marginal Losses Component (MLC) of LMP for each Settlement Location;
(2)
Market Clearing Prices for Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve for each Reserve Zone.
4.3.2
Day-Ahead Reliability Unit Commitment
At 1700 hours or one hour following the posting of the DA Market results, whichever is later, SPP begins the Day-Ahead RUC process to assess capacity adequacy during the Operating Day. No later than 2000 hours or three hours following the start of the DA RUC process, whichever is later, SPP shall communicate the results described under Section 4.3.2.3. SPP then updates the Current Operating Plan, if needed, and start-up and/or shutdown orders are issued simultaneously for Resources other than DVERs and NDVERs for which SPP is calculating an output forecast (these Resources are always assumed to be self-committed if available) which may be anytime after 2000 hours. The Day-Ahead RUC consists of four steps: (1) process RUC inputs; (2) execute RUC algorithm; (3) evaluate and communicate RUC results; and (4) update Current Operating Plan as needed. 4.3.2.1
Day-Ahead RUC Inputs
Inputs to the RUC algorithm consist of: (1)
RTBM Resource Offers, including Resources with a Self-Commit status submitted up to 1700 hours or one hour following the posting of the DA Market results, whichever is later; (a)
During all hours between the start and completion of the Day-Ahead RUC process, Market Participants may continue to update RTBM Offers during DayAhead RUC process. If the DA RUC offer being updated is for the DA RUC Study Period, SPP will notify the Market Participant that the offer will not be used in the ongoing DA RUC solution.
(2)
Confirmed cleared Export Interchange Transaction Bids from the DA Market;
(3)
Confirmed cleared Import Interchange Transaction Offers from the DA Market;
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(4)
Confirmed cleared Through Interchange Transactions from the DA Market;
(5)
Confirmed Export Interchange Transactions specified for use in the RTBM only;
(6)
Confirmed Import Interchange Transactions specified for use in the RTBM only;
(7)
Confirmed Through Interchange Transactions specified for use in the RTBM only;
(8)
SPP Operating Reserve requirements (system-wide and Reserve Zone min and max);
(9)
SPP Head-room and Floor-room requirements;
(10) SPP Mid-Term Load Forecast (MTLF) as described under Section 4.1.2.1; (11) SPP Transmission System topology consistent with Network Model in place for the Operating Day, including adjustments to RCF firm flow entitlements if applicable; (12) Resource commitment schedules from the DA Market unless SPP Operators are informed of a Resource outage; (13) Commitment schedules for long lead time Resources selected in the Multi-Day Reliability Assessment process unless SPP Operators are informed of a Resource outage; (14) Wind Resource MWh output forecast as described under Section 4.1.2.2; (15) Transmission System outages; (16) Parallel Flow forecasts; and (17) Resource outages. 4.3.2.2
Day-Ahead RUC Execution
Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day using the SCUC algorithm. The capacity adequacy analysis provides advisory information to the SPP Operators. (1)
The objective of the SCUC is to commit Resources to meet the SPP Mid-Term Load Forecast, Export Interchange Transactions, Head-room requirements, Floor-room requirements and Operating Reserve requirements less Import Interchange Transactions over the Operating Day such that commitment costs are minimized while adhering to transmission system security constraints and the resource operating parameter constraints submitted as part of the RTBM Offers;
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(2)
Commitment costs are defined as Start-Up Offer, No-Load Offer and incremental cost to operate at minimum output as defined in the submitted Energy Offer Curve. Incremental Energy costs above minimum output and Operating Reserve Offers are not considered by the RUC SCUC in making commitment decisions;
(3)
The SCUC algorithm will initially consider commitment of Resources with a Commit Status of Market or Self only including capacity up to the Resources’ Maximum Economic Capacity Operating Limit (or Maximum Regulation Capacity Operating Limit if selected for Regulation-Up Service and /or Regulation-Down Service) and down to the Resources Minimum Economic Capacity Operating Limit (or Minimum Regulation Capacity Operating Limit if selected for Regulation-Down Service and/or Regulation-Up Service). In addition, combined cycle Resources modeled as described under Section 4.2.2.5.3(4) are not eligible for regulation selection in any hour in which they are transitioning from one configuration to another.
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(a)
If this capacity plus Import Interchange Transactions is not sufficient to meet the system-wide SPP Mid-Term Load Forecast, Export Interchange Transactions, Head-room requirements and Operating Reserve requirements, the SCUC algorithm study will, in priority order: (1) curtail non-firm Export Interchange Transactions until the capacity shortage is eliminated; (2) incorporate capacity up to Resources’ Maximum Emergency Capacity Operating Limit and/or commit Resources’ with a Commit Status of Reliability on an economic basis until the capacity shortage is eliminated while attempting to maintain the Regulation-Up requirement to the extent possible.
(b)
If the sum of Self-Committed capacity at minimum output, Import Interchange Transactions, the Floor-room requirement and the system-wide Regulation-Down requirement is in excess of the sum of the SPP system-wide Mid-Term Load Forecast and Export Interchange Transactions, the RUC SCUC algorithm study will, in priority order: (1) curtail non-firm fixed Import Interchange Transactions until the capacity surplus is eliminated; (2) incorporate capacity down to Resources’ Minimum Emergency Capacity Operating Limit on an economic basis until the capacity surplus is eliminated while attempting to maintain the Regulation-Down requirement to the extent possible; (3) de-commit Resources that were committed in the DA Market with a Commit Status of Market until the capacity surplus in eliminated; and (4) de-commit Self-Committed Resources until the capacity surplus in eliminated.
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(i)
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If there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, SCUC may commit additional Resources and/or de-commit Resources to relieve the constraints provided that any commitment changes do not aggravate the excess capacity situation.
(c)
To the extent that a particular Transmission System reliability issue cannot be directly addressed within the SCUC algorithm and is not a Local Reliability Issue, SPP may manually commit Resources, including Resources with a Commit Status of Reliability, and de-commit Resources, including Resources with a Commit Status of Self, to alleviate such reliability issues in accordance with its authority as Reliability Coordinator. Such manual commitments shall be selected by the Transmission Provider in a non-discriminatory manner, as determined by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff, Additionally, such manual commitments shall be selected by the Transmission Provider such that commitment costs are minimized while adhering to Transmission System security constraints and the Resource operating parameter constraints submitted as part of the RTBM Offers. The recovery of any compensation paid by the Transmission Provider under Section 4.5.9.8 to such committed Resources shall be collected by the Transmission Provider regionally as described under Section 4.5.9.10.
(d)
A Local Reliability Issue may arise within the operating area of a local transmission operator. Such Local Reliability Issues may require out of merit commitment, decommitment or dispatch instructions to be issued to one or more Resources to resolve the Local Reliability Issue. In such cases, the Transmission Provider shall issue or the local transmission operator shall request SPP to issue such instructions and the Transmission Provider shall commit the most applicable Resource using the same process it would use to manually commit a Resource without the request of a local transmission operator. To the extent that SPP, at the request of a local transmission operator, commits a Resource to address a Local Reliability Issue such Resource shall be eligible for compensation in the same manner as any other Resource. The recovery of such compensation paid by the Transmission Provider shall be collected locally as described under Section 4.5.9.10.
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(e)
SPP, the local transmission operator, and Resource owners shall develop operating guides to be applied to manual commitments made by SPP, including such commitments made at the request of the local transmission operator to relieve known and recurring Local Reliability Issues in the Day-Ahead RUC. Such Resources will be compensated in the same manner as any other Resource. The recovery of such compensation paid by the Transmission Provider for such committed Resources under Section 4.5.9.8 shall be collected by the Transmission Provider locally as described under Section 4.5.9.10.
Any curtailment of schedules, use of Reliability Status Resources or use of Emergency operating limits by the RUC algorithms will only be advisory information to the SPP RUC Operators. Day-Ahead RUC and Intra-Day RUC Operators will determine which of these options should be acted on and when as described in the Day-Ahead and Intra-Day RUC Results sections. 4.3.2.3
Day-Ahead RUC Results
No later than 2000 hours Day-Ahead, or three hours following the start of the DA RUC process, whichever is later, SPP electronically communicates the following Day-Ahead RUC results for each hour of the Operating Day to Market Participants: (1)
For any future hours in which SPP anticipates an Emergency situation, SPP shall notify the Market Participants identifying the hours in which the emergency ranges of any Resources are expected to be required, the hours in which Resources with a Commit Status of Reliability are expected to be committed, the hours in which non-firm fixed Export Interchange Transactions are expected to be curtailed and the hours in which nonfirm fixed Import Interchange Transactions are expected to be curtailed.
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(a)
In addition if necessary, affected Market Participants will be notified at least ten (10) minutes prior to the beginning of the Operating Hour but not more than 30 minutes prior to the beginning of the Operating Hour that the Maximum Emergency Capacity Operating Limit will be used;
(b)
In addition if necessary, affected Market Participants will be notified at least ten (10) minutes prior to the beginning of the Operating Hour but not more than 30 minutes prior to the beginning of the Operating Hour that the Minimum Emergency Capacity Operating Limit will be used.
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4.3.2.4
Update Current Operating Plan
Using the results from the Day-Ahead RUC analysis, SPP will update the Current Operating Plan and will issue start-up and shut-down orders to Resources other than DVERs and NDVERs for which SPP is calculating an output forecast (these Resources are always assumed to be selfcommitted if available) as appropriate. SPP can only de-commit DA Market committed Resources or move a DA Market committed combined cycle Resource that has been registered to submit configuration based offers as described under Section 4.2.2.5.3(4) into a lower configuration to address an anticipated excess supply condition as described under Section 4.3.2.2(3)(b) and/or to address any other Emergency conditions. If SPP de-commits an SPP committed Resource or moves a combined cycle resource into a lower configuration for any hour of the DA Market commitment schedule, and causes that Resource to buy back its Energy and/or Operating Reserve position at RTBM prices that exceed the DA Market prices for the comparable products, then that Resource is eligible for compensation under Section 4.5.9.9.
4.4
Operating Day Activities
Operating Day activities begin at 2000 hours Day-Ahead and consist of the Intra-Day RUC processes and RTBM. Exhibit 4-13 provides a representative overall timeline of Operating Day activities. Exhibit 4-13: Operating Day Activities Timeline
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1/30 - 1/31 Perform Intra-Day RUC process as needed
1/31 - 1/31 Develop short-term load forecast next 60 minutes on a rolling 5-minute basis
1/30 - 1/30 Day-Ahead
1/31 - 1/31 Operating Day 1/31
1/30
1/30 - 1/30 Day-Ahead 21:00
22:00
1/31
1/31 - 1/31 Operating Day 23:00
24:00
01:00
20:00
01:59 00:30 MPs submit new or revised offers
01:30 MPs submit new revised offers
00:00 - 01:59 Operating Hours 01:00 00:00
01:59 01:05 Issue Dispatch Instructions
01:10 Issue Dispatch Instructions
01:15 Issue Dispatch Instructions
01:00 - 01:15 Partial Operating Hour 01:01 01:02 01:03 01:04 01:05 01:06 01:07 01:08 01:09 01:10 01:11 01:12 01:13 01:14 01:00
01:15
Clear RTBM 01:00 - 01:05
Clear RTBM 01:05 - 01:10
Clear RTBM 01:10 - 01:15
A detailed description of the Intra-Day RUC and RTBM processes is provided in the following subsections.
4.4.1
Intra-Day Reliability Unit Commitment
Following completion of the Day-Ahead RUC process, SPP continually evaluates the need for an Intra-Day RUC for the remainder of the Day-Ahead period and the Operating Day and performs additional Intra-Day RUCs at least every four hours. Consistent with the Day-Ahead RUC, these additional Intra-Day RUCs assess capacity adequacy during the Operating Day. As soon as practicable following completion of an Intra-Day RUC study, SPP will communicate the results described under Section 4.4.1.3. SPP then updates the Current Operating Plan, if needed, and start-up and/or shutdown orders to Resources other than DVERs and NDVERs for which SPP is calculating an output forecast (these Resources are always assumed to be self-committed if available) are issued simultaneously which may be any time after completion of an Intra-Day RUC study.
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The Intra-Day RUC consists of four steps: (1) process RUC inputs; (2) execute RUC algorithm; (3) evaluate and communicate RUC results; and (4) update Current Operating Plan as needed. 4.4.1.1
Intra-Day RUC Inputs
Inputs to the RUC algorithm consist of: (1)
RTBM Resource Offers;
(2)
Confirmed Export Interchange Transactions;
(3)
Confirmed Import Interchange Transactions;
(4)
Confirmed Through Interchange Transactions;
(5)
SPP Operating Reserve requirements (system-wide and Reserve Zone min and max);
(6)
SPP Head-room and Floor-room requirements;
(7)
SPP Mid-Term Load Forecast as described under Section 4.1.2.1;
(8)
SPP Transmission System topology consistent with Network Model in place for the Operating Day, including adjustments to RCF firm flow entitlements if applicable;
(9)
Resource commitment and de-commitment schedules from the Day-Ahead RUC or previous Intra-Day RUCs;
(10) Wind Resource output forecast as described under Section 4.1.2.2; (11) Transmission System outages; (12) Parallel Flow forecasts; and (13) Resource outages. 4.4.1.2
Intra-Day RUC Execution
Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day and throughout the Operating Day using a SCUC algorithm. The capacity adequacy analysis provides advisory information to the SPP Operators. (1)
The objective of the SCUC is to commit Resources to meet the SPP Mid-Term Load Forecast, Export Interchange Transactions, Head-room requirements, Floor-room requirements and Operating Reserve requirements less Import Interchange Transactions over the Operating Day such that commitment costs are minimized while adhering to
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transmission system security constraints and the resource operating parameter constraints submitted as part of the RTBM Offers; (2)
Commitment costs are defined as Start-Up Offer, No-Load Offer and incremental cost to operate at minimum output as defined on the submitted Energy Offer Curve. Incremental Energy costs above minimum output and Operating Reserve Offers are not considered by the RUC SCUC in making commitment decisions;
(3)
The SCUC algorithm will initially consider commitment of Resources with a Commit Status of Market or Self only including capacity up to the Resources’ Maximum Economic Capacity Operating Limit (or Maximum Regulation Capacity Operating Limit if selected for Regulation-Up Service and/or Regulation-Down Service) and down to the Resources Minimum Economic Capacity Operating Limit (or Minimum Regulation Capacity Operating Limit if selected for Regulation-Down Service and/or Regulation-Up Service). In addition, combined cycle Resources modeled as described under Section 4.2.2.5.3(4) are not eligible for regulation selection in any hour in which they are transitioning from one configuration to another.
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(a)
If this capacity plus Import Interchange Transactions is not sufficient to meet the system-wide SPP Mid-Term Load Forecast, Export Interchange Transactions, Head-room requirements and Operating Reserve requirements, the SCUC algorithm study will, in priority order: (1) curtail non-firm Export Interchange Transactions until the capacity shortage is eliminated; (2) incorporate capacity up to Resources’ Maximum Emergency Capacity Operating Limit and/or commit Resources’ with a Commit Status of Reliability on an economic basis until the capacity shortage is eliminated while attempting to maintain the Regulation-Up requirement to the extent possible.
(b)
If the sum of Self-Committed capacity at minimum output, Import Interchange Transactions, Floor-room requirements and the system-wide Regulation-Down requirement is in excess of the sum of the SPP system-wide Mid-Term Load Forecast and Export Interchange Transactions, the SCUC algorithm study will, in priority order: (1) curtail non-firm fixed Import Interchange Transactions until the capacity surplus is eliminated; (2) incorporate capacity down to Resources’ Minimum Emergency Capacity Operating Limit on an economic basis until the capacity surplus is eliminated while attempting to maintain the Regulation-Down requirement to the extent possible; (3) de-commit Resources that were committed in the DA Market with a Commit Status of Market until the capacity surplus is
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eliminated; and (4) de-commit Self-Committed Resources that were committed following the Day-Ahead RUC process until the capacity surplus is eliminated. (i)
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If there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, RUC may commit additional Resources to relieve the constraints provided that the additional commitment does not aggravate the excess capacity situation.
(c)
To the extent that a particular reliability issue impacting only the Transmission System cannot be directly addressed within the SCUC algorithm and is not a Local Reliability Issue, SPP may manually commit Resources, including Resources with a Commit Status of Reliability, and de-commit Resources, including Resources with a Commit Status of Self, to alleviate such Transmission System reliability issues. Such manual commitments shall be selected in a nondiscriminatory manner, as determined by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. Additionally, such manual commitments shall be selected by the Transmission Provider such that commitment costs are minimized while adhering to Transmission System security constraints and the Resource operating parameter constraints submitted as part of the RTBM Offers. The recovery of the compensation paid by the Transmission Provider for such committed Resources under Section 4.5.9.8 shall be collected by the Transmission Provider regionally as described under Section 4.5.9.10.
(d)
A Local Reliability Issue may arise that may require out of merit commitment, decommitment or dispatch instructions to be issued by the Transmission Provider to one or more Resources to resolve the Local Reliability Issue. Time permitting, the local transmission operator shall request SPP to issue such instructions and any commitment by SPP shall be selected by SPP in a non-discriminatory manner, which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. To the extent SPP issues instructions to a Resource at the request of a local transmission operator to resolve a Local Reliability Issue, the Resource shall be eligible for compensation in the same manner as any other Resource. The recovery of the compensation paid by the Transmission Provider for such committed Resources under Section 4.5.9.8 shall be collected by the Transmission Provider locally as described under Section 4.5.9.10. To the extent time does not permit, the local
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transmission operator may issue such instructions to the Resource in accordance with its authorities as a reliability entity if the Local Reliability Issue is a Local Emergency Condition. In such cases, the following shall take place: (i)
If initial instructions are issued by a local transmission operator, the Transmission Operator shall notify SPP of the instructions given to the Resource.
(ii)
The Transmission Operator and SPP will coordinate to ensure subsequent instructions are provided by SPP.
(iii) SPP shall log such instructions as manual commitment, decommitment or Out-of-Merit Dispatch instruction, as appropriate, as if it gave such instruction to the Resource. (iv) The Resource shall be eligible to receive the compensation for such instructions in the same manner as if it had been committed by SPP, except that, if the Market Monitor determines that the Resource was selected in a discriminatory manner and the Resource was an affiliated Resource, such Resource shall not be eligible to receive compensation under Section 4.5.9.8. For purposes of making such determination by the Market Monitor, the standards and procedures applicable to Resource selection in the Intra-Day Reliability Unit Commitment process as described in Section 6.1.2.1 of Attachment AE to the Tariff, shall apply. Recovery of any compensation shall be collected by the Transmission Provider locally as described under Section 4.5.9.10. (v)
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SPP, the local transmission operator, and Resource owners shall develop operating guides to be applied to manual commitments made by SPP including such commitments made at the request of the local transmission operator or manual commitments made by the local transmission operator during a Local Emergency Condition to relieve known and recurring Local Reliability Issues in the Intra-Day RUC. Such Resources will be compensated in the same manner as any other Resource. The recovery of the compensation paid by the Transmission Provider under Section 4.5.9.8 shall be collected by the Transmission Provider locally as described under Section 4.5.9.10.
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4.4.1.3
Intra-Day RUC Results
SPP electronically communicates the RUC results for each hour of the Operating Day to Market Participants as soon as practical following completion of each Intra-Day RUC execution. These results consist of the following: (1)
For any future hours in which SPP anticipates an Emergency situation, SPP shall notify the market identifying the hours in which the emergency ranges of any Resources are expected to be required, the hours in which Resources with a Commit Status of Reliability are expected to be committed, the hours in which non-firm fixed Export Interchange Transactions are expected to be curtailed and the hours in which non-firm fixed Import Interchange Transactions are expected to be curtailed.
4.4.1.4
(a)
In addition if necessary, affected Market Participants will be notified at least ten (10) minutes prior to the beginning of the Operating Hour but not more than 30 minutes prior to the beginning of the Operating Hour that the Maximum Emergency Capacity Operating Limit will be used;
(b)
In addition if necessary, affected Market Participants will be notified at least ten (10) minutes prior to the beginning of the Operating Hour but not more than 30 minutes prior to the beginning of the Operating Hour that the Minimum Emergency Capacity Operating Limit will be used.
Update Current Operating Plan
Using the results from the Intra-Day RUC analysis, SPP will update the Current Operating Plan and will issue start-up and shut-down orders to Resources other than DVERs and NDVERs for which SPP is calculating an output forecast (these Resources are always assumed to be selfcommitted if available) as appropriate. SPP may only issue changes to shut-down orders issued as part of the DA Market results or move a DA Market committed combined cycle Resource that has been registered to submit configuration based offers as described under Section 4.2.2.5.3(4) into a lower configuration to address an anticipated excess supply condition as described under Section 4.3.2.2(3)(b) and/or to address any other Emergency conditions. If SPP de-commits an SPP committed Resource or moves a combined cycle Resource into a lower configuration for any hour of the DA Market commitment schedule, and causes that Resource to buy back its Energy and/or Operating Reserve position at RTBM prices that exceed the DA Market prices for the comparable products, that Resource is eligible for compensation under Section 4.5.9.9.
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4.4.2
Real-Time Balancing Market
SPP operates the RTBM on a continuous 5-minute basis. SPP clears the RTBM by determining the security-constrained dispatch that is the least costly means of balancing generation and load (supply/demand) while meeting Operating Reserve requirements within the SPP Balancing Authority Area based on actual conditions, forecasted conditions, and submitted Offers. The RTBM uses the same Network Model that is used in the DA Market, with all RTBM network configurations and constraints as determined from the most recent State Estimator results. RTBM operations consist of three steps: (1) Process RTBM inputs; (2) Execute RTBM and (3) Post RTBM results. Each of these steps is described in the following subsections. 4.4.2.1
Managing Regulation Control Status Prior to Operating Hour
SPP selection of Regulation Qualified Resources, Regulation-Up Qualified Resources and Regulation-Down Qualified Resources to be available to be cleared for Regulation-Up Service and/or Regulation-Down Service within the Operating Hour will be performed as follows: (1) Prior to each Operating Hour, SPP will select sufficient on-line regulation qualified Resources to meet the Regulation-Up and Regulation-Down requirements using the results of the most recently completed RUC analysis. Prior to the Operating Hour, in order to prepare for the loss of regulating capability on one or more selected Resources within the Operating Hour and support reliable operations, SPP will also select, as necessary, additional regulation qualified Resources using the selection process described under (2) below. (2) SPP will, in order to support reliable operations, update the Current Operating Plan by selecting additional regulation qualified Resources as being required to regulatebe eligible to clear Regulation-Up Service and/or Regulation-Down Service. Combined cycle Resources modeled as described under Section 4.2.2.5.3(4) are not eligible for regulation selection in any hour in which they are transitioning from one configuration to another. SPP will use the following criteria to select such additional resources in merit order to the extent that such resources can be deployed reliably. Merit order prices for provision of Regulation-Up and Regulation-Down will be calculated as follows: Regulation-Up Merit Order Price = Capacity Cost + RTBM Regulation-Up Offer + Regulation-Up Energy Lost Opportunity Cost
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Regulation-Down Merit Order Price = Capacity Cost + RTBM Regulation-Down Offer + Regulation-Down Energy Increased Cost (a)
Capacity Cost - For Regulation Qualified Resources, Regulation-Up Qualified Resources and Regulation-Down Qualified Resources, Capacity LOC is equal to the sum of Regulation Maximum Capacity Uncompensated Cost and Regulation Minimum Capacity Uncompensated Cost, where Regulation Maximum Capacity Uncompensated Cost ($/MWh) is each Resource’s estimated uncompensated cost for lost Energy output between regulation maximum limit and Capacity Desired Dispatch MW, and Regulation Minimum Capacity Uncompensated Cost ($/MWh) is each Resource’s estimated uncompensated cost for Energy output between Capacity Desired Dispatch MW and regulation minimum limit that Resources Regulation-Up Offer. (i) Regulation Maximum Capacity Uncompensated Cost = [ [ Max (0, estimated LMP ($/MWh) – Energy Offer Curve cost of Energy between regulation maximum limit and Capacity Desired Dispatch MW ($/MWh))] * [Max (0, Desired Dispatch MW – regulation maximum limit)] ] / [regulation ramp rate * 5 minutes]. (ii) Regulation Minimum Capacity Uncompensated Cost = [ [ Max (0, Energy Offer Curve cost of Energy between Capacity Desired Dispatch MW and regulation minimum limit ($/MWh) - estimated LMP ($/MWh) ) ] * [Max ( 0, regulation minimum limit – Desired Dispatch MW)] ] / [regulation ramp rate * 5 minutes]. (iii) Capacity Desired Dispatch MW = the MW point on the Resource’s Energy Offer Curve between economic minimum and economic maximum at which the price point on the curve is equal to the estimated LMP. (b) Regulation-Up Energy Lost Opportunity Cost (LOC) – For Regulation Qualified Resources and Regulation-Up Qualified Resources, Regulation-Up Energy LOC is equal to each Resource’s estimated lost opportunity cost (Energy ELOC $/MWh) for lost Energy output between regulation maximum limit and Energy Desired Dispatch MW if Energy Desired Dispatch MW is greater than regulation maximum limit less regulation ramp rate * 5 minutes. (i) IF Energy Desired Dispatch MW) > (regulation maximum limit regulation ramp rate * 5 minutes) THEN
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(3)
Energy ELOC = [Max (0, (estimated LMP ($/MWh) – Energy Offer Curve cost of Energy between (regulation maximum limit and Energy Desired Dispatch MW))) * (regulation maximum limit – Energy Desired Dispatch MW)) ] / [regulation ramp rate * 5 minutes]. (ii) Energy Desired Dispatch MW = the MW point on the Resource’s Energy Offer Curve between regulation minimum and regulation maximum at which the price point on the curve is equal to the estimated LMP. (c) Regulation-Down Energy Increased Cost (EIC) – For Regulation Qualified Resources and Regulation-Down Qualified Resources, Regulation-Down Energy EIC is equal to each Resource’s estimated increase in cost (Energy EIC - $/MWh) for increased Energy output between regulation minimum limit and Energy Desired Dispatch MW if Energy Desired Dispatch MW is less than regulation minimum limit plus regulation ramp rate * 5 minutes. (i) IF Energy Desired Dispatch MW) < (regulation minimum limit + regulation ramp rate * 5 minutes) THEN Energy EIC = [ Max ( 0, (Energy Offer Curve cost of Energy between (Energy Desired Dispatch MW and regulation minimum limit) - estimated LMP ($/MWh)) * ( Energy Desired Dispatch MW – regulation minimum limit) ] / [regulation ramp rate * 5 minutes]. (ii) Energy Desired Dispatch MW = the MW point on the Resource’s Energy Offer Curve between regulation minimum and regulation maximum at which the price point on the curve is equal to the estimated LMP. No later than 20 minutes prior to the Operating Hour, SPP will notify Market Participants with available qualified regulating Resources as to whether they have or have not been selected to regulate for the upcoming Operating Hour; (a) Market Participants with selected Resources that are physically capable of providing regulation must submit a Resource Control Status = “Regulating” at least ten (10) minutes prior to the Operating Hour to ensure that the Resources will be available to clear Regulation-Up Service and/or Regulation-Down Service in the first Dispatch Interval of the upcoming Operating Hour if that Resource was not selected to regulate in the prior Operating Hour. (b) Market Participants with Resources not selected to regulate for the upcoming Operating Hour that had been selected to regulate in the current Operating Hour must continue to submit a Resource Control Status = “Regulating” for all intervals in the current Operating Hour.
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4.4.2.2
RTBM Inputs
Inputs into the RTBM algorithm consist of data provided prior to each Operating Hour and data provided within each Operating Hour. 4.4.2.2.1
Pre-Operating Hour Inputs:
(1)
RTBM Resource Offers;
(2)
Approved and tagged Export Interchange Transactions, Import Interchange Transactions and Through Interchange Transactions; (a)
Interchange Transactions submitted at an External Interface, SPP uses a common set of weighting factors to distribute the MWs down to PNodes included in the External Interface for modeling purposes. These weighting factors are determined by SPP at the time the External Interface is created and are not dependent upon historical injections/withdrawals.
(3)
SPP Operating Reserve requirements (system-wide and Reserve Zone min and max);
(4)
Resources selected to provide Regulation-Up Service and/or Regulation-Down Service as described under Section 4.4.2.1. This set of Resources will remain on regulation control for the Operating Hour and will be used by SCED to clear Regulation-Up Service and/or Regulation-Down Service on a 5-minute basis to meet the regulation requirements;
Comment [MPRR102.336]: MPRR102 Awaiting implementation. #ER13-1748
Resource commitment from the Current Operating Plan;
Comment [MPRR102.339]: MPRR102 Awaiting implementation. #ER13-1748
(5)
(a)
The Current Operating Plan includes Resource commitments and Resource decommitments from the Multi-Day Reliability Assessment process, DA Market, Day-Ahead RUC and Intra-Day RUC.
(6)
Use of Maximum Emergency Capacity Operating Limits on Resources identified in the Day-Ahead RUC or Intra-Day RUC; and
(7)
Use of Minimum Emergency Capacity Operating Limits on Resources identified in the Day-Ahead RUC or Intra-Day RUC.
4.4.2.2.2 (1)
In-Operating Hour Inputs:
Latest State Estimator solution for:
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(a)
Distribution of load forecast throughout the Network Model;
(b)
Latest transmission topology for the Network Model; and
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(c)
Backup initial energy injection of Resources if SCADA not available.
(2)
Actual Resource output from latest SCADA snapshot to determine initial energy injection of Resources and Generator outages;
(3)
Active transmission constraints including RCFs with firm flow entitlement adjustments if applicable where these constraints are selected and activated as described under Section 4.4.2.6;
(4)
Intra-Hour adjustments to Interchange Transactions due to curtailments or initiation of a Reserve Sharing Event involving external Balancing Authorities;
(5)
Intra-Hour adjustments to Resource Offer parameters; (a)
Market Participants are required to keep their Resource Offer operating parameters up-to-date during the Operating Day. In the event of a required change in a Resource Offer operating parameter due to physical Resource changes during an Operating Hour, the Market Participant is responsible for notifying SPP of required changes, and SPP will make the required modification for the current Operating Hour. Market Participants shall remain responsible for accurately reflecting Resource operating parameters in their Resource Offer submissions for subsequent hours.
(6)
Intra-hour adjustments to selection of regulating Resources as described under Section 4.4.2.1;
(7)
SPP Short-Term Load Forecast (STLF) as described under Section 4.1.2.1; (a)
(8)
SPP distributes the STLF down to the associated PNodes using weighting factors for modeling purposes as described under Section 4.1.2.1.6
Wind Resource output forecast as described under Section 4.1.2.2.
4.4.2.3
RTBM Execution
SPP executes the RTBM every 5-minutes for the next Dispatch Interval based on the inputs described above. (1)
A simultaneous co-optimization methodology utilizing a SCED algorithm is employed to calculate Resource Dispatch Instructions and clear Regulation-Up Service, Regulation Down Service, Spinning Reserve and/or Supplemental Reserve to meet the SPP ShortTerm Load Forecast and Operating Reserve requirements at minimum costs based upon
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submitted Offers while respecting Resource operating constraints and transmission constraints; (2)
The SCED algorithm includes marginal loss sensitivity factors which approximate the change in marginal system losses for a change in Energy dispatch. Inclusion of these factors further optimizes the Energy dispatch and reduces overall production costs;
(3)
In certain situations, enforcing constraints may result in a solution that is not feasible at a Shadow Price less than an appropriately priced VRL. In such cases, SPP must apply Violation Relaxation Limits (VRLs) in SCED as described under Section 4.1.4;
(4)
To ensure rational pricing of cleared Operating Reserve products, the SCED algorithm will include product substitution logic as follows: (a)
(b)
Any Regulation-Up Offers remaining once the Regulation-Up Requirement requirement is satisfied may be used to meet Contingency Reserve requirements if Regulation-Up Offers areis more economic or is needed to meet the overall ContingencyOperating Reserve requirement; Any Spinning Reserve Offers remaining once the Spinning Reserve Requirement is satisfied may be used to meet the Supplemental Reserve requirements if the Spinning Reserve Offer is more economic or is needed to meet the overall Operating Reserve requirement.
The product substitution logic ensures that the MCP for Regulation-Up Service is always greater than or equal to the Spinning Reserve MCP and that the Spinning Reserve MCP is always greater than or equal to the Supplemental Reserve MCP. (5)
To ensure that Market Participants are indifferent as to whether they are cleared for Energy or Operating Reserve, the co-optimization logic will provide through the Shadow Price calculation Market Clearing Prices for Operating Reserve that include any lost opportunity costs incurred as a result of Operating Reserve clearing;
(6)
Additionally, SPP executes a look-ahead SCED prior to the RTBM SCED process. The look-ahead SCED results will be used to: (1) anticipate the need to adjust Dispatch Instructions for the current Dispatch Interval to prepare to meet forecasted changes in the load several Dispatch Intervals into the future and (2) assist in determining commitment of Resources within the Operating Hour that have cold Start-Up Times greater than 10 minutes and can be on-line within the Operating Hour.
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Comment [MPRR102.345]: MPRR102 Awaiting implementation. #ER13-1748
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4.4.2.3.1
Quick-Start Resource Logic
For Resources with a cold Start-Up Time of 10 minutes or less that have submitted a Commitment Status = “Market’, an Energy Dispatch Status = “Market”, a Spinning Reserve Dispatch Status = “Fixed” or “Market” and a regulation Dispatch Status of “Fixed” or “Market”, SCED will consider such Resources as available for Energy dispatch and Operating Reserve clearing based on the rules described in Exhibit 4-14 below. Exhibit 4-14: SCED Quick-Start Resource Logic Is Resource Synchronized?
Not Synchronized
Synchronized
MP Submitted Control Status3
Eligible for Energy Dispatch
Eligible for Spinning Reserve Clearing
Eligible for Regulation Clearing
Eligible for Supplemental Reserve Clearing
Off-line
No
No
No
Yes
NonRegulating
Yes
No
No
Yes
Regulating
Yes
No
No
Yes
Manual
No
No
No
No
NonRegulating
Yes
Yes
No
Yes
Regulating
Yes
Yes
Yes
Yes
Manual
Yes
No
No
No
SCED will only consider RTBM Energy Offer Curves and Operating Reserve Offers to determine Energy Dispatch Instructions and/or Operating Reserve cleared for Quick-Start Resources. Quick-Start Resources dispatched by SCED in this manner will not be eligible for RUC Make-Whole-Payment compensation as described under Section 4.5.9.8. 4.4.2.3.2 (1)
3
Emergency Operations – Capacity Shortage
In addition to the release of Emergency capacity limits prior to the Operating Hour as described under Sections 4.3.2.3 and 4.4.1.3, SPP operators may release any remaining Emergency capacity limits as needed during the Operating Hour. SPP shall continue
See Exhibit 4-11 for Control Status descriptions
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implementation of Emergency procedures which may have been implemented prior to the Operating Hour or shall begin implementation of Emergency procedures within the Operating Hour, as needed, in accordance with its authority as Reliability Coordinator. (a)
If there is an actual Operating Reserve shortage during any Dispatch Interval, either on a system-wide or a Reserve Zone basis, the system-wide or Reserve Zone Scarcity Prices will be invoked as described under Section 4.1.5. (i)
(2)
Ramp sharing continues to be applied to ensure, to the extent possible, that short-term ramping deficiencies within an Operating Hour do not initiate unjustified Scarcity Pricing (i.e. Scarcity Pricing should only be initiated when there is a capacity shortage) as described under Section 4.1.5.
4.4.2.3.3 (1)
(2)
If there is a shortage of available capacity to meet Energy requirements on a system-wide basis, all LMPs will be set as described under Section 4.1.5.
Emergency Operations – Excess Generation
SPP operators may take any or all of the following actions, as time permits, within the Operating Hour to address excess generation conditions on either a system-wide or Reserve Zone basis, that were not alleviated through actions taken prior to the Operating Hour: (a)
Notify any remaining Resources not cleared for Regulation-Down Service that were not notified prior to the Operating Hour that those Resources will be dispatched down to their Minimum Emergency Capacity Operating Limits;
(b)
De-commit any remaining Resources that were Self-Committed following the Day-Ahead RUC process;
(c)
Curtail any remaining non-firm fixed Import Interchange Schedules pro-rata;
(d)
Curtail fixed firm Import Interchange Schedules pro-rata;
(e)
Reduce Resources with cleared Regulation-Down Service economically, as needed, down to Minimum Emergency Capacity Operating Limit;
(f)
Coordinate with Generation Operators, SPP BA Operator and SPP Reliability Coordinator to de-commit generation to meet power balance.
If actions taken under (1) above are not sufficient to relieve the excess generation condition in any Dispatch Interval either on a system-wide basis or Reserve Zone basis, LMPs will be set by the Offers prices associated with Energy down to the Minimum
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Emergency Capacity Operating Limit or zero, whichever is less, to the extent that the Regulation-Down requirement can be maintained. If the actions under (1) above create a Regulation-Down shortage during any Dispatch Interval either on a system-wide basis or Reserve Zone basis, the MCPs for Regulation-Down Service will reflect Scarcity Prices and LMPs will reflect negative Scarcity Prices as described under Section 4.1.5; (3)
Comment [MPRR102.348]: MPRR102 Awaiting implementation. #ER13-1748
In parallel with the actions under (1) above, if there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, SPP operators may take the following additional actions:
4.4.2.3.4
(a)
Identify and communicate with owners of Resources with greater than a 5% Generation Shift Factor (“GSF”) on the constraint and fixed Import Interchange Transactions with greater than a 3% transfer distribution factor on constraint;
(b)
Issue TLR to curtail any Interchange Transactions that may be contributing to the loading;
(c)
Commit Quick Start Resources in the constrained area if they can be redispatched with other Resources in constrained area to relieve constraint without contributing to the excess capacity situation.
Ensuring Reliable Operations
In the event of an emergency situation, SPP will follow the emergency procedures and communication guidelines as described in the Emergency Operating Plan (EOP). Market Participants must provide all necessary information and perform all necessary actions as described in the Emergency Operating Plan (EOP) on SPP.org 4.4.2.4
RTBM Results
Following execution of the RTBM SCED, the following results are communicated to Market Participants prior to the start of the applicable Dispatch Interval. All Market Participants must have the capability to receive and follow Resource Dispatch Instructions via XML in the event of an ICCP communications failure. The following results are communicated to each Market Participant that relates only to that Market Participant: (1)
Resource Dispatch Instructions. The Dispatch Instruction is a MW output target for the end of the applicable Dispatch Interval;
(2)
Cleared Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve MW by Resource.
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These values are used by the Energy Management System (EMS) for Energy and Regulation Deployment and by the Reserve Sharing System (RSS) for Contingency Reserve Deployment. The following results are communicated to all Market Participants and are used for settlement purposes (i.e. prices used for settlement are “ex-ante”); (1)
Locational Marginal Prices (LMPs) for each Settlement Location, the Marginal Congestion Component (MCC) of LMP for each Settlement Location and the Marginal Losses Component (MLC) of LMP for each Settlement Location; and
(2)
Market Clearing Prices for Regulation-Up Service, Expected Regulation-Up Mileage, Regulation-Down Service, Expected Regualtion-Down Mileage, Spinning Reserve and Supplemental Reserve for each Reserve Zone.
4.4.2.5
Comment [MPRR102.351]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.352]: MPRR102 Awaiting implementation. #ER13-1748
Out-of-Merit Energy (OOME) Dispatch
SPP may issue reliability instructions or directives via a Manual Dispatch Instruction to any online Resource to resolve an Emergency Condition or reliability issue the market system cannot resolve to prevent an Emergency Condition that the market cannot resolve (referred to in the system as OOME, or out-of-merit energy) or to resolve an Emergency Condition. In addition, a local transmission operator may request SPP to issue OOME dispatch directives to applicable on-line Resources to resolve or prevent an reliability issue Emergency Condition or may issue OOME dispatch directives directly to resolve a Local Emergency Condition. Time permitting, OOME dispatch directives will be issued by SPP. In such an event, a Resource will receive Setpoint Instructions via ICCP (and XML as backup) from SPP that include a Manual Dispatch Instruction for the duration of the reliability issuedirective or may receive a Manual Dispatch Instruction directly from a local transmission operator. The Manual Dispatch Instructions will specify the MW level the Resource is expected to produce until such time as the constraint can be resolved by SCED through the RTBM. Such MW levels may include (i) dispatch below a Resource’s Minimum Economic Capacity Operating Limit down to Minimum Normal Capacity Operating Limit or Minimum Emergency Capacity Operating Limit as system conditions warrant or (ii) dispatch above a Resource’s Maximum Economic Capacity Operating Limit up to Maximum Normal Capacity Operating Limit or Maximum Emergency Capacity Operating Limit as system conditions warrant. While the OOME instruction is active, the resource minimum and maximum limits will be treated as though they are equal to the OOME instruction. SPP will notify the Market Participant when the OOME event has ended systematically through XML and ICCP instructions. The A resource given a Manual Dispatch Instruction will not be eligible to clear reserve products during an OOME event. SPP will make every effort to define and activate
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Comment [MPRR155.358]: MPRR155 awaiting FERC filing
Comment [MPRR155.359]: MPRR155 awaiting FERC filing Comment [MPRR155.360]: MPRR155 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
the appropriate constraint. A Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility may only receive OOME instructions during an Emergency Condition or a reliability issue equivalent to a TLR 5 or greater. (1)
(2)
Comment [MPRR155.361]: MPRR155 awaiting FERC filing
When an OOME event occurs relating to a Local Emergency Condition, the local transmission operator may, when necessary, issue Manual Dispatch instructions directly to the affected Resource(s) and will notify SPP that it has done so, and SPP will ensure that the following occurs: (a)
Notifications are immediately issued that an OOME has been initiated and the MW level the resource is supposed to produce;
(b)
Setpoint Instructions and Economic/Emergency Minimum and Economic/Emergency Maximum Limits for the current dispatch interval are immediately adjusted to the OOME MW level that has been issued;
(c)
Setpoint Instructions for future intervals and Economic/Emergency Minimum and Economic/Emergency Maximum limits not yet dispatched will be set to the OOME MW level that has been issued; and
(d)
SPP notifies the Market Participant when the OOME event had ended systematically through XML and ICCP instructions;
To the extent that the OOME was initiated directly by a local transmission operator to address a Local Emergency Condition, Market Participants shall be compensated for such OOME events in accordance with Section 4.5.9.9 as if they had been issued a Manual Dispatch Instruction by SPP; except that if the Market Monitor determines that the Resource selected pursuant to Section 4.4.2.5(1) was selected by the local transmission operator in a discriminatory manner and the Resource was affiliated with the local transmission operator, such Resource shall not be eligible for compensation under Section 4.5.9.9. Such determination shall be made using the same standards and procedures prescribed for Resource selection in the Intra-Day Reliability Unit Commitment process, as set forth in Section 6.1.2.1 of Attachment AE to the Tariff. Recovery of any compensation shall be collected locally as described under Section 4.5.9.9.
(3) To the extent that the OOME was initiated by the Transmission Provider at the request of a local transmission operator to address a Local Reliability Issue, such Resources issued Manual Dispatch Instructions shall be selected by SPP in a non-discriminatory manner,
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which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. In such event, Market Participants shall be compensated for such OOME events in accordance with Section 4.5.9.9. The recovery of the compensation paid by the Transmission Provider shall be collected by the Transmission Provider locally as described under Section 4.5.9.9. (4)
To the extent that the OOME was initiated by the Transmission Provider to address Emergency Conditions or a reliability issue that the market systems could not resolve, such Resources issued Manual Dispatch Instructions shall be selected by SPP in a nondiscriminatory manner, which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. Recovery of compensation for Resources directly issued Manual Dispatch Instructions by SPP that are received under Section 4.5.9.9 shall be collected regionally under Section 4.5.12.
(5)
SPP, the local transmission operator, and affected Resource owners shall develop operating guides to be applied to OOMEs made by SPP including such commitments made at the request of the local transmission operator to relieve known and recurring Local Reliability Issues or by the local transmission operator to relieve known and recurring Local Emergency Conditions. Such Resources will be compensated in the same manner as any other Resource that is issued OOME directives. The recovery of the compensation paid by the Transmission Provider under Section 4.5.9.9 shall be collected by the Transmission Provider locally as described under Section 4.5.9.9.
4.4.2.5.1
Out-of-Merit Energy Dispatch for Emergency Conditions
In addition to the actions listed above, if If the OOME event is issued to resolve an Emergency
Comment [MPRR155.363]: MPRR155 awaiting FERC filing
Condition, SPP, in addition to the items listed in 4.4.2.5 (1), will do the following:
Comment [MPRR155.364]: MPRR155 awaiting FERC filing
1) declare Declare the Emergency Condition as soon as possible by, posting it on the SPP OASIS
Comment [MPRR155.365]: MPRR155 awaiting FERC filing
2) Communicate a Reliability Directive via phone call of the Manual Dispatch Instruction
Comment [MPRR155.366]: MPRR155 awaiting FERC filing
, andSPP will displace manual dispatch with a market solution as soon as possible consistent
Comment [MPRR155.367]: MPRR155 awaiting FERC filing
with system safety and reliability.
Comment [MPRR155.368]: MPRR155 awaiting FERC filing Comment [MPRR155.369]: MPRR155 awaiting FERC filing
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4.4.2.6
SPP Congestion Management
Except as provided for Emergency conditions as described under Section 4.4.2.5, when a constraint is observed in real-time, an SPP Congestion Management Event (CME) may be initiated and the constraint may be activated in RTBM. The CME can be initiated through declaration of a TLR and/or through an activation of a constraint in RTBM if an overload situation has been identified internal to the SPP Balancing Authority Area that does not require a TLR. SPP will declare a TLR if curtailable schedules exist in IDC above the curtailment threshold. A curtailable schedule is defined as a tagged SPP Interchange Transaction, external Market Flows and/or external non-market Balancing Authority flows. The CME will cause RTBM to produce a Security Constrained Economic Dispatch using all available dispatchable Resources to provide appropriate reduction in flows to relieve the constraint. An analysis will be performed to determine if curtailable schedules exist in IDC above the curtailment threshold for the current Operating Hour and the next hour. SPP will use RTBM to reliably manage and economically maximize the flow of power on flowgates to within the applicable operating limits as prescribed by NERC for CME events initiated either by IDC via a TLR or initiated through constraint activation for internal SPP constraints not requiring a TLR. 4.4.2.6.1
SPP Congestion Management under TLR Operations
If there are curtailable schedules in IDC at the SPP Congestion Management Event priority level in either the current Operating Hour or the next hour, a TLR will be requested through the IDC. When the TLR is requested, RTBM and the IDC will work jointly to manage congestion on constrained flowgates between the SPP Balancing Authority Area and the applicable external Balancing Authority Areas. The appropriate level of TLR must be requested in the IDC. The IDC will prescribe curtailments of curtailable schedules. The IDC will also prescribe curtailment of SPP Market Flows. SPP will then activate or continue activation of the constraint in RTBM. All Interchange Transaction curtailments are fed into RTOSS from the IDC. 4.4.2.6.2
Congestion Management - Market Flow
As required by the Congestion Management Process (CMP) (Attachment 1 of the SPP-MISO Joint Operating Agreement), SPP will determine and submit to the IDC its Market Flows on all SPP Coordinated Flowgates (CFs) and Reciprocal Coordinated Flowgates (RCFs). SPP’s CFs are flowgates identified as being impacted by activities within SPP. SPP’s RCFs are those
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flowgates identified as being impacted by activities within SPP and one or more entities operating under the requirements similar to those of the CMP. Currently those entities include SPP, MISO, MAPP, TVA and PJM. For additional details regarding the calculation of Market Flow, see SPP-MISO Joint Operating Agreement. 4.4.2.6.3
IDC Curtailments
The IDC will receive all tagged transactions involving SPP. Under SPP RTBM operations, the IDC will be responsible during TLR events for prescribing curtailment of certain types of tagged transactions and prescribing Market Flow relief that SPP must achieve internally. The IDC will be responsible for prescribing curtailment of only those tags associated with Interchange Transactions involving SPP for which impacts are not included in SPP’s Market Flows.
4.4.3
Energy and Operating Reserve Deployment
SPP deploys Energy, Regulation-Up Service, Regulation-Down Service, Spinning Reserve and on-line Supplemental Reserve simultaneously through the issuance of Setpoint Instructions via ICCP to each Resource on a 4-second basis. Deployment of Supplemental Reserve from off-line Quick-Start Resources is accomplished through SPP issuance of a start-up order following a Contingency Reserve event. The Setpoint Instruction is the sum of:
Comment [MPRR102.370]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.371]: MPRR102 Awaiting implementation. #ER13-1748
(1)
The Resource MW Dispatch Instruction for the current Dispatch Interval either as developed by SCED under Section 4.4.2.3.4 or by Manual Dispatch Instruction as described under Section 4.4.2.5;
(2)
Regulation-Up Service Deployment deployment Instructioninstruction;
Comment [MPRR102.372]: MPRR102 Awaiting implementation. #ER13-1748
(3)
Regulation-Down Service Deployment deployment Instructioninstruction;
Comment [MPRR102.373]: MPRR102 Awaiting implementation. #ER13-1748
(4)
Contingency Reserve Spinning Reserve Deployment Instruction for Spinning Reserve; and
Comment [MPRR102.374]: MPRR102 Awaiting implementation. #ER13-1748
(5)
Contingency Reserve On-line Supplemental Reserve Deployment Instruction for on-line Supplement Reserve.
Both a stepped and ramped Setpoint Instruction will be issued on a 4-second basis. The stepped Setpoint Instruction is a step change that represents the total amount of desired deployment. The ramped Setpoint Instruction also represents the total amount of desired deployment but the 4second instruction will change gradually towards the stepped Setpoint Instruction based on the
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Resource’s applicable ramp rate. Market Participants may use either the ramped or stepped Setpoint Instruction as input into their AGC systems. Graphical examples of stepped and ramped Setpoint Instructions are shown under Section 4.4.4.3. In the event of an ICCP communications failure, SPP will communicate Energy Dispatch Instructions to Market Participants via XML and Market Participants must have the capability to receive and follow such XML instructions. This requirement does not necessitate automatic integration of the XML instructions within the Market Participants control systems. 4.4.3.1
Dispatchable Variable Energy Resource Deployment
SPP shall provide a binary signal flag via ICCP (and XML as backup) which notifies the Dispatchable Variable Energy Resource (DVERs) to either “Follow” or “Ignore” the RTBM Dispatch Instruction.
When the “Follow” Dispatch Instruction signal is received, the
Dispatchable Variable Energy Resource shall follow the Setpoint Instruction and the Setpoint Instruction shall be equal to either (i) the sum of the RTBM Dispatch Instruction and Regulation Deployment Instruction instruction if cleared to provide Regulation-Down Service if Control Status is “Regulating”; or (ii) the RTBM Dispatch Instruction if Control Status is “NonRegulating” or “Manual”. In any Dispatch Interval in which the DVER dispatch flag is set to
Comment [MPRR102.378]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.379]: MPRR102 Awaiting implementation. #ER13-1748
“Ignore”, the Setpoint Instruction is calculated as the echo of actual SCADA output. DVERs may also receive a “Follow” and “OOME” dispatch instruction according to the rules in 4.4.2.5 4.4.3.2
Comment [MPRR155.380]: MPRR155 awaiting FERC filing
Non-Dispatchable Variable Energy Resource Deployment
Non-Dispatchable Variable Energy Resources (NDVERs) will be deployed the echo of actual SCADA output via ICCP (and XML as backup). During times when it is necessary to issue an OOME to a Non-Dispatchable Variable Energy Resource to resolve or prevent an Emergency
Comment [MPRR155.381]: MPRR155 awaiting FERC filing
Condition or a reliability issue, SPP will manually direct the Resource via telephone to a
Comment [MPRR155.382]: MPRR155 awaiting FERC filing
specified MW output. In addition, SPP will issue an Out-Of-Merit Energy dispatch instruction to the Resource in accordance with 4.4.2.5(1). If SPP needs to issue manual instructions to an
Comment [MPRR155.383]: MPRR155 awaiting FERC filing
NDVER to resolve or prevent an Emergency Condition, manual dispatch instructions will be Comment [MPRR155.384]: MPRR155 awaiting FERC filing
issued in accordance with the rules specified in 4.4.2.5
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4.4.3.3
Regulation Deployment
Regulation Deployment is limited to Resources that have cleared Regulation-Up Service and/or Regulation-Down Service with a Control Status of “Regulating”. Regulation-Up Service and/or Regulation-Down Service is deployed on specific Resources through Setpoint Instructions via the AGC system. The deployment is on a pro-rata basis, based upon Regulation-Up Service and/or Regulation-Down Service cleared MW and assigned priority group order. As the IntraDay RUC is run, it will populate the priority groups for each interval. Each of the RegulationUp Service and Regulation-Down Service cleared Resources will be assigned to a Regulation-Up Service and/or Regulation-Down Service priority group. If any Resources remain without a priority group assignment after the Intra-Day RUC is run, then RTBM will assign these Resources to the lowest priority group. The AGC system deploys starting with lowest priority group to highest group in the respective direction when regulation is needed in that direction. The number of priority groups is a configurable parameter that may be adjusted from time to time. SPP will analyze the market operations and will recommend to the MWG, ORWG and MOPC the number of priority groups it believes will produce the best operational results.
Comment [MPRR102.385]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.386]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.387]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.388]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.389]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.390]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.391]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.392]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.393]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.394]: MPRR102 Awaiting implementation. #ER13-1748
Resources are assigned to priority groups based on the three criteria below which are independent of each other: (1)
Reserve Zone in which the resource is located
(2)
The effective Ramp Rate of the resource
(3)
The number of priority groups
The first two criteria are made configurable to be switched ON or OFF independently or in conjunction with each other as deemed necessary for operational purposes. In the event that more than one priority group is designated for Regulation-Up Service or Regulation-Down Service, the third criterion is always in effect. When the first two criteria are both set to ‘off’ and the third criterion is greater than 1, Resources are randomly assigned to a priority group for an Intra-Day RUC interval. The initial configuration will be (1) off, (2) off, (3) = 1. If SPP's analysis shows that a change to the current configuration needs to occur, SPP attain approval for such change from the MWG, ORWG and MOPC, including the appropriate compensation and the effective date of the change. The active configuration will be posted on SPP OASIS. No Regulation Deployment will occur on Resources that have not cleared Regulation-Up Service and/or Regulation-Down Service even if their Control Statuses are set to “Regulating”.
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Comment [MPRR102.397]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.398]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Market Participants providing Regulation-Up Service and/or Regulation-Down service Service during the Operating Hour have an obligation to report to SPP when their Resources are no longer capable of providing the service due to physical problems with the associated Resources through submission of the applicable Resource Control Status via ICCP as described under Exhibit 4-14. If the problem persists into the next Operating Hour, that Market Participant must update its Resource Offer by submitting a Regulation-Up Service and Regulation-Down Service Dispatch Status as “Not-Qualified”. If a Market Participant fails to follow this procedure and SPP observes that a particular Resource is failing to provide the Regulation-Up Service or Regulation-Down Service service for 3 or more consecutive Dispatch Intervals, SPP may change the Resource’s regulation Dispatch Status to “Not-Qualified” and will contact the Market Participant to ascertain the nature of the problem. If the physical limitation is expected to be corrected within that Operating Hour, SPP will return the Resource’s Dispatch Status to “Market” or “Fixed”, as applicable when notified by the Market Participant. If the Market Participant fails to notify SPP within that Operating Hour and then fails to submit an updated Resource Offer indicating a Regulation-Up Service and/or Regulation Down Service Dispatch Status of “Not-Qualified”, SPP will change the Resource’s regulation Dispatch Status to “NotQualified” for the remainder of the Operating Day or the Market Participant notifies SPP that the physical limitation is corrected, whichever is shorter. Exhibit 4-15 shows the all of the available Resource Control Statuses in the AGC system.
Comment [MPRR102.399]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.400]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.401]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.402]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.403]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.404]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.405]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.406]: MPRR102 Awaiting implementation. #ER13-1748
Exhibit 4-15: AGC System Control Status Resource Control Status Off-Line Non-Regulating
Regulating
Manual
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Market Systems Impact Off-Line and not available to the RTBM. On-line, not capable of providing Regulation-Up Service or Regulation-Down serviceService, capable of providing online Contingency Reserve deployment and capable of following Dispatch Instructions. On-line, capable of providing Regulation-Up Service and/or Regulation-Down Service deployment, on-line Contingency Reserve deployment and following Dispatch Instructions. On-line, not capable of following Setpoint Instruction. Setpoint Instruction is an echo of the latest SCADA output or State Estimator solution output if SCADA is not available as long as the Resource does not have an active Contingency Reserve
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Comment [MPRR102.409]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.410]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Deployment Instruction. If the Resource has an active Contingency Reserve Deployment Instruction and is now in Manual Control Status, the Resource will receive a Setpoint Instruction that is equal to the sum of the RTBM Dispatch Instruction and the Contingency Reserve Deployment Instruction until the Contingency Reserve Deployment Instruction is terminated. 4.4.3.4
Contingency Reserve Deployment
Contingency Reserve procured in the RTBM will be deployed through a Contingency Reserve Deployment Instruction, via both Inter-Control Center Communications Protocol (ICCP) except in the case of a Block Demand Response Resource which receives an XML instruction, following a system event, normally following the sudden loss of a Resource. The following rules apply to the deployment of Contingency Reserve for both internal SPP BA contingencies and for providing assistance to a Reserve Sharing Group member. Scheduling procedures for provision of assistance to/from Reserve Sharing Group members are described under Section 4.4.3.5: (1)
Contingency Reserve is deployed on Resources with cleared Contingency Reserve and Export Interchange Transactions providing Supplemental Reserve in the Dispatch Interval immediately following the system event;
(2)
Spinning Reserve and on-line Supplemental Reserve is deployed ahead of off-line Supplemental Reserve;
(3)
A Resource with deployed Spinning Reserve and/or on-line Supplemental Reserve that moves into “Manual” Control Status will continue to be issued a Setpoint Instruction that includes the amount of Spinning Reserve and/or Supplemental Reserve deployed on that Resource as described under Exhibit 4-14;
(4)
If the amount of Spinning Reserve and on-line Supplemental Reserve cleared is greater than or equal to the Contingency Reserve amount required in response to a contingency, no off-line Supplemental Reserve is deployed;
(5)
Spinning Reserve and on-line Supplemental Reserve is deployed in proportion to the amount of Spinning Reserve and on-line Supplemental Reserve cleared on each Resource, adjusted as needed to ensure deliverability;
(6)
Supplemental Reserve from off-line Quick-Start Resources is deployed on Resources in merit order based on economics of Start-Up Offer, No-Load Offer, Energy Offer Curves
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and Minimum Run Time, adjusted as needed to ensure deliverability. For the purposes of deploying Supplemental Reserve supplied from Export Interchange Transactions, as described under Section 4.2.3.3, the merit order cost will be equal to zero; (7)
If a Resource fails all four of the tests described under Section 4.4.4.3 and the Resource’s individual smallest positive Shortfall Quantity is greater than 25% of the Contingency Reserve Deployment Instruction, the amount of Contingency Reserve available to be cleared on Resource will be reduced by that percentage based on the current Contingency Reserve Ramp Rate, for online deployment, or Maximum Quick-Start Response Limit for offline deployments, for the remainder of the Operating Day.
4.4.3.5
Reserve Sharing Group Scheduling Procedures
NERC Reliability Standards and applicable SPP Criteria will continue to dictate Contingency Reserve deployment between Reserve Sharing Group (RSG) members. Whereas SPP administers the reserve sharing program, the energy schedules implemented through the reserve sharing Contingency Reserve deployment, as created automatically by the Reserve Sharing System (RSS) are settled through the RTBM as either a fixed export schedule at the applicable External Interface Settlement Location LMP (SPP BA is providing assistance to a RSG member) or a fixed import schedule (SPP BA is receiving assistance from an RSG member) at the applicable External Interface Settlement Location LMP. Any additional compensation over and above the External Interface Settlement Location LMP as specified in the contractual arrangements between RSG members is also settled as part of the RTBM. Deployment of Contingency Reserve by the SPP BA to provide assistance to an RSG member shall be in accordance with the deployment procedures specified under Section 4.4.3.4. 4.4.3.6
Contingency Reserve Recovery
Following an Operating Reserve contingency, the SPP Balancing Authority will restore its Contingency Reserve to its pre-disturbance Contingency Reserve requirement by the end of the Assistance Period, which is defined in the SPP Criteria. During the Assistance Period, the RealTime Balancing Market will clear Contingency Reserve up to the pre-disturbance Contingency Reserve requirement or to the level of available capacity, whichever is less, and Scarcity Pricing will not apply.
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4.4.4
Energy and Operating Reserve Deployment Failure
Market Participants that fail to comply with Setpoint Instructions during Dispatch Intervals that do not include any Contingency Reserve deployment will incur a portion of RUC Make-Whole Payment Amount costs unless specifically exempted per Section 4.4.4.1.1 and may also incur Regulation Deployment failure charges. During any Dispatch Interval that includes a Contingency Reserve deployment, Uninstructed Resource Deviation does not apply on a Resource that is deployed for Contingency Reserve. However, Resources that are deployed for Contingency Reserve may be subject to Contingency Reserve deployment failure charges if these Resources fail to deploy the instructed amount of Contingency Reserve. Uninstructed Resource Deviation, Regulation Deployment failure charges and Contingency Reserve deployment failure charges are described in the following subsections. 4.4.4.1
Uninstructed Resource Deviation
The following rules apply to the calculation of Uninstructed Resource Deviation (URD). (1)
URD is the difference between a Resource’s actual average MW output over the Dispatch Interval and the Resource’s average ramped MW Setpoint Instruction over a Dispatch Interval. For the purposes of determining URD exemptions for Resources that are part of a Common Bus as described under Section 4.4.4.1.1(6), each Asset Owner’s Resources’ combined average ramped MW Setpoint Instruction and combined actual average MW output at the Common Bus will be used to calculate URD at the Common Bus for the Dispatch Interval for each Asset Owner;
(2)
A Resource’s URD is allocated a portion of the RUC Make-Whole Payment costs in any Dispatch Interval where Resource’s URD is outside of its Operating Tolerance unless that Resource has been exempted from URD under Section 4.4.4.1.1.
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(a)
A generating unit Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Emergency Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.
(b)
A Dispatchable Demand Response Resource’s Operating Tolerance in each Dispatch Interval is equal to the resource’s Maximum Emergency Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.
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4.4.4.1.1
(c)
A Block Demand Response Resource’s Operating Tolerance in each Dispatch Interval is equal to the resource’s Maximum Economic Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.
(d)
The Common Bus Operating Tolerance for each Asset Owner registered at a Common Bus is equal to the sum of that Asset Owner’s Resources’ Maximum Emergency Capacity Operating Limits for Resources that are on-line multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.
(e)
If the absolute value of a Resource’s URD is greater than the Resource’s Operating Tolerance in any Dispatch Interval, the Resource URD / 12 is included in the hourly allocation of RUC Make-Whole Payment cost allocation. The hourly URD amount is calculated as the sum of Dispatch Interval URD for the hour. See Section 4.5.9.10 for calculation details. Additionally, if that Resource was eligible to receive a RUC Make-Whole Payment, the payment may be reduced. See Section 4.5.9.8 for calculation details.
URD Exemptions
A Resource’s will receive a URD exemption in a Dispatch Interval shall be considered equal to zero (0) under the following situations: (1)
The Resource is deployed for Contingency Reserve as described under Section 4.4.3.4 or is deployed for a Contingency Reserve test as described under Sections 6.1.11.1 and 6.1.11.2;
(2)
The Resource trips or is derated after receiving Dispatch Instructions;
(3)
There is missing or bad Resource SCADA data in the Dispatch Interval;
(4)
During a system Emergency if the URD is associated with actual Resource output above the Resource’s Setpoint Instruction in a shortage condition or if the URD is associated with actual Resource output below the Resource’s Setpoint Instruction during an excess generation condition;
(5)
If a Dispatch Instruction is issued to a Resource beyond the reported capabilities due to the application of a VRL;
(6)
If the Resource is part of a Common Bus and the URD calculated at the Common Bus is less than the Operating Tolerance calculated at the Common Bus;
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Market Protocols for SPP Integrated Marketplace
(7)
(8)
A ResourceSPP may set will receive an Uninstructed Resource Deviation exemption to zero (0) to the extent a Market Participant can demonstrate the URD resulted from an event of Force force Majeure majeure or, in the case of a Variable Energy Resource, if the URD results from extremely high wind or other extreme weather-related conditions materially and directly impacting a Variable Energy Resource’s ability to provide or reduce the output of Energy. An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, or any order, regulation or restriction imposed by governmental military or lawfully established civilian authorities. A Force Majeure event does not include an act of negligence or intentional wrongdoing. The Market Participant must provide SPP with adequate documentation through the invoice dispute process in order for the Market Participant to be eligible to avoid such Uninstructed Resource Deviation. SPP shall determine through the dispute process whether such Uninstructed Resource Deviation should be waived For purposes of this subsection, the term force majeure shall have the meaning described under Section 10.1 of the SPP Tariff except that acts of Curtailment shall not qualify for exemption.
Comment [MPRR91.414]: MPRR91 awaiting FERC filing Comment [MPRR91.415]: MPRR91 awaiting FERC filing Comment [MPRR91.416]: MPRR91 awaiting FERC filing Comment [MPRR91.417]: MPRR91 awaiting FERC filing
Comment [MPRR91.418]: MPRR91 awaiting FERC filing
The Resource is issued an OOME instruction.
In the event a Resource does not receive a URD exemption in a Dispatch Interval, the Market Participant may provide SPP with adequate documentation through the dispute process in order for the Market Participant to be eligible to avoid such Uninstructed Resource Deviation. SPP shall determine through the dispute process whether an exemption will be given. Adequate documentation may include but is not limited to an audio file documenting a call between the Market Participant and SPP. 4.4.4.1.2
Comment [MPRR91.419]: MPRR91 awaiting FERC filing
Load Deviation Exemptions
A load is exempt from deviation based charges for cost allocation of RUC MWP under the following situations: (1)
The load Real-Time Billing Meter Quantity is less than its Day-Ahead Market cleared quantity during a capacity shortage condition Emergency;
4.4.4.2
Regulation Deployment Failure Charges
In any Dispatch Interval, if the URD of a Resource with cleared Regulation-Up Service, Regulation-Down Service or both is outside of the Resource’s Operating Tolerance, that Market
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Market Protocols for SPP Integrated Marketplace
Participant will incur a Regulation Deployment failure charge. The Regulation Deployment failure charge is described under Section 4.5.9.12. 4.4.4.3
Contingency Reserve Deployment Failure Charges
An Asset Owner receiving a Contingency Reserve Deployment Instruction must pass one of the following four tests in order to be in full compliance with the instruction. Each of these tests is performed either at the individual Resource level or at a Common Bus level if the Asset Owner’s Resource receiving the Contingency Reserve Deployment Instruction is registered at a Common Bus. A Resource that fails all four tests will receive a Contingency Reserve deployment failure charge as described under Section 4.5.9.16. The four tests are described as follows: (1)
Test 1: Test 1 compares the Resource expected output or Common Bus expected output at the end of the Contingency Reserve Deployment Period to the Resource actual output or Common Bus actual output as measured at the end of the Contingency Reserve Deployment Period. (a)
The expected output for Resources deployed for Spinning Reserve or on-line Supplemental Reserve is equal to the Resource’s instantaneous ramped Setpoint Instruction at the end of the Contingency Reserve Deployment Period.
(b)
The expected output for Resources deployed for off-line Supplemental Reserve is equal to the amount of Supplemental Reserve deployed.
(c)
The Common Bus expected output for an Asset Owner is equal to the sum of the expected outputs described under (a) and (b) above for all of the Asset Owner’s Resources at the Common Bus.
(d)
The Common Bus actual output is equal to the sum of actual outputs of all the Asset Owner’s Resources at the Common Bus.
Exhibit 4-16 provides an illustration of Test 1 showing Spinning Reserve deployment for a Resource or Common Bus that has passed Test 1 because the actual output at the end of the Contingency Reserve Deployment Period is greater than or equal to the expected output (Resource A Ramped Setpoint) resulting in a Shortfall Quantity that is equal to zero. An actual output that is less than the expected output would constitute a failure of Test 1 resulting in a Shortfall Quantity equal to the difference between the expected output and the actual output. Exhibit 4-16: Contingency Reserve Deployment Compliance Measurement – Test 1
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Event End
Event Start
Int 1
Int 2
Int 3
Int 4
Shortfall calculated here
Resource A Actual Resource A Stepped Setpoint Resource A Ramped Setpoint Expected Output Actual Output (SCADA)
(2)
Test 2: Test 2 also compares the Resource expected output or Common Bus expected output at the end of the Contingency Reserve Deployment Period to the Resource actual output or Common Bus actual output as measured at the end of the Contingency Reserve Deployment Period. (a)
The expected output for Resources deployed for Spinning Reserve or on-line Supplemental Reserve is equal to the Resource’s instantaneous stepped Setpoint Instruction at the end of the Contingency Reserve Deployment Period.
(b)
The expected output for Resources deployed for off-line Supplemental Reserve is equal to the amount of Supplemental Reserve deployed.
(c)
The Common Bus expected output for an Asset Owner is equal to the sum of the expected outputs described under (a) and (b) above for all of the Asset Owner’s Resources at the Common Bus.
(d)
The Common Bus actual output is equal to the sum of actual outputs of all the Asset Owner’s Resources at the Common Bus.
Exhibit 4-17 provides an illustration of Test 2 showing Spinning Reserve deployment for a Resource or Common Bus that has passed Test 2 because the actual output at the end of the Contingency Reserve Deployment Period is greater than or equal to the expected output (Resource A Stepped Setpoint) resulting in a Shortfall Quantity that is equal to zero. An actual
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output that is less than the expected output would constitute a failure of Test 2 resulting in a Shortfall Quantity equal to the difference between the expected output and the actual output. Exhibit 4-17: Contingency Reserve Deployment Compliance Measurement – Test 2
Event Start
Int 1
Event End
Int 2
Int 3
Int 4
Shortfall calculated here
Resource A Actual Resource A Stepped Setpoint Resource A Ramped Setpoint
Expected Output Actual Output (SCADA)
(3)
Test 3: Test 3 compares the change in Resource expected output or Common Bus expected output between the beginning and the end of the Contingency Reserve Deployment Period to the change in Resource actual output or Common Bus actual output between the beginning and the end of the Contingency Reserve Deployment Period.
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(a)
The change in expected output for Resources deployed for Spinning Reserve or on-line Supplemental Reserve is equal to the difference between the Resource’s instantaneous ramped Setpoint Instruction at the end of the Contingency Reserve Deployment Period and the Resource’s instantaneous ramped Setpoint Instruction at the beginning of the Contingency Reserve Deployment Period.
(b)
The change in expected output for Resources deployed for off-line Supplemental Reserve is equal to the amount of Supplemental Reserve deployed.
(c)
The change in Common Bus expected output is equal to the difference between: (i) the sum of the expected outputs described under (a) and (b) above at the end of
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the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus.; and (ii) the sum of the expected outputs described under (a) and (b) above at the beginning of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus. (d)
The change in Common Bus actual output is equal to the difference between: (i) the sum of all actual outputs at the end of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus; and (ii) the sum of all actual outputs at the beginning of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus.
Exhibit 4-18 provides an illustration of Test 3 showing Spinning Reserve deployment for a Resource or Common Bus that has passed Test 3 because the change in actual output is greater than or equal to the change in expected output (as measured using Resource A Ramped Setpoint) over the Contingency Reserve Deployment Period resulting in a Shortfall Quantity that is equal to zero. A change in actual output that is less than the change in expected output would constitute a failure of Test 3 resulting in a Shortfall Quantity equal to the difference between the change in expected output and the change in actual output.
Exhibit 4-18: Contingency Reserve Deployment Compliance Measurement – Test 3
Event Start
Int 1
Resource A Actual
Event End
Int 2
Int 3
Int 4
Shortfall calculated here
Delta Expected Output
Resource A Stepped Setpoint Resource A Ramped Setpoint Delta Actual Output
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(4)
Test 4: Test 4 also compares the change in Resource expected output or Common Bus expected output between the beginning and the end of the Contingency Reserve Deployment Period to the change in Resource actual output or Common Bus actual output between the beginning and the end of the Contingency Reserve Deployment Period except that the expected output is calculated using the stepped Setpoint Instruction. (a)
The change in expected output for Resources deployed for Spinning Reserve or on-line Supplemental Reserve is equal to the difference between the Resource’s instantaneous stepped Setpoint Instruction at the end of the Contingency Reserve Deployment Period and the Resource’s instantaneous stepped Setpoint Instruction at the beginning of the Contingency Reserve Deployment Period.
(b)
The change in expected output for Resources deployed for off-line Supplemental Reserve is equal to the amount of Supplemental Reserve deployed.
(c)
The change in Common Bus expected output is equal to the difference between: (i) the sum of the expected outputs described under (a) and (b) above at the end of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus; and (ii) the sum of the expected outputs described under (a) and (b) above at the beginning of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus.
(d)
The change in Common Bus actual output is equal to the difference between: (i) the sum of all actual outputs at the end of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus; and (ii) the sum of all actual outputs at the beginning of the Contingency Reserve Deployment Period for all of the Asset Owner’s Resources at the Common Bus.
Exhibit 4-19 provides an illustration of Test 4 showing Spinning Reserve deployment for a Resource or Common Bus that has passed Test 4 because the change in actual output is greater than or equal to the change in expected output (as measured using Resource A Stepped Setpoint) over the Contingency Reserve Deployment Period resulting in a Shortfall Quantity that is equal to zero. A change in actual output that is less than the change in expected output would constitute a failure of Test 4 resulting in a Shortfall Quantity equal to the difference between the change in expected output and the change in actual output. Exhibit 4-19: Contingency Reserve Deployment Compliance Measurement – Test 4
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Event End
Event Start
Int 1
Int 2
Int 3
Int 4
Shortfall calculated here
Delta Expected Output
Resource A Actual Resource A Stepped Setpoint Resource A Ramped Setpoint
Delta Actual Output
End of Deployment Period Telemetered (SCADA) Start of Deployment Period Telemetered (SCADA)
4.4.5
Inadvertent Management
SPP shall maintain inadvertent accounts and administer inadvertent payback for the SPP Balancing Authority Area. In doing so, SPP shall adhere to the following principles: (1)
Inadvertent payback shall be administered in accordance with NERC criteria, applicable Joint Operating Agreements, and Good Utility Practice;
(2)
Inadvertent payback decisions shall be made without regard to possible profits or losses resulting from changes in energy costs over time.
4.4.5.1
Inadvertent Payback Reporting
The SPP BA will report its Inadvertent Interchange balance with the applicable interconnection. SPP reporting will be consistent with the requirements and timelines for Balancing Authorities outlined in NERC Reliability Standard BAL-006-0. The SPP BA will manage and pay back its net Inadvertent Interchange balance following NAESB WEQBPS-005-000 Inadvertent Interchange payback. Inadvertent payback will be initiated based on an objective and publicly available process that is triggered on balances exceeding statistical norms. Inadvertent payback will be done during periods and in amounts such that payback will not burden others or interfere with time corrections. Financial gain will not factor into the decision to payback or recover inadvertent interchange.
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4.5
Post Operating Day and Settlement Activities
Post Operating Day activities begin on the day immediately following the Operating Day. SPP issues initial settlement statements for each Operating Day on the 7th day following the Operating Day and final settlement statements on the 47 th day following the Operating Day. Settlement statements will be configurable by Market Participants to show hourly net amounts or to show that Market Participant’s hourly and sub-hourly billing quantities at each Settlement Location to be paid or credited resulting from the DA Market and RTBM settlements. All charge types and billing determinants defined under Sections 4.5.8, 4.5.8.21, 4.5.9.24, 4.5.11, and 4.5.12 are available on the Settlement Statement and Settlement Determinant Report unless specifically excluded as identified in the table definitions under each charge type. Settlement Invoices are issued on weekly basis. Metering standards associated with submittal of actual load and Resource Energy quantities are specified in Appendix C and settlement data reporting processes are specified in Appendix D to these Market Protocols. Detailed explanations of all DA Market and RTBM charges types, along with example calculations, are contained within Appendix F to these Market Protocols. Exhibit 4-20 provides a representative overall timeline of Post Operating Day activities. Exhibit 4-20: Post Operating Day Activities Timeline 2/8 - 3/31 Issue Daily Initial Settlement Statements 2/4 MP Meter Data Submittal
3/16 MP Meter Data Submittal
2/1 - 3/31 Perform Settlement Calculations
2/1 - 3/31 Post Operating Day 2/7
2/14
2/21
2/28
3/7
3/14
3/21
3/28
2/1 MP Financial Transaction Submittal 2/1 - 2/4
3/31 Issue Invoice 2/18
Issue Invoice 2/25
Issue Invoice 3/4
Issue Invoice 3/11
Issue Invoice 3/18
Issue Invoice 3/25
Issue Daily Final Settlement Statements 3/20 - 3/31
A description of the DA Market and RTBM settlements is provided in the following subsections.
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4.5.1
Settlement Sign Conventions
Settlement statements use negative signs to reflect payments to Market Participants and positive signs to reflect charges to Market Participants. Throughout the settlement calculations, multiplication by (-1) is used to attain the proper sign convention. The following sign conventions are applied for settlement calculations: (1)
Cleared Resource MWh and Virtual Energy Offer MWh in the DA Market is negative value;
(2)
Cleared load MWh and Virtual Energy Bid MWh in the DA Market is a positive value;
(3)
Import Interchange Transaction MWh is a negative value;
(4)
Export Interchange Transaction MWh is a positive value;
(5)
Dispatch Instruction MW is a positive value;
(6)
Setpoint Instruction, Dispatch Instruction, Regulation-Up Service Deployment deployment instructions and Regulation-Down Service Deployment deployment instructions are positive value;
(7)
Cleared Operating Reserve MWs in the DA Market and RTBM are positive values;
(8)
Regulation-Up deployment MW and Regulation-Down deployment MW are positive values;
(9)
All MWs associated with TCRs are positive values;
(10) Actual Meter values and telemetered/State Estimator values for Resource output is a negative value; (11) Actual meter values and telemetered/State Estimator values for Load consumption is a positive value; (12) Net Actual Interchange out of the SPP BAA is a positive value; (13) Net Actual Interchange into the SPP BAA is a negative value; (14) Net Scheduled Interchange out of the SPP BAA is a positive value; (15) Net Scheduled Interchange into the SPP BAA is a negative value; (16) Inadvertent Energy out of the SPP Balancing Authority Area is a positive value; (17) Inadvertent Energy into the SPP Balancing Authority Area is a negative value.
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4.5.2
Commercial Model
The Commercial Model describes the financial market relationships of the Market Participants and the Asset Owners (AOs), and the commercial relationships among the elements of the Network Model. The hierarchy of relationships along with their descriptions is as follows. (1)
Node Level
(2)
Pricing Node Level (PNode) Level (a)
Aggregate Pricing Node Level (APNode) Level
(3)
Settlement Locations
(4)
Asset Owner Level
(5)
Market Participant Level
4.5.2.1
Nodes
Nodes represent Electrical Nodes (ENodes) within the Network Model where LMPs are calculated. ENodes represent the physical connection points in the Transmission System Network Model. ENodes include all locations in the Network Model where electrical equipment components (e.g. generators, loads, transmission lines, and transformers) connect but LMPs are calculated at only a subset of ENodes (i.e. Nodes). 4.5.2.2
Pricing Nodes
Pricing Nodes (PNodes) provide the linkage between the Network Model and the Commercial Model and are the finest level of granularity in the Commercial Model and have a one-to-one relationship with a Node. PNodes are defined for all locations where energy is injected and/or withdrawn from the Transmissions System, as well as other commercially significant buses. 4.5.2.2.1
Aggregated Pricing Nodes
The Aggregated Pricing Node (APNode) represents an aggregation of two or more PNodes using weighting factors. For each APNode, the relationship of PNodes to APNodes determines how Energy at the APNode level is allocated at the PNode/ENode level and/or how prices at the PNode level are weighted at the APNode level. This nodal relationship is maintained in SPP’s registration system. However, weighting factors may vary based on projected or historical injection/withdrawal values at each PNode for the applicable market process.
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4.5.2.3
Settlement Locations
Settlement Locations represent the next hierarchical level in the Commercial Model and have a relationship to a single PNode or APNode. Energy supply and demand is financially settled at the Settlement Locations based on the appropriate PNode or APNode LMP and Settlement Location energy injection or withdrawal level. There are five (5) types of Settlement Locations: Resource (including Pseudo-Tied Resources), Load (including Pseudo-Tied loads), Resource Hub, Trading Hub and Interface. 4.5.2.3.1
Hubs Establishment
Any Market Participant may utilize a Market Hub for financial and trading purposes in the DA Market, Real-Time Balancing Market, and/or ARR/TCR process. A Market Hub is a Settlement Location representing an aggregation of PNodes as defined by this Hubs Establishment process. SPP will post the identification of any approved Market Hub prior to the proposed effective date. The effective date of any initial Market Hub will be consistent with the start of the TCR Market. SPP shall use the following criteria to establish all Market Hubs: (1)
Each Market Hub shall contain a sufficient number of PNodes to ensure that a Market Hub Locational Marginal Price (LMP) can be calculated for that Market Hub at all times;
(2)
Each Market Hub shall contain a sufficient number of PNodes to ensure that the unavailability of, or an adjacent line outage to, any one PNode or set of PNodes would have only a minor impact on the Market Hub LMP;
(3)
Each Market Hub shall consist of PNodes with a relatively high rate of service availability; and
(4)
Each Market Hub shall consist of PNodes among which Transmission Service is relatively unconstrained.
(5)
A Market Hub shall not encompass the combined loads and Resources of a single vertically-integrated utility into a single Settlement Location.
SPP shall post the approved Market Hub at least 45 days prior to the proposed effective date. Any newly approved Market Hub will be added to the commercial model consistent with the commercial model updates for existing Market Participants set forth in Section 6.4, provided that the 45 day window has been met. 4.5.2.3.1.1 Resource Hubs
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A Resource Hub is a Settlement Location representing an aggregation of Resource PNodes as defined by the Hubs Establishment process. SPP will not limit the number of Resource Hubs established at any one time. The Resource Hub proposal may be comprised of any combination of Resource PNodes that the requesting Market Participant represents, consistent with the criteria defined in the Hubs Establishment process in Section 4.5.2.3.1. Proposals for creation of Resource Hubs shall be submitted by the Market Participants via the SPP Market Registration Portal within the Settlement Location update duration set forth in Appendix E. SPP Market Monitoring Unit will review the proposed Resource Hub for consistency with the criteria defined in the Hubs Establishment process in Section 4.5.2.3.1. 4.5.2.3.1.2 Trading Hubs SPP must establish and maintain at least one Trading Hub in accordance with the criteria specified in the Hubs Establishment process in Section 4.5.2.3.1. In addition, any Market Participant may propose the establishment of a Trading Hub through the submission of a hub proposal to the MWG. SPP will not limit the number of Trading Hubs established at any one time. The approval process for a Trading Hub as proposed by either SPP or a Market Participant is as follows: (1)
Submission of proposal of a Trading Hub via a Trading Hub proposal to the MWG;
(2)
MWG review to determine if the proposed Trading Hub should be considered for further analysis;
(3)
If approved for consideration, the Trading Hub proposal will be analyzed by SPP staff based on the criteria listed in 4.5.2.3.1;
(4)
SPP will bring back the results of the analysis at a subsequent meeting of the MWG for review to determine approval or rejection of the proposed Trading Hub;
If approved by the MWG, the proposal will go to the MOPC for approval. If not approved by the MWG, the Trading Hub proposal is considered rejected. 4.5.2.4
Asset Owners
The Asset Owner is the next higher hierarchical level in the Commercial Model and typically, but not necessarily, represents a company. A company may choose to be registered as more than one Asset Owner. Within the Commercial Model, Asset Owners can own any combination of generation, Load, ARR and/or TCR assets within the SPP Region. All Asset Owners must each be represented by a Market Participant. SPP calculates charges and produces market settlements
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statements for each Asset Owner. Each Settlement statement provides the billing determinants for each transaction, along with the Asset Owner’s total financial obligation resulting from its transactions. 4.5.2.5
Market Participants
The Market Participant is the highest hierarchical level in the Commercial Model and is the entity in the Commercial Model that is financially obligated to SPP for market settlements. A single Market Participant represents one or more Asset Owners. A single Market Participant may authorize other entities to act on its behalf. The Market Participant remains financially responsible for market settlements. Exhibit 4-21 provides an illustration of potential relationships within the Commercial Model. Exhibit 4-21: Example of Commercial Model Relationships
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Legend:
AO = Asset Owner MP = Market Participant G = Generator L = Load D = Demand Response
In additional to these defined financial relationships, the Commercial Model is also used to define and represent Loss Pools, Common Buses, Reserve Zones, Meter Data Submittal Locations, Meter Settlement Locations and Demand Response Load. These relationships are defined under Section 5.9, Market Registration.
4.5.3
Bilateral Settlement Schedules
Market Participants may create Bilateral Settlement Schedules for Energy and Operating Reserve obligation by registering and confirming the parameters of the agreement between buyer and seller such as the Schedule ID, Settlement Location, Reserve Zone, maximum allowable hourly quantity, market product, submitting party, auto-confirmation option and the effective & termination dates. Once this “header” information is validated and entered into the system by SPP, hourly quantities submitted reference the Schedule ID in order to be associated with all the parameters required for settlement calculations. In the event that either party no longer consents to participate in the Bilateral Settlement Schedule, the “header” information may be ended in advance of the original termination date effectively preventing further submittal of hourly quantities. In addition, if SPP encounters recurring settlement dispute activity relating to the use of the auto-confirmation option, SPP may remove that option from the header information for that Bilateral Settlement Schedule. Market Participants may submit Bilateral Settlement Schedule quantities for Energy and Operating Reserve obligation up to four (4) days following the applicable Operating Day for the Initial settlement. New submittals and revisions to previously submitted values may be submitted up to 44 days following the applicable Operating Day to be included in the Final settlement. The submittal timeline is subject to acceleration around holidays (see Section 4.5.14). Auto-confirmation applies to only the first submittal per Operating Day and must occur prior to the cutoff for the Initial settlement. Submittals 1) for agreements not using the autoconfirmation option, 2) beyond the cutoff date for the Initial settlement or 3) which update previous submittals must all be explicitly confirmed by the submitting party and counterparty except when the Bilateral Settlement Schedule is associated with an existing bilateral agreement
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under Section 4.5.3.1. Submittals not confirmed by both parties will not be included in any settlement execution. Transactions related to Bilateral Settlement Schedules for Energy must specify the Settlement Location, the MW amount, the buyer, the seller and which market it applies to (DA Market or RTBM) and must be for the physical transfer of Energy with title of the energy transferring from the seller to the buyer at the Settlement Location specified for the transaction. Market Participants that submit Bilateral Settlement Schedules for Energy shall use reasonable efforts to limit megawatt hours of such transactions to amounts reflecting the expected load and other physical obligations of the buyer under the bilateral contract. The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the specified MW amount (the equivalent of a Resource settlement) at the specified Settlement Location. Transactions related to Bilateral Settlement Schedules for Operating Reserve obligation must specify the buyer, the seller, the Operating Reserve product, the MW obligation transfer and the Reserve Zone within which the obligation transfer applies and must be for the physical transfer of energy associated with the Operating Reserve product with title of the Operating Reserve product transferring from the seller to the buyer at the Reserve Zone specified for the transaction (Operating Reserve Bilateral Settlement Schedules only apply to Day-Ahead Market cost allocation). The seller receives an increase in Operating Reserve obligation equal to the specified MW and the buyer receives a corresponding decrease in Operating Reserve obligation within the specified Reserve Zone. 4.5.3.1
Transition Mechanism for Pre-Existing Bilateral Contracts
To the extent that Market Participants are parties to bilateral contracts entered into prior to the start of the Integrated Marketplace, the rules specified under Section 8.2.1 of Attachment AE to the Tariff shall apply regarding submittal of Bilateral Settlement Schedules that are associated with such bilateral contracts. 4.5.3.2
GFA Carve Out Schedules – Internal
The GFA Responsible Entity must submit GFA Carve Out Schedules for all of the energy actually transacted under the GFA. These GFA Carve Out Schedules must be submitted in accordance with the requirements of Section 4.5.3, as specifically modified in Section 4.5.3.2. If no energy is transacted under the GFA, then no schedule is required and no GFA Carve Out
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treatment will be provided. Up to four (4) DA Market GFA Carve Out Schedules for energy may be required for each GFA Carve Out transaction: (1)
(2)
(3)
(4)
GFA Carve Out Schedule #1 (a) Seller: MP responsible for the source (b) Buyer: GFA Responsible Entity (c) Settlement Location: Source Settlement Location of the GFA transmission service GFA Carve Out Schedule #2 (a) Seller: GFA Responsible Entity (b) Buyer: GFA Carve Out account (c) Settlement Location: Source Settlement Location of the GFA transmission service GFA Carve Out Schedule #3 (a) Seller: GFA Carve Out account (b) Buyer: GFA Responsible Entity (c) Settlement Location: Sink Settlement Location of the GFA transmission service GFA Carve Out Schedule #4 (a) Seller: GFA Responsible Entity (b) Buyer: MP responsible for the sink (c) Settlement Location: Sink Settlement Location of the GFA transmission service
If the Market Participant that is responsible for the source is the same as the GFA Responsible Entity, then #1 above does not apply. If the Market Participant that is responsible for the sink is the same as the GFA Responsible Entity, then #4 above does not apply. The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the transacted MW amount at the specified Settlement Location. These Schedules will be settled at DA Market prices. The GFA Responsible Entity is responsible to ensure the consistency of the GFA Carve Out Schedules. The Market Monitor will monitor for gaming by GFA customers and such instances will be reported to the Commission’s Office of Enforcement, or its successor organization. The Transmission Provider shall publish a quarterly report listing the costs allocated to the market caused by the associated GFA Carve Outs. The report should also provide hourly and monthly deviations associated with the GFA Carve Out Schedules.
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4.5.3.3
GFA Carve Out Schedules – External
In addition to 4.5.3.2, if the source or sink of the energy receiving GFA Carve Out treatment is external to the SPP BA, a Fixed Interchange Transaction must be submitted and confirmed in the DA Market with sufficient capacity to cover the GFA Carve Out Schedule. The GFA Responsible Entity will ensure the values of the GFA Carve Out Schedules are equal to the lesser of the Day-Ahead cleared MW volume, energy actually transacted under the GFA or the RealTime hourly Interchange Transaction MW volume. 4.5.3.4
GFA Carve Out Uplift
GFA Carve Out Schedules result in removal of the energy, congestion, and marginal losses for the transaction from settlement statements. SPP will capture the congestion charges and marginal loss charges related to the GFA Carve Outs. These charges will be offset by the ARR/TCR settlement that would have been claimed for the GFA Carve Out under the normal ARR/TCR process and the distribution of the Marginal Loss Overcollection funds. Candidate ARRs associated with the GFA Carve Out service shall not be nominated for a product period if, based upon the twelve preceding months for which congestion data is available, such ARR, had it been converted to a TCR, would have resulted in a TcrFundHrlyAmt net charge to the holder of the TCR over that product period, as defined for the annual ARR allocation process. However, until twelve months of Integrated Marketplace data is available, SPP will use relevant data from both the EIS Market and the Integrated Marketplace to estimate whether the result is a net charge.
4.5.4
Calculation of LMPs, LMP Components and MCPs
SPP uses a co-optimized SCED model to compute Locational Marginal Prices (LMPs) for Energy at PNodes. The LMPs are then mapped to Settlement Locations in the commercial model. The SCED model also computes Market Clearing Prices (MCPs) for Regulation-Up Service, Regulation-Up Mileage, Regulation-Down Service, Regulation-Down Mileage, Spinning Reserve and Supplemental Reserve on a Reserve Zone basis. For the DA Market, LMPs and MCPs are calculated on an hourly basis. For the RTBM, LMPs and MCPs are calculated for each 5-minute Dispatch Interval. Inputs to SCED for the DA Market are as described under Section 4.3.1.1 and inputs to SCED for the RTBM are as described under Section 4.4.2.2. The following subsections further describe how LMPs, LMP Components and MCPs are calculated.
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4.5.4.1
LMP Calculations and LMP Components
The LMP at a PNode is the cost of delivering an incremental MW of energy at that specific PNode, while satisfying all operational constraints where such cost will include applicable Demand Curve prices if the incremental MW of energy causes a corresponding increase in shortage conditions where such Demand Curve prices and shortage conditions are as described under Section 4.1.5. The LMP at any PNode is the sum of three components; the marginal costs of Energy (Marginal Energy Component or MEC), the marginal cost of losses (Marginal Loss Component or MLC), and the marginal cost of congestion (Marginal Congestion Component or MCC). LMP Components at PNode i are calculated based upon the following formulas: LMPi = MEC + MLCi + MCCi Where:
4.5.4.1.1
(1)
MEC is the component of LMPi representing the marginal cost of Energy;
(2)
MLCi is the component of LMPi representing the marginal cost of losses at PNode i relative to the Reference Bus;
(3)
MCCi is the component of LMPi representing the marginal cost of congestion at ENode i relative to the Reference Bus; and
(4)
The Reference Bus represents the network Distributed Load Bus.
Marginal Losses Component Calculation
The MLCi at each PNode i is defined by the following equations: MLCi = -MLSFi * MEC MLSFi = (SPP Losses) / Pi Where:
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(1)
SPP Losses = SPP transmission system losses;
(2)
MLSFi = Marginal Loss Sensitivity Factor at PNode i;
(3)
MEC is the component of LMPi representing the marginal cost of Energy;
(4)
Pi = Net injection at PNode i.
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The MLSFi is a linearized estimate of the change in SPP transmission losses that will result from a 1 MW injection at PNode i coupled with a corresponding withdrawal at the Reference Bus to maintain global power balance (the withdrawal at the Reference Bus will generally be higher or lower than 1 MW since there will be a change in losses). Marginal loss sensitivity factors are dependent on topology, node injections and node withdrawals, and are only considered constant within a small deviation from a fixed operating point. 4.5.4.1.2
Marginal Congestion Component Calculation
The MCC at each PNode i is defined by the following equations K
MCCi = - (
Sensik * SPk )
k 1
Sensik = Flowk / Pi Where:
4.5.4.1.3
(1)
K is the number of transmission constraints;
(2)
Sensik is the linearized estimate of the change in the constraint k flow resulting from an incremental energy injection at PNode i coupled with an incremental energy withdrawal at the Reference Bus;
(3)
Flowk = Calculated flow for constraint k;
(4)
SPk = is the Shadow Price of constraint k;
(5)
Pi = Net injection at PNode i.
Marginal Energy Component Calculation
The MEC is defined as the computed LMP at the Reference Bus. By definition, MCC and MLC components are zero at the Reference Bus. 4.5.4.2
MCP Calculations
The MCP represents the cost of supplying an increment of operating reserve, taking into account lost opportunity cost and is composed of the marginal Operating Reserve costs and marginal costs associated with Operating Reserve scarcity. The DA Market and RTBM MCPs for Regulation-Up Service, Spinning Reserve and Supplemental Reserve at a Reserve Zone for Resources with cleared Regulation-Up Service, Spinning Reserve and/or Supplemental Reserve
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at that Reserve Zone are equal to the summation of the applicable Shadow Prices associated with each Operating Reserve constraint. This type of MCP formulation is referred to as “pricecascading”. MCPs applied to Excess Regulation-Up Mileage, Unused Regulation-Up Mileage. Excess Regulation-Down Mileage and Unused Regulation-Down Mileage are calculated for the RTBM only as described in (2) and (3) below. (1)
There are four sets of constraints: (i) an Operating Reserve constraint which is set equal to the sum of the Contingency Reserve requirement and the Regulation-Up requirement; (ii) a Regulation-Up Service plus Spinning Reserve constraint which is set equal to the sum of the Regulation-Up requirement and the Spinning Reserve requirement; and (iii) a Regulation-Up Service constraint which is set equal to the Regulation-Up requirement; and (iv) a Regulation-Down constraint which is set equal to the Regulation-Down requirement. These constraints apply on both a system-wide basis and a Reserve Zone basis. MCPs for each Reserve Zone are calculated as follows: (a)
(b)
(2)
The zonal Regulation-Up Service MCP is equal to sum of the system-wide and zonal Shadow Prices for the Regulation-Up constraint, Regulation-Up Service plus Spinning Reserve constraint and the Operating Reserve constraint; The zonal Spinning Reserve MCP is equal to the sum of the Shadow Prices for the system-wide and zonal Regulation-Up Service plus Spinning Reserve constraint and the Operating Reserve constraint;
(c)
The zonal Supplemental Reserve MCP is equal to the sum of the Shadow Price of the system-wide and zonal Operating Reserve constraint and
(d)
The zonal Regulation-Down MCP is equal to sum of the system-wide and zonal Shadow Prices for the Regulation-Down constraint.
RTBM MCPs for Expected Regulation-Up Mileage are set equal to the highest Regulation-Up Mileage Offer of all Resource’s economically cleared to provide Regulation-Up Service in a particular Dispatch Interval, multiplied by the Regulation-Up Mileage Factor. For Resource’s submitting a Regulation-Up Service Dispatch Status of “Fixed”, the cleared amount of Regulation-Up Service MW must be greater than the submitted “Fixed” MW in order to be considered economically cleared;
(2)(3) RTBM MCPs for Expected Regulation-Down Mileage are set equal to the highest Regulation-Down Mileage Offer of all Resource’s economically cleared to provide Regulation-Down Service in a particular Dispatch Interval, multiplied by the Regulation-
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Down Mileage Factor. For Resource’s submitting a Regulation-Down Service Dispatch Status of “Fixed”, the cleared amount of Regulation-Up Service MW must be greater than the submitted “Fixed” MW in order to be considered economically cleared;
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(3)(4) During times of Operating Reserve scarcity, MCPs will be impacted by Scarcity Prices as described under Section 4.1.5; (4)(5) The MCP formulations allow for the substitution of higher quality reserve products for lower quality reserve products to meet the Operating Reserve requirements to the extent that there is excess higher quality Operating Reserve available and these excess amounts provide a more economical solution. In the case of allowing RegulationUp Service to substitute for Contingency Reserve, only the Regulation-Up Offers will be used in the evaluation. Allowing for this substitution in combination with the “pricecascading” rules described in (1) above ensures that the clearing for Operating Reserve produces Regulation-Up Service MCPs that are greater than or equal to Spinning Reserve MCPs and Spinning Reserve MCPs that are greater than or equal to Supplemental Reserve MCPs; (a)
Regulation-Down is not eligible to substitute for Spinning Reserve and Supplemental Reserve. Therefore, Resource Regulation-Down Service MCPs can be less than Spinning Reserve and/or Supplemental Reserve MCPs.
(5)(6) The MCPs for the various Operating Reserve products as determined by the market clearing process will be sufficient to cover the Offer costs of each Resource as well as the opportunity costs incurred to allocate a portion of the Resource capacity to the supply of the corresponding Operating Reserve product in lieu of another product. The recovery of both offered cost and opportunity costs via Market Clearing Prices is inherent in the co-optimized SCED formulations, thus the separate calculation of opportunity costs is unnecessary.
4.5.5
Settlement Location LMPs and LMP Components
For Settlement Locations that are associated with more than one PNode, the following calculations are performed to calculate the Settlement Location LMPs and the associated LMP Components. The LMPs for Settlement Locations associated with a single PNode are those LMPs directly calculated by the DA Market software as described under Section 4.3.1.3 and the RTBM software as described under Section 4.4.2.3.4. All nodal LMPs are subject to the price correction procedures described under Section 7.
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4.5.5.1
Calculation of LMP at a Market Hub Settlement Location
SPP calculates an LMP for each Market Hub based on the LMPs for the set of PNodes that comprise the Market Hub. These Market Hub LMPs are the weighted average of the LMPs at the PNodes that comprise the Market Hub. The weighting factors for Market Hubs are predetermined and remain fixed as described under Section 4.3.1.1. These applicable weighting factors are applied for calculating an LMP, MCC and MLC at a Market Hub for both the DA Market and RTBM. The LMP for Hubj is: LMPHubj =
(Wk * LMPk )
(Wk * MCCk )
(Wk * MLCk )
k
The MCC for Hubj is: MCCHubj =
k
The MLC for Hubj is: MLCHubj =
k
Where: (1) Wk is the weighting factor for PNode k which is part of Hub j. The sum of the weighting factors for all PNodes k must sum to 1.0; (2) LMPk is the LMP for PNode k which is part of Hub j; (3) MCCk is the Marginal Congestion Component of the LMP for PNode k which is part of Hub j; (4) MLCk is the Marginal Losses Component of the LMP for PNode k which is part of Hub j.
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4.5.5.2
Calculation of LMP at a Load APNode Settlement Location
SPP calculates an LMP for each APNode Load Settlement Location based on the LMPs for the set of PNodes that comprise the APNode Load Settlement Location. These Load Settlement Location LMPs are the weighted average of the LMPs at the PNodes that comprise the Load Settlement Location. For both the DA Market and RTBM, the weighting factors are those described under Section 4.1.2.1.6 for each respective market. These weighting factors are applied for calculating the LMP, MCP and MLC for the APNode Load Settlement Location. The LMP for APNodej is: LMPAPNodej =
(Wk * LMPk )
(Wk * MCCk )
(Wk * MLCk )
k
The MCC for APNodej is: MCCAPNodej =
k
The MLC for APNodej is: MLCAPNodej =
k
Where: (1) Wk is the weighting factor for PNode k which is part of APNode j. The sum of the weighting factors for all PNodes k must sum to 1.0; (2) LMPk is the LMP for PNode k which is part of APNode j; (3) MCCk is the Marginal Congestion Component of the LMP for PNode k which is part of APNode j; (4) MLCk is the Marginal Losses Components of the LMP for PNode k which is part of APNode j.
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4.5.5.3
Calculation of LMP at an External Interface Settlement Location
SPP calculates an LMP for each External Interface based on the LMPs for the set of PNodes that comprise the External Interface. These External Interface LMPs are the weighted average of the LMPs at the PNodes that comprise the External Interface. The weighting factors are predetermined and remain fixed as described under Section 4.3.1.1. These weighting factors are applied for calculating a LMP, MCP and MLC at an External Interface for both the DA Market and RTBM. The LMP for External Interfacej is: LMPEIj =
(Wk * LMPk )
(Wk * MCCk )
(Wk * MLCk )
k
The MCC for External Interface j is: MCCEIj =
k
The MLC for External Interfacej is: MLCEIj =
k
Where: (1) Wk is the weighting factor for PNode k which is part of External Interface j. The sum of the weighting factors for all PNodes k must sum to 1.0; (2) LMPk is the LMP for PNode k which is part of External Interface j; (3) MCCk is the Marginal Congestion Components of the LMP for PNode k which is part of External Interface j; (4) MLCk is the LMP for PNode k which is part of External Interface j.
4.5.6
Precision and Rounding
Exhibit 4-22 documents the input data precision assumptions and the rounding assumptions related to calculated values for each intermediate bill determinant and all charge types. The Unit
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column corresponds to the Unit column included in the variable description tables included with each charge type. The rounding assumptions in Exhibit 4-22 under the Calculated Data are applied to all variable names that begin with a ‘#’. Exhibit 4-22: Input Data Precision and Rounding Assumptions Input Data Maximum Allowable Precision Unit Precision $/MW or $/MWh .0001 MWh .001 MW .001 Factor .0001 $ .01 (for cost data) Time (minutes) 1 (for Offer parameters)
4.5.7
Calculated Data Unit $ MWh MW Factor Rate
Rounding .01 .001 .001 .0001 .0001
FERC Electric Quarterly Reporting
In order to assist Market Participants in meeting their FERC Electric Quarterly Reporting (EQR) obligations, SPP has provided the required billing determinants under each applicable charge type These charge types along with the EQR transaction type for the billing determinant provided are summarized in the Exhibit 4-23 below.
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Exhibit 4-23: FERC EQR Reporting Billing Determinants Charge Type
EQR Transaction Type
EQR Reporting Interval
DA Market Energy Sale from Resource net of Bilateral Settlement Schedule
Hour
Price for DA Market Energy Sale from Resource net of Bilateral Settlement Schedule
Hour
DA Market Energy Sale from Export Transaction net of Bilateral Settlement Schedule
Hour
Price for DA Market Energy Sale from Export Transaction net of Bilateral Settlement Schedule
Hour
Day-Ahead Regulation-Up Service
DA Market Regulation-Up Service Sale by Resource by Hour
Hour
Comment [MPRR102.442]: MPRR102 Awaiting implementation. #ER13-1748
Price for DA Market Regulation-Up Service Sale by Resource by Hour
Hour
Comment [MPRR102.441]: MPRR102 Awaiting implementation. #ER13-1748
Day-Ahead Regulation-Down Service
DA Market Regulation-Down Service Sale by Resource by Hour
Hour
Comment [MPRR102.443]: MPRR102 Awaiting implementation. #ER13-1748
Price for DA Market Regulation-Down Service Sale by Resource by Hour
Hour
Comment [MPRR102.445]: MPRR102 Awaiting implementation. #ER13-1748
DA Market Spinning Reserve Sale by Resource
Hour
Comment [MPRR102.444]: MPRR102 Awaiting implementation. #ER13-1748
Prices for DA Market Spinning Reserve Sale by Resource
Hour
Comment [MPRR102.446]: MPRR102 Awaiting implementation. #ER13-1748
DA Market Supplemental Reserve Sale by Resource
Hour
Prices for DA Market Supplemental Reserve Sale by Resource
Hour
Day-Ahead Asset Energy
Day-Ahead Non-Asset Energy
Day-Ahead Spinning Reserve
Day-Ahead Supplemental Reserve Day-Ahead Make-Whole Payment
DA Market Make-Whole-Payment $ by Resource
Real-Time Asset Energy
RTBM net Energy transaction from Resource Settlement Location net of Bilateral Settlement Schedule, by Settlement Location
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Charge Type
Real-Time Non-Asset Energy
EQR Transaction Type
EQR Reporting Interval
Price for RTBM net Energy transaction from Resource Settlement Location net of Bilateral Settlement Schedule, by Settlement Location
Dispatch Interval
RTBM net Energy Sale net of Bilateral Settlement Schedule from External Interface Settlement Location, by Settlement Location
Dispatch Interval
Price for RTBM net Energy Sale net of Bilateral Settlement Schedule from External Interface Settlement Location, by Settlement Location
Dispatch Interval
Comment [MPRR102.448]: MPRR102 Awaiting implementation. #ER13-1748
RTBM net Regulation-Up Service transaction by Resource
Dispatch Interval
Comment [MPRR102.449]: MPRR102 Awaiting implementation. #ER13-1748
Price for RTBM net Regulation-Up Service transaction by Resource
Dispatch Interval
Comment [MPRR204.450]: MPRR204 Awaiting FERC filing
RTBM Excess Regulation-Up Mileage transaction by Resource
Dispatch Interval
Comment [MPRR102.447]: MPRR102 Awaiting implementation. #ER13-1748
Price for RTBM Excess Regulation-Up Mileage transaction by Resource
Dispatch Interval
Comment [MPRR204.451]: MPRR204 Awaiting FERC filing
RTBM Unused Regulation-Up Mileage transaction by Resource
Dispatch Interval
Comment [MPRR204.452]: MPRR204 Awaiting FERC filing
Price for RTBM Unused Regulation-Up Mileage transaction by Resource
Dispatch Interval
Comment [MPRR204.453]: MPRR204 Awaiting FERC filing
RTBM net Regulation-Down Service transaction by Resource
Dispatch Interval
Comment [MPRR102.455]: MPRR102 Awaiting implementation. #ER13-1748
Price for RTBM net Regulation-Down Service transaction by Resource
Dispatch Interval
Comment [MPRR102.456]: MPRR102 Awaiting implementation. #ER13-1748
RTBM Excess Regulation-Down Mileage transaction by Resource
Dispatch Interval
Comment [MPRR204.457]: MPRR204 Awaiting FERC filing
Price for RTBM Excess Regulation-Down Mileage transaction by Resource
Dispatch Interval
Comment [MPRR102.454]: MPRR102 Awaiting implementation. #ER13-1748
RTBM Unused Regulation-Down Mileage transaction by Resource
Dispatch Interval
Comment [MPRR204.458]: MPRR204 Awaiting FERC filing
Price for RTBM Unused Regulation-Down Mileage transaction by Resource
Dispatch Interval
RTBM net Spinning Reserve transaction by Resource
Dispatch Interval
Real-Time Regulation-Up Service
Real-Time Regulation-Down Service
Real-Time Spinning Reserve
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Charge Type
EQR Transaction Type
EQR Reporting Interval
Price for RTBM net Spinning Reserve transaction by Resource
Dispatch Interval
RTBM net Supplemental Reserve transaction by Resource
Dispatch Interval
Price for RTBM net Supplemental Reserve transaction by Resource
Dispatch Interval
Real-Time Supplemental Reserve RUC Make-WholePayment Eligibility Period
RUC Make-Whole Payment
RUC Make-Whole-Payment $ by Resource
Real-Time Out-of-Merit
RTBM Out-of-Merit Energy and Operating Reserve $ by Resource
Dispatch Interval
Real-Time Regulation Deployment Adjustment
RTBM Regulation Deployment Adjustment $ by Resource
Dispatch Interval
Real-Time Unused RegulationUp Mileage Make Whole Payment Real-Time Unused RegulationDown Mileage Make Whole Payment
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RTBM Unused Regulation-Up Mileage Make Whole Payment MW Quantity and $ by Resource
RTBM Unused Regulation-Down Mileage Make Whole Payment MW Quantity and $ by Resource
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4.5.8
Day-Ahead Market Settlement
Settlement calculations for Energy and Operating Reserve in the DA Market are performed on an hourly basis for each Operating Day and are based upon the results of the DA Market clearing for that Operating Day. (1)
(2)
(3)
Each Market Participant with cleared Offers is paid for each Settlement Location: (a)
For the amount of physical Energy sold, net of Bilateral Settlement Schedules for Energy, at the associated LMP (see Sections 4.5.8.1 and 4.5.8.2);
(b)
For the amount of virtual Energy sold at the associated LMP (see Sections 4.5.8.3 and 4.5.8.20);
(c)
For the amount of Regulation-Up Service sold at the associated Regulation-Up Service MCP (see Section 4.5.8.4);
(d)
For the amount of Regulation-Down Service sold at the associated RegulationDown Service MCP (see Section 4.5.8.5);
(e)
For the amount of Spinning Reserve sold at the associated Spinning Reserve MCP (see Section 4.5.8.6); and
(f)
For the amount of Supplemental Reserve sold at the associated Supplemental Reserve MCP (see Section 4.5.8.7).
Each Market Participant with cleared Bids is charged for each Settlement Location: (a)
For the amount of physical Energy purchased, net of Bilateral Settlement Schedules for Energy, at the associated LMP (see Sections 4.5.8.1 and 4.5.8.2); and
(b)
For the amount of virtual Energy purchased at the associated LMP (see Sections 4.5.8.3 and 4.5.8.20).
Charges to Market Participants for Operating Reserve procured in the DA Market are calculated on a Reserve Zone basis by multiplying the Reserve Zone Operating Reserve procurement rate by each Asset Owner’s DA Market Operating Reserve Reserve Zone Obligation. See Sections 4.5.8.8, 4.5.8.9, 4.5.8.10, and 4.5.8.11 for additional details; (a)
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the Reserve Zone DA Market Operating Reserve product obligation divided by the DA Market Reserve Zone Operating Reserve obligation. (b)
For Reserve Zones where Operating Reserve procured is more than the entire obligation in the zone, the DA Market Operating Reserve procurement cost is equal to the clearing price for DA Market Operating Reserve for that zone, multiplied by the zone obligation. For Reserve Zones where Operating Reserve procured is less than the entire obligation in the zone, the DA Market Operating Reserve procurement cost is the weighted average of (1) the clearing price for DA Market Operating Reserve for that zone and (2) the average clearing price for the DA Market Operating Reserve procured and imported from other zones, multiplied by the zone obligation.
(4)
Market Participants of SPP committed Resources in the DA Market will also receive a make whole payment if the total revenues received for Energy and Operating Reserve sales in the DA Market settlement are less than the Resource’s Offer costs associated with those sales. Make-Whole payments are calculated on a commitment period basis and are collected on a daily basis from Asset Owners based upon their pro-rata share of the sum of all Demand Bids, Export Interchange Transaction Bids and Virtual Energy Bids cleared in the Day-Ahead Market for the Operating Day. See Sections 4.5.8.12, and 4.5.8.13 for additional details;
(5)
Settlements related to congestion management are also performed as part of the DayAhead Market settlement as follows;
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(a)
Holders of TCRs are paid (or charged) for the amount of TCRs held between a particular source and sink at the difference between the sink MCC and the source MCC. See Section 4.5.8.14 for additional details.
(b)
To the extent that there are insufficient congestion revenues collected in an Operating Day to fully fund TCR holders, TCR holders are charged a pro-rata uplift amount to cover the under collection based upon each TCR holder’s net charges or credits for the Operating Day. If there is excess congestion revenues collected in an Operating Day, the excess is carried for use at the end of the month. See Section 4.5.8.15 for additional details.
(c)
At the end of each month, if there are excess congestion revenues available, these revenues are used to reimburse TCR holders that received an uplift charge for Operating Days during that month. Each TCR holder is reimbursed a pro-rata
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share of the uplift charges paid based upon the level of uplift charges paid until they are fully reimbursed or the excess congestion revenues are depleted. To the extent that there are excess congestion revenues remaining after fully reimbursing TCR holders, this excess is carried forward for use at the end of the year. See Section 4.5.8.16 for additional details.
(6)
(d)
At the end of each year, if there are excess congestion revenues available, these revenues are used to reimburse TCR holders that received an uplift charge for Operating Days during that year that were not fully reimbursed. Each TCR holder is reimbursed a pro-rata share of the remaining uplift charges paid based upon the level of remaining uplift charges paid until they are fully reimbursed or the excess congestion revenues are depleted. See Section 4.5.8.17 for additional details.
(e)
To the extent that there are excess congestion revenues remaining at the end of the year after fully reimbursing TCR holders, this excess is distributed back to ARR holders pro-rata based upon their annual ARR Nomination Caps. See Section 4.5.8.18 for additional details.
Settlement associated with revenue over collection due to the impact of marginal losses on the DA Market LMPs is also performed as part of the Day-Ahead Market settlement as follows. Seedesrcibe under Section 4.5.9.204.5.8.19 for calculation details. (a)
For each Loss Pool, a proxy loss charge contribution amount is developed for each Settlement Location with a net withdrawal that is equal to the positive difference between the MLC at the net withdrawal Settlement Location and the weighted average MLC of all net injections assumed to be serving the net withdrawal, multiplied by that Settlement Location’s net withdrawal. These values are then summed to calculate a Loss Pool proxy loss charge contribution. (i) The net injections assumed to be serving the net withdrawal are the net injections at the Settlement Locations included in the Loss Pool. To the extent that the net injections in the Loss Pool are not sufficient to serve the net withdrawals in the Loss Pool, net injections from an injection exchange are included to make up the difference. To the extent that the net injections in the Loss Pool are greater than the net withdrawals in the Loss Pool, the excess is added to the injection exchange.
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(ii) The injection exchange is comprised of quantities from Loss Pools in which injection exceeds withdrawal. A weighted average of the MLC at the source of these quantities establishes a reference for the component of the loss charge contributions at Settlement Locations with net withdrawal met from outside the Loss Pool.
(7)
(b)
The Loss Pool proxy loss charge contribution calculated in (a) above are then used to allocate the total DA Market loss over-collections dollars to each Loss Pool on a pro rata basis.
(c)
Each Asset Owner’s credit for over collected losses in each Loss Pool at each withdrawal Settlement Location within that Loss Pool is then equal a pro-rata share of the total marginal losses over collection allocated to that Loss Pool. The pro-rata share is calculated as an Asset Owner’s Settlement Location withdrawal divided by the sum of all Asset Owner Settlement Location withdrawals within that Loss Pool. An Asset Owner’s Settlement Location withdrawal is equal to the maximum of (i) zero or (ii) the sum of cleared Demand Bids, cleared Resource Offers, cleared Export Interchange Transactions, cleared Import Interchange Transactions and Bilateral Settlement Schedules for Energy, including those associated with GFA Carve Outs, at that Settlement Location. Asset Owner credits associated with GFA Carve Outs are used to offset GFA Carve Out costs through inclusion of such credits under Section 4.5.8.23.
Demand reduction credits to Market Participants associated with a load Settlement Location that contains a Demand Response Resource are calculated as part of the DayAhead Market settlement in order to ensure that, on a net settlement basis, the charge associated with that load Settlement Location is reflective of the net load (i.e. the load including the impact of a cleared Demand Response Resource). For example, consider a load Settlement Location that consists of a single PNode and that PNode also represents a Demand Response Load that is associated with a Dispatchable Demand Response (DDR) Resource. The Market Participant for the load Settlement Location submits a fixed Demand Bid of 100 MW, which is reflective of that location’s actual load consumption in real-time, assuming that there is no load reduction (i.e. this value represents the baseline value for the DRL that will be submitted for use in realtime). The Market Participant for the DDR Resource submits a Resource Offer that results in the DDR clearing for 20 MWs of Energy. Therefore, the net load consumption at the load Settlement Location is actually 80 MWs and the load settlement amount needs
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to reflect that. If we assume that LMP is $50/MWh, the net settlement at the load Settlement Location would be: Energy Charge: 100 MW * $50/MWh= $5000 Demand Reduction Credit = -20 MW * $50/MWh = ($1000) Net Load Settlement Location Settlement = $4000 The net $4000 charge is the same as the charge that would have been calculated using the net load of 80 MW multiplied by the $50/MWh LMP. However, in order to ensure proper deviation accounting in real-time, the 100 MW of cleared load and the 20 MW of cleared DDR output is used to calculate real-time deviations from cleared Day-Ahead Market amounts. See Section 4.5.8.21 for additional calculation details. (8)
Charges to Market Participants for recovery of Day-Ahead Market demand reduction credits are calculated on a system-wide basis by multiplying the demand reduction charge rate by each Market Participant’s Day-Ahead Market demand reduction obligation. See Sections 4.5.8.22 for additional details; (a) The demand reduction charge rate is equal to the total amount of demand reduction credits paid to load divided by the system-wide total cleared withdrawals (Demand Bids, Virtual Bids and Export Interchange Transaction Bids). (b) Each Market Participant’s demand reduction obligation is equal to that Market Participant’s total cleared withdrawals (Demand Bids, Virtual Bids and Export Interchange Transaction Bids).
The following subsections describe the DA Market settlement charge types. For each charge type, the calculation is performed at the hourly level for each Asset Owner at each Settlement Location. In addition to the hourly values, daily values will be accessible on the Settlement Statement for all charge types. 4.5.8.1 (1)
Day-Ahead Asset Energy Amount A DA Market credit or charge for net physical Energy activity associated with load and Resources, adjusted for Bilateral Settlement Schedules for Energy, is calculated at each Settlement Location for each Asset Owner for each Hour. The net amount is calculated as follows:
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#DaEnergyHrlyAmt a, s, h = DaLmpHrlyPrc s, h * ( DaClrdHrlyQty a, s, h -
DaEnFinHrlyQty a, s, h, t )
t
(2)
For each Asset Owner, a daily amount is calculated at each Settlement Location. The net daily amount is calculated as follows: DaEnergyDlyAmt a, s, d =
DaEnergyHrlyAmt a, s, h
h
(3)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows: DaEnergyAoAmt a, m, d =
DaEnergyDlyAmt a, s, d
s
(4)
For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net amount is calculated as follows: DaEnergyMpAmt m, d =
DaEnergyAoAmt a, m, d
a
(5)
For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows: (a)
#EqrDaAssetEnergyHrlyQty a, s, h = (-1) * Min(0, DaClrdHrlyQty a, s, h -
DaEnFinHrlyQty a, s, h, t )
t
(b)
IF #EqrDaAssetEnergyHrlyQty a, s, h > 0 THEN #EqrDaAssetEnergyHrlyPrc a, s, h = DaLmpHrlyPrc s, h
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The above variables are defined as follows: Variable
Unit
Settlement Interval
$
Hour
$/MWh
Hour
DaClrdHrlyQty a, s, h
MWh
Hour
DaEnFinHrlyQty a, s, h, t
MWh
Hour
DaEnergyDlyAmt a, s, d
$
Operating Day
DaEnergyAoAmt a, m, d
$
Operating Day
DaEnergyHrlyAmt a, s, h
DaLmpHrlyPrc s, h
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Definition
Day-Ahead Asset Energy Amount per AO per Settlement Location per Hour - The DA Market amount to AO a for net cleared Resource’s and load, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Hour. Day-Ahead LMP - The DA Market LMP at Settlement Location s for the Hour. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour - The total net quantity of Energy represented by AO a’s DA Market cleared Resource Offers and Demand Bids in the DA Market at Settlement Location s for the Hour. Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Asset Settlement Location s, for each transaction t, for the Hour. The buyer AO quantity is a positive value and the seller AO quantity is a negative value. Day-Ahead Asset Energy Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Operating Day. Day-Ahead Asset Energy Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day.
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Variable
Unit
Settlement Interval
Definition
$
Operating Day
EqrDaAssetEnergyHrlyQty a, s, h
MWh
Hour
EqrDaAssetEnergyHrlyPrc a, s, h
$/MWh
Hour
a s t
none none none
none none none
h d m
none none none
none none none
Day-Ahead Asset Energy Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day. Day-Ahead Electric Quarterly Reporting Asset Energy Sales per AO per Settlement Location per Hour – AO a’s DA Market Energy sales at Resource Settlement Location s, net of Bilateral Settlement Schedules, in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Electric Quarterly Reporting Asset Energy Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Energy sales price at Resource Settlement Location s, net of Bilateral Settlement Schedules, in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner. A Settlement Location. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Hour. An Operating Day. A Market Participant.
DaEnergyMpAmt m, d
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4.5.8.2 (1)
Day-Ahead Non-Asset Energy Amount A DA Market credit or charge for net physical Energy activity associated Interchange Transactions, adjusted for Bilateral Settlement Schedules for Energy, is calculated at each Settlement Location for each Asset Owner for each Hour. The net amount is calculated as follows:
#DaNEnergyHrlyAmt a, s, h = DaLmpHrlyPrc s, h * (
i
-
( DaImpExp5minQty a, s, i, t, / 12)
t
DaNEnFinHrlyQty a, s, h, t )
t
(2)
For each Asset Owner, a daily amount is calculated at each Settlement Location. The net daily amount is calculated as follows: DaNEnergyDlyAmt a, s, d =
DaNEnergyHrlyAmt a, s, h
h
(3)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows: DaNEnergyAoAmt a, m, d =
DaNEnergyDlyAmt a, s, d
s
(4)
For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net daily amount is calculated as follows: DaNEnergyMpAmt m, d =
DaNEnergyAoAmt a, m, d
a
(5)
For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows: (a)
#EqrDaNAssetEnergyHrlyQty a, s, h = -1* Min[ 0 ,( i
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t
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-
DaNEnFinHrlyQty a, s, h, t ) ]
t
(b)
IF #EqrDaNAssetEnergyHrlyQty a, s, h > 0 THEN #EqrDaNAssetEnergyHrlyPrc a, s, h = DaLmpHrlyPrc s, h
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
$/MWh
Hour
DaNEnFinHrlyQty a, s, h, t
MWh
Hour
DaImpExp5minQty a, s, i, t
MW
Dispatch Interval
DaNEnergyDlyAmt a, s, d
$
Operating Day
DaNEnergyAoAmt a, m, d
$
Operating Day
Day-Ahead Non-Asset Energy Amount per AO per Settlement Location per Hour - The DA Market amount to AO a for net cleared Interchange Transactions, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Hour. Day-Ahead LMP - The DA Market LMP at Settlement Location s for the Hour. Day-Ahead Non-Asset Energy Bilateral Settlement Schedule for Energy per Transaction per AO per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Non-Asset Settlement Location s, for each transaction t, for the Hour. The buyer AO quantity is a positive value and the seller AO quantity is a negative value. Day-Ahead Interchange Transaction Quantity per AO per Transaction per Settlement Location per Dispatch Interval - The quantity of energy represented by AO a’s Interchange Transactions in the DA Market at Settlement Location s, for each tagged transaction t, for the Dispatch Interval. Transaction ramping will be ignored. Day-Ahead Non-Asset Energy Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Operating Day. Day-Ahead Non-Asset Energy Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day.
DaNEnergyHrlyAmt a, s, h
DaLmpHrlyPrc s, h
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Variable
Unit
Settlement Interval
Definition
$
Operating Day
EqrDaNAssetEnergyHrlyQty a, s, h
MWh
Hour
EqrDaNAssetEnergyHrlyPrc a, s, h
$/MWh
Hour
a s t
none none none
none none none
h d m
none none none
none none none
Day-Ahead Non-Asset Energy Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day. Day-Ahead Electric Quarterly Reporting Non-Asset Energy Sales per AO per Settlement Location per Hour – AO a’s Energy sales at External Interface Settlement Location s, net of Bilateral Settlement Schedules, in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Electric Quarterly Reporting Non-Asset Energy Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Energy sales price at External Interface Settlement Location s, net of Bilateral Settlement Schedules, in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner. A Settlement Location. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Hour. An Operating Day. A Market Participant.
DaNEnergyMpAmt m, d
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4.5.8.3
Day-Ahead Virtual Energy Amount
(1) A DA Market credit or charge for net virtual Energy activity will be calculated at each Settlement Location for each Asset Owner for each hour. The net amount is calculated as follows: #DaVEnergyHrlyAmt a, s, h = DaLmpHrlyPrc s, h *
DaClrdVHrlyQty a, s, h, t
t
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The net daily amount is calculated as follows: DaVEnergyDlyAmt a, s, d =
DaVEnergyHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows: DaVEnergyAoAmt a, m, d =
DaVEnergyDlyAmt a, s, d
s
(4) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net daily amount is calculated as follows: DaVEnergyMpAmt m, d =
DaVEnergyAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
$
Hour
$/MWh
Hour
DaClrdVHrlyQty a, s, h, t
MWh
Hour
DaVEnergyDlyAmt a, s, d
$
Operating Day
DaVEnergyAoAmt a, m,
$
Operating Day
$
Operating Day
none none none
none none none
DaVEnergyHrlyAmt a, s, h
DaLmpHrlyPrc s, h
DaVEnergyMpAmt m, d
a h s
Version 23.a
d
Definition
Day-Ahead Virtual Energy Amount per AO per Settlement Location per Hour - The DA Market amount to AO a for net cleared Virtual Energy Offers and Virtual Energy Bids at Settlement Location s for the Hour. Day-Ahead LMP – The value described under Section 4.5.8.1. Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour - The virtual energy quantity represented by AO a’s cleared Virtual Energy Offers and Virtual Demand Bids in the DA Market at Settlement Location s for each transaction t for the Hour. Day-Ahead Virtual Energy Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for net cleared virtual offers and bids, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Operating Day. Day-Ahead Virtual Energy Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for net cleared virtual offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day. Day-Ahead Virtual Energy Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for net cleared virtual offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day. An Asset Owner. An Hour. A Settlement Location.
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Variable
Unit
Settlement Interval
Definition
t
none
none
d m
none none
none none
A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
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4.5.8.4
Comment [MPRR102.468]: MPRR102 Awaiting implementation. #ER13-1748
Day-Ahead Regulation-Up Service Amount
(1) A DA Market credit or charge4 for cleared Regulation-Up Service will be calculated at each Settlement Location for each Asset Owner for each hour. The amount will be calculated as follows: #DaRegUpHrlyAmt a, s, h =
(DaRegUpMcpHrlyPrc z, h * DaRegUpHrlyQty a, z, s, h )
z
* (-1) (2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: DaRegUpDlyAmt a, s, d =
DaRegUpHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaRegUpAoAmt a, m, d =
DaRegUpDlyAmt a, s, d
s
(4) 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: DaRegUpMpAmt m, d =
DaRegUpAoAmt a, m, d
a
(5) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows: (a)
#EqrDaRegUpHrlyQty a, s, h =
DaRegUpHrlyQty a, z, s, h z
4
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
(b)
#EqrDaRegUpHrlyPrc a, s, h =
DaRegUpMcpHrlyPrc z, h z
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The above variables are defined as follows: Variable
Unit
DaRegUpHrlyAmt a, s, h
$
Settlement Interval
Definition
Hour
Day-Ahead Regulation-Up Service Amount per AO per Resource Settlement Location per Hour - The DA Market amount to AO a for cleared Regulation-Up Service Offers at Resource Settlement Location s for the Hour. Day-Ahead MCP for Regulation-Up Service - The DA Market MCP for Regulation-Up Service in Reserve Zone z for the Hour. Day-Ahead Cleared 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 Regulation-Up Service Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s for the Hour. Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for cleared Regulation-Up Service Offers at Settlement Location s for the Operating Day. Day-Ahead Regulation-Up ServiceAmount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for cleared Regulation-Up Service Offers for the Operating Day. Day-Ahead Regulation-Up Service Amount per MP per Operating Day - The DA Market amount to Market Participant m for cleared Regulation-Up Service Offers for the Operating Day. Day-Ahead Electric Quarterly Reporting Regulation-Up Service Sales per AO per Settlement Location per Hour – AO a’s DA Market Regulation-Up Service sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.
DaRegUpMcpHrlyPrc z, h
$/MW
Hour
DaRegUpHrlyQty a, z, s, h
MW
Hour
DaRegUpDlyAmt a, s, d
DaRegUpAoAmt a, m,
d
DaRegUpMpAmt m, d
EqrDaRegUpHrlyQty a, s, h
Version 23.a
$
Operating Day
$
Operating Day
$
Operating Day
MWh
Hour
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Comment [MPRR102.470]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.471]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.472]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.473]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.474]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.475]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.476]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.477]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.478]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.479]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.480]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.481]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.482]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
EqrDaRegUpHrlyPrc a, s, h
a s h z d m
Version 23.a
Unit
Settlement Interval
Definition
$/MWh
Hour
Day-Ahead Electric Quarterly Reporting Regulation-Up Service Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Regulation-Up Service sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner. A Resource Settlement Location. An Hour. A Reserve Zone. An Operating Day. A Market Participant.
none none none none none none
none none none none none none
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Market Protocols for SPP Integrated Marketplace
4.5.8.5
Comment [MPRR102.485]: MPRR102 Awaiting implementation. #ER13-1748
Day-Ahead Regulation-Down Service Amount
(1) A DA Market credit or charge5 for cleared Regulation-Down Service will be calculated at each Settlement Location for each Asset Owner for each hour. The amount will be calculated as follows: #DaRegDnHrlyAmt a, s, h =
(DaRegDnMcpHrlyPrc z, h * DaRegDnHrlyQty a, z, s, h ) * (-1)
z
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: DaRegDnDlyAmt a, s, d =
DaRegDnHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaRegDnAoAmt a, m, d =
DaRegDnDlyAmt a, s, d
s
(4) 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: DaRegDnMpAmt m, d =
DaRegDnAoAmt a, m, d
a
(5) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows: (a)
#EqrDaRegDnHrlyQty a, s, h =
DaRegDnHrlyQty a, z, s, h z
5
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
(b)
#EqrDaRegDnHrlyPrc a, s, h =
DaRegDnMcpHrlyPrc z, h z
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The above variables are defined as follows: Variable
Unit
DaRegDnHrlyAmt a, s, h
$
Settlement Interval
Definition
Hour
Day-Ahead Regulation-Down Service Amount per AO per Resource Settlement Location per Hour - The DA Market amount to AO a for cleared RegulationDown Service Offers at Resource Settlement Location s for the Hour. Day-Ahead MCP for Regulation-Down Service - The DA Market MCP for Regulation-Down Service in Reserve Zone z for the hour. Day-Ahead Cleared Regulation-Down Service Quantity per AO per Settlement Location per Hour - The total quantity of Regulation-Down ServiceMW represented by AO a’s cleared Regulation-Down Service Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s, for the Hour. Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for cleared RegulationDown Service Offers at Settlement Location s for the Operating Day. Day-Ahead Regulation-Down Service Amount per AO per Operating Day The DA Market amount to AO a associated with Market Participant m for cleared Regulation-Down Service Offers for the Operating Day. Day-Ahead Regulation-Down Service Amount per MP per Operating Day The DA Market amount to Market Participant m for cleared Regulation-Down Service Offers for the Operating Day. Day-Ahead Electric Quarterly Reporting Regulation-Down Service Sales per AO per Settlement Location per Hour – AO a’s DA Market Regulation-Down Service sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.
DaRegDnMcpHrlyPrc z, h
$/MW
Hour
DaRegDnHrlyQty a, z, s, h
MW
Hour
DaRegDnDlyAmt a, s, d
$
DaRegDnAoAmt a, m,
$
d
DaRegDnMpAmt m, d
EqrDaRegDnHrlyQty a, s, h
$
MWh
Operating Day Operating Day Operating Day Hour
Comment [MPRR102.487]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.488]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.489]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.490]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.491]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.492]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.493]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.494]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.495]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.496]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.497]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.498]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.499]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.500]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.501]: MPRR102 Awaiting implementation. #ER13-1748
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Variable
EqrDaRegDnHrlyPrc a, s, h
a s h z d m
Version 23.a
Unit
Settlement Interval
$/MWh
Hour
none none none none none none
none none none none none none
Definition
Day-Ahead Electric Quarterly Reporting Regulation-Down Service Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Regulation-Down Service sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner. A Resource Settlement Location. An Hour. A Reserve Zone. An Operating Day. A Market Participant.
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Market Protocols for SPP Integrated Marketplace
4.5.8.6
Day-Ahead Spinning Reserve Amount
(1) A DA Market credit or charge6 for cleared Spinning Reserve will be calculated at each Settlement Location for each Asset Owner for each hour. The amount will be calculated as follows: #DaSpinHrlyAmt a, s, h =
(DaSpinMcpHrlyPrc z, h * DaSpinHrlyQty a, z, s, h ) *(-1)
z
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: DaSpinDlyAmt a, s, d =
DaSpinHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The amount is calculated as follows: DaSpinAoAmt a, m, d =
DaSpinDlyAmt a, s, d
s
(4) 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: DaSpinMpAmt m, d =
DaSpinAoAmt a, m, d
a
(5) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows: (a)
#EqrDaSpinHrlyQty a, s, h =
DaSpinHrlyQty a, z, s, h z
6
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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(b)
#EqrDaSpinHrlyPrc a, s, h =
DaSpinMcpHrlyPrc z, h z
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
Day-Ahead Spinning Reserve Amount per AO per Resource Settlement Location per Hour - The DA Market amount to AO a for cleared Spinning Reserve offers at Resource Settlement Location s for the Hour. Day-Ahead MCP for Spinning Reserve - The DA Market MCP for Spinning Reserve in Reserve Zone z for the hour. Day-Ahead Cleared Spinning Reserve Quantity per AO per Settlement Location per Hour - The total quantity of Spinning Reserve MW represented by AO a’s cleared Spinning Reserve Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s, for the Hour. Day-Ahead Spinning Reserve Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for cleared Spinning Reserve Offers at Settlement Location s for the Operating Day. Day-Ahead Spinning Reserve Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for cleared Spinning Reserve Offers for the Operating Day. Day-Ahead Spinning Reserve Amount per MP per Operating Day - The DA Market amount to Market Participant m for cleared Spinning Reserve Offers for the Operating Day. Day-Ahead Electric Quarterly Reporting Spinning Reserve Sales per AO per Settlement Location per Hour – AO a’s DA Market Spinning Reserve sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Electric Quarterly Reporting Spinning Reserve Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Spinning Reserve sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner.
DaSpinHrlyAmt a, s, h
$
Hour
DaSpinMcpHrlyPrc z, h
$/MW
Hour
DaSpinHrlyQty a, z, s, h
MW
Hour
DaSpinDlyAmt a, s, d
$
Operating Day
DaSpinAoAmt a, m,
$
Operating Day
$
Operating Day
d
DaSpinMpAmt m, d
EqrDaSpinHrlyQty a, s, h
MWh
Hour
EqrDaSpinHrlyPrc a, s, h
$/MWh
Hour
a
none
none
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Variable
s h z d m
Version 23.a
Unit
none none none none none
Settlement Interval none none none none none
Definition
A Resource Settlement Location. An Hour. A Reserve Zone. An Operating Day. A Market Participant
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4.5.8.7
Day-Ahead Supplemental Reserve Amount
(1) A DA Market credit or charge7 for cleared Supplemental Reserve will be calculated at each Settlement Location for each Asset Owner for each hour. The amount will be calculated as follows:
#DaSuppHrlyAmt a, s, h =
(DaSuppMcpHrlyPrc z, h * DaSuppHrlyQty a, z, s, h ) * (-1)
z
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The net daily amount is calculated as follows: DaSuppDlyAmt a, s, d =
DaSuppHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaSuppAoAmt a, m, d =
DaSuppDlyAmt a, s, d
s
(4) 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: DaSuppMpAmt m, d =
DaSuppAoAmt a, m, d
a
(5) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows: (a)
#EqrDaSuppHrlyQty a, s, h =
DaSuppHrlyQty a, z, s, h z
7
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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(b)
#EqrDaSuppHrlyPrc a, s, h =
DaSuppMcpHrlyPrc z, h z
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
Day-Ahead Supplemental Reserve Amount per AO per Resource Settlement Location per Hour - The DA Market amount to AO a for cleared Supplemental Reserve offers at Resource Settlement Location s for the Hour. Day-Ahead MCP for Supplemental Reserve - The DA Market MCP for Supplemental Reserve in Reserve Zone z for the Hour. Day-Ahead Cleared Supplemental Reserve Quantity per AO per Settlement Location per Hour - The total quantity of Supplemental Reserve represented by AO a’s cleared Supplemental Reserve Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s, for the Hour. Day-Ahead Supplemental Reserve Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for cleared Supplemental Reserve Offers at Settlement Location s for the Operating Day. Day-Ahead Supplemental Reserve Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for cleared Supplemental Reserve Offers for the Operating Day. Day-Ahead Supplemental Reserve Amount per MP per Operating Day - The DA Market amount to Market Participant m for cleared Supplemental Reserve Offers for the Operating Day. Day-Ahead Electric Quarterly Reporting Supplemental Reserve Sales per AO per Settlement Location per Hour – AO a’s DA Market Supplemental Reserve sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Electric Quarterly Reporting Supplemental Reserve Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Supplemental Reserve sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner.
DaSuppHrlyAmt a, s, h
$
Hour
DaSuppMcpHrlyPrc z, h
$/MW
Hour
DaSuppHrlyQty a, z, s, h
MW
Hour
DaSuppDlyAmt a, s, d
$
Operating Day
DaSuppAoAmt a, m,
$
Operating Day
$
Operating Day
d
DaSuppMpAmt m, d
EqrDaSuppHrlyQty a, s, h
MWh
Hour
EqrDaSuppHrlyPrc a, s, h
$/MWh
Hour
a
none
none
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Variable
s h z d m
Version 23.a
Unit
none none none none none
Settlement Interval none none none none none
Definition
A Resource Settlement Location. An Hour. A Reserve Zone. An Operating Day. A Market Participant.
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4.5.8.8
Comment [MPRR102.504]: MPRR102 Awaiting implementation. #ER13-1748
Day-Ahead Regulation-Up Service Distribution Amount
(1) A DA Market charge or credit8 will be calculated for each Asset Owner for each hour for each Reserve Zone. The Asset Owner amount within each Reserve Zone will be equal to the net Reserve Zone procurement rate for Regulation-Up Service multiplied by the Asset Owners Regulation-Up obligation within the Reserve Zone. For the purpose of allocating DA Market Regulation-Up Service procurement costs, all Non-Binding Reserve Zones will be combined into a single Non-Binding Reserve Zone. The amount to each Asset Owner is calculated as follows: #DaRegUpDistHrlyAmt a, z, h = DaRegUpDistHrlyRate z, h * DaRegUpAoObligHrlyQty a, z, h Where, (a)
IF DaRegUpObligRznHrlyQty z, h > 0 THEN #DaRegUpDistHrlyRate z, h = DaRegUpRznHrlyCost z, h / DaRegUpObligRznHrlyQty z, h ELSE DaRegUpDistHrlyRate z, h = 0
(a.1)
DaRegUpObligRznHrlyQty z, h =
DaRegUpAoObligHrlyQty a, z, h
a
(a.2)
#DaRegUpRznHrlyCost z, h = Min (DaRegUpRznHrlyQty z, h , DaRegUpObligRznHrlyQty z, h) * DaRegUpMcpHrlyPrc z, h
8
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
+ Max ( 0, (DaRegUpObligRznHrlyQty z, h - DaRegUpRznHrlyQty z, h ) ) * DaRegUpSpxHrlyRate (a.2.1) IF
h
Max (0, DaRegUpRznHrlyQty z, h - DaRegUpObligRznHrlyQty z, h) > 0
z
THEN
#DaRegUpSpxHrlyRate h =
( Max (0, DaRegUpRznHrlyQty z, h - DaRegUpObligRznHrlyQty z, h)
z
* DaRegUpMcpHrlyPrc z, h ) /
Max (0, DaRegUpRznHrlyQty z, h - DaRegUpObligRznHrlyQty z, h )
z
ELSE DaRegUpSpxHrlyRate h = 0 (a.2.2)
DaRegUpRznHrlyQty z, h =
a
(b) *(
DaRegUpHrlyQty a, z, s, h
s
#DaRegUpAoObligHrlyQty a, z, h = DaRegUpSppHrlyQty h
RtRegUpRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh ) -
s
RegUpFinHrlyQty t
a, z, h, t
(b.1)
RtLoadSppHrlyQty h =
m
Version 23.a
a
[ Max ( 0,
s
12/4/2014
RtBillMtr5minQty a, s, i )
i
255
Market Protocols for SPP Integrated Marketplace
+ Max ( 0,
i
(b.2)
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ] / 12
t
DaRegUpSppHrlyQty h =
a
(b.3)
s
DaRegUpHrlyQty a, z, s, h
z
#RtRegUpRznLoadHrlyQty a, z, s, h = [ Max ( 0,
RtBillMtr5minQty a, s, i )
i
+ Max ( 0,
i
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ]
t
* PctSlinRznRegUpHrlyFct a, z, s, h / 12
(c)
#DaRegUpSlObligHrlyQty a, z, s, h = DaRegUpSppHrlyQtyh * (RtRegUpRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh )
(2) For each Asset Owner, a daily amount is calculated at each Reserve Zone. The daily amount is calculated as follows: DaRegUpDistDlyAmt a, z, d =
DaRegUpDistHrlyAmt a, z, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaRegUpDistAoAmt a, m, d =
DaRegUpDistDlyAmt a, z, d
z
(4) 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:
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DaRegUpDistMpAmt m, d =
DaRegUpDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
DaRegUpDistHrlyAmt a, z, h
Unit
Settlement Interval
Definition
$
Hour
Day-Ahead Regulation-Up Service Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a’s share of DA Market Regulation-Up Service procurement costs in Reserve Zone z in Hour h. Day-Ahead Regulation-Up Service Distribution Hourly Rate per Reserve Zone per Hour – The rate applied to AO a’s Regulation-Up obligation within Reserve Zone z in Hour h. Day-Ahead Regulation-Up Service Reserve Zone Cost per Reserve Zone per Hour – The total DA Market Regulation-Up Service procurement cost for Reserve Zone z in Hour h. Day-Ahead Regulation-Up Service Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.4. Day-Ahead Regulation-Up Asset Owner Obligation Quantity per Reserve Zone per Hour – Asset Owner a’s DA Market Regulation-Up obligation in Reserve Zone z for Hour h. Day-Ahead Regulation-Up Service Hourly Quantity per Reserve Zone per Hour – The total amount of cleared Regulation-Up Service in Reserve Zone z for Hour h. Day-Ahead Regulation-Up Obligation per Reserve Zone per Hour – Reserve Zone z’s DA Market Regulation-Up obligation for Hour h. Real-Time SPP Load per Hour – SPP total actual load and Export Interchange Transactions in Hour h. Total SPP Day-Ahead Regulation-Up Service Hourly Quantity per Hour – The total amount of Regulation-Up Service cleared in the DA Market for Hour h.
DaRegUpDistHrlyRate z, h
$/MW
Hour
DaRegUpRznHrlyCost z, h
$
Hour
DaRegUpHrlyQty a, z, s, h
MW
Hour
DaRegUpAoObligHrlyQty a, z, h
MW
Hour
DaRegUpRznHrlyQty z, h
MW
Hour
DaRegUpObligRznHrlyQty z, h
MW
Hour
RtLoadSppHrlyQtyh
MW
Hour
DaRegUpSppHrlyQty h
MW
Hour
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Comment [MPRR102.510]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.511]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.512]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.513]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.514]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.515]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.516]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
MW
Hour
DaRegUpMcpHrlyPrc z, h
$/MW
Hour
DaRegUpSpxHrlyRate
$/MW
Hour
Day-Ahead Regulation-Up Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a’s DA Market Regulation-Up initial at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. Day-Ahead MCP for Regulation-Up Service per Reserve Zone – The value described under Section 4.5.8.4 for Reserve Zone z. Day-Ahead Regulation-Up Service SPP Exchange Rate per Hour – The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Regulation-Up Service from other Reserve Zones in order to meet the Reserve Zone Regulation-Up obligation. Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h – Asset Owner a’s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Regulation-Up cost allocation. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Reserve Zone z. Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’s load at Settlement Location s that is contained within Reserve Zone z for use in Regulation-Up cost allocation.
DaRegUpSlObligHrlyQty a, z, s, h
h
RtRegUpRznLoadHrlyQty a, z, s, h
MWh
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
%
Hour
PctSlinRznRegUpHrlyFct a, z, s, h
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Comment [MPRR102.518]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.519]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgCrdFlgt
none
none
MW
Hour
$
Operating Day
Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 for Reserve Zone z. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – A flag indicating that an import or export is a result of a schedule created by a Reserve Sharing Event. Normally, this flag is null. It is a logical expression of the Event ID – an attribute of the schedule, when the Event ID is not null the flag value =1. Bilateral Settlement Schedule for Regulation-Up per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule transaction t for Regulation-Up at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. Day-Ahead Regulation-Up Service Distribution Amount per AO per Reserve Zone per Operating Day - AO a’s share of DA Market Regulation-Up Service procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Regulation-Up Service Distribution Amount per AO per Operating Day - AO a’s for total DA Market Regulation-Up Service procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Regulation-Up Service Distribution Amount per MP per Operating Day - MP m’s share of total DA Market Regulation-Up Service procurement costs for in Operating Day d. An Asset Owner.
(Not Available on Settlement Statement)
RegUpFinHrlyQty a, z, h, t
DaRegUpDistDlyAmt a, z, d
DaRegUpDistAoAmt a, m, d
DaRegUpDistMpAmt m, d
a
Version 23.a
$
$
none
Operating Day Operating Day none
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Comment [MPRR102.520]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.521]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.522]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.523]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.524]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.525]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
A Settlement Location. An Hour. A Reserve Zone. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
s h z i t
none none none none none
none none none none none
d m
none none
none none
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4.5.8.9
Comment [MPRR102.526]: MPRR102 Awaiting implementation. #ER13-1748
Day-Ahead Regulation-Down Service Distribution Amount
(1) A DA Market charge or credit9 will be calculated for each Asset Owner for each hour for each Reserve Zone. The Asset Owner amount within each Reserve Zone will be equal to the net Reserve Zone procurement rate for Regulation-Down Service multiplied by the Asset Owners Regulation-Down obligation within the Reserve Zone. For the purpose of allocating DA Market Regulation-Down Service procurement costs, all Non-Binding Reserve Zones will be combined into a single Non-Binding Reserve Zone. The amount to each Asset Owner is calculated as follows: #DaRegDnDistHrlyAmt a, z, h = DaRegDnDistHrlyRate z, h * DaRegDnAoObligHrlyQty a, z, h Where, (a)
IF DaRegDnObligRznHrlyQty z, h > 0 THEN #DaRegDnDistHrlyRate z, h = DaRegDnRznHrlyCost z, h / DaRegDnObligRznHrlyQty z, h ELSE DaRegDnDistHrlyRate z, h = 0
(a.1)
DaRegDnObligRznHrlyQty z, h =
DaRegDnAoObligHrlyQty a, z, h
a
(a.2)
#DaRegDnRznHrlyCost z, h = Min (DaRegDnRznHrlyQty z, h , DaRegDnObligRznHrlyQty z, h) * DaRegDnMcpHrlyPrc z, h
9
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
+ Max ( 0, (DaRegDnObligRznHrlyQty z, h - DaRegDnRznHrlyQty z, h ) ) * DaRegDnSpxHrlyRate (a.2.1) IF
h
Max (0, DaRegDnRznHrlyQty z, h - DaRegDnObligRznHrlyQty z, h) > 0
z
THEN
#DaRegDnSpxHrlyRate h =
( Max (0, DaRegDnRznHrlyQty z, h - DaRegDnObligRznHrlyQty z, h)
z
* DaRegDnMcpHrlyPrc z, h ) /
Max (0, DaRegDnRznHrlyQty z, h - DaRegDnObligRznHrlyQty z, h )
z
ELSE DaRegDnSpxHrlyRate h = 0 (a.2.2)
DaRegDnRznHrlyQty z, h =
a
(b) *(
DaRegDnHrlyQty a, z, s, h
s
#DaRegDnAoObligHrlyQty a, z, h = DaRegDnSppHrlyQty h
RtRegDnRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh ) -
s
RegDnFinHrlyQty t
a, z, h, t
(b.1)
DaRegDnSppHrlyQty h =
a
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s
DaRegDnHrlyQty a, s, z, h
z
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(b.2)
#RtRegDnRznLoadHrlyQty a, z, s, h = [ Max ( 0,
RtBillMtr5minQty a, s, i )
i
+ Max ( 0,
i
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ]
t
* PctSlinRznRegDnHrlyFct a, z, s, h / 12 (c)
#DaRegDnSlObligHrlyQty a, z, s, h = DaRegDnSppHrlyQtyh * (RtRegDnRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh )
(2) For each Asset Owner, a daily amount is calculated at each Reserve Zone. The daily amount is calculated as follows: DaRegDnDistDlyAmt a, z, d =
DaRegDnDistHrlyAmt a, z, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaRegDnDistAoAmt a, m, d =
DaRegDnDistDlyAmt a, z, d
z
(4) 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: DaRegDnDistMpAmt m, d =
DaRegDnDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
DaRegDnDistHrlyAmt a, z, h
Unit
Settlement Interval
Definition
$
Hour
Day-Ahead Regulation-Down Service Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a’s share of DA Market Regulation-Down Service procurement costs in Reserve Zone z in Hour h. Day-Ahead Regulation-Down Service Distribution Hourly Rate per Reserve Zone per Hour – The rate applied to AO a’s Regulation-Down obligation within Reserve Zone z in Hour h. Day-Ahead Regulation-Down Service Reserve Zone Cost per Reserve Zone per Hour – The total DA Market Regulation-Down Service procurement cost for Reserve Zone z in Hour h. Day-Ahead Regulation-Down Service Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.5. Day-Ahead Regulation-Down Asset Owner Obligation Quantity per Reserve Zone per Hour – Asset Owner a’s DA Market Regulation-Down obligation in Reserve Zone z for Hour h. Day-Ahead Regulation-Down Service Hourly Quantity per Reserve Zone per Hour – The total amount of cleared Regulation-Down Service in Reserve Zone z for Hour h. Day-Ahead Regulation-Down Obligation per Reserve Zone per Hour – Reserve Zone z’s DA Market Regulation-Down obligation for Hour h. Real-Time SPP Load per Hour – The value described under Section 4.5.8.8. Total SPP Day-Ahead Regulation-Down Service Hourly Quantity per Hour – The total amount of Regulation-Down Service cleared in the DA Market for Hour h.
DaRegDnDistHrlyRate z, h
$/MW
Hour
DaRegDnRznHrlyCost z, h
$
Hour
DaRegDnHrlyQty a, z, s, h
MW
Hour
DaRegDnAoObligHrlyQty a, z, h
MW
Hour
DaRegDnRznHrlyQty z, h
MW
Hour
DaRegDnObligRznHrlyQty z, h
MW
Hour
RtLoadSppHrlyQtyh
MW
Hour
DaRegDnSppHrlyQty h
MW
Hour
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Comment [MPRR102.529]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.530]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.531]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.532]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.533]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.534]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.535]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.536]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.537]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.538]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
MW
Hour
DaRegDnMcpHrlyPrc z, h
$/MW
Hour
DaRegDnSpxHrlyRate
$/MW
Hour
Day-Ahead Regulation-Down Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a’s DA Market Regulation-Down initial obligation at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. Day-Ahead MCP for Regulation-Down Service per Reserve Zone – The value described under Section 4.5.8.5 for Reserve Zone z. Day-Ahead Regulation-Down Service SPP Exchange Rate per Hour – The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Regulation-Down Service from other Reserve Zones in order to meet the Reserve Zone RegulationDown obligation. Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h – Asset Owner a’s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Regulation-Down cost allocation. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Reserve Zone z. Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’s load at Settlement Location s that is contained within Reserve Zone z for use in Regulation-Down cost allocation.
DaRegDnSlObligHrlyQty a, z, s, h
h
RtRegDnRznLoadHrlyQty a, z, s, h
MWh
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
%
Hour
PctSlinRznRegDnHrlyFct a, z, s, h
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgCrdFlgt
none
none
Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 for Reserve Zone z. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.
MW
Hour
DaRegDnDistDlyAmt a, z, d
$
Operating Day
DaRegDnDistAoAmt a, m, d
$
Operating Day
(Not Available on Settlement Statement) RegDnFinHrlyQty a, z, h, t
DaRegDnDistMpAmt m, d
a s h z
Version 23.a
$
none none none none
Operating Day
none none none none
12/4/2014
Real-Time Bilateral Settlement Schedule for Regulation-Down per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule transaction t for Regulation-Down at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. Day-Ahead Regulation-Down Service Distribution Amount per AO per Reserve Zone per Operating Day - AO a’s share of DA Market Regulation-Down procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Regulation-Down Service Distribution Amount per AO per Operating Day - AO a’s for total DA Market Regulation-Down Service procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Regulation-Down Service Distribution Amount per MP per Operating Day - MP m’s share of total DA Market Regulation-Down Service procurement costs for in Operating Day d. An Asset Owner. A Settlement Location. An Hour. A Reserve Zone.
267
Comment [MPRR102.542]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.543]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.544]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.545]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.546]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
i t
none none
none none
d m
none none
none none
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4.5.8.10
Day-Ahead Spinning Reserve Distribution Amount
(1) A DA Market charge or credit10 will be calculated for each Asset Owner for each hour for each Reserve Zone. The Asset Owner amount within each Reserve Zone will be equal to the net Reserve Zone procurement rate for Spinning Reserve multiplied by the Asset Owners Spinning Reserve obligation within the Reserve Zone. For the purpose of allocating DA Market Spinning Reserve procurement costs, all Non-Binding Reserve Zones will be combined into a single Non-Binding Reserve Zone. The amount to each Asset Owner is calculated as follows: #DaSpinDistHrlyAmt a, z, h = DaSpinDistHrlyRate z, h * DaSpinAoObligHrlyQty a, z, h Where, (a)
IF DaSpinObligRznHrlyQty z, h > 0 THEN #DaSpinDistHrlyRate z, h = DaSpinRznHrlyCost z, h / DaSpinObligRznHrlyQty z, h ELSE DaSpinDistHrlyRate z, h = 0
(a.1)
DaSpinObligRznHrlyQty z, h =
DaSpinAoObligHrlyQty a, z, h
a
(a.2)
#DaSpinRznHrlyCost z, h = Min (DaSpinRznHrlyQty z, h , DaSpinObligRznHrlyQty z, h) * DaSpinMcpHrlyPrc z, h
10
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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+ Max ( 0, (DaSpinObligRznHrlyQty z, h - DaSpinRznHrlyQty z, h ) ) * DaSpinSpxHrlyRate (a.2.1) IF
h
Max (0, DaSpinRznHrlyQty z, h - DaSpinObligRznHrlyQty z, h) > 0
z
THEN
#DaSpinSpxHrlyRate h =
( Max (0, DaSpinRznHrlyQty z, h - DaSpinObligRznHrlyQty z, h)
z
* DaSpinMcpHrlyPrc z, h ) /
Max (0, DaSpinRznHrlyQty z, h - DaSpinObligRznHrlyQty z, h )
z
ELSE DaSpinSpxHrlyRate h = 0 (a.2.2)
DaSpinRznHrlyQty z, h =
a
(b) *(
DaSpinHrlyQty a, z, s, h
s
#DaSpinAoObligHrlyQty a, z, h = DaSpinSppHrlyQty h
RtSpinRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh ) -
s
SpinFinHrlyQty a, z, h, t
t
(b.1)
DaSpinSppHrlyQty h =
a
Version 23.a
s
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z
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(b.2)
#RtSpinRznLoadHrlyQty a, z, s, h = [ Max ( 0,
RtBillMtr5minQty a, s, i )
i
+ Max ( 0,
i
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ]
t
* PctSlinRznSpinHrlyFct a, z, s, h / 12 (c)
#DaSpinSlObligHrlyQty a, z, s, h = DaSpinSppHrlyQtyh * (RtSpinRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh )
(2) For each Asset Owner, a daily amount is calculated at each Reserve Zone. The daily amount is calculated as follows: DaSpinDistDlyAmt a, z, d =
DaSpinDistHrlyAmt a, z, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaSpinDistAoAmt a, m, d =
DASpinDistDlyAmt a, z, d
z
(4) 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: DaSpinDistMpAmt m, d =
DaSpinDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaSpinDistHrlyAmt a, z, h
$
Hour
DaSpinDistHrlyRate z, h
$/MW
Hour
DaSpinRznHrlyCost z, h
$
Hour
DaSpinHrlyQty a, z, s, h
MW
Hour
DaSpinAoObligHrlyQty a, z, h
MW
Hour
DaSpinRznHrlyQty z, h
MW
Hour
DaSpinObligRznHrlyQty z, h
MW
Hour
RtLoadSppHrlyQtyh
MW
Hour
DaSpinSppHrlyQty h
MW
Hour
Day-Ahead Spinning Reserve Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a’s share of DA Market Spinning Reserve procurement costs in Reserve Zone z in Hour h. Day-Ahead Spinning Reserve Distribution Hourly Rate per Reserve Zone per Hour – The rate applied to AO a’s Spinning Reserve obligation within Reserve Zone z in Hour h. Day-Ahead Reserve Zone Cost per Reserve Zone Spinning Reserve per Hour – The total DA Market Spinning Reserve procurement cost for Reserve Zone z in Hour h. Day-Ahead Spinning Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.6. Day-Ahead Spinning Reserve Asset Owner Obligation Quantity per Reserve Zone per Hour – Asset Owner a’s DA Market Spinning Reserve obligation in Reserve Zone z for Hour h. Day-Ahead Spinning Reserve Hourly Quantity per Reserve Zone per Hour – The total amount of cleared Spinning Reserve in Reserve Zone z for Hour h. Day-Ahead Spinning Reserve Obligation per Reserve Zone per Hour – Reserve Zone z’s DA Market Spinning Reserve obligation for Hour h. Real-Time SPP Load per Hour – The value described under Section 4.5.8.8. Total SPP Day-Ahead Spinning Reserve Hourly Quantity per Hour – The total amount of Spinning Reserve cleared in the DA Market for Hour h.
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Variable
Unit
Settlement Interval
Definition
MW
Hour
DaSpinMcpHrlyPrc z, h
$/MW
Hour
DaSpinSpxHrlyRate
$/MW
Hour
RtSpinRznLoadHrlyQty a, z, s, h
MWh
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
%
Hour
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgCrdFlgt
none
none
Day-Ahead Spinning Reserve Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a’s DA Market Spinning Reserve initial obligation at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. Day-Ahead MCP for Spinning Reserve per Reserve Zone – The value described under Section 4.5.8.6 for Reserve Zone z. Day-Ahead Spinning Reserve SPP Exchange Rate per Hour – The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Spinning Reserve from other Reserve Zones in order to meet the Reserve Zone Spinning Reserve obligation. Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h – Asset Owner a’s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Spinning Reserve cost allocation. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Reserve Zone z. Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’s load at Settlement Location s that is contained within Reserve Zone z for use in Spinning Reserve cost allocation. Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 for Reserve Zone z. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.
DaSpinSlObligHrlyQty a, z, s, h
h
PctSlinRznSpinHrlyFct a, z, s, h
(Not Available on Settlement Statement)
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Variable
Unit
Settlement Interval
Definition
SpinFinHrlyQty a, z, h, t
MW
Hour
DaSpinDistDlyAmt a, z, d
$
Operating Day
DaSpinDistAoAmt a, m, d
$
Operating Day
DaSpinDistMpAmt m, d
$
Operating Day
Bilateral Settlement Schedule for Spinning Reserve per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule transaction t for Spinning Reserve at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. Day-Ahead Spinning Reserve Distribution Amount per AO per Reserve Zone per Operating Day - AO a’s share of DA Market Spinning Reserve procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Spinning Reserve Distribution Amount per AO per Operating Day - AO a’s for total DA Market Spinning Reserve procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Spinning Reserve Distribution Amount per MP per Operating Day - MP m’s share of total DA Market Spinning Reserve procurement costs for in Operating Day d. An Asset Owner. A Settlement Location. An Hour. A Reserve Zone. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
a s h z i t
none none none none none none
none none none none none none
d m
none none
none none
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4.5.8.11
Day-Ahead Supplemental Reserve Distribution Amount
(1) A DA Market charge or credit11 will be calculated for each Asset Owner for each hour for each Reserve Zone. The Asset Owner amount within each Reserve Zone will be equal to the net Reserve Zone procurement rate for Supplemental Reserve multiplied by the Asset Owners Supplemental Reserve obligation within the Reserve Zone. For the purpose of allocating DA Market Supplemental Reserve procurement costs, all Non-Binding Reserve Zones will be combined into a single Non-Binding Reserve Zone. The amount to each Asset Owner is calculated as follows: #DaSuppDistHrlyAmt a, z, h = DaSuppDistHrlyRate z, h * DaSuppAoObligHrlyQty a, z, h Where, (a)
IF DaSuppObligRznHrlyQty z, h > 0 THEN #DaSuppDistHrlyRate z, h = DaSuppRznHrlyCost z, h / DaSuppObligRznHrlyQty z, h ELSE DaSuppDistHrlyRate z, h = 0
(a.1)
DaSuppObligRznHrlyQty z, h =
DaSuppAoObligHrlyQty a, z, h
a
(a.2)
#DaSuppRznHrlyCost z, h = Min (DaSuppRznHrlyQty z, h , DaSuppObligRznHrlyQty z, h) * DaSuppMcpHrlyPrc z, h
11
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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+ Max ( 0, (DaSuppObligRznHrlyQty z, h - DaSuppRznHrlyQty z, h ) ) * DaSuppSpxHrlyRate (a.2.1) IF
h
Max (0, DaSuppRznHrlyQty z, h - DaSuppObligRznHrlyQty z, h) > 0
z
THEN
#DaSuppSpxHrlyRate h =
( Max (0, DaSuppRznHrlyQty z, h - DaSuppObligRznHrlyQty z, h)
z
* DaSuppMcpHrlyPrc z, h ) /
Max (0, DaSuppRznHrlyQty z, h - DaSuppObligRznHrlyQty z, h )
z
ELSE DaSuppSpxHrlyRate h = 0 (a.2.2)
DaSuppRznHrlyQty z, h =
a
(b)
DaSuppHrlyQty a, z, s, h
s
#DaSuppAoObligHrlyQty a, z, h = ( DaSuppInterAoObligHrlyQty a, z, h
* DaSuppObligRatio h ) -
SuppFinHrlyQty a, z, h, t t
(b.1)
DaSuppInterAoObligHrlyQty a, z, h =
Max (0, DaSuppIniAoObligHrlyQty a, z, h -
ContrSuppHrlyQty a, z, h, t ) t
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(b.2)
DaSuppIniAoObligHrlyQty a, z, h =
( DaSuppSppHrlyQty h + ContrSuppSppHrlyQtyh ) *(
RtSuppRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh )
s
(b.2.1)
ContrSuppSppHrlyQty h =
a
(b.2.2)
DaSuppSppHrlyQty h =
a
(b.3)
z
s
ContrSuppHrlyQty a, z, h, t
t
DaSuppHrlyQty a, z, s, h
z
DaSuppObligRatio h = DaSuppSppHrlyQty h / DaSuppInterObligSppHrlyQtyh
(b.3.1)
DaSuppInterObligSppHrlyQtyh =
a
(b.4)
DaSuppInterAoObligHrlyQty a, z, h
z
#RtSuppRznLoadHrlyQty a, z, s, h = [ Max ( 0,
RtBillMtr5minQty a, s, i )
i
+ Max ( 0,
i
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ]
t
* PctSlinRznSuppHrlyFct a, z, s, h / 12 (c)
#DaSuppSlObligHrlyQty a, z, s, h = ( DaSuppSppHrlyQtyh + ContrSuppSppHrlyQtyh ) * (RtSuppRznLoadHrlyQty a, z, s, h / RtLoadSppHrlyQtyh )
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(2) For each Asset Owner, a daily amount is calculated at each Reserve Zone. The daily amount is calculated as follows: DaSuppDistDlyAmt a, z, d =
DaSuppDistHrlyAmt a, z, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaSuppDistAoAmt a, m, d =
DaSuppDistDlyAmt a, z, d
z
(4) 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: DaSuppDistMpAmt m, d =
DaSuppDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaSuppDistHrlyAmt a, z, h
$
Hour
DaSuppDistHrlyRate z, h
$/MW
Hour
ContrSuppHrlyQty a, z, h, t
MW
Hour
DaSuppRznHrlyCost z, h
$
Hour
DaSuppHrlyQty a, z, s, h
MW
Hour
DaSuppAoObligHrlyQty a, z, h
MW
Hour
DaSuppRznHrlyQty z, h
MW
Hour
Day-Ahead Supplemental Reserve Distribution Amount per AO per Reserve Zone per Hour - The amount to AO a for AO a’s share of DA Market Supplemental Reserve procurement costs in Reserve Zone z in Hour h. Day-Ahead Supplemental Reserve Distribution Hourly Rate per Reserve Zone per Hour – The rate applied to AO a’s Supplemental Reserve obligation within Reserve Zone z in Hour h. Recallable Day-Ahead Export Interchange per Hour – AO a’s contracted Supplemental Reserve obligation in Reserve Zone z being met by Recallable day-Ahead Export Interchange transaction t. Day-Ahead Reserve Zone Supplemental Reserve Cost per Reserve Zone per Hour – The total DA Market Supplemental Reserve procurement cost for Reserve Zone z in Hour h. Day-Ahead Supplemental Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.7. Day-Ahead Supplemental Reserve Asset Owner Obligation Quantity per Reserve Zone per Hour – Asset Owner a’s DA Market Supplemental Reserve obligation in Reserve Zone z for Hour h. Day-Ahead Supplemental Reserve Hourly Quantity per Reserve Zone per Hour – The total amount of cleared Supplemental Reserve in Reserve Zone z for Hour h.
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Variable
Unit
Settlement Interval
Definition
DaSuppObligRznHrlyQty z, h
MW
Hour
ContrSuppSppHrlyQtyh
MW
Hour
RtLoadSppHrlyQtyh
MW
Hour
DaSuppSppHrlyQty h
MW
Hour
DaSuppInterObligSppHrlyQtyh
MW
Hour
DaSuppInterAoObligHrlyQty a, z, h
MW
Hour
DaSuppIniAoObligHrlyQty a, z, h
MW
Hour
Day-Ahead Supplemental Reserve Obligation per Reserve Zone per Hour – Reserve Zone z’s DA Market Supplemental Reserve obligation for Hour h. Recallable Day-Ahead Export Interchange per Hour – The total of all ContrSuppHrlyQty a, z, h, t for Hour h. Real-Time SPP Load per Hour – The value described under Section 4.5.8.8. Total SPP Day-Ahead Supplemental Reserve Hourly Quantity per Hour – The total amount of Supplemental Reserve cleared in the DA Market for Hour h. Day-Ahead SPP Supplemental Reserve Interim Obligation Quantity per Hour – The total of all Asset Owner’s DA Market Supplemental Reserve interim obligation over all Reserve Zones for Hour h . Day-Ahead Supplemental Reserve Interim Asset Owner Obligation Quantity per AO per Reserve Zone per Hour – Asset Owner a’s DA Market Supplemental Reserve interim obligation that includes treatment of ContrSuppHrlyQty a, z, h, t but does not include allocation of excess ContrSuppHrlyQty a, z, h, t in Reserve Zone z for Hour h . Day-Ahead Supplemental Reserve Initial Asset Owner Obligation Quantity per AO per Reserve Zone per Hour – Asset Owner a’s DA Market Supplemental Reserve initial obligation that does not include treatment of ContrSuppHrlyQty a, z, h, t in Reserve Zone z for Hour h.
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Variable
Unit
Settlement Interval
Definition
DaSuppObligRatio h
none
Hour
DaSuppSlObligHrlyQty a, z, s, h
MW
Hour
DaSuppMcpHrlyPrc z, h
$/MW
Hour
DaSuppSpxHrlyRate
$/MW
Hour
RtSuppRznLoadHrlyQty a, z, s, h
MWh
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
Day-Ahead Supplemental Reserve Asset Owner Obligation Ratio per Hour – The percentage applied to Asset Owner a’s DaSuppInterAoObligHrlyQty a, z, h to account for allocation of any excess ContrSuppHrlyQty a, z, h, t in Reserve Zone z in Hour h. Day-Ahead Supplemental Reserve Obligation Quantity per AO per Settlement Location per Hour - Asset Owner a’s DA Market Supplemental Reserve initial obligation that does not include treatment of ContrSuppHrlyQty a, z, h, t at Settlement Location s in Reserve Zone z for Hour h. Note that this value is provided for information purposes only and is not used in any of the cost allocation calculations. Day-Ahead MCP for Supplemental Reserve per Reserve Zone – The value described under Section 4.5.8.7 for Reserve Zone z. Day-Ahead Supplemental Reserve SPP Exchange Rate per Hour – The rate applied to calculate the portion of DA Market Reserve Zone procurement costs associated with Reserve Zones that must purchase cleared Supplemental Reserve from other Reserve Zones in order to meet the Reserve Zone Supplemental Reserve obligation. Real-Time Reserve Zone Load per AO per Settlement Location in Reserve Zone z for Hour h – Asset Owner a’s actual load and Export Interchange Transactions at Settlement Location s in Reserve Zone z for Hour h for use in Supplemental Reserve cost allocation. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Reserve Zone z.
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Variable
Unit
Settlement Interval
Definition
%
Hour
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgCrdFlgt
none
none
Percent Settlement Location in Reserve Zone per AO per Settlement Location per Reserve Zone per Hour – The percentage factor of AO a’s load at Settlement Location s that is contained within Reserve Zone z for use in Supplemental Reserve cost allocation. Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 for Reserve Zone z. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.
MW
Hour
DaSuppDistDlyAmt a, z, d
$
Operating Day
DaSuppDistAoAmt a, m, d
$
Operating Day
DaSuppDistMpAmt m, d
$
Operating Day
PctSlinRznSuppHrlyFct a, z, s, h
(Not Available on Settlement Statement) SuppFinHrlyQty a, z, h, t
a
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none
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Real-Time Bilateral Settlement Schedule for Supplemental Reserve per AO per Settlement Location per Transaction per Hour - The MW amount specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule transaction t for Supplemental Reserve at Reserve Zone z for the Hour. The buyer AO MW amount is a positive value and the seller AO MW amount is a negative value. Day-Ahead Supplemental Reserve Distribution Amount per AO per Reserve Zone per Operating Day - AO a’s share of DA Market Supplemental Reserve procurement costs for Reserve Zone z in Operating Day d. Day-Ahead Supplemental Reserve Distribution Amount per AO per Operating Day - AO a’s for total DA Market Supplemental Reserve procurement costs associated with Market Participant m in Operating Day d. Day-Ahead Supplemental Reserve Distribution Amount per MP per Operating Day - MP m’s share of total DA Market Supplemental Reserve procurement costs for in Operating Day d. An Asset Owner.
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Variable
Unit
Settlement Interval
Definition
A Settlement Location. An Hour. A Reserve Zone. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
s h z i t
none none none none none
none none none none none
d m
none none
none none
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4.5.8.12 (1)
(2)
Day-Ahead Make-Whole-Payment Amount
The Day-Ahead Make-Whole-Payment Amount is a credit or charge12 to a Resource Asset Owner and is calculated for each Resource with an associated DA Market Commitment Period that was committed by SPP with a Day-Ahead Market Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1, or was committed as part of the Multi-Day Reliability Assessment as defined under Section 4.2.6.3. A payment is made to the Resource Asset Owner when the sum of the Resource’s DA Market Start-Up Offer costs, No-Load Offer costs, Transition State Offer costs, Energy Offer Curve and Operating Reserve Offer costs associated with cleared DA Market amounts for Energy and Operating Reserve is greater than the Energy and Operating Reserve DA Market revenues received for that Resource over the Resource’s DA Market Make-Whole-Payment Eligibility Period. A Resource’s DA Market Make-Whole-Payment Eligibility Period is equal to a Resource’s DA Market Commitment Period except as defined below: (a)
(3)
For Resources with an associated DA Market Commitment Period that begins in one Operating Day and ends in the next Operating Day, two DA Market MakeWhole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the hour that the DA Market Commitment Period begins and ends in the last hour of the first Operating Day. The second period begins in the first hour of the next Operating Day and ends in the last hour of the DA Market Commitment Period.
The following cost recovery eligible rules apply to each DA Market Make-WholePayment Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the time the commitment decision was made except under the situation described under Section (b)(i)(1) below. (a)
There may be more than one DA Market Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single DA Market Make-Whole Payment Eligibility Period is contained within a single Operating Day.
12
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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(b)
A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following DA Market Make-Whole Payment Eligibility Periods except as described in (i)(1) and (i)(2) below: (i)
Any DA Market Make-Whole Payment Eligibility Period for which the Day-Ahead Market SCUC did not consider the Resource’s Start-Up Offer in the commitment decision or any Day-Ahead Make-Whole Payment Eligibility Period that is adjacent to the end of a RUC Make-Whole Payment Eligibility Period that was created subsequent to the Day-Ahead Market Make-Whole Payment Eligibility Period during the day before the Operating Day for which the Day-Ahead Market Make-Whole Payment Eligibility Period appliesexcept as described in (1) below; (1)
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Comment [MPRR190.549]: MPRR190 Awaiting FERC filing
Comment [MPRR190.550]: MPRR190 Awaiting FERC filing
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.
(1)(2) Start-Up Offers associated with manual commitments as described under Sections 4.2.6.2 and 4.3.1.2(1)(b) are eligible for recovery.
(c)
Comment [MPRR190.548]: MPRR190 Awaiting FERC filing
(ii)
Any DA Market Make-Whole Payment Eligibility Period resulting from a DA Market Commitment Period that contains a DA Market Self-Commit Hour; and
(iii)
Any DA Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min Time unless such time is within a contiguous RUC Make-Whole Payment Eligibility Period that is created subsequent to the DA Market Make-Whole-Payment Eligibility Period.
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
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Comment [MPRR190.552]: MPRR190 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
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.
(d)(e) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at an average Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, such cost is not due to any independent action of the Market Participant and such cost is not incurred during a RUC Make-Whole Payment Eligibility Period. In such cases, the additional costs are equal to the difference between the Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs is limited to the time period defined as the Transition State Time submitted in the Resource Offer. (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:
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#DaMwpCpAmt a, s, c = Max (0,
( DaMwpCostHrlyAmt a, h, s, c + DaMwpRevHrlyAmt a, h, s, c ) ) * (-1)
h
(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 Comment [MPRR101.554]: MPRR101 awaiting FERC filing
+ DaCcSpinAdjHrlyAmt a, s, h + DaCcSuppAdjHrlyAmt a, s, h + DaNoLoadHrlyAmt a, h, s, c + DaIncrEnHrlyAmt a, h, s, c
Comment [MPRR204.555]: MPRR204 Awaiting FERC filing
+ DaRegUpAvailHrlyAmt a, h, s, c + DaRegDnAvailHrlyAmt a, h, s, c
Comment [MPRR204.556]: MPRR204 Awaiting FERC filing
+
PotDaRegUpMileMwp5minAmt a, s, i
i
+
Comment [MPRR204.557]: MPRR204 Awaiting FERC approval Docket #ER13-1748
PotDaRegDnMileMwp5minAmt a, s, i
i
+ DaSpinAvailHrlyAmt a, h, s, c + DaSuppAvailHrlyAmt a, h, s, c ] Where, ABS (DaClrdHlryQty a, h, s )
#DaIncrEnHrlyAmt a, h, s, c =
DA Market Energy Offer Curve 0
(a.1)
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DaCcSpinAdj5minAmt a, s, i = IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 ) * (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i ) ELSE DaCcSpin5minAmt a, s, h = 0 (a.1.1)
DaCcSpinAdjHrlyAmt a, s, h =
Max ( 0,
Field Code Changed
DaCcSpinAdj5minAmt a, s, i )
i
(a.2)
IF RtTranistionStateFlg a, s, i = 1 THEN DaCcSuppAdj5minAmt a, s, i = IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 ) * (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i ) ELSE DaCcSupp5minAmt a, s, h = 0
(a.2.1)
DaCcSuppAdjHrlyAmt a, s, h =
Max ( 0,
Comment [MPRR101.558]: MPRR101 awaiting FERC filing
DaCcSuppAdj5minAmt a, s, i )
Field Code Changed
i
(b)
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DaMwpRevHrlyAmt a, h, s, c = DaClrdComStatHrlyFlg h, s, c
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* [ ( DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h ) + DaRegUpHrlyAmt a, h, s + DaRegDnHrlyAmt a, h, s +
DaRegUpUnusedMileMwp5minAmt a, s, i
DaRegDnUnusedMileMwp5minAmt a, s, i
i
+
Comment [MPRR204.559]: MPRR204 Awaiting FERC approval Docket #ER13-1748
i
+ DaSpinHrlyAmt a, h, s + DaSuppHrlyAmt a, h, s ] (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 =
DaMwpCpAmt a, s, c
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 =
DaMwpDlyAmt a, s, d
s
(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 =
DaMwpAoAmt a, m, d
a
(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
Comment [MPRR204.560]: MPRR204 Awaiting FERC filing
THEN
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#EqrDaMwpHrlyQty a, s, c = 1
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The above variables are defined as follows: Variable
Unit
Settlement Interval Eligibility Period
DaMwpCpAmt a, s, c
$
DaStartUpHrlyAmt a h, s, c
$
Hour
DaStartUpAmt a s, c
$
Eligibility Period
(Not Available on Settlement Statement)
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Definition 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. 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-WholePayment 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. 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.
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
DaStartUpEligHrlyFlg a, h, s, c
None
Hour
DaClrdComStatHrlyFlg h, s, c
None
Hour
DaRucRmndrStartUpHrlyAmt a, s, h, c
$
Hour
DaTransitionHrlyAmt a, s, h, c
$
Eligibility Period
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. 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”. 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. 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-WholePayment Eligibility Period c. Day-Ahead 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.
DaCcSpinAdjHrlyAmt a, s, h
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$
Hour
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292
Comment [MPRR101.562]: MPRR101 awaiting FERC filing
Comment [MPRR101.563]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
DaCcSuppAdjHrlyAmt a, s, h
$
Hour
DaCcSpinAdj5minAmt a, s, i
$
Dispatch Interval
DaCcSuppAdj5minAmt a, s, i
$
Day-Ahead 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. Day-Ahead 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. Day-Ahead 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. 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. 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. 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.
Dispatch Interval
RtTranistionStateFlg a, s, i
None
RtRucComStat5minFlg a, s, i, c
None
Dispatch Interval
DaMinRunTime a, h, s, c
Time
Hour
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Comment [MPRR101.565]: MPRR101 awaiting FERC filing
Comment [MPRR101.566]: MPRR101 awaiting FERC filing
Comment [MPRR101.567]: MPRR101 awaiting FERC filing
Comment [MPRR101.568]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
DaMwpCostHrlyAmt a, h, s, c
$
Hour
PotDaRegUpMileMwp5minAmt a, s, i
$
Dispatch Interval
PotDaRegDnMileMwp5minAmt a, s, i
$
Dispatch Interval
Day-Ahead Make-Whole Payment Cost Amount per AO per Settlement Location per Hour in the DA Market Make-WholePayment 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. 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 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 Day-Ahead Make-Whole Payment Revenue Amount per AO per Settlement Location per Hour in the DA Market Make-WholePayment Eligibility Period – The hourly revenue associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. 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 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 Day-Ahead No-Load Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The No-Load Offer, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c.
DaMwpRevHrlyAmt a, h, s, c
$
Hour
DaRegUpUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
DaRegDnUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
DaNoLoadHrlyAmt a, h, s, c
$
Hour
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Comment [MPRR204.570]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.571]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.572]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable DaIncrEnHrlyAmt a, h, s, c
DaRegUpAvailHrlyAmt a, h, s, c
DaRegDnAvailHrlyAmt a, h, s, c
Unit
Settlement Interval
Definition
$
Hour
Day-Ahead Incremental Energy Cost Amount per AO per Settlement Location per Hour in the DA Market Make-WholePayment Eligibility Period - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-WholePayment Eligibility Period c at an output level equal to DaClrdHrlyQty a, s, h. Day-Ahead Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-WholePayment Eligibility Period - The Regulation-Up Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-WholePayment Eligibility Period c. The Resource’s Regulation-Up Service Offer cost in the Hour is equal to the Resources DaRegUpHrlyQty a, z, s, h multiplied by the Resource’s Regulation-Up Service Offer, in $/MW. Day-Ahead Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Hour per DA Market MakeWhole-Payment Eligibility Period - The Regulation-Down Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Regulation-Down Service Offer cost in the Hour is equal to the Resources DaRegDnHrlyQty a, z, s, h, multiplied by the Resource’s Regulation-Down Service Offer, in $/MW.
$
$
Hour
Hour
Comment [MPRR204.573]: MPRR204 Awaiting FERC filing Comment [MPRR102.574]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.575]: MPRR204 Awaiting FERC filing Comment [MPRR102.576]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.577]: MPRR204 Awaiting FERC filing Comment [MPRR204.578]: MPRR204 Awaiting FERC filing Comment [MPRR102.579]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.580]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.581]: MPRR204 Awaiting FERC filing Comment [MPRR102.582]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.583]: MPRR204 Awaiting FERC filing Comment [MPRR102.584]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.585]: MPRR204 Awaiting FERC filing Comment [MPRR204.586]: MPRR204 Awaiting FERC filing Comment [MPRR102.587]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.588]: MPRR102 Awaiting implementation. #ER13-1748
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Variable
Unit
Settlement Interval
Definition
DaSpinAvailHrlyAmt a, h, s, c
$
Hour
DaSuppAvailHrlyAmt a, h, s, c
$
Hour
DaLmpHrlyPrc s, h,
$/MWh
Hour
DaClrdHrlyQty a, s, h
MWh
Hour
DaRegUpHrlyAmt a, h, s
$
Hour
DaRegDnHrlyAmt a, h, s
$
Hour
Day-Ahead Spin Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Spinning Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Spinning Reserve Offer cost in the Hour is equal to the Resource’s DaSpinHrlyQty a, z, s, h multiplied by the Resource’s Spinning Reserve Offer, in $/MW. Day-Ahead Supplemental Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-WholePayment Eligibility Period - The Supplemental Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-WholePayment Eligibility Period c. The Resource’s Supplemental Reserve Offer cost in the Hour is equal to the Resources DaSuppHrlyQty a, z, s, h multiplied by the Resource’s Supplemental Reserve Offer, in $/MW. Day-Ahead LMP - The DA Market LMP at Resource Settlement Location s for Hour h. Day-Ahead Cleared Energy Quantity per AO per Resource Settlement Location per Hour – The value described under Section 4.5.8.1 for AO a’s eligible Resource Settlement Location s. Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Hour – The DaRegUpHrlyAmt a, s h, calculated under Section 4.5.8.4 associated with AO a’s eligible Resource at Settlement Location s for Hour h. Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Hour– The DaRegDnHrlyAmt a, s h, calculated under Section 4.5.8.5 associated with AO a’s eligible Resource at Settlement Location s for Hour h.
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Comment [MPRR102.590]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
DaSpinHrlyAmt a, h, s
$
Hour
DaSuppHrlyAmt a, h, s
$
Hour
DaMwpDlyAmt a, s, d
$
Operating Day
DaMwpAoAmt a, m,
$
Operating Day
$
Operating Day
$
Eligibility Period
Day-Ahead Spinning Reserve Amount per AO per Settlement Location per Hour– The DaSpinHrlyAmt a, s, h calculated under Section 4.5.8.6 associated with AO a’s eligible Resource at Settlement Location s for Hour h. Day-Ahead Supplemental Reserve Amount per AO per Settlement Location per Hour - The DaSuppHrlyAmt a, s, h calculated under Section 4.5.8.7 associated with AO a’s eligible Resource at Settlement Location s for Hour h. Day-Ahead Make-Whole-Payment Amount per AO per Settlement Location per Operating Day - The DA Market makewhole amount to AO a for Operating Day d at Resource Settlement Location s. Day-Ahead Make-Whole-Payment Amount per AO per Operating Day - The DA Market make-whole amount to AO a associated with Market Participant m for Operating Day d. Day-Ahead Make-Whole-Payment Amount per MP per Operating Day - The DA Market make-whole amount to Market Participant m for Operating Day d. Day-Ahead Electric Quarterly Reporting Make-Whole-Payment Amount per AO per Settlement Location per DA Market MakeWhole-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 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements..
d
DaMwpMpAmt m, d
EqrDaMwpHrlyPrc a, s, c
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Variable
Unit
Settlement Interval Eligibility Period
EqrDaMwpHrlyQty a, s, c
MWh
a h
none none
none none
s c d m
none none none none
none none none none
Version 23.a
12/4/2014
Definition Day-Ahead Electric Quarterly Reporting Make-Whole-Payment Quantity per AO per Settlement Location per DA Market MakeWhole-Payment Eligibility Period – This value is set equal to 1 if EqrDaMwpHrlyPrc a, s, c > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.. An Asset Owner. An Hour in a DA Market Make-Whole-Payment Eligibility Period. A Resource Settlement Location. A DA Market Make-Whole-Payment Eligibility Period. An Operating Day. A Market Participant.
298
Market Protocols for SPP Integrated Marketplace
4.5.8.13
Day-Ahead Make-Whole-Payment Distribution Amount
(1) The Day-Ahead Make-Whole-Payment Distribution Amount is an hourly charge or credit13 based on a daily distribution rate to Asset Owners with net cleared Energy withdrawals at a Settlement Location in the DA Market. Total daily charges to Asset Owners are equal to the total Day-Ahead Make-Whole-Payment Amount for the Operating Day. The hourly amount to each Asset Owner at each Settlement Location is calculated as follows: #DaMwpDistHrlyAmt a, s, h = DaMwpSppDistRate d * DaMwpDistHrlyQty a, s, h Where, (a) DaMwpDistHrlyQty a, s, h = Max (0, DaClrdHrlyQty a, s, h ) +
Max( 0, DaClrdVHrlyQty a, s, h, t ) + [
i
t
Max( 0,
t
DaImpExp5minQty a, s, i, t ) ]/ 12 (b) #DaMwpSppDistRate d = ( DaMwpSppAmt d / DaMwpSppDistQty d ) * (-1) (a.1) DaMwpSppAmt d =
DaMwpMpAmt m, d
m
(a.2) DaMwpSppDistQty d =
a
s
DaMwpDistHrlyQty a, s, h
h
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: DaMwpDistDlyAmt a, s, d =
DaMwpDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: 13
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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DaMwpDistAoAmt a, m, d =
DaMwpDistDlyAmt a, s, d
s
(4) 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: DaMwpDistMpAmt m, d =
DaMwpDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaMwpDistHrlyAmt a, s, h
$
Hour
$/MWh
Operating Day
MWh
Hour
$
Operating Day
Day-Ahead Make-Whole-Payment Distribution Amount per AO per Hour per Settlement Location - The amount to AO a for Hour h and Settlement Location s for recovery of the DaMwpSppAmt d for Operating Day d. Day-Ahead SPP Make-Whole Payment Distribution Rate per Operating Day – The rate applied to each AO’s total withdrawal volume in each Hour h at Settlement Location s in Operating Day d. Day-Ahead Make-Whole Payment Distribution Volume per Asset Owner per Settlement Location per Hour – The withdrawal volume associated with AO a at Settlement Location s for the Hour. Day-Ahead SPP Make-Whole Payment Amount per Operating Day – The total of all DaMwpAmt a, c, s in Operating Day d.
DaMwpSppDistQty d
MWh
Operating Day
DaClrdHrlyQty a, s, h
MWh
Hour
DaClrdVHrlyQty a, s, h, t
MWh
Hour
DaImpExp5minQty a, s, i, t
MW
Dispatch Interval
$
Operating Day
DaMwpSppDistRate d
DaMwpDistHrlyQty a, s, h
DaMwpSppAmt d
DaMwpMpAmt m, d
Version 23.a
Day-Ahead SPP Make-Whole Payment Distribution Volume per Operating Day – The sum across all hours and Settlement Locations of all AO withdrawal volumes in Operating Day d. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1. Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3. Day-Ahead Interchange Transaction Quantity per AO per Transaction per Settlement Location per Dispatch Interval – The value described under Section 4.5.8.2. Day-Ahead Make-Whole-Payment Amount per MP per Operating Day - The value calculated under Section 4.5.8.8.
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Variable
Unit
Settlement Interval
Definition
DaMwpDistDlyAmt a, s, d
$
Operating Day
DaMwpDistAoAmt a, m,
$
Operating Day
$
Operating Day
h d a c s t
none none none none none none
none none none none none none
m
none
none
Day-Ahead Make-Whole-Payment Distribution Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for Operating Day d at Resource Settlement Location s for recovery of the DaMwpSppAmt d. Day-Ahead Make-Whole-Payment Distribution Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for Operating Day d for recovery of the DaMwpSppAmt d. Day-Ahead Make-Whole-Payment Distribution Amount per MP per Operating Day - The DA Market amount to Market Participant m for Operating Day d for recovery of the DaMwpSppAmt d. An Hour in a DA Market Make-Whole-Payment Eligibility Period. An Operating Day. An Asset Owner. A DA Market Make-Whole-Payment Eligibility Period. A Settlement Location. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. A Market Participant
DaMwpDistMpAmt m, d
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4.5.8.14
Transmission Congestion Rights Funding Amount
(1) The Transmission Congestion Rights Funding Amount can be either a credit or charge to an Asset Owner and is calculated for each TCR instrument held by the Asset Owner. TCR instruments will be fully funded in each hour. The amount to each Asset Owner (AO) for each TCR instrument for a given hour of the Operating Day is calculated as follows: #TcrFundHrlyAmt a, h =
(TcrHrlyQty a, h, t * (DaMccHrlyPrc source, h - DaMccHrlyPrc sink, h ) )
t
(2) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: TcrFundAoAmt a, m, d =
TcrFundHrlyAmt a, h
h
(3) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows: TcrFundMpAmt m, d =
TcrFundAoAmt a, m, d
a
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The above variables are defined as follows: Variable
TcrFundHrlyAmt a, h TcrHrlyQty a, h, t
Unit
Settlement Interval
Definition
$
Hour
MWh
Hour
Transmission Congestion Rights Hourly Funding Amount per AO per Hour - The net amount to AO a for all AO a’s TCR instruments for the Hour. Transmission Congestion Right Quantity - The MW quantity specified in TCR instrument t, for AO a for the Hour. Day-Ahead Marginal Congestion Component of Day-Ahead LMP at the Sink per Hour – The Marginal Congestion Component of the Day-Ahead LMP at the Settlement Location of the sink point specified in TCR instrument t for Hour h. Day-Ahead Marginal Congestion Component of Day-Ahead LMP at the Source per Hour – The Marginal Congestion Component of the Day-Ahead LMP at the Settlement Location of the source point specified in TCR instrument t for Hour h. Transmission Congestion Rights Funding Amount per AO per Operating Day- - The net amount to AO a associated with Market Participant m for all AO a’s TCR instruments for the Operating Day. Transmission Congestion Rights Hourly Funding Amount per MP per Operating Day- The net amount to MP m for all MP m’s TCR instruments for the Operating Day. The Settlement Location identified as the source point in TCR instrument t. The Settlement Location identified as the sink point in TCR instrument t. An Asset Owner. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Hour. An Operating Day. A Market Participant.
DaMccHrlyPrc
sink, h
$/MWh
Hour
DaMccHrlyPrc
source, h
$/MWh
Hour
TcrFundAoAmt a, m, d
$
Operating Day
TcrFundMpAmt m, d
$
Operating Day
source sink a t
none none none none
none none none none
h d m
none none none
none none none
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4.5.8.15
Transmission Congestion Rights Daily Uplift Amount
(1) A DA Market charge or credit14 will be calculated for each Asset Owner holding TCRs for each Operating Day to the extent that congestion revenues collected over the Operating Day are not sufficient to fund the net of the total charges and credits calculated under Section 4.5.8.14 over the Operating Day. The amount is calculated as follows: #TcrUpliftDlyAmt a, d = ShortFallDlyAmt d * [TcrUpliftRatioAoDlyAmt a, d / TcrUpliftRatioSppDlyAmt d] Where, (a)
#TcrUpliftRatioAoDlyAmt a, d =
h
(b)
#TcrUpliftRatioSppDlyAmt d =
a
(c)
ABS ((TcrHrlyQty a, h, t * (DaMccHrlyPrc source, h - DaMccHrlyPrc sink, h ) ) )
t
h
ABS ((TcrHrlyQty a, h, t * (DaMccHrlyPrc source, h - DaMccHrlyPrc sink, h ) ) )
t
#ShortFallDlyAmt d =
(-1) * MIN { 0,
a
+
i
+
[ DaMccHrlyPrc s, h * (DaClrdHrlyQty a, s, h
h
( DaImpExp5minQty a, s, i, t / 12 ) +
t
a
s
DaClrdVHrlyQty a, s, h, t ) ]
t
TcrFundHrlyAmt a, h }
h
14
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
(2) 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: TcrUpliftDlyMpAmt m, d =
TcrUpliftDlyAmt a, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
TcrUpliftDlyAmt a, d
$
Operating Day
Transmission Congestion Rights Daily Uplift Amount per AO - AO a’s share of the ShortFallDlyAmt d in Operating Day d.
TcrUpliftRatioAoDlyAmt a, d
$
Operating Transmission Congestion Rights Uplift Ratio per Asset Owner per Operating Day Day – The total of the absolute value of Asset Owner a’s hourly TCR instrument economic value for Operating Day d.
TcrUpliftRatioSppDlyAmt d
$
Operating SPP Transmission Congestion Rights Uplift Ratio per Operating Day – The total of TcrUpliftRatioAoDlyAmt a, d for Operating Day d. Day
ShortFallDlyAmt d
$
Operating Transmission Congestion Rights Daily Shortfall Amount – The shortfall in congestion revenues that would be required to fully fund TCRs in Operating Day
$/MWh
Hour
DaClrdHrlyQty a, s, h,
MWh
Hour
DaClrdVHrlyQty a, s, h, t
MWh
Hour
DaImpExp5minQty a, s, i, t
MW
TcrHrlyQty a, h, t
MWh
Dispatch Interval Hour
$
Hour
DaMccHrlyPrc
s, h
TcrFundHrlyAmt a, h
Version 23.a
Day d. Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The Marginal Congestion Component of the Day-Ahead LMP at Settlement Location s for Hour h. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1. Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3. Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.2. Transmission Congestion Right Quantity - The value described under Section 4.5.8.14. Transmission Congestion Rights Hourly Funding Amount per AO per Hour The value calculated under Section 4.5.8.14.
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Variable
Unit
Settlement Interval
$
a h s i t
none none none none none
Operating Day none none none none none
d m
none none
none none
TcrUpliftDlyMpAmt m, d
Version 23.a
Definition
Transmission Congestion Rights Daily Uplift Amount per MP per Operating Day - MP m’s share of the ShortFallDlyAmt d in Operating Day d. An Asset Owner. An Hour. A Settlement Location. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
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4.5.8.16
Transmission Congestion Rights Monthly Payback Amount
(1) A DA Market monthly credit or charge15 will be calculated for each Asset Owner receiving a charge under Section 4.5.8.15 in any Operating Day of the month in order to ensure full funding of TCRs to the extent possible. The amount is calculated as follows: #TcrPaybackMnthlyAmt a, mn = (-1) * Min {TcrUpliftAoMnthlyAmt a, mn, [ ECFMnthlyAmt mn * TcrUpliftAoMnthlyAmt a, mn / TcrUpliftSppMnthlyAmt mn ] } Where, (a)
TcrUpliftAoMnthlyAmt a, mn =
TcrUpliftDlyAmt a, d
d
(b)
TcrUpliftSppMnthlyAmt mn =
a
(c)
# ECFMnthlyAmt mn =
TcrUpliftDlyAmt a, d
d
ECFDlyAmt d
d
(c.1)
#ECFDlyAmt d = Max { 0,
a
+
i
+
[ DaMccHrlyPrc s, h * ( DaClrdHrlyQty a, s, h
h
( DaImpExp5minQty a, s, i, t / 12 ) +
t
a
s
DaClrdVHrlyQty a, s, h, t ) ]
t
TcrFundHrlyAmt a, h }
h
15
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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(2) For each Market Participant, a monthly amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The monthly amount is calculated as follows: TcrPaybackMnthlyMpAmt m, mn =
TcrPaybackMnthlyAmt a, mn
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
TcrPaybackMnthlyAmt a, mn
$
Month
Transmission Congestion Rights Monthly Payback Amount per AO - AO a’s share of the ECFMnthlyAmt mn in month mn.
TcrUpliftAoMnthlyAmt a, mn
$
Month
Transmission Congestion Rights Monthly Uplift Amount per AO – The sum of TcrUpliftDlyAmt a, d for AO a for Month mn.
TcrUpliftSppMnthlyAmt mn
$
Month
ECFMnthlyAmt mn
$
Month
ECFDlyAmt d
$
Operating Day
Transmission Congestion Rights Monthly Uplift Amount – The sum of TcrUpliftAoMnthlyAmt a, mn for all AOs for Month mn. Excess Congestion Fund Monthly Amount – The sum of ECFDlyAmt d in month mn. Excess Congestion Fund Daily Amount – The excess in congestion revenues over that required to fully fund TCRs in Operating Day d.
$/MWh
Hour
DaClrdHrlyQty a, s, h
MWh
Hour
DaClrdVHrlyQty a, s, h, t
MWh
Hour
DaImpExp5minQty a, s, i, t
MW
Dispatch Interval
TcrFundHrlyAmt a, h
$
Hour
TcrUpliftDlyAmt a, d
$
Operating Day
DaMccHrlyPrc
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s, h
Definition
Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The Marginal Congestion Component of the Day-Ahead LMP at Settlement Location s for Hour h. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1. Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3. Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.2. Transmission Congestion Rights Hourly Funding Amount per AO per Hour - The value calculated under Section 4.5.8.14. Transmission Congestion Rights Daily Uplift Amount per AO - The value calculated under Section 4.5.8.15.
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Variable
Unit
Settlement Interval
$
Month
a h s i t
none none none none none
none none none none none
d mn m
none none none
none none none
TcrPaybackMnthlyMpAmt m, mn
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Definition
Transmission Congestion Rights Monthly Payback Amount per MP per Month - MP a’s share of the ECFMnthlyAmt mn in month mn. An Asset Owner. An Hour. A Settlement Location. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A month. A Market Participant.
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4.5.8.17
Transmission Congestion Rights Annual Payback Amount
(1) A DA Market annual credit or charge16 will be calculated for each Asset Owner receiving credits under Section 4.5.8.16 that were not sufficient to cover charges received under Section 4.5.8.15 over the year in order to ensure full funding of TCRs to the extent possible. The amount is calculated as follows: #TcrPaybackYrlyAmt a, yr = (-1) * Min {TcrNetUpliftAoYrlyAmt a, yr, ECFYrlyAmt yr * [ TcrNetUpliftAoYrlyAmt a, yr / TcrNetUpliftSppYrlyAmt yr ] } Where, (a)
TcrNetUpliftAoYrlyAmt a, yr =
TcrUpliftDlyAmt a, d +
(b)
TcrPaybackMnthlyAmt a, mn
TcrNetUpliftSppYrlyAmt yr =
[ a
(c)
mn
d
TcrUpliftDlyAmt a, d +
ECFYrlyAmt yr =
TcrPaybackMnthlyAmt a, mn ]
mn
d
ECFMnthlyAmt mn +
mn
mn
TcrPaybackMnthlyAmt a, mn
a
(2) For each Market Participant, an annual amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The annual amount is calculated as follows: TcrPaybackYrlyMpAmt m, yr =
TcrPaybackYrlyAmt a, yr
a
16
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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The above variables are defined as follows: Variable
Unit
Settlement Interval
TcrPaybackYrlyAmt a, yr
$
Year
Transmission Congestion Rights Annual Payback Amount per AO - AO a’s share of the ECFYrlyAmt mn in year yr limited to the amount required to fully fund AO a’s TCRs.
TcrNetUpliftAoYrlyAmt a, yr
$
Year
Transmission Congestion Rights Net Uplift Amount per AO per Year – AO a’s remaining uplift amount to be paid in year yr.
TcrNetUpliftSppYrlyAmt yr
$
Year
TcrPaybackMnthlyAmt a, mn
$
Month
ECFYrlyAmt yr
$
Year
ECFMnthlyAmt mn
$
Month
TcrUpliftDlyAmt a, d
MWh $
Operating Day Year
none none none none none
none none none none none
Transmission Congestion Rights Net Uplift Amount per Year – The total of all AO’s remaining uplift amounts to be paid in year yr. Transmission Congestion Rights Monthly Payback Amount per AO - The value described under Section 4.5.8.16. Excess Congestion Fund Yearly Amount – The sum of ECFMthlyAmt mn in year yr, net of payback from the month-end process. Excess Congestion Fund Monthly Amount – The value described under Section 4.5.8.16. Transmission Congestion Rights Daily Uplift Amount per AO - The value calculated under Section 4.5.8.15. Transmission Congestion Rights Monthly Payback Amount per MP per Year MP a’s share of the ECFYrlyAmt yr in year yr. An Asset Owner. An Operating Day. A month. A year. A Market Participant.
TcrPaybackYrlyMpAmt m, yr a d mn yr m
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4.5.8.18
Transmission Congestion Rights Annual Closeout Amount
(1) A DA Market annual credit or charge17 will be calculated for each Asset Owner Transmission Customer with ARR Nomination Caps established under Section 5.1.3 to the extent that there are any funds remaining once all credits are paid under Section 4.5.8.17. The calculation of the Transmission Congestion Rights Annual Closeout Amount for each Asset Owner with an ARR nomination Cap can result in residual amounts due to rounding. The sum of the residual amounts due to rounding across Asset Owners can result in the Transmission Congestion Rights not being revenue neutral for the year. The difference, whether a credit or charge, will be uplifted to the Asset Owners on a yearly basis. On Operating Day March 1, of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Owners. The Transmission Congestion Rights Annual Closeout amount is calculated as follows: #TcrCloseoutYrlyAmt a, yr = (-1) * [ ECFYrlyAmt yr + TcrPaybackSppYrlyAmt yr ] * ArrNominationCapAoYrlyQty a, yr / ArrNominationCapSppYrlyQty yr
(a)
TcrPaybackSppYrlyAmt yr =
TcrPaybackYrlyAmt a, yr
a
(b)
ArrNominationCapAoYrlyQty a, yr =
ArrNominationCapQty a, d
d
(c)
ArrNominationCapSppYrlyQty yr =
a
ArrNominationCapQty a, d
d
(2) For each Market Participant, an annual amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The annual amount is calculated as follows:
17
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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TcrCloseoutYrlyMpAmt m, yr =
TcrCloseoutYrlyAmt a, yr
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
TcrCloseoutYrlyAmt a, yr
$
Year
TcrPaybackYrlyAmt a, yr
$
Year
TcrPaybackSppYrlyAmt yr
$
Year
ArrNominationCapAoYrlyQty a, yr
MW
Year
ArrNominationCapSppYrlyQty yr
MW
Year
$
Year
MW
Operating Day
$
Year
none none none none
none none none none
Transmission Congestion Rights Annual Payback Amount per AO - AO a’s share of any remaining ECFYrlyAmt mn in year yr. Transmission Congestion Rights Annual Payback Amount per AO - The value calculated under Section 4.5.8.17. Transmission Congestion Rights Payback Total per Year- The SPP total of the values calculated under Section 4.5.8.17 for year yr. ARR Nomination Cap per AO per Year – The sum of ArrNominationCapQty for AO a for year yr. ARR Nomination Cap Total per Year – The SPP total of ArrNominationCapQty for year yr. Excess Congestion Fund Yearly Amount – The sum of ECFMthlyAmt mn in year yr. ARR Nomination Cap per AO per Operating Day – AO a’s ARR Nomination Maximum Daily Quantity that an Eligible Entity qualifies for as described under Section 5.1.3 ARR Nomination Cap. Transmission Congestion Rights Annual Payback Amount per MP per Year - MP a’s share of the ECFYrlyAmt yr in year yr. An Asset Owner. An Operating Day. A year. A Market Participant.
ECFYrlyAmt yr ArrNominationCapQty a, d
TcrCloseoutYrlyMpAmt m, yr a d yr m
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4.5.8.19
Day-Ahead Over-Collected Losses Distribution Amount
(1) The Marginal Losses Component of the DA Market LMP that results from the economic market solution which considers the cost of marginal losses, congestion costs and incremental Energy costs creates an over collection related to payment for losses (“DA Market Over-Collected Losses”) that must be accounted for. DA Market Over-Collected Losses are calculated and distributed as described under Section 4.5.9.20refunded. A DA Market credit or charge18 is calculated for each hour at each Settlement Location for which an Asset Owner has a DA Market Energy withdrawal in a Loss Pool that contributed positively to the over collection. Each Loss Pool’s contribution to the DA Market OverCollected Losses is calculated based upon the Settlement Locations contained within the Loss Pool. There are two types of Loss Pools: (a) Loss Pools defined by all Settlement Locations within a Settlement Area (“Settlement Area Loss Pool”); and (b) a single Loss Pool defined by all Hub and External Interface Settlement Locations (“System-Wide Loss Pool”). Injection/withdrawal amounts associated with Settlement Locations spanning multiple Settlement Area Loss Pools are allocated pro rata using the billable metering values submitted at the associated Meter Data Submittal Locations. A loss rebate factor is calculated for each withdrawal Settlement Location as the difference between the Marginal Loss Component at a withdrawal Settlement Location and the injection weighted average Marginal Loss Component for the Loss Pool, multiplied by the net DA Market Energy withdrawal at that Settlement Location. The injection weighted average MLC for the Loss Pool is calculated assuming that injection in the Loss Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools which do not have sufficient injections to meet all withdrawals. The sum of the Settlement Location loss rebate factors (positive value only, negative values are ignored) in a Loss Pool is a measure of that Loss Pool’s payment for losses on a marginal basis. The Loss Pool sum of the Settlement Location loss rebate factors are then normalized to allocate a pro-rata portion of the total over collection in the hour to each Loss Pool. Within a Loss Pool, each Asset Owner is allocated a portion of the Loss Pool subtotal at each Settlement Location based on a ratio share of its DA Market Energy withdrawal (excluding Virtual Energy Bids and Virtual Energy Offers) to that of the Loss Pool in total. Asset Owners with GFA Carve Out energy transactions are not
18
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
qualified to receive loss rebates associated with the GFA Carve Out transactions. The amount is calculated as follows: (2) #DaOclDistHrlyAmt a, s, lp, h = DaAoSlLpLrsHrlyFct a, s, lp, h * DaNormLpRbtHrlyFct * DaOclHrlyAmt h * (-1)
lp, h
(3) Where, (4) (a)
#DaOclHrlyAmt h =
(5) * ( DaClrdHrlyQty a, s, h +
[(DaLmpHrlyPrc s, h - DaMccHrlyPrc s, h )
s
a
DaClrdVHrlyQty a, s,
h, t
t
(6) +
DaImpExp5minQty a, s,
/ 12 )]
i, t
t
i
(7) (b) IF DaSppRbtHrlyFct h = 0 (8) THEN (9) DaNormLpRbtHrlyFct lp, h = 0 (10)
ELSE
(11)
#DaNormLpRbtHrlyFct
(12)
Max ( 0, DaLpRbtHrlyFct
(13)
(b.1)
lp, h
lp, h
=
/ DaSppRbtHrlyFct h )
DaSppRbtHrlyFct h =
DaLpRbtHrlyFct
lp, h
lp
(14)
(b.2)
DaLpRbtHrlyFct lp, h =
Max ( 0, DaSlRbtHrlyFct s, lp, h )
s
(15)
(b.3)
(16)
* ( DaMlcHrlyPrc s, h – DaLpIwaMlcHrlyPrc lp, h )
(17)
+ ( 1 – DaLpIntSupplyHrlyFct lp, h )
(18)
* ( DaMlcHrlyPrc s, h – DaSppIwaMlcHrlyPrc h ) ]
(19)
#DaSlRbtHrlyFct
s, lp, h
= [ DaLpIntSupplyHrlyFct lp, h
* DaSlWdrHrlyQty s, lp, h
(20)
(b.4)
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DaSlWdrHrlyQty s, lp, h =
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(21)
Max ( 0,
SltoLpHrlyMap s, lp, h * [ DaClrdHrlyQty
a, s, h
+
DaClrdVHrlyQty a, s,
t
a
h, t
(22)
+
i
(23)
( DaImpExp5minQty a, s,
i, t
/ 12 ) ] )
t
(b.5)
DaLpWdrHrlyQty lp, h =
DaSlWdrHrlyQty s, lp, h
s
(24)
(b.6)
IF DaLpWdrHrlyQty lp, h = 0
(25)
THEN
(26)
DaLpIntSupplyHrlyFct lp, h = 0
(27)
ELSE
(28)
DaLpIntSupplyHrlyFct lp, h =
(29)
Min [ 1, DaLpInjHrlyQty
(30)
(b.7)
(31)
{ Min (0,
lp, h
/ DaLpWdrHrlyQty
lp, h
]
DaSlInjHrlyQty s, lp, h =
SltoLpHrlyMap s, lp, h * [ DaClrdHrlyQty a, s,
h
+
DaClrdVHrlyQty
t
a
a, s, h, t
(32)
+
i
(33)
( DaImpExp5minQty a, s,
i, t
/ 12 ) ] ) } * (-1)
t
(b.8)
DaLpInjHrlyQty lp, h =
DaSlInjHrlyQty s, lp, h
s
(34)
(b.9)
(35)
THEN
(36)
DaLpExtSupplyHrlyFct lp, h = 0
(37)
ELSE
(38)
DaLpExtSupplyHrlyFct lp, h =
(39)
Max [ 0, ( 1 – (DaLpWdrHrlyQty lp, h
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lp, h
=0
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(40)
/ DaLpInjHrlyQty
(41)
(b.10) IF DaLpInjHrlyQty
(42)
THEN
(43)
DaLpIwaMlcHrlyPrc lp, h = 0
(44)
ELSE
(45)
DaLpIwaMlcHrlyPrc lp, h =
(46)
lp, h
DaSlInjHrlyQty
))]
s, lp, h
lp, h
=0
* DaMlcHrlyPrc s, h
s
(47)
/ DaLpInjHrlyQty
(48)
(b.11) DaSppIwaMlcHrlyPrc h =
lp, h
[ DaLpExtSupplyHrlyFct
lp, h
lp
(49)
*
( DaSlInjHrlyQty
* DaMlcHrlyPrc s, h ) ]
s, lp, h
s
(50)
/
[ DaLpExtSupplyHrlyFct lp, h * DaLpInjHrlyQty
lp, h
]
lp
(51)
(c)
(52)
DaAoSlWdrHrlyQty a, s, lp, h / DaAoLpWdrHrlyQty lp, h
(53)
(c.1)
(54)
SltoLpHrlyMap s, lp, h * [ Max (0, ( DaClrdHrlyQty a, s, h
(55)
-
DaAoSlLpLrsHrlyFct a, s, lp, h =
DaAoSlWdrHrlyQty a, s, lp, h =
DaEnFinHrlyQty a, s, h, t -
t
(56)
DaNEnFinHrlyQty a, s, h, t
t
+
i
(57)
(c.2)
( DaImpExp5minQty a, s, i, t / 12 ) ) ) ]
t
DaAoLpWdrHrlyQty lp, h =
a
DaAoSlWdrHrlyQty a, s, lp, h
s
(58) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows:
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(59)
DaOclDistDlyAmt a, s, lp, d =
DaOclDistHrlyAmt a, s, lp, h
h
(60) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: (61)
DaOclDistAoAmt a, m, d =
s
DaOclDistDlyAmt a, s, lp, d
lp
(62) 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: (63)
DaOclDistMpAmt m, d =
DaOclDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
none
Hour
DaSlRbtHrlyFct s, lp, h
$
Hour
DaLpRbtHrlyFct lp, h
$
Hour
DaSppRbtHrlyFct h
$
Hour
DaOclHrlyAmt h
$
Hour
DaLpIntSupplyHrlyFct lp, h
none
Hour
DaLpExtSupplyHrlyFct lp, h
none
Hour
$/MWh
Hour
Day-Ahead Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool per Hour - The amount to AO a for AO a’s share of total over collection due to marginal losses at Settlement Location s in Loss Pool lp for the Hour. Day-Ahead Normalized Loss Rebate Factor per Loss Pool per Hour – The percentage of DaOclHrlyAmt h allocated to Loss Pool lp for the Hour. Day-Ahead Loss Rebate Factor per Settlement Location per Loss Pool per Hour – The amount of marginal loss dollars collected at Settlement Location s in Loss Pool lp for the Hour. Day-Ahead Loss Rebate Factor per Loss Pool per Hour – the amount of marginal loss dollars collected in Loss Pool lp for the Hour. Day-Ahead Loss Rebate Factor per Hour – The SPP total of DaLpRbtHrlyFct lp, h for the Hour. Day-Ahead Over Collected Losses Amount per Hour – The amount of over collection in the DA Market due to marginal losses for the Hour. Day-Ahead Loss Pool Internal Supply Factor per Loss Pool per Hour – A ratio indicating the percentage of Loss Pool lp’s net DA Market Energy withdrawals that are being served by net injections inside of Loss Pool lp. Day-Ahead Loss Pool External Supply Factor per Loss Pool per Hour – A ratio indicating the percentage of Loss Pool lp’s net DA Market Energy injections that are in excess of Loss Pool lp’s net withdrawals. Day-Ahead Loss Pool Injection Weighted Average Marginal Loss Component per Loss Pool per Hour - The weighted average DaMlcHrlyPrc s, h for all net DA Market Energy injections in loss pool lp in Hour h.
DaOclDistHrlyAmt a, s, lp, h
DaNormLpRbtHrlyFct
lp, h
DaLpIwaMlcHrlyPrc lp, h
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Variable
Unit
Settlement Interval
Definition
$/MWh
Hour
lp, h
MWh
Hour
DaSlInjHrlyQty s, lp, h
MWh
Hour
DaLpWdrHrlyQty
lp, h
MWh
Hour
DaSlWdrHrlyQty s, lp, h
MWh
Hour
DaLmpHrlyPrc s, h
$/MWh
Hour
DaMccHrlyPrc
$/MWh
Hour
$/MWh
Hour
SltoLpHrlyMap s, lp, h
none
Hour
DaClrdHrlyQty a, s,
MWh
Hour
Day-Ahead SPP Injection Weighted Average Marginal Loss Component per Hour - The weighted average DaMlcHrlyPrc s, h for all loss pool DA Market Energy injections in excess of loss pool net DA Market Energy withdrawals in Hour h. Day-Ahead Net Injection Quantity per Loss Pool per Hour –The net DA Market Energy injection quantity in Loss pool lp in Hour h. Day-Ahead Net Injection Quantity per Settlement Location per Loss Pool per Hour – Settlement Location s’s net DA Market Energy injection quantity in Loss pool lp in Hour h. Day-Ahead Net Withdrawal Quantity per Loss Pool per Hour –The net DA Market Energy withdrawal in Loss pool lp in Hour h. Day-Ahead Net Withdrawal Quantity per Settlement Location per Loss Pool per Hour –Settlement Location s’s net DA Market Energy withdrawal quantity for Hour h. Day-Ahead LMP – The value described under Section 4.5.8.1 at Settlement Location s for Hour h. Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The value described under Section 4.5.8.14 at Settlement Location s for Hour h. Day-Ahead Marginal Losses Component of Day-Ahead LMP – The Marginal Losses Component of the Day-Ahead LMP at Settlement Location s for Hour h. Settlement Location to Loss Pool Map per Settlement Location per Loss Pool per Hour - The portion of injection or withdrawal at Settlement Location s associated with Loss Pool lp for the Hour. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1 for AO a at Settlement Location s in for Hour h.
DaSppIwaMlcHrlyPrc h
DaLpInjHrlyQty
s, h
DaMlcHrlyPrc s, h
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Variable
Unit
Settlement Interval
Definition
MWh
Hour
MW
Dispatch Interval
DaEnFinHrlyQty a, s, h, t
MWh
Hour
DaNEnFinHrlyQty a, s, h, t
MWh
Hour
DaAoSlLpLrsHrlyFct a, s, lp, h
none
Hour
DaAoSlWdrHrlyQty a, s, lp, h
MWh
Hour
DaAoLpWdrHrlyQty lp, h
MWh
Hour
Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Transaction per Hour in the DA Market – The value described under Section 4.5.8.3 for AO a at Settlement Location s in for transaction t for Hour h. Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.8.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i. Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h Day-Ahead Non-Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h Day-Ahead Loss Pool Load Ratio Share per AO per Settlement Location per Loss Pool per Hour – The ratio of AO a’s net DA Market Energy withdrawals at Settlement Location s to the total net DA Market Energy withdrawals in Loss Pool lp for Hour h. Day-Ahead Net Market Energy Asset Owner withdrawal per AO per Settlement Location per Loss Pool per Hour – The positive value of the net sum of AO a’s Day-Ahead Cleared Energy, Day-Ahead Interchange Transaction, Day-Ahead Asset Energy Bilateral Settlement Schedule and Day-Ahead Non-Asset Energy Bilateral Settlement Schedule Quantities at Settlement Location s in a Loss Pool lp for Hour h. Day-Ahead Net Market Asset Owner Energy withdrawal per Loss Pool per Hour – The sum of Day-Ahead Market Energy Asset Owner net DA Market Energy withdrawal in a Loss Pool lp for Hour h.
DaClrdVHrlyQty a, s,
h, t
DaImpExp5minQty a, s,
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Variable
Unit
Settlement Interval
Definition
DaOclDistDlyAmt a, s, lp, d
$
Operating Day
DaOclDistAoAmt a, m,
$
Operating Day
$
Operating Day
a s h i t
none none none none none
none none none none none
d lp m
none none none
none none none
Day-Ahead Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool per Operating Day- The amount to AO a for AO a’s share of total over collection due to marginal losses at Settlement Location s in Loss Pool lp for the Operating Day. Day-Ahead Over Collected Losses Distribution Amount per AO per Operating Day- The amount to AO a associated with Market Participant m for AO a’s share of total over collection due to marginal losses for the Operating Day. Day-Ahead Over Collected Losses Distribution Amount per MP per Operating Day- The amount to MP m for MP m’s share of total over collection due to marginal losses for the Operating Day. An Asset Owner. A Settlement Location. An Hour. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Loss Pool. A Market Participant.
DaOclDistMpAmt m, d
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4.5.8.20
Day-Ahead Virtual Energy Transaction Fee Amount
(1) A DA Market credit19 or charge for each hour of the Operating Day in which a Virtual Energy Offer and Virtual Energy Bid is submitted as of the close of the Day-Ahead Market will be calculated for each Asset Owner for each Operating Day. Charges collected by SPP under this charge type are used by SPP to reduce the SPP budgeted expenses used to calculate the rate specified under Schedule 1-A of the SPP Tariff. The amount is calculated as follows: #DaVTxnFeeAoAmt a, m, d = DaVTxnDlyCnt a, d * DaVTxnFeeDlyRate d (2) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net daily charge or credit is calculated as follows: DaVTxnFeeMpAmt m, d =
DaVTxnFeeAoAmt a, m, d
a
19
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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The above variables are defined as follows: Variable
DaVTxnFeeAoAmt a, m, d
DaVTxnDlyCnt a, d
DaVTxnFeeDlyRate d
DaVTxnFeeMpAmt m, d
a d m
Version 23.a
Unit
Settlement Interval
Definition
$
Operating Day
none
Operating Day
$/Transaction
Operating Day
$
Operating Day
none none none
none none none
Day-Ahead Virtual Energy Transaction Fee Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for total amount of submitted Virtual Energy Offers and Virtual Energy Bids in Operating Day d. Day-Ahead Virtual Energy Transaction Daily Count per AO per Operating Day - The total number of AO a’s submitted Virtual Energy Offers and Virtual Energy Bids in Operating Day d. Day-Ahead Virtual Energy Transaction Fee Rate per Operating Day The daily rate applied to DaVTxnDlyCnt a, d in Operating Day d as specified in the SPP Tariff. Day-Ahead Virtual Energy Transaction Fee Amount per MP per Operating Day - The DA Market amount to MP m for total amount of submitted Virtual Energy Offers and Virtual Energy Bids in Operating Day d submitted by all AOs associated with Market Participant m. An Asset Owner. An Operating Day. A Market Participant.
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4.5.8.21 (1)
Day-Ahead Demand Reduction Amount
A DA Market credit or charge20 associated with each Demand Response Resource cleared in the Day-Ahead Market will be calculated for the Asset Owner associated with the host load Settlement Location which includes the associated Demand Response Load for each hour. This credit is required in order to remove the settlement impact of grossing up the host load by the amount of associated Demand Response Resource output. The net amount is calculated as follows: #DaDRHrlyAmt a, s (host), h = DaLoadGrossUpHrlyQty a, s (host), h * DaLmpHrlyPrc s (host), h * (-1) Where, (a)
DaLoadGrossUpHrlyQty a, s (host), h =
{ MAPdrr to host [ DaClrdHrlyQty a, s (drr), h ] } * (-1) drr
(2)
For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: DaDRDlyAmt a, s, d =
DaDRHrlyAmt a, s, h
h
(3)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaDRAoAmt a, m, d =
DaDRDlyAmt a, s, d
s
(4)
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:
20
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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DaDRMpAmt m, d =
DaDRAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement
Definition
Interval $
Hour
MWh
Hour
$/MWh
Hour
MWh
Dispatch Interval
DaDRDlyAmt a, s, d
$
Operating Day
DaDRAoAmt a, m, d
$
Operating Day
DaDRMpAmt m, d
$
Operating Day
none none none none
none none none none
DaDRHrlyAmt a, s (host), h
DaLoadGrossUpHrlyQty a, s (host), h
DaLmpHrlyPrc s, h DaClrdHrlyQty a, s, h
a s h d
Version 23.a
Day-Ahead Demand Reduction Amount per AO per Settlement Location per Hour - The DA Market amount to AO a for Demand Reduction at host load Settlement Location s for the Hour. Day-Ahead Load Gross-Up Quantity per AO per Settlement Location per Hour - The sum of Demand Response Resources cleared in the Day-Ahead Market associated with AO a’s load Settlement Location s in Hour h. Day-Ahead LMP – The value described under Section 4.5.8.1 at the host load Settlement Location s for Hour h. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1 for AO a at DRR Settlement Location s for Hour h. Day-Ahead Demand Reduction Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for Demand Reduction at Settlement Location s for the Operating Day. Day-Ahead Demand Reduction Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for Demand Reduction for the Operating Day. Day-Ahead Demand Reduction Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for Demand Reduction for the Operating Day. An Asset Owner. A Settlement Location. An Hour. An Operating Day.
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Variable
Unit
Settlement
Definition
Interval m
Version 23.a
none
none
A Market Participant.
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4.5.8.22 (1)
Day-Ahead Demand Reduction Distribution Amount
A DA Market charge or credit21 will be calculated for each Asset Owner for each Settlement Location for each hour in which a Demand Response Resource was cleared in order to fund the credits paid under Section 4.5.8.1. The Settlement Location amount will be equal to the distribution rate for Demand Reduction multiplied by the Asset Owners’ DA Market cleared Energy withdrawals. The amount to each Settlement Location is calculated as follows: #DaDRDistHrlyAmt a, s, h =
DaDRLoadHrlyQty a, s, h * DaDRDistHrlyRate h
s
Where, (a)
#DaDRLoadHrlyQty a, s, h = Max (0, DaClrdHrlyQty a, s, h )
+ Max ( 0 ,
DaClrdVHrlyQty a, s, h, t ) + Max ( 0 ,
i
t
DaImpExp5minQty a, s, i, t
t
/ 12 ) The cost allocation rate is calculated by dividing the total of all demand reduction credits by the total of allocation quantities. (b)
#DaDRDistHrlyRate h = DaDRDistHrlyCost h / DaDRDistHrlyQty h
(b.1) (
DaDRDistHrlyCost
h
=
DaDRHrlyAmt a, s, h ) * -1 a
s
21
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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(b.2)
DaDRDistHrlyQty h =
a
(2)
DaDRLoadHrlyQty a, s, h
s
For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: DaDRDistDlyAmt a, s, d =
DaDRDistHrlyAmt a, s, h
h
(3)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: DaDRDistAoAmt a, m, d =
DaDRDistDlyAmt a, s, d
s
(4)
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: DaDRDistMpAmt m, d =
DaDRDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
DaDRDistHrlyAmt a,
s, h
DaDRLoadHrlyQty a, s,
h
Unit
Settlement Interval
Definition
$
Hour
MWh
Hour
Day-Ahead Demand Reduction Distribution Amount per AO per Hour The amount to AO a for AO a’s share of DA Market Demand Reduction costs per Settlement Location per Hour. Day-Ahead Demand Reduction Load per AO per Settlement Location for Hour h – Asset Owner a’s load, virtual withdrawal and Export Interchange Transactions cleared in the DA Market at Settlement Location s for Hour h for use in Demand Reduction cost allocation. Day-Ahead Demand Reduction Distribution Rate per Hour – The rate applied to AO a’s Demand Reduction load in Hour h. Day-Ahead Demand Reduction Distribution Cost per Hour – The cost of Demand Reduction in Hour h. Day-Ahead Demand Reduction Distribution Quantity per Hour – The total cost allocation quantity for Demand Reduction in Hour h. Day-Ahead Demand Reduction Amount per AO per Settlement Location per Hour - The value described under Section 4.5.8.21. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1 for AO a at Settlement Location s for Hour h. Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3. Day-Ahead Interchange Transaction Quantity per AO per Transaction per Settlement Location per Dispatch Interval – The value described under Section 4.5.8.2. Day-Ahead Demand Reduction Distribution Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for Demand Reduction for the Operating Day.
DaDRDistHrlyRate
h
$/MWh
Hour
DaDRDistHrlyCost
h
$
Hour
MWh
Hour
DaDRHrlyAmt a, s, h
$
Hour
DaClrdHrlyQty a, s, h
MWh
Dispatch Interval
DaClrdVHrlyQty a, s, h, t
MWh
Hour
DaImpExp5minQty a, s, i, t
MWh
Dispatch Interval
$
Operating Day
DaDRDistHrlyQty
h
DaDRDistAoAmt a, m, d
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Variable
Unit
Settlement Interval
DaDRDistMpAmt m, d
$
Operating Day
DaDRDistDlyAmt a, s, d
$
Operating Day
none none none none none
none none none none none
a s h d m
Version 23.a
Definition
Day-Ahead Demand Reduction Distribution Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for Demand Reduction for the Operating Day. Day-Ahead Demand Reduction Distribution Amount per Settlement Location per Operating Day - The DA Market amount to Settlement Location s associated with AO a for Demand Reduction for the Operating Day. An Asset Owner. A Settlement Location. An Hour. An Operating Day. A Market Participant.
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4.5.8.23
Day-Ahead Grandfathered Agreement Carve-Out Daily Amount
(1) A DA Market credit or charge for exclusion of transactions associated with Grandfathered Agreements from Market Settlement of congestion, losses and hedging instruments, is calculated each day for every Asset Owner modeled to represent a Grandfathered Agreement Carve-Out. The net amount is calculated as follows: #DaGFAAoAmt a, m, d = -1 * [ DaEnergyAoAmt a, m, d + DaNEnergyAoAmt a, m, d + TcrFundAoAmt a, m, d + TcrUpliftDlyAmt a, m, d Comment [MPRR212.592]: MPRR212 Awaiting FERC filing
+ DaRtOclDistAoAmt a, m, d + TcrAucTxnAoAmt a, m, d + ArrAucTxnAoAmt a, m, d + ArrUpliftAoAmt a, m, d ] * AoIsGFADlyFlg a, m, d (2)
For each Market Participant, a daily amount is calculated representing the sum of Grandfathered Agreement Carve-Out Asset Owner amounts associated with that Market Participant. The net amount is calculated as follows: DaGFAMpAmt m, d =
DaGFAAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaGFAAoAmt a, m, d
$
Operating Day
DaEnergyAoAmt a, m, d
$
Operating Day
Day-Ahead Grandfathered Agreement Carve-Out Daily Amount per AO per Operating Day – The net reversal of charges and credits from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead OverCollected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount to AO a modeled to represent a Grandfathered Agreement Carve-Out associated with Market Participant m for the Operating Day Day-Ahead Asset Energy Amount per AO per Operating Day – The value as calculated under 4.5.8.1.
DaNEnergyAoAmt a, m, d
$
Operating Day
Day-Ahead Non-Asset Energy Amount per AO per Operating Day – The value as calculated under 4.5.8.2.
TcrFundAoAmt a, m, d
$
Operating Day
Transmission Congestion Rights Funding Amount per AO per Operating Day – The value as calculated under 4.5.8.14.
TcrUpliftDlyAmt a, m, d
$
Operating Day
Transmission Congestion Rights Daily Uplift Amount per AO – The value as calculated under 4.5.8.15.
DaRtOclDistAoAmt a, m, d
$
Operating Day
Day-AheadReal-Time Over Collected Losses Distribution Amount per AO per Operating Day – The value as calculated under 4.5.9.204.5.8.19.
TcrAucTxnAoAmt a, m, d
$
Operating Day
Transmission Congestion Right Auction Daily Amount per AO per Operating Day – The value as calculated under 4.5.10.1.
ArrAucTxnAoAmt a, m, d
$
Operating Day
Auction Revenue Rights Daily Amount per AO per Operating Day – The value as calculated under 4.5.10.2.
ArrUpliftAoAmt a, m, d
$
Operating Day
Auction Revenue Rights Daily Uplift Amount per AO per Operating Day – The value as calculated under 4.5.10.3.
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Market Protocols for SPP Integrated Marketplace
Variable
AoIsGFADlyFlg a, m.
d
DaGFAMpAmt m, d
a d m
Version 23.a
Unit
Settlement Interval
Definition
Operating Day
Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Operating Day – A Flag which indicates that the AO is exempt from Day-Ahead Transmission Congestion charge types, thus forcing the cost allocation of the exclusion into Non GFA Load Ratio Share Day-Ahead Grandfathered Agreement Carve-Out Daily Amount per MP per Operating Day – The net reversal of charges and credits from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead OverCollected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day. An Asset Owner. An Operating Day. A Market Participant.
$
Operating Day
none none none
none none none
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4.5.8.24 (1)
Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount
A Monthly Market credit or charge for exclusion of transactions associated with Grandfathered Agreements from Market Settlement of congestion hedging instruments, is calculated each month for every Asset Owner modeled to represent a Grandfathered Agreement Carve-Out. The net amount is calculated as follows:
#DaGFAAoMnthlyAmt a, m, mn = -1 * [ TcrPaybackMnthlyAmt a, m, mn + ArrPaybackMnthlyAmt a, m, mn ] * AoIsGFAMnthlyFlg a, m, mn (a)
AoIsGFAMnthlyFlg a, m, mn = { IF
AoIsGFADlyFlg a, m, d > 0 THEN 1, ELSE 0}
d
(2)
For each Market Participant, a monthly amount is calculated representing the sum of Grandfathered Agreement Carve-Out Asset Owner monthly amounts associated with that Market Participant. The net amount is calculated as follows:
DaGFAMpMnthlyAmt m, mn =
DaGFAAoMnthlyAmt a, m, mn
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaGFAAoMnthlyAmt a, m, mn
$
Month
TcrPaybackMnthlyAmt a, m, mn
$
Month
ArrPaybackMnthlyAmt a, m, mn
$
Month
Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount per AO per Month– The net reversal of charges and credits from the settlement of Transmission Congestion Rights Monthly Payback & Auction Revenue Rights Monthly Payback to AO a modeled to represent a Grandfathered Agreement Carve-Outs associated with Market Participant m for the Month Transmission Congestion Right Monthly Payback Amount per AO per Asset Owner per MP per Month – The amount calculated under Section 4.5.8.16. Auction Revenue Rights Monthly Payback Amount per AO per month The amount calculated under Section 4.5.10.4.
AoIsGFAMnthlyFlg a, m, mn
none
Month
AoIsGFADlyFlg a, m, d
none
Month
$
Month
none none none none
none none none none
DaGFAMpMnthlyAmt m, mn
a d mn m
Version 23.a
Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Month – A Flag which indicates that the AO is exempt from Day-Ahead Transmission Congestion charge types, thus forcing the cost allocation of the exclusion into Non GFA Load Ratio Share Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Day – The flag described under Section 4.5.8.23 Day-Ahead Grandfathered Agreement Carve-Out Monthly Amount per MP per Month – The net reversal of charges and credits from the settlement of Monthly Transmission Congestion Rights Paybacks & Monthly Auction Revenue Rights Paybacks to MP m modeled to represent a Grandfathered Agreement Carve-Out for the Month. An Asset Owner. An Operating Day. A Month. A Market Participant.
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4.5.8.25 (1)
Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount
A Yearly Market credit or charge for exclusion of transactions associated with Grandfathered Agreements from Market Settlement of congestion hedging instruments, is calculated each Year for every Asset Owner modeled to represent a Grandfathered Agreement Carve-Out. The net amount is calculated as follows:
#DaGFAAoYrlyAmt a, m, yr = -1 * [ TcrPaybackYrlyAmt a, m, yr + TcrCloseout YrlyAmt a, m, yr + ArrPaybackYrlyAmt a, m, yr + ArrCloseout YrlyAmt a, m, yr ] * AoIsGFAYrlyFlg a, m, yr (a)
AoIsGFAYrlyFlg a, m, yr = { IF
AoIsGFADlyFlg a, m, d > 0 THEN 1, ELSE 0}
d
(2)
For each Market Participant, a yearly amount is calculated representing the sum of Grandfathered Agreement Carve-Out Asset Owner yearly amounts associated with that Market Participant. The net amount is calculated as follows: DaGFAMpYrlyAmt m, yr =
DaGFAAoYrlyAmt a, mn, yr
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaGFAAoYrlyAmt a, m, yr
$
Year
TcrPaybackYrlyAmt a, m, yr
$
Year
Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount per AO per Year– The net reversal of charges and credits from the settlement of Transmission Congestion Rights Yearly Payback & Closeout, and Auction Revenue Rights Yearly Payback & Closeout to AO a modeled to represent a Grandfathered Agreement Carve-Out associated with Market Participant m for the Year Transmission Congestion Rights Annual Payback Amount per AO - The amount calculated under Section 4.5.8.17.
TcrCloseoutYrlyAmt a, m, yr
$
Year
ArrPaybackYrlyAmt a, m, yr
$
Year
ArrCloseoutYrlyAmt a, m, yr
$
Year
AoIsGFAYrlyFlg a, m, yr
none
Year
AoIsGFADlyFlg a, m, d
none
Day
$
Year
none
none
DaGFAMpYrlyAmt m, yr
a
Version 23.a
Transmission Congestion Rights Annual Payback Amount per AO – The amount calculated under Section 4.5.8.18. Auction Revenue Rights Annual Payback Amount per AO per year - The amount calculated under Section 4.5.10.5. Auction Revenue Rights Annual Payback Amount per AO per Year - The amount calculated under Section 4.5.10.6. Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Year – A Flag which indicates that the AO is exempt from Day-Ahead Transmission Congestion charge types, thus forcing the cost allocation of the exclusion into Non GFA Load Ratio Share Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Day – The flag described under Section 4.5.8.23 Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount per MP per Year – The net reversal of charges and credits from the settlement of Yearly Transmission Congestion Rights Paybacks & Closeouts, and Yearly Auction Revenue Rights Paybacks & Closeouts to MP m modeled to represent a Grandfather Agreement Carve-Out for the Year. An Asset Owner.
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Variable
mn yr m
Version 23.a
Unit
Settlement Interval
none none none
none none none
Definition
A Month A Year. A Market Participant.
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4.5.8.26
GFA Carve Out Distribution Daily Amount
(1) A GFA Carve-Out Amount charge or credit will be calculated for each Asset Owner for each day. The Asset Owner amount will be equal to the Asset Owner’s daily real-time load ratio share of the net GFA Carve-Out Amount costs where such real-time load ratio share excludes GFA Carve-Out load. The amount to each Asset Owner is calculated as follows: #DaGFACarveOutDistDlyAmt a, s, d = GFARevInadqcSppAmt spp, d * RtGFALoadRatioShareDlyFct a, s, d * (-1) Where, (a)
GFARevInadqcSppAmt spp, d =
DaGFAMpAmt m, d
m
(b)
RtGFALoadRatioShareDlyFct a, s, d =
RtNonGFAHrlyQty a, s, h /
h
(c)
h
a
RtNonGFAHrlyQty a, s, h
s
#RtNonGFAHrlyQty a, s, h =
= Max { 0,
Max ( 0, RtBillMtr5minQty a, s, i ) /12
i
+
i
Max( 0, RtImpExp5minQty a, s, i, t ) /12
t
– (AoIsGFALoadDlyFlg a, s, d, t * [Max (0, DaEnFinHrlyQty a, s, h, t ) + Max (0, DaNEnFinHrlyQty a, s, h, t )] ) }
(2) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:
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DaGFACarveOutDistAoDlyAmt a, m, d =
DaGFACarveOutDistDlyAmt a, s, d
s
(3) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows: DaGFACarveOutDistMpDlyAmt m, d =
DaGFACarveOutAoDlyAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for Reserve Zone z. Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 for Reserve Zone z. Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Operating Day – A Flag which indicates that the AO is exempt from the distribution of the GFA Carve Out Account Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Asset Settlement Location s, for each transaction t, for the Hour. The buyer AO quantity is a positive value and the seller AO quantity is a negative value. Day-Ahead Non-Asset Energy Bilateral Settlement Schedule for Energy per Transaction per AO per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Non-Asset Settlement Location s, for each transaction t, for the Hour. The buyer AO quantity is a positive value and the seller AO quantity is a negative value. Day Ahead GFA Carve Out Distribution Daily Amount per AO per Settlement Location per Operating Day – The amount to distribute to AO a at Settlement Location s in an Operating Day d. Day Ahead GFA Carve Out Distribution Amount per AO per Operating Day – The amount to distribute to AO a associated with Market Participant m in an Operating Day d.
Operating Day
AoIsGFALoadDlyFlg a, s, d, t
DaEnFinHrlyQty a, s, h, t
MWh
Hour
DaNEnFinHrlyQty a, s, h, t
MWh
Hour
DaGFACarveOutDistDlyAmt a, s, d
$
Operating Day
DaGFACarveOutDistAoDlyAmt a, m, d
$
Operating Day
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Variable
Unit
Settlement Interval
Definition
DaGFACarveOutDistMpDlyAmt m, d
$
Operating Day
GFARevInadqcSppDlyAmt spp, d
$
Operating Day
Day Ahead GFA Carve Out Distribution Daily Amount per MP per Operating Day – The amount for to distribute to MP m in an Operating Day d. Grandfathered Agreement Carve-Out Revenue Inadequacy Daily Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of DayAhead Asset & Non-Asset Energy, Day-Ahead Over-Collected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day. Real-Time Non-GFA Hourly Quantity per AO per Hour per Settlement Location – The value is calculated by taking the Load’s Real-Time Meter plus the Load’s Exports minus the GFA Carved Out Load MWs per AO a at Settlement Location s in hour h Real-Time GFA Load Ratio Share Daily Factor per AO per Hour per Settlement Location – The value is calculated by taking a single Asset Owner Load Settlement Location’s Real-Time GFA Exclusion Hourly Factor and divided it by the sum of all of the Asset Owner Load Settlement Location’s Real-Time GFA Exclusion Hourly Factor. Day-Ahead Grandfathered Agreement Carve-Out Amount per MP per Day - The value calculated under Section 4.5.8.23 An Asset Owner. A Resource Settlement Location. An Hour. An Operating Day. A Month A Market Participant.
Hour
RtNonGFAHrlyQty a, s, h
Operating Day
RtGFALoadRatioShareDlyFct a, s, d
DaGFAMpAmt m, d a s h d mn m
Version 23.a
$ none none none none none none
Operating Day None none none none none none
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Variable
spp
Version 23.a
Unit
Settlement Interval
none
none
Definition
Southwest Power Pool.
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4.5.8.27 (1)
GFA Carve Out Distribution Monthly Amount
A charge or credit will be calculated at each Settlement Location for each Asset Owner in order for SPP to remain revenue neutral on a monthly basis. Contributors to revenue non-neutrality include: (a)
Reversal of credits to GFA Carve-Outs through Monthly TCR Payback and
(b)
Reversal of credits to GFA Carve-Outs through Monthly ARR Payback;
The amount will be determined by multiplying the Asset Owner monthly determinant by the monthly GFA Carve-Out revenue inadequacy amount. The Asset Owner monthly determinant is equal to the Asset Owner’s monthly real-time load ratio share where such real-time load ratio share excludes GFA Carve Out load. The amount to each applicable Asset Owner is calculated as follows. #DaGFACarveOutDistMnthlyAmt a, s, mn = (GFARevInadqcSppMnthlyAmt spp, mn * RtGFALoadRatioShareMnthlyFct a, s, mn ) * (-1) Where, (a) #RtGFALoadRatioShareMnthlyFct a, s, mn =
(
RtGFALoadRatioShareDlyFct a, s, d) d
/ (
a
s
RtGFALoadRatioShareDlyFct a, s, d)
d
(b) GFARevInadqcSppMnthlyAmt spp, mn =
DaGFAMpMnthlyAmt
m, mn
m
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(2)
For each Asset Owner associated with Market Participant m, a monthly amount is calculated. The monthly amount is calculated as follows: DaGFACarveOutDistAoMnthlyAmt a, m, mn =
DaGFACarveOutDistMnthlyAmt a, s, mn
s
(3)
For each Market Participant, a monthly amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The monthly amount is calculated as follows:
DaGFACarveOutDistMpMnthlyAmt m, mn =
DaGFACarveOutDistAoMnthlyAmt a, m, mn
a
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The above variables are defined as follows: Variable
DaGFACarveOutDistMnthlyAmt
Unit
Settlement Interval
a, s,
$
Month
Day Ahead GFA Carve Out Distribution Monthly Amount per AO per Settlement Location per Month – The amount to distribute to AO a at Settlement Location s in Month mn.
a, s,
$/MW
Month
$
Month
$
Month
$
Month
MW
Hour
$
Month
none none none none
None none none none
Real-Time GFA Share Load Ratio Share Distribution Factor per AO per Month per Settlement Location – The ratio determining the portion of the total Grandfathered Agreement Carve-Out Revenue Inadequacy Monthly Amount assigned to AO a at Settlement Location s in Month mn. Day Ahead GFA Carve Out Distribution Amount per AO per Month – The amount to distribute to AO a associated with Market Participant m in Month mn. Day Ahead GFA Carve Out Distribution Monthly Amount per MP per Month – The amount for to distribute to MP m in Month mn. Grandfathered Agreement Carve-Out Revenue Inadequacy Monthly Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of Transmission Congestion Rights Payback Amount and Auction Revenue Rights Payback Amount for Month mn. Real-Time GFA Load Ratio Share per AO per Day per Settlement Location – The value calculated under Section 4.5.8.26 Day-Ahead Grandfathered Agreement Carve-Out Amount per MP per Month - The value calculated under Section 4.5.8.24 An Asset Owner. A Resource Settlement Location. An Hour. An Operating Day.
mn
RtGFALoadRatioShareMnthlyFct mn
DaGFACarveOutDistAoMnthlyAmt a, m, mn
DaGFACarveOutDistMpMnthlyAmt m, mn
GFARevInadqcSppMnthlyAmt spp, mn
RtGFALoadRatioShareDlyFct a, s, d DaGFAMpMnthlyAmt m, mn a s h d
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Definition
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Variable
mn m spp
Version 23.a
Unit
Settlement Interval
none none none
none none none
Definition
A Month A Market Participant. Southwest Power Pool.
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4.5.8.28 (1)
GFA Carve Out Distribution Yearly Amount
A charge or credit will be calculated at each Settlement Location for each Asset Owner in order for SPP to remain revenue neutral on a yearly basis. Contributors to revenue non-neutrality include: (a)
Reversal of credits to GFA Carve-Outs through Yearly TCR Payback;
(b)
Reversal of credits to GFA Carve-Outs through Yearly TCR Closeout;
(c)
Reversal of credits to GFA Carve-Outs through Yearly ARR Payback and
(d)
Reversal of credits to GFA Carve-Outs through Yearly ARR Closeout
The amount will be determined by multiplying the Asset Owner yearly determinant by the yearly GFA Carve-Out revenue inadequacy amount. The Asset Owner yearly determinant is equal to the Asset Owner’s yearly load ratio share where such load ratio excluded GFA Carve Out load. The amount to each applicable Asset Owner is calculated as follows. #DaGFACarveOutDistYrlyAmt a, s, yr = (GFARevInadqcSppYrlyAmt spp, yr * RtGFALoadRatioShareYrlyFct a, s, yr ) * (-1) Where, (a) #RtGFALoadRatioShareYrlyFct a, s, yr =
(
RtGFALoadRatioShareDlyFct a, s, d)
d
/ (
a
s
RtGFALoadRatioShareDlyFctQty a, s, d )
d
(b) GFARevInadqcSppYrlyAmt spp, yr =
DaGFAMpYrlyAmt
m, yr
m
(2)
For each Asset Owner associated with Market Participant m, a yearly amount is calculated. The yearly amount is calculated as follows: DaGFACarveOutDistAoYrlyAmt a, m, yr =
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DaGFACarveOutDistYrlyAmt a, s, yr
s
(3)
For each Market Participant, a yearly amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The yearly amount is calculated as follows: DaGFACarveOutDistMpYrlyAmt m, mn =
DaGFACarveOutDistAoYrlyAmt a, m, mn
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
DaGFACarveOutDistYrlyAmt a, s, yr
$
Year
none
Year
$
Year
$
Year
MW
Hour
$
Year
none none none none none none
None none none none none none
Day Ahead GFA Carve Out Distribution Yearly Amount per AO per Settlement Location per Yearly – The amount to distribute to AO a at Settlement Location s in Year yr. Real-Time GFA Load Ratio Share Factor per AO per Year per Settlement Location – The ratio determining the portion of the total Grandfathered Agreement Carve-Out Revenue Inadequacy Yearly Amount assigned to AO a at Settlement Location s in Year yr. Day Ahead GFA Carve Out Distribution Amount per AO per Year – The amount to distribute to AO a associated with Market Participant m in Year yr. Grandfathered Agreement Carve-Out Revenue Inadequacy Yearly Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of Transmission Congestion Rights Payback Amount, Transmission Congestion Rights Closeout Amount, Auction Revenue Rights Payback Amount and Auction Revenue Rights Closeout Amount for Year yr. Real-Time GFA Load Ratio Share per AO per Day per Settlement Location – The value calculated under Section 4.5.8.26 Day-Ahead Grandfathered Agreement Carve-Out Yearly Amount per MP per Year - The value calculated under Section 4.5.8.25 An Asset Owner. A Resource Settlement Location. An Hour. An Operating Day. A Month A Year
RtGFALoadRatioShareYrlyFct
a, s,
yr
DaGFACarveOutDistAoYrlyAmt
a,
m, yr
GFARevInadqcSppYrlyAmt spp, yr
RtGFALoadRatioShareDlyFct a, s, h DaGFAMpYrlyAmt m, yr a s h d mn yr
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Variable
m Spp
Version 23.a
Unit
Settlement Interval
none none
none none
Definition
A Market Participant. Southwest Power Pool.
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4.5.9
Real-Time Balancing Market Settlement
Settlement calculations for the Real-Time Balancing Market are performed on a Dispatch Interval basis for each Operating Day and are based upon the difference between the results of the RTBM process and the DA Market clearing for that Operating Day. To calculate RTBM actual Energy in a Dispatch Interval for Asset Owners that have not directly submitted 5-minute interval meter data, SPP allocates the submitted hourly meter data for Resources and loads into 5-minute values using 5-minute telemetered or State Estimator profiles for the corresponding hour. The profiling of the hourly meter data maintains the shape of the 5-minute telemetered or State Estimator values even if there are both positive and negative values contained within the 12 intervals. All Dispatch Interval values are expressed in MW, not MWh. Exhibit 4-24 shows an example of how the profiling will work for a Resource that submits an actual hourly meter amount of -80 MWh. Exhibit 4-24: Meter Profiling Example Interval
(1) State Estimator MW
(2) Absolute Value of Column (1)
1 2 3 4 5 6 7 8 9 10 11 12
10 5 0 -50 -60 -70 -80 -90 -100 -110 -120 -130 -66.25 MWh
10 5 0 50 60 70 80 90 100 110 120 130 825 (total)
(3) Normalize Column (2) [Col (2) MW / Total Col (2) MW] 0.012 0.006 0.000 0.061 0.073 0.085 0.097 0.109 0.121 0.133 0.145 0.158 1.000
(4) Profiled Hourly Meter (-80 – (-66.25)) * 12 * Col (3) + Col (1) 8 4 0 -60 -72 -84 -96 -108 -120 -132 -144 -156 -80 MWh (Meter) (submitted)
RTBM results are presented on an hourly basis but Market Participants and Asset Owners have access to the 5 minute data for verification purposes.
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(1)
Each Market Participant with actual Resource output is charged or paid for each Settlement Location for the difference between the amount of actual RTBM physical Energy sold and the amount of physical Energy sold in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.1);
(2)
Each Market Participant with Import Interchange Transactions or Through Interchange Transactions (Resource Node) is charged or paid for each Settlement Location for the difference between the amount of actual RTBM physical import Energy scheduled and the amount of physical Energy sold in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.2);
(3)
Each Market Participant with virtual Energy purchased in the DA Market is paid for the amount of virtual Energy purchased in the DA Market at the associated RTBM LMP (see Section 4.5.9.3);
(4)
Each Market Participant with cleared Operating Reserve Offers is charged or paid for each Settlement Location: (a)
(b)
charged or paid for each Settlement Location For for the difference between the amount of Regulation-Up Service sold in the RTBM and the amount of Regulation-Up Service sold in the DA Market at the associated RTBM Regulation-Up Service MCP (see Section 4.5.9.4);
Comment [MPRR102.596]: MPRR102 Awaiting implementation. #ER13-1748
paid for each Settlement Location for Excess Regulation-Up Mileage at the associated Expected Regulation-Up Mileage MCP (see Section 4.5.9.4);
Comment [MPRR102.599]: MPRR102 Awaiting implementation. #ER13-1748
(a)(c) charged for each Settlement Location for Unused Regulation-Up Mileage at the associated Expected Regulation-Up Mileage MCP (see Section 4.5.9.4); (d)
(e)
Comment [MPRR102.598]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.600]: MPRR102 Awaiting implementation. #ER13-1748
charged or paid for each Settlement Location For for the difference between the amount of Regulation-Down Service sold in the RTBM and the amount of Regulation-Up Service sold in the DA Market at the associated RTBM Regulation-Down Service MCP (see Section 4.5.9.5);
Comment [MPRR102.601]: MPRR102 Awaiting implementation. #ER13-1748
paid for each Settlement Location for Excess Regulation-Down Mileage at the associated Expected Regulation-Down Mileage MCP (see Section 4.5.9.5);
Comment [MPRR102.604]: MPRR102 Awaiting implementation. #ER13-1748
(b)(f) charged for each Settlement Location for Unused Regulation-Down Mileage at the associated Expected Resource’s Regulation-Down Mileage MCP (see Section 4.5.9.5);
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Comment [MPRR102.602]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.603]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.605]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
(c)(g) charged or paid for each Settlement Location Ffor the difference between the amount of Spinning Reserve sold in the RTBM and the amount of RegulationUp Spinning Reserve sold in the DA Market at the associated RTBM Spinning Reserve MCP (see Section 4.5.9.6); and
Comment [MPRR204.606]: MPRR204 Awaiting FERC filing
(d)(h) charged or paid for each Settlement Location Ffor the difference between the amount of Supplemental Reserve sold in the RTBM and the amount of Regulation-UpSupplement Reserve sold in the DA Market at the associated RTBM Supplemental Reserve MCP (see Section 4.5.9.7).
Comment [MPRR204.608]: MPRR204 Awaiting FERC filing
(5)
Each Market Participant with actual load consumption is charged or paid for each Settlement Location for the difference between the amount of actual physical load purchased and the amount of physical Energy purchased in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.1);
(6)
Each Market Participant with Export Interchange Transactions or Through Interchange Transactions (Load Node) is charged or paid for each Settlement Location for the difference between the amount of actual physical export Energy scheduled and the amount of physical export Energy purchased in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.2);
(7)
Market Participants with SPP committed Resources in any of the RUC processes that were not committed in the DA Market and combined cycle Resources that were committed in the DA Market and committed by SPP into a higher configuration as part of the RUC processes may receive a make whole-payment if the total revenues received for Energy and Operating Reserve sales in the RTBM settlement are less than the Resource’s Offer costs. See Section 4.5.9.8 for calculation details. Certain costs are not eligible for recovery as follows:
Version 23.a
(a)
If the Resource operates outside of its Operating Tolerance in a Dispatch Interval, costs associated with Energy provided in excess of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch Interval;
(b)
If Resource is in “Manual” Control Status in a Dispatch Interval, costs associated with Energy provided in excess of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch Interval; and
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Comment [MPRR102.607]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.609]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR101.610]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
(c)
(8)
If the Resource increases its minimum limits in a Dispatch Interval above the minimum limits used by SPP to make the commitment decision by more than the Resource’s Operating Tolerance, costs associated with Energy provided in excess of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch Interval.
Make-Whole payments for SPP committed Resources as described in (7) above are collected on a daily basis from Market Participants based upon their pro-rata share of the sum of following quantities for the Operating Day as described in detail under Section 4.5.9.10:
Version 23.a
(a)
The absolute value of the net Settlement Location deviations from DA Market cleared amounts for load, virtual transactions and interchange transactions – excluding deviations resulting from actual load consumption that is less than DA Market cleared load MWh during capacity shortage condition Emergencies;
(b)
The positive difference between RTBM Resource minimum limits and DA Market Resource cleared Energy amount, subject to exclusion if certain criteria are met. Special rules apply if a Resource cleared regulation in real-time but did not clear regulation in the Day-Ahead Market;
(c)
The positive difference between the DA Market Resource cleared Energy amount and the RTBM Resource maximum limits, subject to exclusion if certain criteria are met. Special rules apply if a Resource cleared regulation in real-time but did not clear regulation in the Day-Ahead Market;
(d)
A Resource’s DA Market cleared amount if that Resource is off-line in the RTBM, subject to exclusion if certain criteria are met;
(e)
The absolute value of the difference between a Resource’s actual output and the Resource’s Desired Dispatch quantity if Resource is in “Manual” Control Status;
(f)
The actual Resource output for Resources that self-committed following the close of the DA Market, subject to exclusion if certain criteria are met;
(g)
A Resource’s Desired Dispatch quantity for Resources that were committed following the close of the DA Market if that Resource is off-line in the RTBM, subject to exclusion if certain criteria are met; and
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(h)
(9)
The absolute value of a Resource’s Uninstructed Resource Deviation if that Resource operated outside of its Operating Tolerance, subject to exclusion if certain criteria are met.
In addition, Resources may receive a make-whole payment related to a Manual Dispatch Instruction as described under Section 4.5.9.9, subject to certain eligibility requirements, as follows: (a)
If the Resource is issued a Manual Dispatch Instruction by SPP in any hour that creates Out Of Merit Energy (OOME) MW in excess of the Resource’s Dispatch Instruction and the Resource Offer costs associated with the OOME MW are greater than the Energy revenue received for the OOME MW, the Resource will receive the difference between the Energy Offer Curve costs associated with the OOME MW and the OOME MW Energy revenue. The OOME MW is calculated as Max (0, or the difference between (i) the (lesser of actual Resource output or the Resource’s Manual Dispatch Instruction MW) and (ii) the Resource’s Desired Dispatch);
(b)
If the Manual Dispatch Instruction is for Energy in the down direction and the RTBM LMP is greater than the DA Market LMP, the Asset Owner will receive a credit for the difference multiplied by the OOME MW. The OOME MW is calculated as Max (0, the difference between (i) the Resource’s DA Market cleared Energy MW and (ii) the (greater of actual Resource output or the Resource’s Manual Dispatch Instruction MW)); and
(c)
If during the Manual Dispatch Instruction, the RTBM cleared amount of an Operating Reserve product is less than the DA Market cleared amount of the corresponding Operating Reserve product and the RTBM MCP is greater than the DA Market MCP, the Asset Owner will receive a credit for the difference multiplied by the OOMOR MW. The OOMOR MW is calculated as Max (0, the difference between the Resource’s DA Market cleared Operating Reserve MW and the Resource’s RTBM cleared Operating Reserve MW).
Make-whole payments associated with OOME are collected as part of revenue neutrality uplift as described under Section 4.5.12. (10) Charges for failure to deploy Regulation-Up Service or Regulation-Down Service and charges for failure to deploy the specified amount of cleared Spinning Reserve or Supplemental Reserve are collected from Market Participants as part of the RTBM
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Comment [MPRR102.611]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.612]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
settlement as described under Sections 4.5.9.15 and 4.5.9.17 are distributed to Market Participants on a load ratio share basis as described under Sections 4.5.9.16 and 4.5.9.18; (11) Charges to Market Participants for RTBM Operating Reserve procurement costs are collected on a Real-Time load ratio share basis as described under Sections 4.5.9.11, 4.5.9.12, 4.5.9.13 and 4.5.9.14; (12) Resources providing Regulation-Up Service and/or Regulation-Down Service deployment will receive a credit or charge associated with the regulation deployment energy as described under Section 4.5.9.19 such that Resources maintain Energy margins that are equal to the Energy margins that would have been attained absent the regulation deployment; (a)
(b)
For Regulation-Up Service, a credit is calculated if the cost rate of the RegulationUp Service Energy is greater than the associated LMP and a charge is calculated if the associated LMP is greater the Regulation-Up Service Energy cost rate;22 For Regulation-Down Service, a credit is calculated if the associated LMP is greater than cost rate of the Regulation-Down Service Energy and a charge is calculated if the cost rate of the Regulation-Down Energy is greater than the associated LMP.23
(13) Settlement associated with revenue mismatch due to the impact of marginal losses on the Day-Ahead Market LMPs and RTBM LMPs is also performed as part of the RTBM settlement as follows. See Section 4.5.9.20 for calculation details; (a)
For each Loss Pool, a proxy loss charge contribution amount is developed for each Settlement Location with a net RTBM withdrawal (RTBM actual – DA Market cleared amount) that is equal to the sum of i) the positive difference between the MLC at the net withdrawal Settlement Location and the weighted average MLC of all net injections (RTBM actual – DA Market cleared amount) assumed to be serving the net withdrawal, multiplied by that Settlement Location’s net withdrawal, and ii) the sum of charges for Real-Time pseudo-tie Losses at the Settlement Location of the Sink of the pseudo-tie path. These values are then summed to calculate a Loss Pool proxy loss charge contribution.
22
A charge is calculated here because this difference (opportunity cost) has already been included in the RegulationUp MCP. 23
A charge is calculated here because this difference has already been included in the Regulation-Down MCP.
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Comment [MPRR102.613]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.614]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.615]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.616]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.617]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.618]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.619]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR212.620]: MPRR212 Awaiting FERC filing
Comment [MPRR212.621]: MPRR212 Awaiting FERC filing Comment [MPRR212.622]: MPRR212 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
(b)
(c)
(i)
The net injections assumed to be serving the net withdrawal are the net injections at the Settlement Locations included in that the Loss Pool. To the extent that the net injections in the Loss Pool are not sufficient to serve the net withdrawals in the Loss Pool, net injections from an injection exchange are included to make up the difference. To the extent that the net injections in the Loss Pool are greater than the net withdrawals in the Loss Pool, the excess is added to the injection exchange;
(ii)
The injection exchange is comprised of quantities from Loss Pools in which injection exceeds withdrawal. A weighted average of the MLC at the source of these quantities establishes a reference for the component of the loss charge contributions at Settlement Locations with net withdrawal met from outside the Loss Pool.
The Loss Pool proxy loss charge contribution calculated in (a) above are then used to allocated to the total DA Market loss over-collections dollars to each Loss Pool on a pro rata basis. Each Asset Owner’s credit or charge (all Asset Owner net withdrawals at Settlement Location participate) in each Loss Pool at each withdrawal Settlement Location within that Loss Pool is then equal a pro-rata share of the total marginal losses over collection or under collection allocated to that Loss Pool. The pro-rata share is calculated as an Asset Owner’s Settlement Location withdrawal divided by the sum of all Asset Owner Settlement Location withdrawals within that Loss Pool. Settlement Location withdrawal is equal to the maximum of (1) zero or (2) the sum of the (i) the difference between Real-Time metered load and DA Market cleared Demand Bids, (ii) the difference between Real-Time metered generation and Day-Ahead Market cleared Resource Offers, (iii) the difference between Real-Time and Day-Ahead Export Interchange Transactions, (iv) the difference between Real-Time and Day-Ahead Import Interchange Transactions, and (v) Real-Time Bilateral Settlement Schedules for Energy, and (vi) Day-Ahead Market Bilateral Settlement Schedules for Energy, including those associated with GFA Carve Outs, at that Settlement Location. Asset Owner credits associated with GFA Carve Outs are used to offset GFA Carve Out costs through inclusion of such credits under Section 4.5.8.23.
Comment [MPRR212.623]: MPRR212 Awaiting FERC filing
Comment [MPRR212.624]: MPRR212 Awaiting FERC filing Comment [MPRR212.625]: MPRR212 Awaiting FERC filing Comment [MPRR212.626]: MPRR212 Awaiting FERC filing Comment [MPRR212.627]: MPRR212 Awaiting FERC filing Comment [MPRR212.628]: MPRR212 Awaiting FERC filing Comment [MPRR212.629]: MPRR212 Awaiting FERC filing Comment [MPRR212.630]: MPRR212 Awaiting FERC filing Comment [MPRR212.631]: MPRR212 Awaiting FERC filing Comment [MPRR212.632]: MPRR212 Awaiting FERC filing Comment [MPRR212.633]: MPRR212 Awaiting FERC filing Comment [MPRR212.634]: MPRR212 Awaiting FERC filing Comment [MPRR212.635]: MPRR212 Awaiting FERC filing
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(14) Settlement (charges or credits) associated with services provided under Joint Operating Agreements are described under Section 4.5.9.21. These Charges or credits are collected or distributed as part of revenue neutrality uplift as described under Section 4.5.12; (15) Settlement (charges or credits) associated with Contingency Reserve deployment involving Reserve Sharing Group members is accounted for as described under Section 4.5.9.22. These charges or credits are collected or distributed on a load ratio share as described under Section 4.5.9.23. (16) Demand reduction credits to Market Participants associated with a load Settlement Location that contains a Demand Response Resource are calculated as part of the RTBM settlement in order to ensure that, on a net settlement basis, the RTBM charge associated with that load Settlement Location is reflective of the net load (i.e. the load including the impact of a cleared Demand Response Resource). For example, consider a load Settlement Location that consists of a single PNode and that PNode also represents a Demand Response Load that is associated with a Dispatchable Demand Response (DDR) Resource. The Market Participant for the load Settlement Location submits a fixed Demand Bid in the Day-Ahead Market of 100 MW, which is reflective of that location’s actual load consumption in real-time, assuming that there is no load reduction (i.e. this value represents the baseline value for the DRL that will be submitted for use in real-time). The Market Participant for the DDR Resource submits a Resource Offer that results in the DDR clearing for 20 MWs of Energy (resulting in a net Day-Ahead Market cleared load of 80 MW). For the corresponding hour in real-time, the DDR actual output was 25 MWs and the actual submitted meter value of the DRL was 75 MW. However, to ensure proper accounting for deviations in real-time load from cleared Day-Ahead Market amounts and calibration calculations, the submitted DRL actual meter value must be grossed up by the amount of DDR output. If we assume that RTBM LMP is $50/MWh, the net settlement at the load Settlement Location would be: Load Settlement: {(75 MW + 25 MW) – (100 MW (DA Market)} * $50/MWh = $0 Demand Reduction Amount (Credit) = (-25 MW – (-20 MW (DA Market)) * $50/MWh = ($250) Net Load Settlement Location Settlement = ($250)
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The net ($250) credit is the same as the credit that would have been calculated using the net RTBM load of 75 MW and the net cleared Day-Ahead Market load of 80 MW in the RTBM settlement ((75 MW – 80 MW) multiplied by the $50/MWh LMP). However, in order to ensure proper deviation and calibration accounting in real-time, the 100 MW of cleared load and the 25 MW of cleared DDR output is used to calculate real-time deviations from cleared Day-Ahead Market amounts and calibration energy amounts. See Section 4.5.9.24 for additional calculation details. (17) Charges or credits to Market Participants for allocation of RTBM demand reduction amounts are calculated on a system-wide basis by multiplying the demand reduction rate by each Market Participant’s RTBM demand reduction obligation. See Sections 4.5.9.25 for additional details; (a)
The demand reduction rate is equal to the total of demand reduction amounts calculated for load divided by the system-wide total actual withdrawals (real-time metered load and export transactions).
(b)
Each Market Participant’s demand reduction obligation is equal to that Market Participant’s total actual withdrawals (real-time metered load and export transactions).
(18) Settlements (charges or credits) for congestion and losses associated with Resources or load internal to the SPP footprint that has pseudo-tied out of the SPP Balancing Authority, is accounted for as described under Sections 4.5.9.26 and 4.5.9.27. (19) Resources with cleared Regulation-Up Service in either the Day-Ahead Market and/or RTBM may be eligible to receive an Unused Regulation-Up Mileage Make Whole Payment as described under Sections 4.5.9.28 under the following conditions: (a)
The Resource must have been charged for Unused Regulation-Up Mileage at a Regulation-Up Mileage MCP that is greater than the Resource’s Regulation-Up Mileage Offer;
(b)
The Resource’s cleared Regulation-Up Service Margin must be less than or equal to the Resource’s Potential Unused Regulation-Up Mileage Make Whole Payment; (i)
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For Regulation-Up Service MWs cleared in the Day-Ahead Market, DayAhead Market Regulation-Up Service Margin is equal to the cleared Regulation-Up Service MWs multiplied by the difference between the
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Resource’s Regulation-Up Service MCP and the Resource’s Regulation-Up Service Offer. This Day-Ahead Market Regulation-Up Service Margin is adjusted downward to account for any portion of the cleared Day-Ahead Regulation-Up Service MWs that are bought back in the RTBM (i.e. if cleared RTBM Regulation-Up Service MWs are less than cleared DayAhead Market Regulation-Up Service MWs); (ii)
For Regulation-Up Service MWs cleared in the RTBM in excess of those cleared in the Day-Ahead Market, Real-Time Regulation-Up Service Margin is equal to the (cleared Regulation-Up Service MWs minus cleared Day-Ahead Market Regulation-Up Service MWs) multiplied by the difference between the Resource’s Regulation-Up Service MCP and the Resource’s Regulation-Up Service Offer;
(iii) Potential Unused Regulation-Up Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Potential Unused Regulation-Up Mileage Make Whole Payment and Real-Time Potential Unused Regulation-Up Mileage Make Whole Payment. A Resource’s Day-Ahead Potential Unused Regulation-Up Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Up Mileage allocated to the Day-Ahead Market multiplied by the difference between the RegulationUp Mileage MCP and the Resource’s RTBM Regulation-Up Mileage Offer. A Resource’s Real-Time Potential Unused Regulation-Up Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Up Mileage allocated to the RTBM multiplied by the difference between the Regulation-Up Mileage MCP and the Resource’s RTBM Regulation-Up Mileage Offer; (c)
A Resource’s Unused Regulation-Up Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Market Unused Regulation-Up Mileage Make Whole Payment and Real-Time Unused Regulation-Up Mileage Make Whole Payment. (i)
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A Resource’s Day-Ahead Market Unused Regulation-Up Mileage Make Whole Payment is equal to the Resource’s Day-Ahead Market Potential Unused Regulation-Up Mileage Make Whole Payment minus the Resource’s Day-Ahead Market Regulation-Up Service Margin.
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(ii)
A Resource’s Real-Time Market Unused Regulation-Up Mileage Make Whole Payment is equal to the Resource’s Real-Time Potential Unused Regulation-Up Mileage Make Whole Payment minus the Resource’s RealTime Regulation-Up Service Margin.
(20) Resources with cleared Regulation-Down Service in either the Day-Ahead Market and/or RTBM may be eligible to receive an Unused Regulation-Down Mileage Make Whole Payment as described under Sections 4.5.9.29 under the following conditions: (a)
The Resource must have been charged for Unused Regulation-Down Mileage at a Regulation-Down Mileage MCP that is greater than the Resource’s RegulationDown Mileage Offer;
(b)
The Resource’s cleared Regulation-Down Service Margin must be less than or equal to the Resource’s Potential Unused Regulation-Down Mileage Make Whole Payment; (i)
For Regulation-Down Service MWs cleared in the Day-Ahead Market, DayAhead Market Regulation-Up Service Margin is equal to the cleared Regulation-Down Service MWs multiplied by the difference between the Resource’s Regulation-Down Service MCP and the Resource’s RegulationDown Service Offer. This Day-Ahead Market Regulation-Down Service Margin is adjusted downward to account for any portion of the cleared DayAhead Regulation-Down Service MWs that are bought back in the RTBM (i.e. if cleared RTBM Regulation-Down Service MWs are less than cleared Day-Ahead Market Regulation-Down Service MWs);
(ii)
For Regulation-Down Service MWs cleared in the RTBM in excess of those cleared in the Day-Ahead Market, Real-Time Regulation-Down Service Margin is equal to the (cleared Regulation-Down Service MWs minus cleared Day-Ahead Market Regulation-Down Service MWs) multiplied by the difference between the Resource’s Regulation-Down Service MCP and the Resource’s Regulation-Down Service Offer;
(iii) Potential Unused Regulation-Down Unused Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Potential Unused Regulation-Down Mileage Make Whole Payment and Real-Time Potential Unused Regulation-Down Mileage Make Whole Payment. A Resource’s Day-Ahead Potential Unused Regulation-Down Mileage Make Whole
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Payment is equal to the portion of the Resource’s Unused Regulation-Down Mileage allocated to the Day-Ahead Market multiplied by the difference between the Regulation-Down Mileage MCP and the Resource’s RTBM Regulation-Down Mileage Offer. A Resource’s Real-Time Potential Unused Regulation-Down Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Down Mileage allocated to the RTBM multiplied by the difference between the Regulation-Down Mileage MCP and the Resource’s RTBM Regulation-Down Mileage Offer; (c)
A Resource’s Unused Regulation-Down Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Market Unused Regulation-Down Mileage Make Whole Payment and Real-Time Unused Regulation-Down Mileage Make Whole Payment. (i)
A Resource’s Day-Ahead Market Unused Regulation-Down Mileage Make Whole Payment is equal to the Resource’s Day-Ahead Market Potential Unused Regulation-Down Mileage Make Whole Payment minus the Resource’s Day-Ahead Market Regulation-Down Service Margin.
(ii)
A Resource’s Real-Time Market Unused Regulation-Down Mileage Make Whole Payment is equal to the Resource’s Real-Time Potential Unused Regulation-Down Mileage Make Whole Payment minus the Resource’s Real-Time Regulation-Down Service Margin.
The following subsections describe the RTBM settlement charge types in more detail. For each charge type, the initial calculation is performed either at the Dispatch Interval level or hourly level for each Asset Owner at each Settlement Location. In addition to the Dispatch Interval and hourly values, hourly and daily values will be accessible on the Settlement Statement for all charge types. 4.5.9.1 (1)
Real-Time Asset Energy Amount The Real-Time Asset Energy Amount can be either a credit to an Asset Owner or a charge to an Asset Owner and is calculated on a net basis at each Settlement Location for:
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(a)
The difference between actual metered supply MWh amounts in a Dispatch Interval and cleared Resource Offers in the DA Market;
(b)
The difference between actual metered demand MWh amounts in a Dispatch Interval and all cleared Demand Bids in the DA Market; and
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Market Protocols for SPP Integrated Marketplace
(c)
Real-Time Bilateral Settlement Schedules for Energy in a Dispatch Interval.
The net amount to each Asset Owner (AO) for each Settlement Location in a Dispatch Interval is calculated as follows: #RtEnergy5minAmt a, s, i = RtLmp5minPrc s, i * [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h ) -
RtEnFinHrlyQty a, s, t, h ] / 12
t
Where, (a)
The 5-minute billable meter determinant at the Settlement Location level is the sum of the 5-minute billable meter determinants at the Meter Data Submittal Location level as shown in the formula below. Most Settlement Locations will be comprised of only one Meter Data Submittal Location, but in certain cases a single Settlement Location will represent multiple Meter Data Submittal Locations, each of which is in a separate Settlement Area. Since the calibration function must be performed within Settlement Area boundaries, it is done before summing the data to the Settlement Location level. The 5-minute determinants are expressed in terms of levelized MW at both the Settlement Location and Meter Data Submittal Location level. RtBillMtr5minQty a, s, i =
RtMlBillMtr5minQty a, ml, i
ml
(b)
The 5-minute billable meter determinant at the Meter Data Submittal Location level is the sum of the 5-minute adjusted meter determinant and the 5-minute calibration meter determinants at the Meter Data Submittal Location level as shown in the formula below. Both 5-minute determinants are expressed in terms of levelized MW. RtMlBillMtr5minQty a, ml, i = RtAdjMtr5minQty a, ml, i + RtCalMtr5minQty a, ml, i
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(c)
For Resource and load assets, the 5-minute adjusted meter determinant is a hierarchal selection among 1) 5-minute submitted actual meter reading, 2) profiled hourly submitted actual meter reading and 3) default 5-minute state estimator value. Registration records whether 5-minute or hourly meter data submittals are selected. The methodologies are mutually exclusive for any given period. Market Participants who choose to submit their actual hourly meter reading into 5-minute intervals must use a profiling method consistent with the method described below using a data source as described in Appendix D Section 10.1.1. Under the Marginal Loss approach, it is assumed that meter submissions, with the exception of those with a “top-down load” relationship to the Settlement Area – generally those for which a top-down calculation is used – are net of transmission losses. Losses will be backed out of load submittals for the “topdown load”. For Demand Response Resources, the hierarchy is the same for submitted data, but instead of defaulting to the State Estimator data, the Resource output is calculated as the maximum of zero or the difference between (i) and (ii) below. If the baseline hourly load profile of the DRL was not submitted, the State Estimator snapshot will be used for this value in (i) below. (i) a) tThe minimum of i)(1) the hourly baseline load profile of the DRL submitted for the Demand Response Load, andor ii(2) the State Estimator snapshot for the Demand Response Load for the 5 minute interval immediately preceding the first dispatch interval (i = -1) and (ii) b) tThe Adjusted Meter Quantity for the DRL for each 5 minute interval.
Comment [MPRR144.637]: MPRR144 Awaiting FERC filing Comment [MPRR144.638]: MPRR144 Awaiting FERC filing Comment [MPRR144.639]: MPRR144 Awaiting FERC filing Comment [MPRR144.640]: MPRR144 Awaiting FERC filing Comment [MPRR144.641]: MPRR144 Awaiting FERC filing Comment [MPRR144.642]: MPRR144 Awaiting FERC filing
Registration records whether meter submittals are permitted or if the Demand Response resource must rely solely on the calculated resource output. For loads in which a Demand Response Resource is imbedded within a Settlement Location, the response is added to the load meter data “grossing-up” the MW to avoid introducing deviation between DA Market cleared Energy and the billable meter quantity. 5-minute adjusted meter, state estimator, SCADA and gross-up determinants are expressed in terms of levelized MW and both hourly and 5minute submitted actual determinants are in terms of MWh. The formula for the 5-minute adjusted meter determinant is shown below. IF EXISTS { RtActMtr5minQty a, ml, i } THEN
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#RtAdjMtr5minQty a, ml, i = RtActMtr5minQty a, ml, i * 12 + RtLoadGrossUp5minQty a, s, ml, i - {IF TOPDOWNLOAD(ml) THEN RtSELoss5minQty sa, i , ELSE 0 } ELSE IF EXISTS { RtActMtrHrlyQty a, ml, h } THEN #RtAdjMtr5minQty a, ml, i = RtSE5minQty a, ml, i + { ( RtActMtrHrlyQty a, ml, h - RtSE5minQty a, ml, i / 12) i
* {IF (
ABS (RtSE5minQtya, ml, i ) > 0 THEN [ABS (RtSE5minQtya, ml, i)
i
/
ABS ( RtSE5minQty a, ml, i ) ], ELSE 1 /12 } * 12 }
i
+ RtLoadGrossUp5minQty a, s, ml, i - { IF TOPDOWNLOAD(ml) THEN RtSELoss5minQty sa, i , ELSE 0 } ELSE IF { DRR } THEN #RtAdjMtr5minQty a, ml, i = MAX [( MIN ( RtBaseLineHrlyQtya, ml(drl) , h , RtSE5minQtya, ml(drl),
i = -1
)
– RtAdjMtr5minQtya, ml(drl), i ) , 0 ] * (-1) ELSE #RtAdjMtr5minQty a, ml, i = RtSE5minQty a, ml, i + RtLoadGrossUp5minQty a, s, ml, i
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(d)
The 5-minute load gross-up determinant is the inverse of the 5-minute adjusted meter determinant for the Demand Response resource which is behind the meter of the load. The 5-minute load gross-up determinant is expressed in terms of levelized MW. The formula for the 5-minute load gross-up determinant is shown below. RtLoadGrossUp5minQty a, s, ml, i =
RtAdjMtr5minQty a, ml(drr), i * (-1)
ml (drr)
(e)
The 5-minute calibration meter determinant is the hourly quantity, profiled by State Estimator data into 5-minute intervals as shown in the formula below. The 5-minute calibration meter determinant is expressed in terms of levelized MW. The formula for the 5-minute calibration meter determinant is shown below. #RtCalMtr5minQty a, ml, i = If RtCalMtrHrlyQty a, ml, h = 0 THEN 0 ELSE RtSE5minQty a, ml, i + { (RtCalMtrHrlyQty a, ml, h -
RtSE5minQty a, ml, i / 12)
i
* {IF
ABS(RtSE5minQty a, ml, i > 0 THEN [ ABS(RtSE5minQty a, ml, i
i
)/
ABS(RtSE5minQty a, ml, i ) ] , ELSE 1/12} * 12 }
i
(f)
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The hourly calibration meter determinant is the weighted distribution of Settlement Area residual among load in the Settlement Area (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of
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interchange of any Settlement Area). The hourly calibration meter determinant is expressed in terms of levelized MW. The formula for the hourly calibration meter determinant is shown below. IF IsPsgiPsli (ml) THEN #RtCalMtrHrlyQty a, ml, h = 0 ELSE #RtCalMtrHrlyQty a, ml, h = RtResMtrHrlyQty sa, h * [ MAX ( RtAdjMtrHrlyQty sa, a, ml, h , 0 ) /
MAX ( RtAdjMtrHrlyQty sa, a, ml, h , 0 ) ]
ml
(g)
The hourly adjusted meter determinant is the sum of the 5-minute adjusted meter determinant divided by 12. The hourly adjusted meter determinant is expressed in terms of levelized MW. The formula for the hourly adjusted meter determinant is shown below. #RtAdjMtrHrlyQty a, ml, h =
RtAdjMtr5minQty a, ml, i / 12
i
(h)
Version 23.a
The hourly residual load determinant is the net difference between generation & load (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area), interchange and losses per Settlement Area. Hourly Net Actual Interchange is derived as the sum of the hourly metering submitted for aggregate ties between interconnected Settlement Areas. Missing tie values are replaced with State Estimator values. The hourly residual determinant is expressed in terms of levelized MW. The formula for the hourly residual load determinant is shown below.
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RtResMtrHrlyQty sa, h = (
a
{ IF IsPsgiPsli (ml) THEN 0 ELSE
ml
RtAdjMtrHrlyQty sa ,a, ml, h } + RtSaNetActIchngHrlyQty sa, h +
RtSELoss5minQty sa, i / 12) * (-1)
i
(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtEnergyHrlyAmt a, s, h =
RtEnergy5minAmt a, s, i
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The amount is calculated as follows: RtEnergyDlyAmt a, s, d =
RtEnergyHrlyAmt a, s, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtEnergyAoAmt a, m, d =
RtEnergyDlyAmt a, s, d
s
(5) 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: RtEnergyMpAmt m, d =
RtEnergyAoAmt a, m, d
a
(3) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows: (a)
Version 23.a
#EqrRtAssetEnergy5minQty a, s, i =
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Max ( 0, -1 * [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h ) -
RtEnFinHrlyQty a, s, t, h ] / 12)
t
+ { IF #EqrDaAssetEnergyHrlyQty a, s, h > 0 THEN Min ( 0, -1 * [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h ) -
RtEnFinHrlyQty a, s, t, h ] / 12) }
t
(b)
IF #EqrRtAssetEnergy5minQty a, s, i < > 0 THEN #EqrRtAssetEnergy5minPrc a, s, i = RtLmp5minPrc s, i
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The above variables are defined as follows: Variable
Unit
Settlement Interval
$
Dispatch Interval
RtLmp5minPrc s, i
$/MW
Dispatch Interval
DaClrdHrlyQty a, s, h
MWh
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
RtActMtr5minQty a, ml, i
MWh
Dispatch Interval
RtActMtrHrlyQty a, ml, h
MWh
Hour
RtMlBillMtr5minQty a, ml, i
MW
Dispatch Interval
RtEnergy5minAmt a, s, i
Version 23.a
Definition
Real-Time Energy Amount per AO per Settlement Location per Dispatch Interval - The amount to AO a for deviations between RealTime actual Energy amounts and net cleared energy offers and bids at Settlement Location s for the Dispatch Interval. Real-Time LMP - The RTBM LMP at Settlement Location s for Dispatch Interval i. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The Dispatch Interval metered quantities for AO a Resources and load at Settlement Location s in Dispatch Interval i used by SPP for settlement purposes. Real-Time Actual Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval metered quantity, in MWh, for AO a’s Resources and load directly submitted by the Market Participant. Real-Time Actual Meter Quantity per AO per Meter Data Submittal Location per Hour - The hourly metered quantity, in MWh, for AO a’s Resources and load directly submitted by the Market Participant. Real-Time Billing Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval RtAdjMtr5minQty a, ml, i quantities adjusted to account for calibration Energy for AO a load at Meter Location ml in Dispatch Interval i.
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RtCalMtr5minQty a, ml, i
MW
Dispatch Interval
RtCalMtrHrlyQty a, ml, h
MWh
Hour
RtLoadGrossUp5minQty a, s, ml, i
MW
Dispatch Interval
RtSE5minQty a, ml, i
MW
Dispatch Interval
RtBaseLineHrlyQtya, ml(drl), h
MWh
Hour
RtSELoss5minQty sa, i
MW
Dispatch Interval
RtResMtrHrlyQty sa, h
MWh
Hour
IsPsgiPsli (ml)
None
None
Version 23.a
Real-Time Calibration Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval calibration quantities calculated by SPP for AO a at load at Meter Data Submittal Location ml in Dispatch Interval i. Real-Time Calibration Meter Quantity per AO per Meter Settlement Location per Hour- The Dispatch Interval calibration Energy quantities calculated by SPP for AO a at load at Meter Data Submittal Location ml in Hour h. Real-Time Load Gross Up per AO per Meter Settlement Location per Dispatch Interval - The Dispatch Interval load gross up associated with a Demand Response Reserve for AO a at load Meter Data Submittal Location ml associated with Settlement Location s in Dispatch Interval i. Real-Time State Estimator Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval State Estimator value for AO a at Meter Data Submittal Location ml in Dispatch Interval i. Real-Time Base Line Load Quantity per AO per Demand Response Load Meter Data Submittal Location per Hour – The estimated consumption value associated with AO a’s Demand Response Load as submitted prior to Operating Hour h. Real-Time State Estimator Losses per AO per Settlement Area per Dispatch Interval - The Dispatch Interval State Estimator total losses value for Settlement Area sa in Dispatch Interval i. Real-Time Residual Load per Settlement Area per Hour - The hourly Residual Load for Settlement Area sa in Hour h. A Logical operation of the Meter Data Submittal Location to determine if it is of type PSGI or PSLI – a Resource or load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area
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RtSaNetActIchngHrlyQty sa, h
MWh
Hour
RtAdjMtr5minQty a, ml, i
MW
Dispatch Interval
RtAdjMtrHrlyQty sa, a, ml, h
MWh
Hour
RtEnFinHrlyQty a, s, t, h
MWh
Hour
RtEnergyHrlyAmt a, s, h
$
Hour
RtEnergyDlyAmt a, s, d
$
Operating Day
Version 23.a
Real-Time Net Actual Interchange per Settlement Area per Hour - The sum of hourly actual interchange values submitted for Settlement Area sa in Hour h. Real-Time Adjusted Actual Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval metered quantity, in MW, for AO a’s Resources and load calculated by SPP to account for load adjustments related to Demand Response Resources and to calculate a default value if RtActMtrHrlyQty a, ml, h or RtActMtr5minQty a, ml, i is not submitted. Real-Time Adjusted Actual Meter Quantity per AO per Meter Data Submittal Location per Hour - The hourly metered quantity, in MWh, for AO a’s Resources and load calculated by SPP to account for load adjustments related to Demand Response Resources and to calculate a default value if RtActMtrHrlyQty a, ml, h or RtActMtr5minQty a, ml, i is not submitted for AO a at Meter Data Submittal Location ml in Settlement Area sa in Hour h. Real-Time Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The amount specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule for Energy at Asset Settlement Location s, for transaction t, for the Hour. The buyer AO amount is a positive value and the seller AO amount is a negative value. Real-Time Energy Amount per AO per Settlement Location per Hour The amount to AO a for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids at Settlement Location s for the Hour. Real-Time Energy Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between RealTime actual Energy amounts and net cleared energy offers and bids at Settlement Location s for the Operating Day.
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RtEnergyAoAmt a, m, d
$
Operating Day
RtEnergyMpAmt m, d
$
Operating Day
EqrRtAssetEnergy5minQty a, s, i
MWh
Dispatch Interval
EqrRtAssetEnergy5minPrc a, s, i
$/MWh
Dispatch Interval
a h i s t
none none none none none
none none none none none
ml(drr)
none none
none none
ml(drl)
Version 23.a
Real-Time Energy Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids for the Operating Day. Real-Time Energy Amount per MP per Operating Day - The amount to MP m for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids for the Operating Day. Real-Time Electric Quarterly Reporting net Asset Energy Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Energy sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead, net of Bilateral Settlement Schedules, in Dispatch Interval i or AO a’s RTBM Energy purchase at Resource Settlement Location s created when the actual Real-Time output is less than the amount cleared Day-Ahead, net of Financial Schedules, in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting net Asset Energy Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtAssetEnergy5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner. An Hour. A Dispatch Interval. A Settlement Location. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. A Demand Response Resource Meter Data Submittal Location. A Demand Response Load Meter Data Submittal Location.
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sa ml d m
Version 23.a
none none none none
none none none none
A Settlement Area. A Meter Data Submittal Location. An Operating Day. A Market Participant.
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4.5.9.2
Real-Time Non-Asset Energy Amount
(1) The Real-Time Non-Asset Energy Amount can be either a credit to an Asset Owner or a charge to an Asset Owner and is calculated on a net basis at each Settlement Location for: (a) The difference between actual scheduled Import Interchange Transactions in a Dispatch Interval and cleared Import Interchange Transactions in the DA Market; (b) The difference between actual scheduled Export Interchange Transactions in a Dispatch Interval and cleared Export Interchange Transactions in the DA Market; (c) The difference between actual scheduled Through Interchange Transactions in a Dispatch Interval and cleared Through Interchange Transactions in the DA Market; and (d) Real-Time Bilateral Settlement Schedules for Energy in a Dispatch Interval. The net amount to each Asset Owner (AO) for each Settlement Location in a Dispatch Interval is calculated as follows: #RtNEnergy5minAmt a, s, i = RtLmp5minPrc s, i *[
RtImpExp5minQty a, s, i, t -
t
-
DaImpExp5minQty a, s, i, t
t
RtNEnFinHrlyQty a, s, h, t ] / 12
t
(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtNEnergyHrlyAmt a, s, h =
RtNEnergy5minAmt a, s, i
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtNEnergyDlyAmt a, s, d =
The
RtNEnergyHrlyAmt a, s, h
h
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(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtNEnergyAoAmt a, m, d =
RtNEnergyDlyAmt a, s, d
s
(5) 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: RtNEnergyMpAmt m, d =
RtNEnergyAoAmt a, m, d
a
(6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows: (a)
#EqrRtNAssetEnergy5minQty a, s, i = Max ( 0, -1 * [* [
t
-
RtImpExp5minQty a, s, i, t - DaImpExp5minQty a, s, i, t t
RtNEnFinHrlyQty a, s, h, t ] / 12)
t
+ { IF #EqrDaNAssetEnergyHrlyQty a, s, h > 0 THEN Min ( 0, -1 * [
t
-
RtImpExp5minQty a, s, i, t - DaImpExp5minQty a, s, i, t t
RtNEnFinHrlyQty a, s, h, t ] / 12) }
t
(b)
IF #EqrRtNAssetEnergy5minQty a, s, i < > 0 THEN
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Market Protocols for SPP Integrated Marketplace
#EqrRtNAssetEnergy5minPrc a, s, i = RtLmp5minPrc s, i
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
$/MW
Dispatch Interval
Real-Time Non-Asset Energy Amount per AO per Settlement Location per Dispatch Interval - The amount to AO a for deviations between RTBM scheduled Interchange Transaction quantities and DA Market cleared Interchange Transactions, net of Bilateral Settlement Schedules at Settlement Location s for the Dispatch Interval. Real-Time LMP - The RTBM LMP at Settlement Location s for Dispatch Interval i.
DaImpExp5minQty a, s, i, t
MW
Dispatch Interval
RtNEnFinHrlyQty a, s, h, t
MWh
Hour
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RtNEnergyHrlyAmt a, s, h
$
Hour
RtNEnergy5minAmt a, s, i
RtLmp5minPrc s, i
Version 23.a
Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.8.2. Real-Time Non-Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The quantity specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule for Energy at Non-Asset Settlement Location s, for transaction t, for the Hour. The buyer AO amount is a positive value and the seller AO amount is a negative value. Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval - The total net quantity of energy represented by AO a’s actual Interchange Transactions in the RTBM at Settlement Location s, for each tagged transaction t, for the Dispatch Interval i. The Dispatch Interval value of the transaction will be equal to the scheduled MW within the scheduled start-time and stop-time of the transaction. Transaction ramping will be ignored. Real-Time Non-Asset Energy Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between RTBM scheduled Interchange Transaction quantities and DA Market cleared Interchange Transactions, net of Bilateral Settlement Schedules at Settlement Location s for the Hour.
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Variable
Unit
Settlement Interval
Definition
RtNEnergyDlyAmt a, s, d
$
Operating Day
RtNEnergyAoAmt a, m, d
$
Operating Day
RtNEnergyMpAmt m, d
$
Operating Day
EqrRtNAssetEnergy5minQty a, s, i
MWh
Dispatch Interval
EqrRtNAssetEnergy5minPrc a, s, i
$/MWh
Dispatch Interval
none none
none none
Real-Time Non-Asset Energy Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between RTBM scheduled Interchange Transaction quantities and DA Market cleared Interchange Transactions, net of Bilateral Settlement Schedules at Settlement Location s for the Operating Day. Real-Time Non-Asset Energy Amount per AO per Operating Day - The amount to AO a for deviations between RTBM scheduled Interchange Transaction quantities and DA Market cleared Interchange Transactions, net of Bilateral Settlement Schedules for the Operating Day. Real-Time Non-Asset Energy Amount per MP per Operating Day - The amount to MP m for deviations between RTBM scheduled Interchange Transaction quantities and DA Market cleared Interchange Transactions, net of Bilateral Settlement Schedules for the Operating Day. Real-Time Electric Quarterly Reporting net Non-Asset Energy Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Energy sale at External Interface Settlement Location s in excess of the amount cleared Day-Ahead, net of Bilateral Settlement Schedules, in Dispatch Interval i or AO a’s RTBM Energy purchase at External Interface Settlement Location s created when the actual Real-Time schedule is less than the amount cleared Day-Ahead, net of Bilateral Settlement Schedules, in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting net Non-Asset Energy Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtNAssetEnergy5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. An Asset Owner. An Hour.
a h
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Variable
Unit
Settlement Interval
Definition
i s t
none none none
none none none
d m
none none
none none
A Dispatch Interval. A Settlement Location. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
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4.5.9.3
Real-Time Virtual Energy Amount
(a) The Real-Time Virtual Energy Amount can be either a credit to charge to an Asset Owner and is calculated on an Asset Owner net virtual transaction basis at each Settlement Location for all cleared Virtual Energy Offers and all cleared Virtual Energy Bids in the DA Market. Cleared Virtual Energy Offers and cleared Virtual Energy Bids in the DA Market create deviations in the RTBM that are equal to the negative of the cleared DA Market amounts. The net amount to each Asset Owner (AO) for each Settlement Location for a Dispatch Interval is calculated as follows: #RtVEnergy5minAmt a, s, i = ( RtLmp5minPrc s, i * (
DaClrdVHrlyQty a, s, h, t /12 ) )
t
* (-1) (b) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtVEnergyHrlyAmt a, s, h =
RtVEnergy5minAmt a, s, i
i
(c) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtVEnergyDlyAmt a, s, d =
The
RtVEnergyHrlyAmt a, s, h
h
(d) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtVEnergyAoAmt a, m, d =
RtVEnergyDlyAmt a, s, d
s
(e) 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: RtVEnergyMpAmt m, d =
RtVEnergyAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
$
Dispatch Interval
$/MWh
Dispatch Interval
MWh
Hour
RtVEnergyHrlyAmt a, s, h
$
Hour
RtVEnergyDlyAmt a, s, d
$
Operating Day
RtVEnergyAoAmt a, m, d
$
Operating Day
RtVEnergyMpAmt m, d
$
Operating Day
none none none none
none none none none
RtVEnergy5minAmt a, s, i
RtLmp5minPrc s, i DaClrdVHrlyQty a, s, h, t
a s h i
Version 23.a
Definition
Real-Time Virtual Energy Amount per AO per Settlement Location per Dispatch Interval - The amount to AO a for DA Market cleared Virtual Energy Offers and Virtual Energy Bids at Settlement Location s for each transaction for the Dispatch Interval. Real-Time LMP - The value defined under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i. Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3. Real-Time Virtual Energy Amount per AO per Settlement Location per Hour - The amount to AO a for DA Market cleared Virtual Energy Offers and Virtual Energy Bids at Settlement Location s for the Hour. Real-Time Virtual Energy Amount per AO per Settlement Location per Operating Day - The amount to AO a for DA Market cleared Virtual Energy Offers and Virtual Energy Bids at Settlement Location s for the Operating Day. Real-Time Virtual Energy Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for DA Market cleared Virtual Energy Offers and Virtual Energy Bids for the Operating Day. Real-Time Virtual Energy Amount per MP per Operating Day - The amount to MP m for DA Market cleared Virtual Energy Offers and Virtual Energy Bids for the Operating Day. An Asset Owner. A Settlement Location. An Hour. A Dispatch Interval.
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Variable
Unit
Settlement Interval
Definition
t
none
none
d m
none none
none none
A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
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4.5.9.4
Comment [MPRR102.644]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation-Up Service Amount
(1) A RTBM charge or credit for deviations between cleared RTBM Regulation-Up Service and cleared DA Market Regulation-Up Service and deviations between Expected Regulation-Up Mileage and the Actual Regulation-Up Mileage provided will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval. The amount will be calculated as follows: #RtRegUp5minAmt a, s, i = (
Comment [MPRR102.645]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.646]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.647]: MPRR102 Awaiting implementation. #ER13-1748
( RtRegUpMcp5minPrc z, i
z
* ( RtRegUp5minQty a, z, s, i -
DaRegUpHrlyQty a, z, s, h ) / 12 ) z
- RtRegUpUnusedMile5minAmt a, s, i - RtRegUpExcessMile5minAmt a, s, i ) * (-1)
Comment [MPRR102.648]: MPRR102 Awaiting implementation. #ER13-1748
Where, (a)
#RtRegUpUnusedMile5minAmt a, s, i =
RtRegUpUnusedMile5minQty a, z, s, i * RtRegUpMileMcp5minPrc
i
Comment [MPRR204.649]: MPRR204 Awaiting FERC filing
/ 12
Comment [MPRR204.650]: MPRR204 Awaiting FERC filing
z
(a.1)
#RtRegUpUnusedMile5minQty a, z, s, i
Formatted: Font: Times New Roman Bold, 11 pt, Lowered by 14 pt
=
Comment [MPRR204.651]: MPRR204 Awaiting FERC filing
Max ( 0, ( RtRegUp5minQty a, z, s, i * RtRegUpMile5minFct i )
Comment [MPRR204.652]: MPRR204 Awaiting FERC filing
- RtRegUpMile5minQty a, z, s, i ) (b)
Comment [MPRR204.653]: MPRR204 Awaiting FERC filing
#RtRegUpExcessMile5minAmt a, s, i =
RtRegUpExcessMile5minQty
Comment [MPRR204.654]: MPRR204 Awaiting FERC filing
a, s, i
Min ( 0, ( ( RtRegUp5minQty
a, z, s, i
*
Formatted: Font: Times New Roman Bold, 11 pt, Lowered by 14 pt
z
RtRegUpMile5minFct i ) - RtRegUpMile5minQty a, z, s, i )
Comment [MPRR204.655]: MPRR204 Awaiting FERC filing
* RtRegUpMileMcp5minPrc
Version 23.a
i
Comment [MPRR204.656]: MPRR204 Awaiting FERC filing
) / 12
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391
(b.1)
#RtRegUpExcessMile5minQty a, s, i = Min ( 0, ( RtRegUp5minQty a, s, i * RtRegUpMile5minFct i ) - RtRegUpMile5minQty a, s, i )
(c)
Comment [MPRR204.657]: MPRR204 Awaiting FERC filing
IF RtRegUpActMile5minQty a, z, s, i >= (1 - RtRegMileOpTolPct a, z, s, i ) *
Comment [MPRR204.658]: MPRR204 Awaiting FERC filing
RtRegUpInstrMile5minQty a, z, s, i )
Comment [MPRR204.659]: MPRR204 Awaiting FERC filing
THEN
Comment [MPRR204.660]: MPRR204 Awaiting FERC filing
RtRegUpMile5minQty a, z, s, i = RtRegUpInstrMile5minQty a, z, s, i
Comment [MPRR204.661]: MPRR204 Awaiting FERC filing
ELSE
Comment [MPRR204.662]: MPRR204 Awaiting FERC filing
RtRegUpMile5minQty a, z, s, i = RtRegUpActMile5minQty a, z, s, i
Comment [MPRR204.663]: MPRR204 Awaiting FERC filing Comment [MPRR204.664]: MPRR204 Awaiting FERC filing
(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows: RtRegUpHrlyAmt a, s, h =
Comment [MPRR102.665]: MPRR102 Awaiting implementation. #ER13-1748
RtRegUp5minAmt a, s, i
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtRegUpDlyAmt a, s, d =
The
RtRegUpHrlyAmt a, s, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegUpAoAmt a, m, d =
RtRegUpDlyAmt a, s, d
s
(5) 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:
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RtRegUpMpAmt m, d =
RtRegUpAoAmt a, m, d
a
(6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows: (a)
RTBM Regulation-Up Service
(a.1)
#EqrRtRegUp5minQty a, s, i =
Comment [MPRR204.666]: MPRR204 Awaiting FERC filing
Max ( 0, ( RtRegUp5minQty a, z, s, i - DaRegUpHrlyQty a, z, s, h ) / 12 ) z
z
+ { IF #EqrDaRegUpHrlyQty a, s, h > 0 THEN
Min ( 0, ( RtRegUp5minQty a, z, s, i - DaRegUpHrlyQty a, z, s, h ) / 12 ) } z
z
(a.2b) IF #EqrRtRegUp5minQty a, s, i < > 0
Comment [MPRR204.667]: MPRR204 Awaiting FERC filing
THEN #EqrRtRegUp5minPrc a, s, i = RtRegUpMcp5minPrc z, i (b)
RTBM Excess Regulation-Up Mileage
(b.1) EqrRtRegUpExcessMile5minQty a, s, i = RtRegUpExcessMile5minQty a, s, i (b.2) EqrRtRegUpExcessMileMcp5minPrc a, s, i = ( 0 * EqrRtRegUpExcessMile5minQty a, s, i + RtRegUpMileMcp5minPrc i ) (c)
RTBM Unused Regulation-Up Mileage
(c.1) EqrRtRegUpUnusedMile5minQty a, s, i = RtRegUpUnusedMile5minQty a, s, i
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(c.2) EqrRtRegUpUnusedMileMcp5minPrc a, s, i = ( 0 * EqrRtRegUpUnusedMile5minQty
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a, s, i
+ RtRegUpMileMcp5minPrc
394
Comment [MPRR204.668]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
Comment [MPRR102.669]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.673]: MPRR102 Awaiting implementation. #ER13-1748
RtRegUpMcp5minPrc z, i
$/MW
Dispatch Interval
Real-Time Regulation-Up ServiceAmount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Up Service Offers Unused Regulation-Up Mileage and Excess Regulation-Up Mileage at Resource Settlement Location s for the Dispatch Interval. Real-Time MCP for Regulation-Up Service per Reserve Zone - The RTBM MCP for Regulation-Up Service in Reserve Zone z for Dispatch Interval i.
RtRegUpMileMcp5minPrc i
$/MW
Dispatch Interval
Real-Time MCP for Regulation-Up Mileage - The RTBM MCP for Expected Regulation-Up Mileage for Dispatch Interval i.
RtRegUpUnusedMile5minAm t a, s, i
$
Dispatch Interval
RtRegUpExcessMile5minAmt
$
Dispatch Interval
Real-Time Unused Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The charge to AO a for Unused RegulationUp Mileage at Resource Settlement Location s for Dispatch Interval i. Real-Time Excess Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The payment to AO a for Excess Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i. Real-Time Regulation-Up Mileage Factor Dispatch Interval - The Regulation-Up Mileage Factor for Dispatch Interval i.
RtRegUp5minAmt a, s, i
a, s, i
Ratio
RtRegUpMile5minFct i RtRegUpActMile5minQty s, i
Version 23.a
a, z,
MW
Dispatch Interval Dispatch Interval
Real-Time Actual Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Actual Regulation-Up Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the actual up and down Resource movement in response to Regulation-Up deployment instructions in Dispatch Interval i.
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Comment [MPRR102.670]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.671]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.672]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.674]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.675]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.676]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.677]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.678]: Comment [MPRR204.679]: MPRR204 Awaiting FERC filing Comment [MPRR102.680]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtRegUpMile5minQty a, z, s, i
RtRegUpInstrMile5minQty
a,
Unit
Settlement Interval
Definition
MW
Dispatch Interval
Real-Time Regulation-Up Mileage Settlement Quantity per AO per Settlement Location per Dispatch Interval - AO a’s settled Actual Regulation-Up Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z used for Settlement that includes the impact of the Resource Regulating Mileage Operating Tolerance. Real-Time Instructed Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Instructed Regulation-Up Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the instructed up and down Resource movement received through Regulation-Up deployment instructions in Dispatch Interval i. Real-Time Unused Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i.
MW
z, s, i
RtRegUpUnusedMile5minQt y a, z, s, i
MW
RtRegUpExcessMile5minQty
MW
a, s, i
RtRegMileOpTolPct a, z, s, i
RtRegUp5minQty a, z, s, i
Percent
MW
Dispatch Interval
Dispatch Interval
Comment [MPRR204.682]: MPRR204 Awaiting FERC filing Comment [MPRR102.683]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.684]: MPRR204 Awaiting FERC filing Comment [MPRR204.685]: MPRR204 Awaiting FERC filing Comment [MPRR102.686]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.687]: MPRR204 Awaiting FERC filing Comment [MPRR102.688]: MPRR102 Awaiting implementation. #ER13-1748
Dispatch Interval
Real-Time Excess Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Excess Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i.
Dispatch Interval
Resource Mileage Operating Tolerance per AO per Settlement Location per Dispatch Interval – The Resource Regulating Mileage Operating Tolerance associated with AO a’s Resource at Settlement Location s in Reserve Zone z in Dispatch Interval i. Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Regulation-Up Service MW represented by AO a’s cleared Regulation-Up Service Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i.
Dispatch Interval
Comment [MPRR204.681]: MPRR204 Awaiting FERC filing
Comment [MPRR204.689]: MPRR204 Awaiting FERC filing Comment [MPRR204.690]: MPRR204 Awaiting FERC filing Comment [MPRR204.691]: MPRR204 Awaiting FERC filing Comment [MPRR102.692]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.693]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.694]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.695]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.696]: MPRR102 Awaiting implementation. #ER13-1748
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Variable
RtRegUpHrlyAmt a, s, h
RtRegUpDlyAmt a, s, d
RtRegUpAoAmt a, m, d
RtRegUpMpAmt m, d
EqrRtRegUp5minQty a, s, i
EqrRtRegUp5minPrc a, s, i
Version 23.a
Unit
Settlement Interval
Definition
$
Hour
Real-Time Regulation-Up Service Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Up Service Offers at Resource Settlement Location s for the Hour. Real-Time Regulation-Up Service Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Up Service Offers at Resource Settlement Location s for the Operating Day. Real-Time Regulation-Up Service Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between cleared RTBM and DA Market Regulation-Up Service Offers for the Operating Day. Real-Time Regulation-Up Service Amount per MP per Operating Day - The amount to MP m for deviations between cleared RTBM and DA Market Regulation-Up Service Offers for the Operating Day. Real-Time Electric Quarterly Reporting net Regulation-Up Service Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Regulation-Up Service sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM Regulation-Up Service purchase at Resource Settlement Location s created when the cleared Real-Time Regulation-Up Service is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting net Regulation Up Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegUp5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.
$
$
$
MWh
$/MWh
Operating Day
Operating Day
Operating Day Dispatch Interval
Dispatch Interval
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Comment [MPRR102.697]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.698]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.699]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.700]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.701]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.702]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.703]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.704]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.705]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.706]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.707]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.708]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
Real-Time Electric Quarterly Reporting Excess Regulation-Up Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Excess Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting Excess Regulation-Up Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegUpExcessMile5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Unused Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegUpUnusedMile5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Cleared Regulation-Up Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.4 An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. An Operating Day. A Reserve Zone.
EqrRtRegUpExcessMile5min Qty a, s, i
MW
Dispatch Interval
EqrRtRegUpExcessMile5min Prc a, s, i
$/MW
Dispatch Interval
EqrRtRegUpUnusedMile5mi nQty a, s, i
MW
Dispatch Interval
EqrRtRegUpUnusedMile5mi nPrc a, s, i
DaRegUpHrlyQty a, z, s, h a s h i d z
Version 23.a
$/MW
MW none none none none none none
Dispatch Interval
Hour none none none none none none
12/4/2014
398
Comment [MPRR204.709]: MPRR204 Awaiting FERC filing
Comment [MPRR204.710]: MPRR204 Awaiting FERC filing
Comment [MPRR204.711]: MPRR204 Awaiting FERC filing
Comment [MPRR204.712]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
m
Version 23.a
Unit
none
Settlement Interval none
Definition
A Market Participant.
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Market Protocols for SPP Integrated Marketplace
4.5.9.5
Comment [MPRR102.713]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation-Down Service Amount
(1) A RTBM charge or credit for deviations between cleared RTBM Regulation-Down Service and cleared DA Market Regulation-Down Service and deviations between Expected Regulation-Down Mileage and Actual Regulation-Down Mileage provided will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval. The amount will be calculated as follows: #RtRegDn5minAmt a, s, i = (
Comment [MPRR102.714]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.715]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.716]: MPRR102 Awaiting implementation. #ER13-1748
( RtRegDnMcp5minPrc z, i
z
* ( RtRegDn5minQty a, z, s, i -
DaRegDnHrlyQty a, z, s, h ) /12 ) z
- RtRegDnUnusedMile5minAmt a, s, i - RtRegDnExcessMile5minAmt a, s, i )
Comment [MPRR102.717]: MPRR102 Awaiting implementation. #ER13-1748
* (-1) Where, (a)
#RtRegDownUnusedMile5minAmt a, s, i =
Comment [MPRR204.718]: MPRR204 Awaiting FERC filing
RtRegDownUnusedMile5minQty a, z, s, i
* RtRegDownMileMcp5minPrc
i
/
z
(a.1)
RtRegDownUnusedMile5minQty a, z, s, i
Comment [MPRR204.722]: MPRR204 Awaiting FERC filing Comment [MPRR204.723]: MPRR204 Awaiting FERC filing
- RtRegDownMile5minQty a, z, s, i )
Comment [MPRR204.724]: MPRR204 Awaiting FERC filing
#RtRegDnExcessMile5minAmt a, s, i =
RtRegDnExcessMile5minQty
a, s, i
Comment [MPRR204.725]: MPRR204 Awaiting FERC filing
Min ( 0, ( ( RtRegDn5minQty
a, z, s, i
*
z
RtRegDnMile5minFct i )
Version 23.a
Comment [MPRR204.720]: MPRR204 Awaiting FERC filing Comment [MPRR204.721]: MPRR204 Awaiting FERC filing
=
Max ( 0, ( RtRegDown5minQty a, z, s, i * RtRegDownMile5minFct i )
(b)
Comment [MPRR204.719]: MPRR204 Awaiting FERC filing
Comment [MPRR204.726]: MPRR204 Awaiting FERC filing Comment [MPRR204.727]: MPRR204 Awaiting FERC filing Comment [MPRR204.728]: MPRR204 Awaiting FERC filing
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400
Market Protocols for SPP Integrated Marketplace
- RtRegDnMile5minQty a, z, s, i )
Comment [MPRR204.729]: MPRR204 Awaiting FERC filing
* RtRegDnMileMcp5minPrc (b.1)
i
) / 12
Comment [MPRR204.730]: MPRR204 Awaiting FERC filing
#RtRegDnExcessMile5minQty a, s, i = Min ( 0, ( RtRegDn5minQty a, s, i * RtRegDnMile5minFct i ) - RtRegDnMile5minQty a, s, i )
(c)
Comment [MPRR204.731]: MPRR204 Awaiting FERC filing
IF RtRegDnActMile5minQty a, z, s, i >= (1 - RtRegMileOpTolPct a, z, s, i ) *
Comment [MPRR204.732]: MPRR204 Awaiting FERC filing
RtRegDnInstrMile5minQty a, z, s, i )
Comment [MPRR204.733]: MPRR204 Awaiting FERC filing
THEN
Comment [MPRR204.734]: MPRR204 Awaiting FERC filing
RtRegDnMile5minQty a, z, s, i = RtRegDnInstrMile5minQty a, z, s, i
Comment [MPRR204.735]: MPRR204 Awaiting FERC filing
ELSE
Comment [MPRR204.736]: MPRR204 Awaiting FERC filing
RtRegDnMile5minQty a, z, s, i = RtRegDnActMile5minQty a, z, s, i
Comment [MPRR204.737]: MPRR204 Awaiting FERC filing Comment [MPRR204.738]: MPRR204 Awaiting FERC filing Comment [MPRR102.739]: MPRR102 Awaiting implementation. #ER13-1748
(1) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows: RtRegDnHrlyAmt a, s, h =
RtRegDn5minAmt a, s, i
i
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtRegDnDlyAmt a, s, d =
The
RtRegDnHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:
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Market Protocols for SPP Integrated Marketplace
RtRegDnAoAmt a, m, d =
RtRegDnDlyAmt a, s, d
s
(4) 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: RtRegDnMpAmt m, d =
RtRegDnAoAmt a, m, d
a
(6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows: (a)
RTBM Regulation-Down Service
(a.1)
#EqrRtRegDn5minQty a, s, i =
Comment [MPRR204.740]: MPRR204 Awaiting FERC filing Comment [MPRR204.741]: MPRR204 Awaiting FERC filing
Max ( 0, ( RtRegDn5minQty a, z, s, i - DaRegDnHrlyQty a, z, s, h ) / 12 ) z
z
+ { IF #EqrDaRegDnHrlyQty a, s, h > 0 THEN
Min ( 0, ( RtRegDn5minQty a, z, s, i - DaRegDnHrlyQty a, z, s, h ) / 12 ) } z
z
(ba.2) IF #EqrRtRegDn5minQty a, s, i < > 0
Comment [MPRR204.742]: MPRR204 Awaiting FERC filing
THEN #EqrRtRegDn5minPrc a, s, i = RtRegDnMcp5minPrc z, i (b)
RTBM Excess Regulation-Down Mileage
(b.1) EqrRtRegDnExcessMile5minQty a, s, i = RtRegDnExcessMile5minQty a, s, i
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(b.2) EqrRtRegDnExcessMileMcp5minPrc a, s, i = ( 0 * EqrRtRegDnExcessMile5minQty a, s, i + RtRegDnMileMcp5minPrc i ) (c)
RTBM Unused Regulation-Down Mileage
(c.1) EqrRtRegDnUnusedMile5minQty a, s, i = RtRegDnUnusedMile5minQty a, s, i (c.2) EqrRtRegDnUnusedMileMcp5minPrc a, s, i = ( 0 * EqrRtRegDnUnusedMile5minQty a, s, i + RtRegDnMileMcp5minPrc i )
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Comment [MPRR204.743]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
RtRegDn5minAmt a, s, i
Unit
Settlement Interval
Definition
$
Dispatch Interval
Real-Time Regulation-Down Service Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Down Service Offers , Unused Regulation-Up Mileage and Excess RegulationUp Mileage at Resource Settlement Location s for the Dispatch Interval. Real-Time MCP for Regulation-Down Service per Reserve Zone - The RTBM MCP for Regulation-Down Service in Reserve Zone z for Dispatch Interval i. Real-Time MCP for Regulation-Down Mileage - The RTBM MCP for ExcessExpected Regulation-Down Mileage for Dispatch Interval i.
$/MW
RtRegDnMcp5minPrc z, i
RtRegDnMileMcp5minPrc i RtRegDnUnusedMile5minAm t a, s, i
RtRegDnExcessMile5minAmt
$/MW
Dispatch Interval
$
Dispatch Interval
$
Dispatch Interval
Ratio
Dispatch Interval
a, s, i
RtRegDnMile5minFct i RtRegDnActMile5minQty s, i
Version 23.a
a, z,
Dispatch Interval
MW
Dispatch Interval
Comment [MPRR102.745]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.746]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.747]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.748]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.749]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Unused Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The charge to AO a for Unused Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i. Real-Time Excess Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The payment to AO a for Excess Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i. Real-Time Regulation-Down Mileage Factor Dispatch Interval - The Regulation-Down Mileage Factor for Dispatch Interval i.
Comment [MPRR102.750]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.751]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.752]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Actual Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - The AO a’s Actual Regulation-Down Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the actual up and down Resource movement in response to Regulation-Down deployment instructions in Dispatch Interval i.
12/4/2014
Comment [MPRR102.744]: MPRR102 Awaiting implementation. #ER13-1748
404
Comment [MPRR204.753]: MPRR204 Awaiting FERC filing Comment [MPRR204.754]: MPRR204 Awaiting FERC filing Comment [MPRR102.755]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtRegDnMile5minQty a, z, s, i
RtRegDnInstrMile5minQty
a,
Unit
Settlement Interval
Definition
MW
Dispatch Interval
Real-Time Regulation-Down Mileage Settlement Quantity per AO per Settlement Location per Dispatch Interval - AO a’s settled Actual Regulation-Down Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z used for Settlement that includes the impact of the Regulating Mileage Operating Tolerance. Real-Time Instructed Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Instructed RegulationDown Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the instructed up and down Resource movement received through Regulation-Down deployment instructions in Dispatch Interval i. Real-Time Unused Regulation-DownMileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused RegulationDown Mileage at Resource Settlement Location s for Dispatch Interval i. Real-Time Excess Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused RegulationDown Mileage at Resource Settlement Location s for Dispatch Interval i. Resource Mileage Operating Tolerance per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.4.
Comment [MPRR204.756]: MPRR204 Awaiting FERC filing
Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Regulation-Down Service represented by AO a’s cleared RegulationDown Service Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i. Real-Time Regulation-Down Service Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Down Service Offers at Resource Settlement Location s for the Hour.
Comment [MPRR102.766]: MPRR102 Awaiting implementation. #ER13-1748
MW
z, s, i
RtRegDnUnusedMile5minQt y a, z, s, i
MW
RtRegDnExcessMile5minQty
MW
a, s, i
RtRegMileOpTolPct a, z, s, i RtRegDn5minQty a, z, s, i
RtRegDnHrlyAmt a, s, h
Dispatch Interval
Dispatch Interval Dispatch Interval
Percent
Dispatch Interval
MW
Dispatch Interval
$
Hour
Comment [MPRR204.757]: MPRR204 Awaiting FERC filing Comment [MPRR102.758]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.759]: MPRR204 Awaiting FERC filing Comment [MPRR204.760]: MPRR204 Awaiting FERC filing Comment [MPRR102.761]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.762]: MPRR204 Awaiting FERC filing Comment [MPRR102.763]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.764]: MPRR204 Awaiting FERC filing Comment [MPRR204.765]: MPRR204 Awaiting FERC filing
Comment [MPRR102.767]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.768]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.769]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.770]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.771]: MPRR102 Awaiting implementation. #ER13-1748
Version 23.a
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Market Protocols for SPP Integrated Marketplace
Variable
RtRegDnDlyAmt a, s, d
RtRegDnAoAmt a, m, d
RtRegDnMpAmt m, d
EqrRtRegDn5minQty a, s, i
EqrRtRegDn5minPrc a, s, i
EqrRtRegDnExcessMile5min Qty a, s, i
Version 23.a
Unit
Settlement Interval
Definition
$
Operating Day
Real-Time Regulation-Down Service Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Down Resource Offers at Resource Settlement Location s for the Operating Day. Real-Time Regulation-Down Service Amount per AO per Operating Day The amount to AO a associated with Market Participant m for deviations between cleared RTBM and DA Market Regulation-Down Service Offers for the Operating Day. Real-Time Regulation-Down Service Amount per MP per Operating Day The amount to MP m for deviations between cleared RTBM and DA Market Regulation-Down Service Offers for the Operating Day. Real-Time Electric Quarterly Reporting net Regulation-Down Service Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Regulation-Down Service sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM Regulation-Down Service purchase at Resource Settlement Location s created when the cleared Real-Time Regulation-Down Service is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting net Regulation-Down Service Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegDn5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting Excess Regulation-Down Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Excess Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.
$
$
MWh
Operating Day
Operating Day Dispatch Interval
$/MWh
Dispatch Interval
MW
Dispatch Interval
12/4/2014
406
Comment [MPRR102.772]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.773]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.774]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.775]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.776]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.777]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.778]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.779]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.780]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.781]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.782]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR204.783]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
EqrRtRegDnExcessMile5min Prc a, s, i
$/MW
Dispatch Interval
EqrRtRegDnUnusedMile5mi nQty a, s, i
MW
Dispatch Interval
EqrRtRegDnUnusedMile5mi nPrc a, s, i
$/MW
Dispatch Interval
DaRegDnHrlyQty a, z, s, h
MW
Hour
a s h i d z m
none none none none none none none
none none none none none none none
Real-Time Electric Quarterly Reporting Excess Regulation-Down Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegDnExcessMile5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting Unused Regulation-Down Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Unused Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting Unused Regulation-Down Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegDnUnusedMile5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Cleared Regulation-Down Service Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.5 An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. An Operating Day. A Reserve Zone. A Market Participant.
Version 23.a
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407
Comment [MPRR204.784]: MPRR204 Awaiting FERC filing
Comment [MPRR204.785]: MPRR204 Awaiting FERC filing
Comment [MPRR204.786]: MPRR204 Awaiting FERC filing Comment [MPRR102.787]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
4.5.9.6
Real-Time Spinning Reserve Amount
(1) A RTBM charge or credit for deviations between cleared RTBM Spinning Reserve and cleared DA Market Spinning Reserve will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval. The amount will be calculated as follows:
#RtSpin5minAmt a, s, i =
( RtSpinMcp5minPrc z, i
z
* ( RtSpin5minQty a, z, s, i -
DaSpinHrlyQty a, z, s, h ) / 12 ) * (-1) z
For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtSpinHrlyAmt a, s, h =
RtSpin5minAmt a, s, i
i
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtSpinDlyAmt a, s, d =
The
RtSpinHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtSpinAoAmt a, m, d =
RtSpinDlyAmt a, s, d
s
(4) 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: RtSpinMpAmt m, d =
RtSpinAoAmt a, m, d
a
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Market Protocols for SPP Integrated Marketplace
(6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows: (a)
#EqrRtSpin5minQty a, s, i =
Max ( 0, ( RtSpin5minQty a, z, s, i - DaSpinHrlyQty a, z, s, h ) / 12 ) z
z
+ { IF #EqrDaSpinHrlyQty a, s, h > 0 THEN
Min ( 0, ( RtSpin5minQty a, z, s, i - DaSpinHrlyQty a, z, s, h ) / 12 ) } z
(b)
z
IF #EqrRtSpin5minQty a, s, i < > 0 THEN #EqrRtSpin5minPrc a, s, i = RtSpinMcp5minPrc z, i
Version 23.a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
$/MWh
Dispatch Interval
Real-Time Spinning Reserve Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for deviations between cleared RTBM and DA Market Spinning Reserve Offers at Resource Settlement Location s for the Dispatch Interval. Real-Time MCP for Spinning Reserve - The RTBM MCP for Spinning Reserve in Reserve Zone z for Dispatch Interval i.
RtSpin5minQty a, z, s, i
MW
Dispatch Interval
RtSpinHrlyAmt a, s, h
$
Hour
RtSpinDlyAmt a, s, d
$
Operating Day
RtSpinAoAmt a, m, d
$
Operating Day
RtSpinMpAmt m, d
$
Operating Day
RtSpin5minAmt a, s, i
RtSpinMcp5minPrc z, i
Version 23.a
Real-Time Cleared Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Spinning Reserve represented by AO a’s cleared Spinning Reserve Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i. Real-Time Spinning Reserve Amount per AO per Settlement Location per Hour The amount to AO a for deviations between cleared RTBM and DA Market Spinning Reserve Offers at Resource Settlement Location s for the Hour. Real-Time Spinning Reserve Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between cleared RTBM and DA Market Spinning Reserve Offers at Resource Settlement Location s for the Operating Day. Real-Time Spinning Reserve Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between cleared RTBM and DA Market Spinning Reserve Offers for the Operating Day. Real-Time Spinning Reserve Amount per MP per Operating Day - The amount to MP m for deviations between cleared RTBM and DA Market Spinning Reserve Offers for the Operating Day.
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
EqrRtSpin5minQty a, s, i
MWh
Dispatch Interval
EqrRtSpin5minPrc a, s, i
$/MWh
Dispatch Interval
DaSpinHrlyQty a, z, s, h
MW
Hour
a s h i d z m
none none none none none none none
none none none none none none none
Real-Time Electric Quarterly Reporting net Spinning Reserve Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Spinning Reserve sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM Spinning Reserve purchase at Resource Settlement Location s created when the cleared Real-Time Spinning Reserve is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting net Spinning Reserve Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtSpin5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Cleared Spinning Reserve Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.6 An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. An Operating Day. A Reserve Zone. A Market Participant.
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Market Protocols for SPP Integrated Marketplace
4.5.9.7
Real-Time Supplemental Reserve Amount
(1) A RTBM charge or credit for deviations between cleared RTBM Supplemental Reserve and cleared DA Market Supplemental Reserve will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval. The amount will be calculated as follows:
#RtSupp5minAmt a, s, i =
( RtSuppMcp5minPrc z, i
z
* ( RtSupp5minQty a, z, s, i -
DaSuppHrlyQty a, z, s, h ) /12 ) * (-1) z
For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtSuppHrlyAmt a, s, h =
RtSupp5minAmt a, s, i
i
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtSuppDlyAmt a, s, d =
The
RtSuppHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtSuppAoAmt a, m, d =
RtSuppDlyAmt a, s, d
s
(4) 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: RtSuppMpAmt m, d =
RtSuppAoAmt a, m, d
a
Version 23.a
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Market Protocols for SPP Integrated Marketplace
(6) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows: (a)
#EqrRtSupp5minQty a, s, i =
Max ( 0, ( RtSupp5minQty a, z, s, i - DaSuppHrlyQty a, z, s, h ) / 12 ) z
z
+ { IF #EqrDaSuppHrlyQty a, s, h > 0 THEN
Min ( 0, ( RtSupp5minQty a, z, s, i - DaSuppHrlyQty a, z, s, h ) / 12 ) } z
(b)
z
IF #EqrRtSupp5minQty a, s, i < > 0 THEN #EqrRtSupp5minPrc a, s, i = RtSuppMcp5minPrc z, i
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
$/MWh
Dispatch Interval
Real-Time Supplemental Reserve Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for deviations between cleared RTBM and DA Market Supplemental Reserve Offers at Resource Settlement Location s for the Dispatch Interval. Real-Time MCP for Supplemental Reserve - The RTBM MCP for Supplemental Reserve in Reserve Zone z for Dispatch Interval i.
RtSupp5minQty a, z, s, i
MW
Dispatch Interval
RtSuppHrlyAmt a, s, h
$
Hour
RtSuppDlyAmt a, s, d
$
Operating Day
RtSuppAoAmt a, m, d
$
Operating Day
RtSuppMpAmt m, d
$
Operating Day
RtSupp5minAmt a, s, i
RtSuppMcp5minPrc z, i
Version 23.a
Real-Time Cleared Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Supplemental Reserve represented by AO a’s cleared Supplemental Reserve Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i. Real-Time Supplemental Reserve Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between cleared RTBM and DA Market Supplemental Reserve Offers at Resource Settlement Location s for the Hour. Real-Time Supplemental Reserve Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between cleared RTBM and DA Market Supplemental Reserve Offers at Resource Settlement Location s for the Operating Day. Real-Time Supplemental Reserve Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between cleared RTBM and DA Market Supplemental Reserve Offers for the Operating Day. Real-Time Supplemental Reserve Amount per MP per Operating Day The amount to MP m for deviations between cleared RTBM and DA Market Supplemental Reserve Offers for the Operating Day.
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Variable
Unit
Settlement Interval
Definition
EqrRtSupp5minQty a, s, i
MWh
Dispatch Interval
EqrRtSupp5minPrc a, s, i
$/MWh
Dispatch Interval
DaSuppHrlyQty a, z, s, h
MW
Hour
a s h i d z m
none none none none none none none
none none none none none none none
Real-Time Electric Quarterly Reporting net Supplemental Reserve Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Supplemental Reserve sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM Supplemental Reserve purchase at Resource Settlement Location s created when the cleared Real-Time Supplemental Reserve is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements. Real-Time Electric Quarterly Reporting net Supplemental Reserve Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtSupp5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements. Day-Ahead Cleared Supplemental Reserve Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.7 An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. An Operating Day. A Reserve Zone. A Market Participant.
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4.5.9.8
RUC Make-Whole-Payment Amount
(1) The RUC Make-Whole-Payment Amount is a credit or charge24 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The RUC Make-WholePayment Amount is also calculated for combined cycle Resources with a RUC Commitment Period during which the Resource is moved into a configuration that incurs additional costs over the Resource configuration used in the DA Market Commitment Period for the corresponding time period. A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve, Transition State Offer costs and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE. (2) A Resource’s RUC Make-Whole-Payment Eligibility Period is equal to the Resource’s RUC Commitment Period except as described below: (a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first 24
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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Market Protocols for SPP Integrated Marketplace
Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time. Exhibit 4-25: RUC Make-Whole Payment Eligibility Period – Multiple Operating Days Operating Day 1 Real-Time MakeWhole Payment Eligibility Period
Operating Day 2 Real-Time MakeWhole Payment Eligibility Period
Time RUC Commitment Period
(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved into a configuration that is different from the configuration used in the DA Market Commitment period and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is higher than the No-Load Offer cost associated with the configuration used in the DA Market, that RTBM hour will be considered the start of a RUC Make-Whole-Payment Eligibility Period. The end of this RUC Make-WholePayment Eligibility Period will be defined by the RTBM hour when the configuration in that RTBM hour is the same configuration as the configuration used in the corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end of the Operating Day, whichever is less. (3) The following cost recovery eligible rules apply to each RUC Make-Whole-Payment Eligibility Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made for start-up, no-load, and minimumenergy; 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-WholePayment Eligibility Period and the Resource is not a Synchronized Resource, the Asset
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Market Protocols for SPP Integrated Marketplace
Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery. (b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period. (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)
(ii)
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 recoverythat is adjacent to the end of a DA Market Make-Whole Payment Eligibility Period; 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
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Market Protocols for SPP Integrated Marketplace
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 MakeWhole 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 MakeWhole 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 MakeWhole 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. (h)(i) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time 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. 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
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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.
Comment [MPRR101.792]: MPRR101 awaiting FERC filing
(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) }
*
{ RtStartUpElig5minFlg a, s, i, c * RtStartUp5minAmt a, s, i, c
i
+ RtRucComStat5minFlg a, s, i, c * [ RtMwpCost5minAmt a, s, i, c + RtTransition5minAmt a, s, i, c + RtMwpRev5minAmt a, s, i, c
Comment [MPRR101.793]: MPRR101 awaiting FERC filing
+ RtOom5minAmt a, s, i + RtRegAdj5minAmt a, s, i – RtURDAdj5minAmt a, s, i, c – RtStatusAdj5minAmt a, s, i, c – RtLimitAdj5minAmt a, s, i, c ] } +
Field Code Changed
( RtCcRegUpAdjHrlyAmt a, s, h, c + RtCcRegDnAdjHrlyAmt a, s, h, c
h
+ RtCcSpinAdjHrlyAmt a, s, h, c + RtCcSuppAdjHrlyAmt a, s, h, c ) ) ) ) * (-1) Where, (a)
#RtMwpCost5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c * ( RtIncrEn5minAmt a, s, i + Max ( 0, [ RtNoLoad5minAmt a, s, i, c - IF (DaClrdHrlyQty a, s, h < 0, THEN DaNoLoadHrlyAmt a, s, h, c , ELSE 0 ) ] )
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+ RtMinEn5minAmt a, s, i, c + RtRegUpAvail5minAmt a, s, i, c + RtRegDnAvail5minAmt a, s, i, c
Comment [MPRR204.795]: MPRR204 Awaiting FERC filing
+ PotRtRegUpMileMwp5minAmt a, s, i + PotRtRegDnMileMwp5minAmt a, s, i
Comment [MPRR204.796]: MPRR204 Awaiting FERC filing
+ RtSpinAvail5minAmt a, s, i, c + RtSuppAvail5minAmt a, s, i, c ) / 12
Comment [MPRR204.797]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(a.1)
IF ABS (DaClrdHrlyQty a, s, h ) > = ABS ( RtBillMtr5minQty a, s, i ) THEN RtIncrEn5minAmt a, s, i = 0 ELSE y
#RtIncrEn5minAmt a, s, i =
RTBM As Dispatched Energy Offer Curve x
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 ,
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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)
Comment [MPRR101.798]: MPRR101 awaiting FERC filing
IF ABS (DaClrdHrlyQty a, s, h ) <> 0 RtEffMin5minQty a, s, i THEN
Field Code Changed
y
#RtMinEn5minAmt a, s, i =
RTBM As Committed Energy Offer Curve x
Where: X = DaClrdHrlyQty a, s, h Y = RtEffMin5minQty a, s, i ELSE
Comment [MPRR101.799]: MPRR101 awaiting FERC filing
RtMinEn5minAmt a, s, i, c = 0 ELSE # RtMinEn5minAmt a, s, i, c =
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RtEffMin5minQty a, s, i
RTBM As Committed Energy Offer Curve 0
(a.3)
Comment [MPRR204.801]: MPRR204 Awaiting FERC filing
If RtRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i THEN
Comment [MPRR204.802]: MPRR204 Awaiting FERC filing
RtRegUpAvail5minAmt a, s, i, c =
( Max ( 0, [ RtRegUp5minQty a, z, s, i -
Comment [MPRR102.803]: MPRR102 Awaiting implementation. #ER13-1748
DaRegUpHrlyQty a, z, s, h] ) z
Comment [MPRR204.804]: MPRR204 Awaiting FERC approval Docket #ER13-1748
* RtRegUpOffer a, s, i, c ) + RtRegUpUnusedMile5minAmt a, s, i
Comment [MPRR102.805]: MPRR102 Awaiting implementation. #ER13-1748
- ( RtRegUpMileOffer5minPrc a, s, i * RtRegUpExcessMile5minQty a, s, i )
Comment [MPRR204.806]: MPRR204 Awaiting FERC approval Docket #ER13-1748
ELSE Comment [MPRR204.807]: MPRR204 Awaiting FERC filing
RtRegUpAvail5minAmt a, s, i, c =0 IF RtTranistionStateFlg a, s, i, c = 1 THEN RtRegUpAvail5minAmt a, s, i, c =
Field Code Changed
DaRegUpHrlyQty a, z, s, h z
* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h ) ELSE Comment [MPRR101.808]: MPRR101 awaiting FERC filing
RtRegUpAvail5minAmt a, s, i, c = RtRegUpAvail5minAmt a, s, i = 0
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(a.4)
Comment [MPRR204.809]: MPRR204 Awaiting FERC filing
If RtRegDn5minQty a, s, i > RtFixedRegDn5minQty a, s, c, i THEN
Comment [MPRR204.810]: MPRR204 Awaiting FERC filing
RtRegDnAvail5minAmt a, s, i, c =
( Max ( 0, [ RtRegDn5minQty a, z, s, i -
Comment [MPRR102.811]: MPRR102 Awaiting implementation. #ER13-1748
DaRegDnHrlyQty a, z, s, h] ) z
* RtRegDnOffer a, s, i, c ) + RtRegDnUnusedMile5minAmt a, s, i
Comment [MPRR204.812]: MPRR204 Awaiting FERC filing
- ( RtRegDnMileOffer5minPrc a, s, i, * RtRegDnExcessMile5minQty a, s, i )
Comment [MPRR102.813]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.814]: MPRR204 Awaiting FERC approval Docket #ER13-1748
ELSE
Comment [MPRR101.815]: MPRR101 awaiting FERC filing
RtRegDnAvail5minAmt a, s, i, c =0 (a.5)
Comment [MPRR204.816]: MPRR204 Awaiting FERC filing
If RtSpin5minQty a, s, i > RtFixedSpin5minQty a, s, c, i
Comment [MPRR204.817]: MPRR204 Awaiting FERC filing
THEN RtSpinAvail5minAmt a, s, i, c =
Max ( 0, [ RtSpin5minQty a, z, s, i -
DaSpinHrlyQty a, z, s, h] ) z
* RtSpinOffer a, s, i, c ELSE Comment [MPRR204.818]: MPRR204 Awaiting FERC filing
RtSpinAvail5minAmt a, s, i, c =0
Comment [MPRR101.819]: MPRR101 awaiting FERC filing
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(a.6)
If RtSupp5minQty a, s, i > RtFixedSupp5minQty a, s, c, i THEN RtSuppAvail5minAmt a, s, i, c =
Max ( 0, [ RtSupp5minQty a, z, s, i -
DaSuppHrlyQty a, z, s, h] ) z
* RtSuppOffer a, s, i, c ELSE Comment [MPRR204.820]: MPRR204 Awaiting FERC filing
RtSuppAvail5minAmt a, s, i, c =0 (b)
Comment [MPRR101.821]: MPRR101 awaiting FERC filing
#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
(b.1)
+ RtSpinRev5minAmt a, s, i, c + RtSuppRev5minAmt a, s, i, c ]
Comment [MPRR204.822]: MPRR204 Awaiting FERC filing
+ RegUpUnusedMileMwp5minAmt a, s, i
Comment [MPRR204.823]: MPRR204 Awaiting FERC filing
+ RegDnUnusedMileMwp5minAmt a, s, i
Comment [MPRR204.824]: MPRR204 Awaiting FERC approval Docket #ER13-1748
RtRegUpRev5minAmt a, s, i, c = (-1) * RtRucComStat5minFlg a, s, i, c * ( ( Max ( 0, [ RtRegUp5minQty a, z, s, i -
Comment [MPRR204.825]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.826]: MPRR102 Awaiting implementation. #ER13-1748
DaRegUpHrlyQty a, z, s, h] ) z
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(b.2)
* RtRegUpMcp5minPrc z, i ) / 12 ) -+ RtRegUpExcessMile5minAmt a, s, i
Comment [MPRR204.827]: MPRR204 Awaiting FERC approval Docket #ER13-1748
- RtRegUpUnusedMileMwp5minAmt a, s, i
Comment [MPRR102.828]: MPRR102 Awaiting implementation. #ER13-1748
RtRegDnRev5minAmt a, s, i, c =
Comment [MPRR204.829]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(-1) * RtRucComStat5minFlg a, s, i, c
Comment [MPRR204.830]: MPRR204 Awaiting FERC approval Docket #ER13-1748
*( ( Max ( 0, [ RtRegDn5minQty a, z, s, i -
Comment [MPRR102.831]: MPRR102 Awaiting implementation. #ER13-1748
DaRegDnHrlyQty a, z, s, h] ) z
Comment [MPRR204.832]: MPRR204 Awaiting FERC approval Docket #ER13-1748
* RtRegDnMcp5minPrc z, i ) / 12 ) -+ RtRegDnExcessMile5minAmt a, s, i
Comment [MPRR102.833]: MPRR102 Awaiting implementation. #ER13-1748
- RtRegDnUnusedMileMwp5minAmt a, s, i (b.3)
Comment [MPRR204.834]: MPRR204 Awaiting FERC approval Docket #ER13-1748
RtSpinRev5minAmt a, s, i, c = (-1) * RtRucComStat5minFlg a, s, i, c
*( Max ( 0, [ RtSpin5minQty a, z, s, i -
DaSpinHrlyQty a, z, s, h ] ) z
* RtSpinMcp5minPrc z, i ) / 12 (b.4)
RtSuppRev5minAmt a, s, i, c = (-1) * RtRucComStat5minFlg a, s, i, c
*( Max ( 0, [ RtSupp5minQty a, z, s, i -
DaSuppHrlyQty a, z, s, h ] ) z
* RtSuppMcp5minPrc z, i ) / 12
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(c)
#CncldStartAmt a, s, c =
( RtStartUp5minAmt a, s, i, c * RtStartUpElig5minFlg a, s, i, c )
i
* 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 ) )
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(d.3)
IF RtDesiredEn5minQty a, s, i < ABS (DaClrdHrlyQty a, s, h ) THEN #RtDesiredEn5minAmt a, s, i = RtIncrEn5minAmt a, s, i ELSE y
#RtDesiredEn5minAmt a, s, i =
RTBM As Dispatched Energy Offer Curve x
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
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(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 combined Cycle 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:
Comment [MPRR102.835]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.836]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR101.837]: MPRR101 awaiting FERC filing
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
Comment [MPRR204.838]: MPRR204 Awaiting FERC filing
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
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#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)
If
Field Code Changed
RtTranistionStateFlg a, s, i, c > = 1 THEN
i
RtCcRegUpAdjHrlyAmt a, s, h, c =
* Max ( 0,
Field Code Changed
( RtCcRegUpAdj5minAmt a, s, i c * RtRucComStat5minFlg a, s, i,
i
c)
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
Field Code Changed
RtTranistionStateFlg a, s, i, c > = 1 THEN
i
RtCcRegDnAdjHrlyAmt a, s, h, c =
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Market Protocols for SPP Integrated Marketplace
* Max ( 0,
Field Code Changed
( RtCcRegDnAdj5minAmt a, s, i c * RtRucComStat5minFlg a, s, i,
i
c)
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 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,
Field Code Changed
RtCcSpinAdj5minAmt a, s, i, c )
i
(j)
Version 23.a
IF RtTranistionStateFlg a, s, i = 1 THEN
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RtCcSuppAdj5minAmt a, s, i, c = RtRucComStat5minFlg RtSupp5minAmt a, s, i )
a,
s,
i,
c
* (DaSuppHrlyAmt
a,
s,
h
/ 12 +
ELSE RtCcSupp5minAmt a, s, i, c = 0 (j.1)
RtCcSuppAdjHrlyAmt a, s, h, c =
Max ( 0,
Comment [MPRR101.839]: MPRR101 awaiting FERC filing
RtCcSuppAdj5minAmt a, s, i, c
Field Code Changed
i
(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 =
RtMwpCpAmt a, s, c
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 =
RtMwpDlyAmt a, s, d
s
(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 =
RtMwpAoAmt a, m, d
a
(8) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates RUC MakeWhole Payment $ per RUC Make-Whole-Payment Eligibility Period for each Asset Owner as follows: (a)
Version 23.a
#EqrRtMwp5minPrc a, s, c = (-1) * RtMwpCpAmt a, s, c
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Market Protocols for SPP Integrated Marketplace
(b)
IF #EqrRtMwp5minPrc a, s, c > 0 THEN #EqrRtMwp5minQty a, s, c = 1
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtMwpCpAmt a, s, c
$
Eligibility Period
DaClrdHrlyQty a, s, h
MWh
Hour
RtTransition5minAmt a, s, i, c
$
Eligibility Period
RtTransitionStateFlg a, s, i, c
Flag
Dispatch Interval
RUC Make-Whole-Payment Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The amount to AO a for RUC MakeWhole-Payment Eligibility Period c at Resource Settlement Location s.. 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. 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-WholePayment Eligibility Period c. 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 when a combined cycle Resource at Settlement Location s is transitioning from one configuration to another in RUC Make-Whole-Payment Eligibility Period c.
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Comment [MPRR101.840]: MPRR101 awaiting FERC filing
Comment [MPRR101.841]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtStartUp5minAmt a s, i, c
$
Eligibility Period
RtStartUpAmt a s, c
$
Eligibility Period
Real-Time Start-Up Cost Amount per AO per Settlement Location per Dispatch Interval per RUC Make-WholePayment 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. 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 MakeWhole-Payment Eligibility Period c. 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 MakeWhole-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.
(Not Available on Settlement Statement)
RtStartUpElig5minFlg a, s, i, c
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None
Dispatch Interval
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Comment [MPRR190.842]: MPRR190 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtRucComStat5minFlg a, s, i, c
None
Dispatch Interval
CncldStartRatio a, s, c
None
RtMinRunTime a, i, s, c
Time
Dispatch Interval
RtSynchToMinTime a, i, s, c
Time
Dispatch Interval
RUC Commitment Status Flag per AO per Resource Settlement Location per Dispatch Interval in RUC MakeWhole-Payment Eligibility Period – This flag is set equal to 1 for each Dispatch Interval of a RUC Make-WholePayment Eligibility Period in which a Resource’s Commitment Status was “Market” or “Reliability”, or 0 if its Commitment Status was “Self”. 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. Real-Time Minimum Run Time per AO per Settlement Location Per Dispatch Interval per RUC Make-WholePayment 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. 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-WholePayment Eligibility Period c as submitted as part of the RTBM Market Offer.
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Variable
Unit
Settlement Interval
Definition
RtNoLoad5minAmt a, i, s, c
$
Dispatch Interval
RtMwpCost5minAmt a, s, i, c
$
Dispatch Interval
PotRtRegUpMileMwp5minAmt a, s, i
$
Dispatch Interval
PotRtRegDnMileMwp5minAmt a, s, i
$
Dispatch Interval
Real-Time No-Load Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-WholePayment 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. RUC Make-Whole-Payment Cost per AO per Settlement Location per Dispatch Interval in the RUC Make-WholePayment 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. 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 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 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.
RtMwpRev5minAmt a, s, i, c
Version 23.a
$
Dispatch Interval
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Comment [MPRR204.843]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.844]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtRegUpUnusedMileMwp5minAmt a, s, i
RtRegDnUnusedMileMwp5minAmt a, s, i
RtRegUpMileOffer5minPrc a, s, i
RtRegUpExcessMile5minQty a, s, i
RtRegDnMileOffer5minPrc a, s, i
RtRegDnExcessMile5minQty a, s, i
CncldStartAmt a, s, c
Version 23.a
Unit
Settlement Interval
Definition
$
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 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 Real-Time Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - The value described under Section 4.5.9.28 Real-Time Excess Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.4 Real-Time Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - The value described under Section 4.5.9.29 Real-Time Excess Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.5 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.
$
Dispatch Interval
$/MW
Dispatch Interval
MW
$/MW
MW
$
Dispatch Interval Dispatch Interval Dispatch Interval Eligibility Period
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Comment [MPRR204.845]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.846]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.847]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.848]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.849]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.850]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
ElapsedTime a, s, c
Time
Eligibility Period
StartUpTime a, s, c
Time
Eligibility Period
$
Dispatch Interval
URD5minQty a, s, i
MW
Dispatch Interval
ResOpTol5minQty a, s, i
MW
Dispatch Interval
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. Start-up Time per AO per Settlement Location for the RUC Make-Whole-Payment Eligibility Period – The StartUp 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. 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. 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. 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.
RtURDAdj5minAmt a, s, i, c
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
URDMaxTol5minQty i
MW
Dispatch Interval
URDMinTol5minQty i
MW
Dispatch Interval
Percent
Dispatch Interval
RtAvgSetPoint5minQty a, s, i
MW
Dispatch Interval
XmptDev5minFlg a, s, i
none
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. Uninstructed Resource Deviation Minimum Tolerance per Dispatch Interval – The minimum value of ResOpTol5minQty a, s, i that is currently set at 5 MW. 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%. 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. 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
URDTol5minPct i
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtStatusAdj5minAmt a, s, i, c
$
Dispatch Interval
ControlStatus5minFlg a, s, i
None
Dispatch Interval
RtDispMaxEmerCapOL5minQty a, s, i
MW
Dispatch Interval
RtEffMin5minQty a, s, i
MW
Dispatch Interval
RtDispMinEconCapOL5minQty a, s, i
MW
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”. 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. 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. 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. 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.
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Variable
RtDispMinRegCapOL5minQty a, s, i
RtLimitAdj5minAmt a, s, i, c
RtComMinEconCapOL5minQty a, s, i
Version 23.a
Unit
Settlement Interval
Definition
MW
Dispatch Interval
$
Dispatch Interval
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. 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. 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.
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Comment [MPRR101.851]:
Market Protocols for SPP Integrated Marketplace
Variable
RtComMinRegCapOL5minQty a, s, i
Unit
Settlement Interval
Definition
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. 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. 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 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.
RtIncrEn5minAmt a, s, i
$
Dispatch Interval
RtMinEn5minAmt a, s, i, c
$
Dispatch Interval
RtDesiredEn5minAmt a, s, i
$
Dispatch Interval
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Comment [MPRR101.852]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
MW
Dispatch Interval
RtOom5minAmt a, s, i
$
Dispatch Interval
RtRegAdj5minAmt a, s, i
$
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. 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. Real-Time Regulation Deployment Adjustment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.19. Real-Time Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Regulation-Up Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c. Real-Time Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Regulation-Down Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.
RtDesiredEn5minQty a, s, i
RtRegUpOffer a, s, i, c
$/MW
(Not Available on Settlement Statement)
RtRegDnOffer a, s, i, c
(Not Available on Settlement Statement)
$/MW
Dispatch Interval
Dispatch Interval
Comment [MPRR102.854]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.853]: MPRR204 Awaiting FERC filing Comment [MPRR204.855]: MPRR204 Awaiting FERC filing Comment [MPRR102.856]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.857]: MPRR204 Awaiting FERC filing Comment [MPRR102.859]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.858]: MPRR204 Awaiting FERC filing Comment [MPRR204.860]: MPRR204 Awaiting FERC filing Comment [MPRR102.861]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.862]: MPRR204 Awaiting FERC filing
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Market Protocols for SPP Integrated Marketplace
Variable
RtSpinOffer a, s, i, c
Unit
Settlement Interval
Definition
$/MW
Dispatch Interval
Real-Time Spinning Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC MakeWhole-Payment Eligibility Period – The Spinning Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-WholePayment Eligibility Period c. Real-Time Supplemental Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c. Real-Time Fixed Regulation-Up Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – 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 the commitment decision was made for RUC Make-Whole-Payment Eligibility Period c in Dispatch Interval i. Real-Time Fixed Regulation-Down Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – 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 RTBMthe commitment decision was made for RUC Make-Whole-Payment Eligibility Period c in Dispatch Interval i.
(Not Available on Settlement Statement)
RtSuppOffer a, s, i, c
$/MW
(Not Available on Settlement Statement)
RtFixedRegUp5minQty a, s, c, i
RtFixedRegDn5minQty a, s, c, i
Version 23.a
MW
MW
Dispatch Interval
Dispatch Interval
Dispatch Interval
12/4/2014
445
Comment [MPRR204.863]: MPRR204 Awaiting FERC filing
Comment [MPRR204.864]: MPRR204 Awaiting FERC filing
Comment [MPRR204.865]: MPRR204 Awaiting FERC filing Comment [MPRR204.866]: MPRR204 Awaiting FERC filing
Comment [MPRR204.867]: MPRR204 Awaiting FERC filing Comment [MPRR204.868]: MPRR204 Awaiting FERC filing Comment [MPRR204.869]: MPRR204 Awaiting FERC filing
Comment [MPRR204.870]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtFixedSpin5minQty a, s, c, i
MW
Dispatch Interval
Real-Time Fixed Spinning Reserve Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – 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 the commitment decision was made for RUC Make-Whole-Payment Eligibility Period c in Dispatch Interval i. Real-Time Fixed Supplemental Reserve Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – 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 the commitment decision was made for RUC Make-WholePayment Eligibility Period c in Dispatch Interval i. Real-Time Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The Regulation-Up Service 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. Real-Time Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The Regulation-Down Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in DA Market Commitment Period c.
RtFixedSupp5minQty a, s, c, i
RtRegUpAvail5minAmt a, s, i, c
RtRegDnAvail5minAmt a, s, i, c
MW
$
$
Dispatch Interval
Dispatch Interval
Dispatch Interval
Comment [MPRR204.871]: MPRR204 Awaiting FERC filing Comment [MPRR204.872]: MPRR204 Awaiting FERC filing Comment [MPRR204.873]: MPRR204 Awaiting FERC filing Comment [MPRR204.874]: MPRR204 Awaiting FERC filing Comment [MPRR204.875]: MPRR204 Awaiting FERC filing Comment [MPRR204.876]: MPRR204 Awaiting FERC filing Comment [MPRR204.877]: MPRR204 Awaiting FERC filing Comment [MPRR102.878]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.879]: MPRR204 Awaiting FERC filing Comment [MPRR102.880]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.881]: MPRR204 Awaiting FERC filing Comment [MPRR204.882]: MPRR204 Awaiting FERC filing Comment [MPRR204.883]: MPRR204 Awaiting FERC filing Comment [MPRR102.884]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.885]: MPRR204 Awaiting FERC filing Comment [MPRR102.886]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.887]: MPRR204 Awaiting FERC filing Comment [MPRR204.888]: MPRR204 Awaiting FERC filing
Version 23.a
12/4/2014
446
Market Protocols for SPP Integrated Marketplace
Variable
RtRegUpUnusedMile5minAmt a, s, i
Unit
Settlement Interval
Definition
$
Dispatch Interval
Real-Time Unused Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.4. Real-Time Excess Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4. Real-Time Unused Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.5. Real-Time Excess Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5. Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.24. Real-Time Unused Regulation-Dn Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.25. Real-Time Spin Offer Cost Amount per AO per Settlement Location per Dispatch Interval in RUC Make-WholePayment 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.
RtRegUpExcessMile5minAmt a, s, i
$
Dispatch Interval
RtRegDnUnusedMile5minAmt a, s, i
$
Dispatch Interval
RtRegDnExcessMile5minAmt a, s, i
$
Dispatch Interval
RtRegUpUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
RtRegDnUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
RtSpinAvail5minAmt a, s, i, c
Version 23.a
$
Dispatch Interval
12/4/2014
447
Comment [MPRR102.889]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.890]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.891]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.892]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.893]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.894]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.895]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.896]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.897]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.898]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtSuppAvail5minAmt a, s, i, c
RtLmp5minPrc s, i RtBillMtr5minQty a, s, i
RtRegUpMcp5minPrc z, i RtRegDnMcp5minPrc z, i RtSpinMcp5minPrc z, i RtSuppMcp5minPrc z, i RtCcRegUpAdjHrlyAmt a, s, h, c
Version 23.a
Unit
Settlement Interval
Definition
$
Dispatch Interval
Real-Time Supplemental Offer Cost Amount per AO per Settlement Location per Dispatch Interval in RUC MakeWhole-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. Real-Time LMP - The value defined under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.
$/MWh
Dispatch Interval
MW
Dispatch Interval
$/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. Real-Time MCP for Regulation-Up per Reserve Zone The value defined under Section 4.5.9.4.
Dispatch Interval
Real-Time MCP for Regulation-Down per Reserve Zone The value defined under Section 4.5.9.5.
Dispatch Interval
Real-Time MCP for Spinning Reserve per Reserve Zone The value defined under Section 4.5.9.6.
Dispatch Interval
Real-Time MCP for Supplemental Reserve per Reserve Zone - The value defined under Section 4.5.9.7.
$/MW $/MW $/MW $
Hour
12/4/2014
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.
448
Comment [MPRR101.899]: MPRR101 awaiting FERC filing Comment [MPRR101.900]: MPRR101 awaiting FERC filing Comment [MPRR101.901]: MPRR101 awaiting FERC filing Comment [MPRR101.902]: MPRR101 awaiting FERC filing
Comment [MPRR101.903]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
RtCcRegDnAdjHrlyAmt a, s, h, c
RtCcSpinAdjHrlyAmt a, s, h, c
Unit
Settlement Interval
Definition
$
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. 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. 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. 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.
$
Hour
RtCcSuppAdjHrlyAmt a, s, h, c
$
Hour
RtCcRegUpAdj5minAmt a, s, i, c
$
Dispatch Interval
Version 23.a
12/4/2014
449
Comment [MPRR101.904]: MPRR101 awaiting FERC filing
Comment [MPRR101.905]: MPRR101 awaiting FERC filing
Comment [MPRR101.906]: MPRR101 awaiting FERC filing
Comment [MPRR101.907]: MPRR101 awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
RTCcRegDnAdj5minAmt a, s, i, c
RtCcSpinAdj5minAmt a, s, i, c
RTCcSuppAdj5minAmt a, s, i, c
RtRegUpRev5minAmt a, s, i, c
RtRegDnRev5minAmt a, s, i, c
Version 23.a
Unit
Settlement Interval
Definition
$
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. 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. 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. Real-Time Regulation-Up Service Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Real-Time incremental Regulation-Up Service revenue associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c. Real-Time Regulation-Down Service Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC
$
$
$
$
Dispatch Interval
Dispatch Interval
Dispatch Interval
Dispatch Interval
12/4/2014
450
Comment [MPRR101.908]: MPRR101 awaiting FERC filing
Comment [MPRR101.909]: MPRR101 awaiting FERC filing Comment [MPRR101.910]: MPRR101 awaiting FERC filing Comment [MPRR204.911]: MPRR204 Awaiting FERC filing Comment [MPRR102.912]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.913]: MPRR204 Awaiting FERC filing Comment [MPRR102.914]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.915]: MPRR204 Awaiting FERC filing Comment [MPRR204.916]: MPRR204 Awaiting FERC filing Comment [MPRR204.917]: MPRR204 Awaiting FERC filing Comment [MPRR102.918]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
RtSpinRev5minAmt a, s, i, c
$
Dispatch Interval
RtSuppRev5minAmt a, s, i, c
$
Dispatch Interval
RtMwpDlyAmt a, s, d
$
Operating Day
RtMwpAoAmt a, m,
$
Operating Day
$
Operating Day
RtMwpMpAmt m, d
Version 23.a
d
12/4/2014
Definition Make-Whole-Payment Eligibility Period – The Real-Time incremental Regulation-Down Service revenue associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c. Real-Time Spinning Reserve Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC MakeWhole-Payment Eligibility Period – The Real-Time incremental Spinning Reserve associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c. Real-Time Supplemental Reserve Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Real-Time incremental Supplemental Reserve revenue associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c. RUC Make-Whole-Payment Amount per AO per Settlement Location per Operating Day - The RUC Makewhole amount to AO a for Operating Day d at Resource Settlement Location s. RUC Make-Whole-Payment Amount per AO per Operating Day - The RUC Make-whole amount to AO a associated with Market Participant m for Operating Day d. RUC Make-Whole-Payment Amount per MP per Operating Day - The RUC Make-whole amount to Market Participant m for Operating Day d.
451
Comment [MPRR204.919]: MPRR204 Awaiting FERC filing Comment [MPRR102.920]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.921]: MPRR204 Awaiting FERC filing Comment [MPRR204.922]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
EqrRtMwp5minPrc a, s, c
$
Eligibility Period
EqrRtMwp5minQty a, s, c
MWh
Eligibility Period
RtRegUp5minQty a, z, s, i
MW
Dispatch Interval
RUC Electric Quarterly Reporting Make-Whole-Payment Amount per AO per Settlement Location per RUC MakeWhole-Payment Eligibility Period - The RUC make-whole amount to AO a for RUC Make-Whole-Payment Eligibility Period c at Resource Settlement Location s for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.. RUC Electric Quarterly Reporting Make-Whole-Payment Quantity per AO per Settlement Location per RUC MakeWhole-Payment Eligibility Period – This value is set equal to 1 if EqrRtMwp5minPrc a, s, c > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.. Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4 Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.4 Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.5 Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5 Real-Time Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.6
DaRegUpHrlyAmt a, s, h
$
Hour
DaRegDnHrlyAmt a, s, h
$
Hour
RtRegDn5minQty a, z, s, i
MW
Dispatch Interval
RtSpin5minQty a, z, s, i
MW
Dispatch Interval
Version 23.a
12/4/2014
452
Comment [MPRR204.923]: MPRR204 Awaiting FERC filing
Comment [MPRR204.924]: MPRR204 Awaiting FERC filing
Comment [MPRR204.925]: MPRR204 Awaiting FERC filing
Comment [MPRR204.926]: MPRR204 Awaiting FERC filing
Comment [MPRR204.927]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
DaSpinHrlyQty a, z, s, h
RtSupp5minQty a, z, s, i
DaSuppHrlyQty a, z, s, h
a i h d s c m
Version 23.a
Unit
Settlement Interval
MW
Hour
MW
Dispatch Interval
MW
Hour
none none none
none none none
none none none
none none none
12/4/2014
Definition
Day-Ahead Spinning Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.6 Real-Time Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.7 Day-Ahead Supplemental Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.7 An Asset Owner. A Dispatch Interval. An Hour. An Operating Day. A Settlement Location. A RUC Make-Whole-Payment Eligibility Period. A Market Participant.
453
Comment [MPRR204.928]: MPRR204 Awaiting FERC filing
Comment [MPRR204.929]: MPRR204 Awaiting FERC filing
Comment [MPRR204.930]: MPRR204 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
4.5.9.9
Real-Time Out-Of-Merit Amount
(1) An RTBM credit or charge25 will be made to each Market Participant with a Resource that passes a primary Contingency Reserve deployment test as described under Section 6.1.11.1(3)(b)(i) and/or otherwise receives a Manual Dispatch Instruction from SPP or a local transmission operator that creates a cost to the Asset Owner or that adversely impacts the Asset Owner’s DA Market position and/or if a Market Participant must buy back its DA Market position for any Operating Reserve product at a RTBM MCP that is greater than that product’s DA Market MCP. Resources issued Manual Dispatch Instructions by or at the request of a local transmission operator in order to solve a Local Emergency Condition or a Local Reliability Issue are eligible for out-of-merit credits as defined in this Section unless selection of the Resource by the local transmission operator was performed in a discriminatory manner as determined by the MMU and the Resource was an affiliated Resource; however, a manual process is employed for the calculation of the out-of-merit credits and they will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The cost allocation of out-of-merit credits associated with Manual Dispatch Instructions issued by or at the request of a local transmission operator will be determined hourly by multiplying an Asset Owner’s RTBM actual load in the impacted Settlement Area by a rate determined by dividing the daily sum of all out-of-merit credits applicable to the impacted Settlement Area by the daily sum of all Asset Owners’ RTBM actual load in the impacted Settlement Area. A manual process is also employed for these calculations and the charges will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. Outof-merit credits associated with Manual Dispatch Instructions issued directly by SPP to address a reliability issue other than a Local Reliability Issue will be recovered under Section 4.5.12. The amount will be calculated on a Dispatch Interval basis under the following conditions: (a)
If the Manual Dispatch Instruction is for Energy in the up direction and the Energy Offer Curve cost associated with the Out-Of-Merit-Energy (OOME) MW is greater than the RTBM LMP, the Asset Owner will receive a credit equal to the difference multiplied by the OOME MW. The OOME MW is calculated as Max (0, or the difference between (i) (lesser of the the absolute value of the actual
25
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
Version 23.a
12/4/2014
454
Market Protocols for SPP Integrated Marketplace
Resource output or the Resource’s Manual Dispatch Instruction MW) and (ii) the Resource’s Desired Dispatch); (b)
If the Manual Dispatch Instruction is for Energy in the down direction, including a Resource de-commitment and the RTBM LMP is greater than the DA Market LMP, the Asset Owner will receive a credit for the difference multiplied by the OOME MW. The OOME MW is calculated as Max (0, or the difference between (i) the absolute value of the Resource’s DA Market cleared Energy MW and (ii) the (greater of the absolute value of the actual Resource output or the Resource’s Manual Dispatch Instruction MW)); and/or
(c)
If the Manual Dispatch Instruction or a Resource de-commitment instruction, causes the RTBM cleared amount of an Operating Reserve product to be less than the DA Market cleared amount of the corresponding Operating Reserve product and the RTBM MCP is greater than the DA Market MCP, the Asset Owner will receive a credit for the difference multiplied by the Out-Of-Merit-Operating Reserve (OOMOR) MW. The OOMOR MW is calculated as Max (0, or the difference between the Resource’s DA Market cleared Operating Reserve MW and the Resource’s RTBM cleared Operating Reserve MW).
To the extent that additional costs are incurred as a direct result of a Manual Dispatch Instruction through the compensation mechanisms described above, Market Participants may request additional compensation through submittal of actual cost documentation to SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery. The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each Dispatch Interval is calculated as follows: IF RtOom5minFlg a, s, i = 1 OR ResDeCommit5minFlg a, s, i = 1 OR RtReprice5minFlg a, s, i = 1
Comment [MPRR206.931]: MPRR206 Awaiting implementation
THEN #RtOom5minAmt a, s, i = ( RtOomeIncr5minAmt a, s, i + RtOomeDecr5minAmt a, s, i
+ RtOomor5minAmt a, s, i ) * (-1)
Version 23.a
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455
Market Protocols for SPP Integrated Marketplace
ELSE #RtOom5minAmt a, s, i = 0 Where, (a)
RtOomeIncr5minAmt a, s, i = Max ( 0, Max ( 0, RtOomeIncrEn5minAmt a, s, i – RtOomeDesiredEn5minAmt a, s, i ) Max (0, Min (Min (0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i ) - RtOomeDesiredEn5minQty a, s, i ) * Max( 0, RtLmp5minPrc s, i ) ) / 12
(a.1)
#RtOomeIncrEn5minAmt a, s, i =
y
RTBM As Dispatched Energy Offer Curve x
Where: X = 0 Y = Min ( Min ( 0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i ) (a.2) #RtOomeDesiredEn5minAmt a, s, i = y
RTBM As Dispatched Energy Offer Curve x
Where: X = 0 Y = RtOomeDesiredEn5minQtya, s, i (b)
Version 23.a
RtOomeDecr5minAmt a, s, i =
12/4/2014
456
Market Protocols for SPP Integrated Marketplace
Max (0, (-1) * Max (Min ( 0, RtBillMtr5minQty RtAvgSetpoint5minQty a, s, i ) - DaClrdHrlyQty a, s, h )
a, s, i
) * (-1),
* Max ( 0, RtLmp5minPrc s, i - DaLmpHrlyPrc s, h ) / 12 (c)
RtOomor5minAmt a, s, i =
[ ( Max (0,
z
DaRegUpHrlyQty a, z, s, h - RtRegUp5minQty a, z, s, i ) z
* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h ) ) + ( Max (0,
DaRegDnHrlyQty a, z, s, h - RtRegDn5minQty a, z, s, i ) z
* Max ( 0, RtRegDnMcp5minPrc z, i - DaRegDnMcpHrlyPrc z, h ) ) + ( Max (0,
DaSpinHrlyQty a, z, s, h - RtSpin5minQty a, z, s, i ) z
* Max ( 0, RtSpinMcp5minPrc z, i - DaSpinMcpHrlyPrc z, h ) ) + ( Max (0,
DaSuppHrlyQty a, z, s, h - RtSupp5minQty a, z, s, i ) z
* Max ( 0, RtSuppMcp5minPrc z, i - DaSuppMcpHrlyPrc z, h ) ) ] / 12 (2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The hourly amount is calculated as follows: RtOomHrlyAmt a, s, h =
RtOom5minAmt a, s, i
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily credit amount is calculated as follows:
Version 23.a
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Market Protocols for SPP Integrated Marketplace
RtOomDlyAmt a, s, d =
RtOomHrlyAmt a, s, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtOomAoAmt a, m, d =
RtOomDlyAmt a, s, d
s
(5) 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: RtOomMpAmt m, d =
RtOomAoAmt a, m, d
a
(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Outof-Merit Energy and Operating Reserve $ per Dispatch Interval for each Asset Owner as follows: (a)
#EqrRtOom5minPrc a, s, i = (-1) * RtOom5minAmt a, s, i
(b)
IF #EqrRtOom5minPrc a, s, i > 0 THEN #EqrRtOom5minQty a, s, i = 1
Version 23.a
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458
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement Interval
RtOom5minAmt a, s, i
$
Dispatch Interval
RtOomeIncr5minAmt a, s, i
$
Dispatch Interval
RtOomeDecr5minAmt a, s, i
$
Dispatch Interval
ResDeCommit5minFlg a, s, i
None
Dispatch Interval
RtOom5minFlg a, s, i
None
Dispatch Interval
RtReprice5minFlg a, s, i
Version 23.a
None
Dispatch Interval
Definition
Real-Time Out-Of-Merit Make-Whole-Payment Amount per AO per Settlement Location per Dispatch Interval - The amount to AO a for eligible Resource Settlement Location s in Dispatch Interval i for OutOf-Merit Energy and Operating Reserve resulting from an SPP Manual Dispatch Instruction. Real-Time Out-Of-Merit Incremental Energy Make-Whole-Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i amount for eligible Resource Settlement Location s in Dispatch Interval i for Out-Of-Merit Energy resulting from an SPP manual Dispatch Instruction in the up direction. Real-Time Out-Of-Merit Decremental Energy Make-Whole-Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i amount for eligible Resource Settlement Location s in Dispatch Interval i for Out-Of-Merit Energy resulting from an SPP manual Dispatch Instruction in the down direction. Resource De-Commitment Flag per AO per Dispatch Interval per Settlement Location – The value as described under Section 4.5.9.10. Real-Time Out-of-Merit Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 when SPP issues a Manual Dispatch Instruction or whenever there is a price correction event as described under Section 7, otherwise, this flag is set equal to zero. Real-Time Repricing Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever there is a price correction event as described under Section 7, otherwise, this flag is set equal to zero.
12/4/2014
459
Comment [MPRR206.932]: MPRR206 Awaiting implementation
Comment [MPRR206.933]: MPRR206 Awaiting implementation
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
MW
Dispatch Interval
RtOomeIncrEn5minAmt a, s, i
$
Dispatch Interval
RtOomeDesiredEn5minAmt a, s, i
$
Dispatch Interval
Real-Time Out-Of-Merit Operating Reserve Make-Whole-Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i attributable to buying back a DA Market Operating Reserve position in the RTBM at a RTBM MCP that is greater than the corresponding DA Market MCP. This should not be a normal occurrence but could happen as a result of price corrections as described under Section 7. Real-Time OOME 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-Dispatched Minimum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the Manual Dispatch Instruction as an output floor and the As-Dispatched Maximum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the Manual Dispatch Instruction as an output ceiling. Real-Time OOME 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 as calculated from the Resource’s As Dispatched Energy Offer Curve from 0 MW to the lesser of the Manual Dispatch Instruction MW or RtBillMtr5minQty a, s, i. Real-Time OOME Energy Cost at Desired Dispatch Quantity 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 as calculated from the Resource’s As Dispatched Energy Offer Curve from 0 MW to RtOomeDesiredEn5minQty a, s, i.
RtOomor5minAmt a, s, i
RtOomeDesiredEn5minQty a, s, i
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Variable
Unit
Settlement Interval
Definition
RtAvgSetPoint5minQty a, s, i
MW
Dispatch Interval
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
RtLmp5minPrc s, i
$/MW
DaClrdHrlyQty a, s, h
MWh
Dispatch Interval Hour
DaRegUpHrlyQty a, z, s, h
MW
Hour
DaRegDnHrlyQty a, z, s, h
MW
Hour
DaSpinHrlyQty a, z, s, h
MW
Hour
DaSuppHrlyQty a, z, s, h
MW
Hour
RtRegUp5minQty a, z, s, i
MW
Dispatch Interval
RtRegDn5minQty a, z, s, i
MW
Dispatch Interval
Real-Time Average Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8 except that when RtOom5minFlg a, s, i is set to 1, RtAvgSetPoint5minQty a, s, i is set equal to the Manual Dispatch Instruction MW. 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. Real-Time LMP - The value defined under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1. Day-Ahead Regulation-Up Service Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.4. Day-Ahead Regulation-Down Service Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.5. Day-Ahead Spinning Reserve Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.6. Day-Ahead Supplemental Reserve Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.7. Real-Time Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.4. Real-Time Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.5.
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Comment [MPRR102.935]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.936]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.937]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtSpin5minQty a, z, s, i
MW
Dispatch Interval
RtSupp5minQty a, z, s, i
MW
Dispatch Interval
DaRegUpMcpHrlyPrc z, h
$/MW
Hour
DaRegDnMcpHrlyPrc z, h
$/MW
Hour
DaSpinMcpHrlyPrc z, h
$/MW
Hour
DaSuppMcpHrlyPrc z, h
$/MW
Hour
RtRegUpMcp5minPrc z, i
$/MW
Dispatch Interval
RtRegDnMcp5minPrc z, i
$/MW
Dispatch Interval
RtSpinMcp5minPrc z, i
$/MW
Dispatch Interval
Real-Time Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.6. Real-Time Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.7. Day-Ahead Regulation-Up Service Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.4. Day-Ahead Regulation-Down Service Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.5. Day-Ahead Spinning Reserve Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.6. Day-Ahead Supplemental Reserve Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.7. Real-Time Regulation-Up Service Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.4. Real-Time Regulation-Down Service Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.5. Real-Time Spinning Reserve Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.6.
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Comment [MPRR102.939]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.940]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.941]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
$/MW
Dispatch Interval
RtOomHrlyAmt a, s, h
$
Hour
RtOomDlyAmt a, s, d
$
Operating Day
RtOomAoAmt a, m,
$
Operating Day
RtOomMpAmt m, d
$
Operating Day
EqrRtOom5minPrc a, s, i
$
Dispatch Interval
Real-Time Supplemental Reserve Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.7. Real-Time Out-Of-Merit Make-Whole-Payment Amount per AO per Settlement Location per Hour - The amount to AO a for eligible Resource Settlement Location s in Hour h for Out-Of-Merit Energy and Operating Reserve resulting from an SPP Manual Dispatch Instruction. Real-Time Out-Of-Merit Make-Whole-Payment Amount per AO per Settlement Location per Operating Day - The amount to AO a for eligible Resource Settlement Location s in Operating Day d for Out-OfMerit Energy and Operating Reserve resulting from an SPP Manual Dispatch Instruction. Real-Time Out-Of-Merit Make-Whole-Payment Amount per AO per Operating Day - The amount to AO a associated with Market Participant m in Operating Day d for Out-Of-Merit Energy and Operating Reserve resulting from an SPP Manual Dispatch Instruction. Real-Time Out-Of-Merit Make-Whole-Payment Amount per MP per Operating Day - The amount to MP m in Operating Day d for Out-OfMerit Energy and Operating Reserve resulting from an SPP Manual Dispatch Instruction. Real-Time Electric Quarterly Reporting Out-of-Merit Make-WholePayment Amount per AO per Settlement Location per Dispatch Interval The Out-of-Merit make-whole amount to AO a for Dispatch Interval i at Resource Settlement Location s for use by AO a in reporting such makewhole-payments to FERC in accordance with FERC EQR requirements.
RtSuppMcp5minPrc z, i
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Variable
Unit
Settlement Interval
Definition
EqrRtOom5minQty a, s, i
MWh
Dispatch Interval
a s i h d m
none none none none none none
none none none none none none
Real-Time Electric Quarterly Reporting Out-of-Merit Make-WholePayment Quantity per AO per Settlement Location per Dispatch Interval – This value is set equal to 1 if EqrRtOom5minPrc a, s, i > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.. An Asset Owner. A Settlement Location. A Dispatch Interval. An Hour. An Operating Day. A Market Participant.
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4.5.9.10
RUC Make-Whole-Payment Distribution Amount
(1) An RTBM system-wide charge or credit26 will be calculated at each Settlement Location for each Asset Owner for each hour in order to fund the payments made under Section 4.5.9.8 to Resources committed by SPP to resolve a regional reliability issue. This system-wide amount will be determined by multiplying the system-wide Asset Owner deviations by a daily system-wide RTBM MWP rate. Additionally, a local charge will be calculated for Asset Owners within each Settlement Area in order to fund the payments made under Section 4.5.9.8 to Resources committed by SPP at the request of a local transmission operator to solve a Local Reliability Issue or committed by a local transmission operator to address a Local Emergency Condition. The local hourly amount will be determined by multiplying an Asset Owner’s RTBM actual load in the Settlement Area by a rate determined by dividing (i) the daily sum of all RUC make-whole-payments made under Section 4.5.9.8 to Resources committed to address a Local Reliability Issue or Local Emergency Condition in the impacted Settlement Area by (ii) the daily sum of all Asset Owners’ RTBM actual load in the impacted Settlement Area. A manual process is employed for the calculations and the charges will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The system-wide hourly amount is calculated as follows: #RtMwpDistHrlyAmt a, s, h = RtMwpSppDistRate d * RtDevHrlyQty a, s, h Where, (a)
RtDevHrlyQty a, s, h = RtNetSlDevHrlyQty a, s, h + RtMinLimitDevHrlyQty a, s, h + RtMaxLimitDevHrlyQty a, s, h+ RtOutageDevHrlyQty a, s, h + RtStatusDevHrlyQty a, s, h + RtRucScDevHrlyQty a, s, h + RtRucCommitDevHrlyQty a, s, h + RtURDDevHrlyQty a, s, h
(a.1) An Asset Owner’s Settlement Location deviation is calculated as the Absolute Value of the sum of (1) (RTBM actual load MWh - DA Market cleared load MWh) – 26
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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excluding deviations resulting from actual load consumption that is less than DA Market cleared load MWh during capacity shortage condition Emergencies, (2) (RTBM actual Export Interchange Transactions – DA Market cleared Export Interchange Transactions), (3) (RTBM actual Import Interchange Transactions – DA Market cleared Import Interchange Transactions), (4) (RTBM actual Through Interchange Transactions (sink only) – DA Market cleared Through Interchange Transactions (sink only)), and (5) DA Market cleared Virtual Energy Offers * (-1). An Asset Owner’s Settlement Location deviation is calculated as follows.
RtNetSlDevHrlyQty a, s, h = ABS
RtNetSlDev5minQty a, s, i
i
#RtNetSlDev5minQty a, s, i = { [ IF XmptDev5minFlg a, s, i = 0 THEN 1 ELSE 0 ] * [Max ( 0, RtBillMtr5minQty a, s, i ) – Max ( 0, DaClrdHrlyQty a, s, h ) ] +
{ [Max ( 0, RtImpExp5minQty a, s, i, t, dir )
t
- Max ( 0, DaImpExp5minQty a, s, i, t, dir ) + [ IF DIR <> “THROUGH”, THEN Min ( 0, RtImpExp5minQty a, s, i, t, dir ) - Min ( 0, DaImpExp5minQty a, s, i, t, dir ), ELSE 0 ] ] * (1 – RsgCrdFlgt ) } -
Min (0, DaClrdVHrlyQty a, s, h, t ) } / 12
t
(a.2) For a Resource with DA Market cleared MW in an hour the difference between the Resource’s applicable minimum limit and its DA Market cleared MW is included as a deviation if the Resource’s Minimum Economic Capacity Operating Limit (or Minimum Regulation Capacity Operating Limit if cleared for Regulation-Up Service or
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Regulation-Down Service) in the RTBM is (1) greater than the comparable limits used to clear the Resource in the DA Market by more than the Resource Operating Tolerance except that, combined cycle Resources that were committed by SPP into a higher configuration in the RUC are excluded from this calculation; (2) is greater than its DA Market cleared MW; and (3) the Resource’s Dispatch Instruction in any Dispatch Interval within the Hour is less than or equal to the Resource’s applicable minimum limit, where the applicable minimum limit is equal to the Resource’s RTBM Minimum Economic Capacity Operating Limit if the Resource is not regulating or is equal to the sum of the Resource’s RTBM Minimum Regulation Capacity Operating Limit and the amount of Regulation-Down Service cleared on that Resource if the Resource is regulating. In the case where the Resource has cleared Regulation-Up Service or Regulation Down Service in the RTBM and has not cleared Regulation-Up Service or Regulation Down Service in the DA Market, the deviation is the lesser of the (1) the difference between the Resource’s RTBM regulation minimum limit and its DA Market cleared MW or (2) the difference between the Resource’s RTBM regulation minimum limit the its DA Market regulation minimum limit. RtMinLimitDevHrlyQty a, s, h =
RtMinLimitDev5minQty a, s, i
i
Where, IF DispInstrucMinHrlyFlg a, s, h= “1” AND DaClrdHrlyQty a, s, h < 0 AND RtRucComStat5minFlg a, s, i, c < > “1” AND RtRucComStat5minFlg a, s, i, c < > “0” THEN ** Regulation is not cleared in RTBM ** IF ControlStatus5minFlg a, s, i <> “Regulating” AND ( RtDispMinEconCapOL5minQty a, s, i - DaComMinEconCapOLHrlyQty a, s, h) > ResOpTol5minQty a, s, i
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Comment [MPRR101.944]: MPRR101 awaiting FERC filing
Comment [MPRR102.945]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.946]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.947]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.948]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.949]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
THEN #RtMinLimitDev5minQty a, s, i = Max [ ( RtDispMinEconCapOL5minQty a, s, i + DaClrdHrlyQty a, s, h ), 0 ] / 12 ELSE IF ** Regulation is cleared in both DA Market and RTBM ** IF ControlStatus5minFlg a, s, i = “Regulating” AND DaRegUpHrlyQty a, z, s, h + DaRegDnHrlyQty a, z, s, h > 0 AND ( RtDispMinRegCapOL5minQty a, s, i - DaComMinRegCapOLHrlyQty a, s, h) > ResOpTol5minQty a, s, i THEN #RtMinLimitDev5minQty a, s, i = Max [ ( RtDispMinRegCapOL5minQty a, s, i + DaClrdHrlyQty a, s, h ), 0 ] / 12 ELSE IF ** Regulation is cleared in RTBM and not cleared in DA Market ** IF ControlStatus5minFlg a, s, i = “Regulating” AND DaRegUpHrlyQty a, z, s, h + DaRegDnHrlyQty a, z, s, h = 0 AND ( RtDispMinRegCapOL5minQty a, s, i - DaComMinRegCapOLHrlyQty a, s, h) > ResOpTol5minQty a, s, i THEN #RtMinLimitDev5minQty a, s, i = Max { RtDispMinRegCapOL5minQty a, s, i
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– Max [ ABS ( DaClrdHrlyQty a, s, h ) , DaComMinRegCapOLHrlyQty a, s, h ] , 0 } / 12 ELSE RtMinLimitDev5minQty a, s, i = 0 (a.3) For a Resource with DA Market cleared MW in an hour, the difference between the Resource’s DA Market cleared MW and its applicable maximum limit is included as a deviation if the Resource’s Maximum Economic Capacity Operating Limit (or Maximum Regulation Capacity Operating Limit if cleared for Regulation-Up Service or Regulation-Down Service) in the RTBM is (1) less than the comparable limits used to clear the Resource in the DA Market by more than the Resource Operating Tolerance; (2) is less than its DA Market cleared MW; and (3) the Resource’s Dispatch Instruction in any Dispatch Interval within the Hour is greater than or equal to the Resource’s applicable maximum limit, where the applicable maximum limit is equal to the Resource’s RTBM Maximum Economic Capacity Operating Limit if the Resource is not regulating or is equal to the difference between the Resource’s RTBM Maximum Regulation Capacity Operating Limit and the amount of Regulation-Up Service cleared on that Resource if the Resource is regulating. In the case where the Resource has cleared Regulation-Up Service or Regulation Down Service in the RTBM and has not cleared Regulation-Up Service or Regulation Down Service in the DA Market, the deviation is the lesser of the (1) the difference between the Resource’s DA Market cleared MW and its RTBM regulation maximum limit or (2) the difference between the Resource’s DA Market regulation maximum limit and its RTBM regulation maximum limit. RtMaxLimitDevHrlyQty a, s, h =
RtMaxLimitDev5minQty a, s, i
i
Where, IF DispInstrucMaxHrlyFlg a, s, h= “1” AND DaClrdHrlyQty a, s, h < 0 THEN ** Regulation is not cleared in RTBM ** IF ControlStatus5minFlg a, s, i <> “Regulating” AND
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Comment [MPRR102.952]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.953]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.954]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.955]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.956]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
( DaComMaxEconCapOLHrlyQty a, s, h - RtDispMaxEconCapOL5minQty a, s, i) > ResOpTol5minQty a, s, i THEN #RtMaxLimitDev5minQty a, s, i = Max [ (ABS ( DaClrdHrlyQty a, s, h ) - RtDispMaxEconCapOL5minQty a, s, i), 0 ] / 12 ELSE IF ** Regulation is cleared in both DA Market and RTBM ** IF ControlStatus5minFlg a, s, i = “Regulating” AND DaRegUpHrlyQty a, z, s, h + DaRegDnHrlyQty a, z, s, h > 0 AND ( DaComMaxRegCapOLHrlyQty a, s, h - RtDispMaxRegCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i THEN #RtMaxLimitDev5minQty a, s, i = Max [ (ABS ( DaClrdHrlyQty a, s, h ) - RtDispMaxRegCapOL5minQty a, s, i), 0 ] / 12 ELSE IF ** Regulation is cleared in RTBM and not cleared in DA Market ** IF ControlStatus5minFlg a, s, i = “Regulating” AND DaRegUpHrlyQty a, z, s, h + DaRegDnHrlyQty a, z, s, h = 0 AND ( DaComMaxRegCapOLHrlyQty a, s, h - RtDispMaxRegCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i THEN
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#RtMaxLimitDev5minQty a, s, i = Max { Min [ ABS ( DaClrdHrlyQty a, s, h ) , DaComMaxRegCapOLHrlyQty a, s, h ] - RtDispMaxRegCapOL5minQty a, s, i , 0 } / 12 ELSE RtMaxLimitDev5minQty a, s, i = 0 (a.4) For Resources with DA Market cleared MW in an hour, if the Resource is off-line in the RTBM and it has not been de-committed by SPP the Resource DA Market cleared MW is included as a deviation. An Asset Owner’s outage deviation is calculated as follows. RtOutageDevHrlyQty a, s, h =
RtOutageDev5minQty a, s, i
i
IF DaClrdHrlyQty a, s, h < 0 AND RtBillMtr5minQty a, s, i >= 0 AND ResDeCommit5minFlg a, s, i, c < > “1” THEN #RtOutageDev5minQty a, s, i = ABS ( DaClrdHrlyQty a, s, h ) / 12 ELSE RtOutageDev5minQty a, s, i = 0 (a.5) For Resources with DA Market cleared MW in an hour, for each Dispatch Interval the Resource is in “Manual” status, a deviation is calculated that is equal to one-twelfth of the difference between the Resource actual output and the Resource’s Desired Dispatch. An Asset Owner’s status change deviation is calculated as follows. RtStatusDevHrlyQty a, s, h =
RtStatusDev5minQty a, s, i
i
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IF ControlStatus5minFlg a, s, i = “Manual” AND DaClrdHrlyQty a, s, h < 0 THEN #RtStatusDev5minQty a, s, i = ABS ( RtBillMtr5minQty a, s, i + RtDispDesiredEn5minQty a, s, i ) / 12 ELSE RtStatusDev5minQty a, s, i = 0 (a.6) For Resources that Self-Committed following the Day-Ahead Market, including a combined cycle Resource that was committed in the DA Market and then SelfCommitted into a higher configuration in RUC and the Resource’s Dispatch Instruction in any Dispatch Interval within the Hour is less than or equal to the Resource’s applicable minimum limit, a deviation is included in an amount equal to the Resource actual output. The applicable minimum limit is equal to the Resource’s RTBM Minimum Economic Capacity Operating Limit if the Resource is not regulating or is equal to the sum of the Resource’s RTBM Minimum Regulation Capacity Operating Limit and the amount of Regulation-Down Service cleared on that Resource if the Resource is regulating. Resources that were offered into the DA Market for SPP commitment and not committed in the DA Market and then Self-Committed prior to the Day-Ahead RUC are exempted from this calculation. An Asset Owner’s Self-Commit deviation is calculated as follows. RtRucScDevHrlyQty a, s, h =
RtRucScDev5minQty a, s, i
i
IF RtRucComStat5minFlg a, s, i, c = “0” AND DispInstrucMinHrlyFlg a, s, h = “1” AND RtRucScDevXmpt5minFlg a, s, i <> “1” THEN
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#RtRucScDev5minQty a, s, i = ABS ( Min (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h , 0 ) / 12 ) ELSE RtRucScDev5minQty a, s, i = 0 (a.7) For Resources that are either Self-Committed or committed by SPP following the DA Market and that are off-line in the RTBM and have not been de-committed by SPP, the greater of the Minimum Economic Capacity Operating Limit at the time of commitment or the Resource’s Desired Dispatch will be included as a deviation. An Asset Owner’s RTBM commitment outage deviation is calculated as follows. RtRucCommitDevHrlyQty a, s, h =
RtRucCommitDev5minQty a, s, i
i
IF [ RtRucComStat5minFlg a, s, i, c = “0” OR RtRucComStat5minFlg a, s, i, c = “1” ] AND
RtBillMtr5minQty a, s, i >= 0 AND
i
ResDeCommit5minFlg a, s, i, c < > 1 THEN #RtRucCommitDev5minQty a, s, i = RtDesiredEn5minQty a, s, i / 12 ELSE RtRucCommitDev5minQty a, s, i = 0 (a.8) In any Dispatch Interval in which a Resource operates outside of its Operating Tolerance and the Resource has not been exempted from URD per Section 4.4.4.1, onetwelfth of the Absolute Value of the Resource’s Uninstructed Resource Deviation is included as a deviation. An Asset Owner’s URD deviation is calculated as follows.
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RtURDDevHrlyQty a, s, h =
RtURDDev5minQty a, s, i
i
IF ABS (URD5minQty a, s, i ) > ResOpTol5minQty a, s, i AND ( XmptDev5minFlg a, s, i = 0 ) THEN #RtURDDev5minQty a, s, i = ABS ( URD5minQty a, s, i ) / 12 ELSE RtURDDev5minQty a, s, i = 0 (b)
#RtMwpSppDistRate d = ( RtMwpSppDlyAmt d / RtDevSppDlyQty d ) * (-1)
(b.1)
RtMwpSppDlyAmt d =
RtMwpMpAmt m, d
m
(b.2)
RtDevSppDlyQty d =
a
s
RtDevHrlyQty a, s, h
h
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtMwpDistDlyAmt a, s, d =
RtMwpDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtMwpDistAoAmt a, m, d =
RtMwpDistDlyAmt a, s, d
s
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(4) 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: RtMwpDistMpAmt m, d =
RtMwpDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
MWh
Hour
$/MWh
Operating Day
RtMwpMpAmt m, d
$
Operating Day
RtMwpSppDlyAmt d
$
Operating Day
RtDevSppDlyQty d
MWh
Operating Day
RUC Make-Whole-Payment Distribution Amount per AO per Hour per Settlement Location - The amount to AO a for Hour h and Settlement Location s for recovery of the total amount paid under Section 4.5.9.8 for Operating Day d. Real-Time Deviation Quantity per AO per Hour per Settlement Location – The total deviation MWh for AO a at Settlement Location s for Hour h. RUC Make-Whole Payment SPP Distribution Rate per Operating Day – The rate applied to AO a’s RtDevHrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d. RUC Make-Whole-Payment Amount per MP per Operating Day - The value calculated under Section 4.5.9.8 for Operating Day d. RUC Make-Whole-Payment Amount per Operating Day The SPP total of the values calculated under Section 4.5.9.8 for Operating Day d. Real-Time Deviation Quantity per Operating Day - The SPP total deviation MWh for all AOs for Operating Day d.
RtNetSlDev5minQty a, s, i
MWh
Dispatch Interval
RtMwpDistHrlyAmt a, s, h
RtDevHrlyQty a, s, h
RtMwpSppDistRate d
Version 23.a
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Real-Time Net Settlement Location Deviation per AO per Dispatch Interval per Settlement Location – AO a’s portion of RtDevHrlyQty a, s, h related to net of Real-Time load deviations from Day-Ahead amount, Real-Time Interchange Transaction deviations from Day-Ahead amounts and virtual transactions at Settlement Location s in Dispatch Interval i.
476
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtNetSlDevHrlyQty a, s, h
MWh
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
DaClrdHrlyQty a, s, h
MWh
Hour
RtImpExp5minQty a, s, i, t, dir
MW
Dispatch Interval
RsgCrdFlgt
none
none
Real-Time Net Settlement Location Deviation per AO per Hour per Settlement Location – The sum of AO a’s RtNetSlDev5minQty a, s, i at Settlement Location s in Hour h. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The quantity described under Section 4.5.9.1. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The quantity described under Section 4.5.8.1. Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval - The quantity described under Section 4.5.9.2 as identified by direction dir. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.
DaImpExp5minQty a, s, i, t, dir
MW
Dispatch Interval
DaClrdVHrlyQty a, s, h, t
MWh
Hour
(Not Available on Settlement Statement)
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Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval - The quantity described under Section 4.5.8.2 as identified by direction dir. Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Transaction per Hour in the DA Market – The quantity described under Section 4.5.8.3.
477
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtMinLimitDev5minQty a, s, i
MWh
Dispatch Interval
RtMinLimitDevHrlyQty a, s, h
MWh
Hour
RtMaxLimitDev5minQty a, s, i
MWh
Dispatch Interval
RtMaxLimitDevHrlyQty a, s, h
MWh
Hour
RtOutageDev5minQty a, s, i
MWh
Dispatch Interval
Real-Time Minimum Limit Deviation per AO per Dispatch Interval per Settlement Location – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources with cleared Day-Ahead amounts that increase their applicable minimum limit in Real-Time above their applicable minimum limit from the Day-Ahead Market commitment at Resource Settlement Location s in Hour h. Real-Time Minimum Limit Deviation per AO per Hour per Settlement Location – The sum of AO a’s RtMinLimitDev5minQty a, s, i at Resource Settlement Location s in Hour h. Real-Time Maximum Limit Deviation per AO per Dispatch Interval per Settlement Location – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources with cleared Day-Ahead amounts that reduce their applicable maximum limit in Real-Time below their applicable maximum limit from the Day-Ahead Market commitment at Resource Settlement Location s in Hour h. Real-Time Maximum Limit Deviation per AO per Hour per Settlement Location – The sum of AO a’s RtMaxLimitDev5minQty a, s, i at Resource Settlement Location s in Hour h. Real-Time Outage Deviation per AO per Dispatch Interval per Settlement Location – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources with cleared Day-Ahead amounts that are off-line in Real-Time and have not be decommitted by SPP at Resource Settlement Location s in Dispatch Interval i.
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtOutageDevHrlyQty a, s, h
MWh
Hour
RtStatusDev5minQty a, s, i
MWh
Dispatch Interval
RtStatusDevHrlyQty a, s, h
MWh
Hour
ControlStatus5minFlg a, s, i
none
Dispatch Interval
Real-Time Outage Deviation per AO per Hour per Settlement Location – The sum of AO a’s RtOutageDev5minQty a, s, i at Resource Settlement Location s in Hour h. Real-Time Resource Status Change Deviation per AO per Settlement Location per Dispatch Interval – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources for which the Control Status is set to “Manual” at Settlement Location s for Dispatch Interval i. Real-Time Status Deviation per AO per Hour per Settlement Location – The sum of AO a’s RtStatusDev5minQty a, s, i at Resource Settlement Location s in Hour h. Control Status per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8.
RtRucScDev5minQty a, s, i
MWh
Dispatch Interval
RtRucScDevXmpt5minFlg a, s, i
none
Dispatch Interval
Version 23.a
12/4/2014
Real-Time RUC Self-Commit Deviation per AO per Settlement Location per Dispatch Interval – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources that have Self-Committed following completion of the Day-Ahead RUC process at Settlement Location s for Dispatch Interval i. Real-Time RUC Self-Commit Deviation Exemption Flag per AO per Settlement Location per Dispatch Interval – a value of 1 for AO a’s Resources at Settlement Location s for Dispatch Interval i that were offered into the DA Market for SPP commitment and not committed in the DA Market and then Self-Committed prior to the Day-Ahead RUC, thus are exempted from Self-Commit deviation calculations.
479
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtRucScDevHrlyQty a, s, h
MWh
Hour
RtRucCommitDev5minQty a, s, i
MWh
Dispatch Interval
RtRucCommitDevHrlyQty a, s, h
MWh
Hour
RtURDDev5minQty a, s, i
MWh
Dispatch Interval
RtURDDevHrlyQty a, s, h
MWh
Hour
URD5minQty a, s, i,
MW
Dispatch Interval
XmptDev5minFlg a, s, i
none
Dispatch Interval
Real-Time RUC Self-Commit Deviation per AO per Settlement Location per Hour – The summation of AO a’s RtRucScDev5minQty a, s, i for Hour h. Real-Time RUC Commit Deviation per AO per Settlement Location per Dispatch Interval – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources that were committed in the Day-Ahead RUC process and fail to come on line at Settlement Location s for Dispatch Interval i. Real-Time RUC Commit Deviation per AO per Settlement Location per Hour – The summation of AO a’s RtRucCommitDev5minQty a, s, i for Hour h. Real-Time URD Deviation per AO per Settlement Location per Dispatch Interval – AO a’s portion of RtDevHrlyQty a, s, h associated with Resources that have operated outside of their ResOpTol5minQty a, s, i at Settlement Location s for Dispatch Interval i. Real-Time URD Deviation per AO per Hour per Settlement Location – The sum of AO a’s RtURDDev5minQty a, s, i at Resource Settlement Location s in Hour h. Uninstructed Resource Deviation per AO per Settlement Location per Dispatch Interval– The value calculated as described under Section 4.5.9.8. Failure-to-Follow Dispatch Exemption Flag per AO per Resource Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8.
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtDispDesiredEn5minQty a, s, i
MW
Dispatch Interval
RtDesiredEn5minQty a, s, i
MW
Dispatch Interval
RtDispMinEconCapOL5minQty a, s, i
MW
Dispatch Interval
RtDispMinRegCapOL5minQty a, s, i
MW
Dispatch Interval
DaComMinEconCapOLHrlyQty a, s, h
MW
Hour
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-Dispatched Minimum Capacity Limit (Economic or Regulating, as applicable) as an output floor and the AsDispatched Maximum Capacity Limit (Economic or Regulating, as applicable) as an output ceiling. Real-Time Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8. Real-Time Minimum Economic Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8 for Dispatch Interval i. Real-Time Minimum Regulation Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8 for Dispatch Interval i. Day-Ahead Minimum Economic Capacity Operating Limit Quantity per AO per Settlement Location per Hour – The Minimum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Hour h as submitted in the DA Market Offer used in the DA Market commitment decision.
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
DaComMinRegCapOLHrlyQty a, s, h
MW
Hour
RtDispMaxEconCapOL5minQty a, s, i
MW
Dispatch Interval
RtDispMaxRegCapOL5minQty a, s, i
MW
Dispatch Interval
DaComMaxEconCapOLHrlyQty a, s, h
MW
Hour
DaComMaxRegCapOLHrlyQty a, s, h
MW
Hour
Day-Ahead Minimum Regulation Capacity Operating Limit Quantity per AO per Settlement Location per Hour – The Minimum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Hour h as submitted in the DA Market Offer used in the DA Market commitment decision. Real-Time Maximum Economic Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Maximum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i. Real-Time Maximum Regulation Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Maximum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i. Day-Ahead Maximum Economic Capacity Operating Limit Quantity per AO per Settlement Location per Hour – The Maximum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Hour h as submitted in the DA Market Offer used in the DA Market commitment decision. Day-Ahead Maximum Regulation Capacity Operating Limit Quantity per AO per Settlement Location per Hour – The Maximum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Hour h as submitted in the DA Market Offer used in the DA Market commitment decision.
Version 23.a
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482
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
ResOpTol5minQty a, s, i
MW
Dispatch Interval
ResDeCommit5minFlg a, s, i , c
none
Dispatch Interval
RtRucComStat5minFlg a, s, i, c
none
Dispatch Interval
DispInstrucMinHrlyFlg a, s, h
none
Hour
DispInstrucMaxHrlyFlg a, s, h
none
Hour
DaRegUpHrlyQty a, z, s, h
MW
Hour
DaRegDnHrlyQty a, z, s, h
MW
Hour
Resource Operating Tolerance per AO per Settlement Location per Hour – The value calculated as described under Section 4.5.9.8. Resource De-Commitment Flag per AO per Dispatch Interval per Settlement Location – A flag set by SPP indicating that AO a’s Resource has been de-committed by SPP at Resource Settlement Location s in Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c. RUC Commitment Status Flag per AO per Resource Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8. Dispatch Instruction Minimum Flag per AO per Hour per Settlement Location – A flag associated with AO a’s Resource that is set equal to “1” if the Resource receives a Dispatch Instruction that is less than or equal to the Resource’s applicable minimum limit at any time in Hour h. Dispatch Instruction Maximum Flag per AO per Hour per Settlement Location – A flag associated with AO a’s Resource that is set equal to “1” if the Resource receives a Dispatch Instruction that is greater than or equal to the Resource’s applicable maximum limit at any time in Hour h. Day-Ahead Regulation-Up Service Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.4. Day-Ahead Regulation-Down Service Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.5.
Version 23.a
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483
Comment [MPRR102.959]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.960]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtMwpDistDlyAmt a, s, d
$
Operating Day
RtMwpDistAoAmt a, m,
$
Operating Day
$
Operating Day
i h d a c s t
none none none none none none none
none none none none none None none
dir m
none none
none none
RUC Make-Whole-Payment Distribution Amount per AO per Settlement Location per Operating Day - The amount to AO a at Settlement Location s for recovery of the total amount paid under Section 4.5.9.8 for Operating Day d. RUC Make-Whole-Payment Distribution Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for recovery of the total amounts paid under Section 4.5.9.8 for Operating Day d. RUC Make-Whole-Payment Distribution Amount per MP per Operating Day - The amount to MP m for recovery of the total amounts paid under Section 4.5.9.8 for Operating Day d. An Dispatch Interval An Hour. An Operating Day. An Asset Owner. A RUC Make-Whole-Payment Eligibility Period. A Settlement Location. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. Direction (Import, Export or Through). A Market Participant.
RtMwpDistMpAmt m, d
Version 23.a
d
12/4/2014
484
Market Protocols for SPP Integrated Marketplace
4.5.9.11
Comment [MPRR102.961]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation-Up Service Distribution Amount
(4) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the net RTBM Regulation-Up Service procurement costs. The amount to each Asset Owner is calculated as follows:
Comment [MPRR102.962]: MPRR102 Awaiting implementation. #ER13-1748
#RtRegUpDistHrlyAmt a, s, h = RtRegUpSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where, (a)
RtRegUpSppHrlyAmt h =
a
+
a
RtRegUpHrlyAmt a, s, h
s
Comment [MPRR204.963]: MPRR204 Awaiting FERC approval Docket #ER13-1748
RtRegUpUnusedMileMwpHrlyAmt a, s, h
Comment [MPRR102.964]: MPRR102 Awaiting implementation. #ER13-1748
s
Formatted: Font: Bold, Lowered by 14 pt
(b)
#RtLoadRatioShareHrlyFct a, s, h = [ [ Max ( 0,
RtBillMtr5minQty a, s, i )
i
+ Max ( 0,
i
RtImpExp5minQty a, s, i, t ) * (1 – RsgCrdFlgt ) ] /12 ]
t
/ RtLoadSppHrlyQty h (5) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtRegUpDistDlyAmt a, s, d =
RtRegUpDistHrlyAmt a, s, h
h
(6) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegUpDistAoAmt a, m, d =
RtRegUpDistDlyAmt a, s, d
s
Version 23.a
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Market Protocols for SPP Integrated Marketplace
(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: RtRegUpDistMpAmt m, d =
RtRegUpDistAoAmt a, m, d
a
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Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
RtRegUpDistHrlyAmt a, s, h
RtLoadRatioShareHrlyFct a, s, h
RtRegUpHrlyAmt a, s, h RtRegUpUnusedMileMwpHrlyAmt
a,
Unit
Settlement Interval
Definition
$
Hour
Ratio
Hour
$
Hour
$
Hour
Real-Time Regulation-Up Service Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtRegUpHrlyAmt a, s, h in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – AO a’s percentage share of total SPP actual real-time load plus Export Interchange Transactions at Settlement Location s in Hour h. Real-Time Regulation-Up Service Amount per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.4. Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Hour - The value described under Section 4.5.9.23. Real-Time Regulation-Up Service Amount per Hour – The SPP total amount of the values calculated under Section 4.5.9.4 in Hour h. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.
s, h
RtRegUpSppHrlyAmt h
$
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RtLoadSppHrlyQty h
MW
Hour
RsgCrdFlgt
none
none
(Not Available on Settlement Statement)
Version 23.a
Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2. Real-Time SPP Load per Hour – SPP total actual load and Export Interchange Transactions in Hour h as calculated under Section 4.5.8.8. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.
12/4/2014
487
Comment [MPRR102.965]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.966]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.967]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.968]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.969]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtRegUpDistDlyAmt a, s, d
RtRegUpDistAoAmt a, m, d
RtRegUpDistMpAmt m, d
Unit
Settlement Interval
Definition
$
Operating Day
Real-Time Regulation-Up Service Distribution Amount per AO Operating Day. The amount to AO a for total net Regulation-Up Service procurement costs in Operating Day d. Real-Time Regulation-Up Service Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total net Regulation-Up Service procurement costs in Operating Day d. Real-Time Regulation-Up Service Distribution Amount per MP per Operating Day The amount to MP m for total net Regulation-Up Service procurement costs in Operating Day d. An Asset Owner. A Settlement Location. An Hour. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Market Participant.
$
$
Operating Day
Operating Day
a s h i t
none none none none none
none none none none none
d m
none none
none none
Version 23.a
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488
Comment [MPRR102.970]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.971]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.972]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.973]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.974]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.975]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
4.5.9.12
Comment [MPRR102.976]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation-Down Service Distribution Amount
(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the net RTBM Regulation-Down Service procurement costs. The amount to each Asset Owner is calculated as follows:
Comment [MPRR102.977]: MPRR102 Awaiting implementation. #ER13-1748
#RtRegDnDistHrlyAmt a, s, h = RtRegDnSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where,
RtRegDnSppHrlyAmt h =
a
+
a
RtRegDnHrlyAmt a, s, h
s
Comment [MPRR204.978]: MPRR204 Awaiting FERC approval Docket #ER13-1748
RtRegDnUnusedMileMwpHrlyAmt a, s, h
Comment [MPRR102.979]: MPRR102 Awaiting implementation. #ER13-1748
s
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtRegDnDistDlyAmt a, s, d =
RtRegDnDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegDnDistAoAmt a, m, d =
RtRegDnDistDlyAmt a, s, d
s
(4) 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: RtRegDnDistMpAmt m, d =
RtRegDnDistAoAmt a, m, d
a
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Formatted: Font: Bold, Lowered by 14 pt
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
Ratio
Hour
$
Hour
$
Hour
RtRegDnSppHrlyAmt h
$
Hour
RtRegDnDistDlyAmt a, s, d
$
Operating Day
RtRegDnDistAoAmt a, m, d
$
Operating Day
Real-Time Regulation-Down Service Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtRegDnHrlyAmt a, s, h in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11. Real-Time Regulation-Down Service Amount per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.5. Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Settlement Location per Hour - The value described under Section 4.5.9.24. Real-Time Regulation-Down Service Amount per Hour – The SPP total amount of the values calculated under Section 4.5.9.5 in Hour h. Real-Time Regulation-Down Service Distribution Amount per AO per Operating Day The amount to AO a for total net RegulationDown Service procurement costs in Operating Day d. Real-Time Regulation-Down Service Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total net Regulation-Down Service procurement costs in Operating Day d. Real-Time Regulation-Down Service Distribution Amount per MP per Operating Day The amount to MP m for total net RegulationDown Service procurement costs in Operating Day d. An Asset Owner. A Settlement Location. An Hour. An Operating Day.
RtRegDnDistHrlyAmt a, s, h
RtLoadRatioShareHrlyFct a, s, h RtRegDnHrlyAmt a, s, h RtRegDnUnusedMileMwpHrlyAmt
a,
s, h
RtRegDnDistMpAmt m, d
a s h d
Version 23.a
$
none none none none
Operating Day none none none none
12/4/2014
490
Comment [MPRR102.980]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.981]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.982]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.983]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.984]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.985]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.986]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.987]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.988]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.989]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.990]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
m
Version 23.a
Unit
none
Settlement Interval none
Definition
A Market Participant.
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Market Protocols for SPP Integrated Marketplace
4.5.9.13
Real-Time Spinning Reserve Distribution Amount
(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the net RTBM Spinning Reserve procurement costs. The amount to each Asset Owner is calculated as follows: #RtSpinDistHrlyAmt a, s, h = RtSpinSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where,
RtSpinSppHrlyAmt h =
a
RtSpinHrlyAmt a, s, h
s
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtSpinDistDlyAmt a, s, d =
RtSpinDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtSpinDistAoAmt a, m, d =
RtSpinDistDlyAmt a, s, d
s
(4) 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: RtSpinDistMpAmt m, d =
RtSpinDistAoAmt a, m, d
a
Version 23.a
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Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
Ratio
Hour
RtSpinHrlyAmt a, s, h
$
Hour
RtSpinSppHrlyAmt h
$
Hour
RtSpinDistDlyAmt a, s, d
$
Operating Day
RtSpinDistAoAmt a, m, d
$
Operating Day
RtSpinDistMpAmt m, d
$
Operating Day
Real-Time Spinning Reserve Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtSpinHrlyAmt a, s, h in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11. Real-Time Spinning Reserve Amount per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.6. Real-Time Spinning Reserve Amount per Hour – The SPP total amount of the values calculated under Section 4.5.9.6 in Hour h. Real-Time Spinning Reserve Distribution Amount per AO per Operating Day The amount to AO a for total net Spinning Reserve procurement costs in Operating Day d. Real-Time Spinning Reserve Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total net Spinning Reserve procurement costs in Operating Day d. Real-Time Spinning Reserve Distribution Amount per MP per Operating Day The amount to MP m for total net Spinning Reserve procurement costs in Operating Day d. An Asset Owner. A Settlement Location. An Hour. An Operating Day. A Market Participant.
RtSpinDistHrlyAmt a, s, h
RtLoadRatioShareHrlyFct a, s, h
a s h d m
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4.5.9.14
Real-Time Supplemental Reserve Distribution Amount
(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the net RTBM Supplemental Reserve procurement costs. The amount to each Asset Owner is calculated as follows: #RtSuppDistHrlyAmt a, s, h = RtSuppSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where,
RtSuppSppHrlyAmt h =
a
RtSuppHrlyAmt a, s, h
s
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtSuppDistDlyAmt a, s, d =
RtSuppDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtSuppDistAoAmt a, m, d =
RtSuppDistDlyAmt a, s, d
s
(4) 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: RtSuppDistMpAmt m, d =
RtSuppDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
Ratio
Hour
RtSuppHrlyAmt a, s, h
$
Hour
RtSuppSppHrlyAmt h
$
Hour
RtSuppDistDlyAmt a, s, d
$
Operating Day
RtSuppDistAoAmt a, m, d
$
Operating Day
RtSuppDistMpAmt m, d
$
Operating Day
Real-Time Supplemental Reserve Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtSuppHrlyAmt a, s, h in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11. Real-Time Supplemental Reserve Amount per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.7. Real-Time Supplemental Reserve Amount per Hour – The SPP total amount of the values calculated under Section 4.5.9.7 in Hour h. Real-Time Supplemental Reserve Distribution Amount per AO per Operating Day The amount to AO a for total net Supplemental Reserve procurement costs in Operating Day d. Real-Time Supplemental Reserve Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total net Supplemental Reserve procurement costs in Operating Day d. Real-Time Supplemental Reserve Distribution Amount per MP per Operating Day The amount to MP m for total net Supplemental Reserve procurement costs in Operating Day d. An Asset Owner. A Settlement Location. An Hour. An Operating Day. A Market Participant.
RtSuppDistHrlyAmt a, s, h
RtLoadRatioShareHrlyFct a, s, h
a s h d m
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4.5.9.15
Comment [MPRR102.991]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation Service Non-Performance Amount
(1) A RTBM charge or credit27 will be calculated at each Resource Settlement Location for each Asset Owner for each Dispatch Interval when a Resource with cleared RTBM Regulation-Up Service, Regulation-Down Service or both operates outside of its Operating Tolerance. The amount will be determined as one-twelfth of the sum of: (a)
(b)
one-twelfth of the greater of: (i) zero; or (ii) DA Market cleared Regulation-Up MW multiplied by DA Market Regulation-Up Service MCP plus (RTBM cleared Regulation-Up MW – DA Market cleared Regulation-Up Service MW) multiplied by RTBM Regulation-Up MCP; plusand one twelfth of the greater of: (i) zero; or (ii) DA Market cleared Regulation-Down MW multiplied by DA Market Regulation-Down Service MCP plus (RTBM cleared Regulation-Down Service MW – DA Market cleared Regulation-Down Service MW) multiplied by RTBM Regulation-Down Service MCP; minus.
(c)
Unused Regulation-Down Mileage Amount; minus
(d)
Unused Regulation-Up Mileage Amount; minus
(c)
Excess Regulation-Down Mileage Amount; minus
(d)
Excess Regulation-Up Mileage Amount.
Comment [MPRR102.994]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.995]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.996]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.997]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.998]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.999]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1001]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1002]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1003]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1004]: MPRR102 Awaiting implementation. #ER13-1748
IF ABS (URD5minQty a, s, i ) > ResOpTol5minQty a, s, i AND ( RtRegUp5minQty a, z, s, i + RtRegDn5minQty a, z, s, i ) > 0 AND ( XmptDev5minFlg a, s, i = 0 ) THEN #RtRegNonPerf5minAmt a, s, i =
27
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
12/4/2014
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Comment [MPRR102.1000]: MPRR102 Awaiting implementation. #ER13-1748
The amount to each applicable Asset Owner is calculated as follows.
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Market Protocols for SPP Integrated Marketplace
Max ( 0, ( DaRegUpHrlyQty a, z, s, h z
* DaRegUpMcpHrlyPrc z, h
z
+ ( RtRegUp5minQty a, z, s, i -
DaRegUpHrlyQty a, z, s, h ) z
* RtRegUpMcp5minPrc z, i ) / 12 +(
DaRegDnHrlyQty a, z, s, h * DaRegDnMcpHrlyPrc z, h
z
DaRegDnHrlyQty a, z, s, h )
+ ( RtRegDn5minQty a, z, s, i -
z
* RtRegDnMcp5minPrc z, i ) / 12 ) - RtRegUpExcessMile5minAmt a, s, i - RtRegUpUnusedMile5minAmt a, s, i Comment [MPRR102.1005]: MPRR102 Awaiting implementation. #ER13-1748
- RtRegDnExcessMile5minAmt a, s, i - RtRegDnUnusedMile5minAmt a, s, i ELSE RtRegNonPerf5minAmt a, s, i = 0 (2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtRegNonPerfHrlyAmt a, s, h =
RtRegNonPerf5minAmt a, s, i
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. amount is calculated as follows: RtRegNonPerfDlyAmt a, s, d =
The
RtRegNonPerfHrlyAmt a, s, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:
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RtRegNonPerfAoAmt a, m, d =
RtRegNonPerfDlyAmt a, s, d
s
(5) 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: RtRegNonPerfMpAmt m, d =
RtRegNonPerfAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
RtRegUpMcp5minPrc z, i
$/MW
Dispatch Interval
RtRegDnMcp5minPrc z, i
$/MW
Dispatch Interval
XmptDev5minFlg a, s, i
none
Dispatch Interval
RtRegUp5minQty a, z, s, i
MW
Dispatch Interval
RtRegDn5minQty a, z, s, i
MW
Dispatch Interval
DaRegUpHrlyQty a, z, s, h
MW
Hour
DaRegDnHrlyQty a, s, h
MW
Hour
Real-Time Regulation Non-Performance Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for failure to provide regulation deployment at Resource Settlement Location s for the Dispatch Interval. Real-Time MCP for Regulation-Up Service per Settlement Location per Dispatch Interval per Reserve Zone - The value described under Section 4.5.9.4. Real-Time MCP for Regulation-Down Service per Settlement Location per Dispatch Interval per Reserve Zone - The value described under Section 4.5.9.5. Failure-to-Follow Dispatch Exemption Flag per AO per Resource Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8. Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4. Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5. Day-Ahead Cleared Regulation-Up Service Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.4. Day-Ahead Cleared Regulation-Down Service Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.5.
RtRegNonPerf5minAmt a, s, i
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Comment [MPRR102.1007]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1008]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1009]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1010]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1011]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
DaRegUpMcpHrlyPrc z, h
$/MW
Hour
DaRegDnMcpHrlyPrc z, h
$/MW
Hour
RtRegNonPerfHrlyAmt a, s, h
$
Hour
RtRegNonPerfDlyAmt a, s, d
$
Operating Day
RtRegNonPerfAoAmt a, m, d
$
Operating Day
RtRegNonPerfMpAmt m, d
$
Operating Day
URD5minQty a, s, i
MW
Dispatch Interval
ResOpTol5minQty a, s, i
MW
Dispatch Interval
Day-Ahead MCP for Regulation-Up Service per Settlement Location per Dispatch Interval per Reserve Zone - The value described under Section 4.5.8.4. Day-Ahead MCP for Regulation-Up Service per Settlement Location per Dispatch Interval per Reserve Zone - The value described under Section 4.5.8.5. Real-Time Regulation Non-Performance Amount per AO per Settlement Location per Hour - The amount to AO a for failure to provide regulation deployment at Resource Settlement Location s for the Hour. Real-Time Regulation-Non-Performance Amount per AO per Settlement Location per Operating Day - The amount to AO a for failure to provide regulation deployment at Resource Settlement Location s for the Operating Day. Real-Time Regulation Non-Performance Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for failure to provide regulation deployment for the Operating Day. Real-Time Regulation-Non-Performance Amount per MP per Operating Day - The amount to MP m for failure to provide regulation deployment for the Operating Day. Uninstructed Resource Deviation per AO per Settlement Location per Dispatch Interval– The value calculated as described under Section 4.5.9.8. Resource Operating Tolerance per AO per Settlement Location per Hour – The value calculated as described under Section 4.5.9.8.
a s
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none none
An Asset Owner. A Resource Settlement Location.
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500
Comment [MPRR102.1012]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1013]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
h i d m
Version 23.a
Unit
none none none none
Settlement Interval none none none none
Definition
An Hour. A Dispatch Interval. An Operating Day. A Market Participant.
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4.5.9.16
Real-Time Regulation Non-Performance Distribution Amount
(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the Real-Time Regulation Non-Performance Amount. The amount to each Asset Owner is calculated as follows: #RtRegNonPerfDistHrlyAmt a, s, h = RtRegNonPerfSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where,
RtRegNonPerfSppHrlyAmt h =
a
RtRegNonPerfHrlyAmt a, s, h
s
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtRegNonPerfDistDlyAmt a, s, d =
RtRegNonPerfDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegNonPerfDistAoAmt a, m, d =
RtRegNonPerfDistDlyAmt a, s, d
s
(4) 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: RtRegNonPerfDistMpAmt m, d =
RtRegNonPerfDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtRegNonPerfDistHrlyAmt a, s, h
$
Hour
RtLoadRatioShareHrlyFct a, s, h
Ratio
Hour
RtRegNonPerfHrlyAmt a, s, h
$
Hour
RtRegNonPerfSppHrlyAmt h
$
Hour
RtRegNonPerfDistDlyAmt a, s, d
$
Operating Day
RtRegNonPerfDistAoAmt a, m, d
$
Operating Day
RtRegNonPerfDistMpAmt m, d
$
Operating Day
Real-Time Regulation Non-Performance Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtRegNonPerfHrlyAmt a, s, h in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11. Real-Time Regulation Non-Performance Amount per AO per Resource Settlement Location per Hour – The value calculated under Section 4.5.9.15. Real-Time Regulation Non-Performance Amount per Hour – The SPP total of the values calculated under Section 4.5.9.15 in Hour h. Real-Time Regulation Non-Performance Distribution Amount per AO per Operating Day The amount to AO a for total Regulation Non-Performance charges in Operating Day d. Real-Time Regulation Non-Performance Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total Regulation Non-Performance charges in Operating Day d. Real-Time Regulation Non-Performance Distribution Amount per MP per Operating Day The amount to MP m for total Regulation Non-Performance charges in Operating Day d. An Asset Owner. A Settlement Location. An Hour. An Operating Day. A Market Participant.
a s h d m
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4.5.9.17
Real-Time Contingency Reserve Deployment Failure Amount
(1) A RTBM charge or credit28 will be assessed at each Resource Settlement Location or Common Bus for each Asset Owner following deployment of Contingency Reserve if the amount of Contingency Reserve specified in the Contingency Reserve Deployment Instruction fails to be provided. Failure to provide the specified amount of Contingency Reserve is determined through a series four (4) tests as described in Section 4.4.4.3. The tests are performed either at the individual Resource level or, at the Common Bus level if the Resource receiving the Contingency Reserve Deployment Instruction is registered at a Common Bus. An Asset Owner must fail all four tests in order to receive a penalty for deployment failure. The penalty amount will be determined by multiplying the RTBM LMP (Absolute Value) for the Dispatch Interval in which the Contingency Reserve Deployment Period ends by the minimum of all ShortFall Quantity Amounts calculated from each of the four tests. The amount to each applicable Asset Owner is calculated as follows. IF CommonBusFlg
a, cb, s, i
= “1”
THEN #RtCRDeplFailAmt a, s, i = RtCRCBShortFallQty a, cb, i * ABS ( RtLmp5minPrc
s, i
)
ELSE #RtCRDeplFailAmt a, s, i = RtCRSLShortFallQty a, s, i * ABS ( RtLmp5minPrc
s, i
)
Where, (a)
RtCRSLShortFallQty a, s, i = Min (Test1SLShortFallQty a, s, i , Test2SLShortFallQty a, s, i , Test3SLShortFallQty a, s, i , Test4SLShortFallQty a, s, i )
28
Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
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(b)
RtCRCBShortFallQty a, cb, i = Min (Test1CBShortFallQty a, cb, i , Test2CBShortFallQty a, cb, i , Test3CBShortFallQty a, cb, i , Test4CBShortFallQty a, cb, i )
(c)
Test1SLShortFallQty a, s, i = Max (0, RtEndTelemtr5minQty a, s, i + RtEndInstRampSP5minQty
(d)
RtEndTelemtr5minQty a, s, i +
s
RtEndInstRampSP5minQty
)
Test2SLShortFallQty a, s, i = a, s, i
)
Test2CBShortFallQty a, cb, i = Max (0,
RtEndTelemtr5minQty a, s, i +
s
(g)
a, s, i
s
Max (0, RtEndTelemtr5minQty a, s, i + RtEndInstStepSP5minQty (f)
)
Test1CBShortFallQty a, cb, i = Max (0,
(e)
a, s, i
RtEndInstStepSP5minQty
a, s, i
)
s
Test3SLShortFallQty a, s, i = Max (0, { RtEndTelemtr5minQty a, s, i - RtBeginTelemtr5minQty a, s, i } + { RtEndInstRampSP5minQty
a, s, i
- RtBeginInstRampSP5minQty a, s, i } )
(h)
Test3CBShortFallQty a, cb, i = Max (0, {
RtEndTelemtr5minQty a, s, i
s
-
RtBeginTelemtr5minQty a, s, i }
s
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+ {
RtEndInstRampSP5minQty
a, s, i
s
-
RtBeginInstRampSP5minQty a, s, i } )
s
(i)
Test4SLShortFallQty a, s, i = Max (0, { RtEndTelemtr5minQty a, s, i - RtBeginTelemtr5minQty a, s, i } + { RtEndInstStepSP5minQty
a, s, i
- RtBeginInstStepSP5minQty a, s, i } )
(j)
Test4CBShortFallQty a, cb, i = Max (0, {
RtEndTelemtr5minQty a, s, i
s
-
RtBeginTelemtr5minQty a, s, i }
s
+ {
RtEndInstStepSP5minQty
a, s, i
s
-
RtBeginInstStepSP5minQty a, s, i } )
s
(2) For each Asset Owner, an hourly amount at each Settlement Location is calculated. The amount is calculated as follows: RtCRDeplFailHrlyAmt a, s, h =
RtCRDeplFailAmt a, s, i
i
(3) For each Asset Owner, a daily amount at each Settlement Location is calculated. amount is calculated as follows:
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506
Market Protocols for SPP Integrated Marketplace
RtCRDeplFailDlyAmt a, s, d =
RtCRDeplFailHrlyAmt a, s, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtCRDeplFailAoAmt a, m, d =
RtCRDeplFailDlyAmt a, s, d
s
(5) 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: RtCRDeplFailMpAmt m, d =
RtCRDeplFailAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
RtCRCBShortFallQty a, cb, i
MW
Dispatch Interval
RtCRSLShortFallQty a, s, i
MW
Dispatch Interval
Test1SLShortFallQty a, s, i
MW
Dispatch Interval
Test1CBShortFallQty a, cb, i
MW
Dispatch Interval
Test2SLShortFallQty a, s, i
MW
Dispatch Interval
Real-Time Contingency Reserve Deployment Failure Amount per AO per Settlement Location per Dispatch Interval – The amount to AO a for failure to provide Contingency Reserve deployment at Resource Settlement Location s or Common Bus location cb for the Dispatch Interval. Real-Time Contingency Reserve ShortFall Quantity per AO per Common Bus per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Common Bus location cb for the Dispatch Interval. Real-Time Contingency Reserve ShortFall Quantity per AO per Settlement Location per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Settlement Location s for the Dispatch Interval. Real-Time Contingency Reserve Deployment Test 1 ShortFall Quantity per AO per Settlement Location per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Settlement Location s or Common Bus location cb for the Dispatch Interval under Test 1 described under Section 4.4.4.3. Real-Time Contingency Reserve Deployment Test 1 ShortFall Quantity per AO per Common Bus per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Common Bus cb for the Dispatch Interval under Test 1 described under Section 4.4.4.3. Real-Time Contingency Reserve Deployment Test 2 ShortFall Quantity per AO per Settlement Location per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Settlement Location s or Common Bus location cb for the Dispatch Interval under Test 2 described under Section 4.4.4.3.
RtCRDeplFailAmt a, s, i
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Variable
Unit
Settlement Interval
Definition
Test2CBShortFallQty a, cb, i
MW
Dispatch Interval
Test3SLShortFallQty a, s, i
MW
Dispatch Interval
Test3CBShortFallQty a, cb, i
MW
Dispatch Interval
Test4SLShortFallQty a, s, i
MW
Dispatch Interval
Test4CBShortFallQty a, cb, i
MW
Dispatch Interval
$/MW
Dispatch Interval
Real-Time Contingency Reserve Deployment Test 2 ShortFall Quantity per AO per Common Bus per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Common Bus cb for the Dispatch Interval under Test 2 described under Section 4.4.4.3. Real-Time Contingency Reserve Deployment Test 3 ShortFall Quantity per AO per Settlement Location per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Settlement Location s or Common Bus location cb for the Dispatch Interval under Test 3 described under Section 4.4.4.3. Real-Time Contingency Reserve Deployment Test 3 ShortFall Quantity per AO per Common Bus per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Common Bus cb for the Dispatch Interval under Test 3 described under Section 4.4.4.3. Real-Time Contingency Reserve Deployment Test 4 ShortFall Quantity per AO per Settlement Location per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Settlement Location s or Common Bus location cb for the Dispatch Interval under Test 4 described under Section 4.4.4.3. Real-Time Contingency Reserve Deployment Test 4 ShortFall Quantity per AO per Common Bus per Dispatch Interval – AO a’s MW amount of Contingency Reserve that failed to deploy at Common Bus cb for the Dispatch Interval under Test 4 described under Section 4.4.4.3. Real-Time LMP - The value defined under Section 4.5.9.1 at the Settlement Location s for Dispatch Interval i that is associated with the Resource receiving the Contingency Reserve Deployment Instruction.
RtLmp5minPrc
Version 23.a
s, i
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtBeginTelemtr5minQty a, s, i
MW
Dispatch Interval
RtEndTelemtr5minQty a, s, i
MW
Dispatch Interval
MW
Dispatch Interval
Real-Time Telemetered Quantity per AO per Settlement Location per Dispatch Interval – AO a’s Resource telemetered (SCADA) MW output as measured at the beginning of the Contingency Reserve Deployment Period. Real-Time Telemetered Quantity per AO per Settlement Location per Dispatch Interval – AO a’s Resource telemetered (SCADA) MW output as measured at the end of the Contingency Reserve Deployment Period. Real-Time Instantaneous Ramped Setpoint Quantity per AO per Settlement Location per Dispatch Interval – AO a’s Resource ramped Setpoint Instruction at the beginning of the Contingency Reserve Deployment Period. Real-Time Instantaneous Ramped Setpoint Quantity per AO per Settlement Location per Dispatch Interval – AO a’s Resource ramped Setpoint Instruction at the end of the Contingency Reserve Deployment Period. Real-Time Instantaneous Stepped Setpoint Quantity per AO per Settlement Location per Dispatch Interval – AO a’s Resource stepped Setpoint Instruction at the beginning of the Contingency Reserve Deployment Period. Real-Time Instantaneous Stepped Setpoint Quantity per AO per Settlement Location per Dispatch Interval – AO a’s Resource stepped Setpoint Instruction at the end of the Contingency Reserve Deployment Period. Common Bus Flag per AO per Settlement Location per Common Bus per Dispatch Interval – A Flag that is set equal to 1 in Dispatch Interval i at any one of AO a’s Resource Settlement Locations s that is registered at Common Bus cb.
RtBeginInstRampSP5minQty
a, s, i
RtEndInstRampSP5minQty
a, s, i
MW
Dispatch Interval
RtBeginInstStepSP5minQty
a, s, i
MW
Dispatch Interval
MW
Dispatch Interval
None
Dispatch Interval
RtEndInstStepSP5minQty
CommonBusFlg
Version 23.a
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a, s, i
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtCRDeplFailHrlyAmt a, s, h
$
Hour
RtCRDeplFailDlyAmt a, s, d
$
Operating Day
RtCRDeplFailAoAmt a, m, d
$
Operating Day
RtCRDeplFailMpAmt m, d
$
Operating Day
Real-Time Contingency Reserve Deployment Failure Amount per AO per Settlement Location per Hour – The amount to AO a for failure to provide Contingency Reserve deployment at Settlement Location s for the Hour. Real-Time Contingency Reserve Deployment Failure Amount per AO per Settlement Location per Operating Day – The amount to AO a associated with Market Participant m for failure to provide Contingency Reserve deployment as Settlement Location s for the Operating Day. Real-Time Contingency Reserve Deployment Failure Amount per AO per Operating Day – The amount to AO a associated with Market Participant m for failure to provide Contingency Reserve deployment for the Operating Day. Real-Time Spinning Reserve Deployment Failure Amount per MP per Operating Day – The amount to MP m for failure to provide Contingency Reserve deployment for the Operating Day. An Asset Owner. A Resource Settlement Location. A Common Bus. An Hour. A Dispatch Interval. An Operating Day. A Market Participant.
a s cb h i d m
Version 23.a
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none none none none none none none
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Market Protocols for SPP Integrated Marketplace
4.5.9.18
Real-Time Contingency Reserve Deployment Failure Distribution Amount
(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the Real-Time Contingency Reserve Deployment Failure Amount. The amount to each Asset Owner is calculated as follows: # RtCRDeplFailDistHrlyAmt a, s, h = RtCRDeplFailSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where,
RtCRDeplFailSppHrlyAmt h =
a
RtCRDeplFailHrlyAmt a, s, h
s
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtCRDeplFailDistDlyAmt a, s, d =
RtCRDeplFailDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtCRDeplFailDistAoAmt a, m, d =
RtCRDeplFailDistDlyAmt a, s, d
s
(4) 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: RtCRDeplFailDistMpAmt m, d =
RtCRDeplFailDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtCRDeplFailDistHrlyAmt a, s, h
$
Hour
RtLoadRatioShareHrlyFct a, s, h
Ratio
Hour
RtCrDeplFailHrlyAmt a, s, h
$
Hour
RtCRDeplFailSppHrlyAmt h
$
Hour
RtCRDeplFailDistDlyAmt a, s, d
$
Operating Day
RtCRDeplFailDistAoAmt a, m, d
$
Operating Day
RtCRDeplFailDistMpAmt m, d
$
Operating Day
Real-Time Contingency Reserve Deployment Failure Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtCRDeplFailHrlyAmt a, s, h in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11. Real-Time Contingency Reserve Deployment Failure Amount per AO per Hour – The value calculated under Section 4.5.9.17. Real-Time Contingency Reserve Deployment Failure Amount per Hour – The SPP total of the values calculated under Section 4.5.9.17 in Hour h. Real-Time Contingency Reserve Deployment Failure Distribution Amount per AO per Reserve Zone per Operating Day The amount to AO a for total Contingency Reserve deployment failure charges in Operating Day d. Real-Time Contingency Reserve Deployment Failure Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total Contingency Reserve deployment failure charges in Operating Day d. Real-Time Contingency Reserve Deployment Failure Distribution Amount per MP per Operating Day The amount to MP m for total Contingency Reserve deployment failure charges in Operating Day d. An Asset Owner. A Settlement Location. An Hour. An Operating Day.
a s h d
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Market Protocols for SPP Integrated Marketplace
Variable
m
Version 23.a
Unit
none
Settlement Interval none
Definition
A Market Participant.
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4.5.9.19
Comment [MPRR102.1014]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation Service Deployment Adjustment Amount
(1) A RTBM charge or credit will be calculated at each Resource Settlement Location for each Asset Owner for each Dispatch Interval when a Resource with cleared RTBM Regulation-Up Service or Regulation-Down Service is deployed. The amount will be determined as onetwelfth of the sum of: (a)
For Regulation-Up Service deployment, the amount is equal to the difference between (1) actual Regulation-Up Service deployment MW multiplied by RTBM LMP, and (2) Energy Offer Curve cost of actual Regulation-Up Service deployment MW; (i)
(b)
The actual Regulation-Up Service deployment MW is calculated as the difference between the lesser of (1) (average Dispatch Instruction for Energy + average Regulation-Up Service deployment) or (2) Absolute Value of actual Resource output, and the Resource’s average Dispatch Instruction for Energy. If the Absolute Value of the Resource’s actual output is less than or equal to the Resource’s average Dispatch Instruction for Energy, then the actual Regulation-Up Service deployment MW is equal to zero.
Comment [MPRR102.1016]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1017]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1018]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1019]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1020]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1021]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1022]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1023]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1024]: MPRR102 Awaiting implementation. #ER13-1748
For Regulation-Down Service deployment, the amount is equal to the difference between (1) Energy Offer Curve cost of actual Regulation-Down Service deployment MW, and (2) actual Regulation-Down Service deployment MW multiplied by RTBM LMP;
Comment [MPRR102.1025]: MPRR102 Awaiting implementation. #ER13-1748
(i)
Comment [MPRR102.1028]: MPRR102 Awaiting implementation. #ER13-1748
The actual Regulation-Down Service deployment MW is calculated as the difference between the Resource’s average Dispatch Instruction for Energy and the greater of (1) (average Dispatch Instruction - average Regulation-Down Service deployment) or (2) Absolute Value of actual Resource output. If the Absolute Value of the Resource’s actual output is greater than or equal to the Resource’s average Dispatch Instruction for Energy, then the actual Regulation-Down Service deployment MW is equal to zero.
The amount to each applicable Asset Owner is calculated as follows. IF ControlStatus5minFlg a, s, i = “Regulating”
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Comment [MPRR102.1026]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1027]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1029]: MPRR102 Awaiting implementation. #ER13-1748
Comment [MPRR102.1030]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
THEN RtRegAdj5minAmt a, s, i = RtRegUpAdj5minAmt a, s, i + RtRegDnAdj5minAmt a, s, i ELSE RtRegAdj5minAmt a, s, i = 0 Where, (a)
#RtRegUpAdj5minAmt a, s, i = RtRegUpDepl5minQty a, s, i * (RtLmp5minPrc
(a.1)
s, i
- RtRegUpDepl5minCostRate a, s, i ) / 12
RtRegUpDepl5minQty a, s, i = Max (RtAvgDispatch5minQty a, s, i, Min ( RtBillMtr5minQty a, s, i * (-1) , ( RtAvgDispatch5minQty a, s, i + RtAvgRegUpSp5minQty a, s, i ) ) ) - RtAvgDispatch5minQty a, s, i
(b)
#RtRegDnAdj5minAmt a, s, i = RtRegDnDepl5minQty a, s, i * ( RtRegDnDepl5minCostRate a, s, i - RtLmp5minPrc
(b.1)
s, i
) / 12
RtRegDnDepl5minQty a, s, i = RtAvgDispatch5minQty a, s, i - Min (RtAvgDispatch5minQty a, s, i , Max ( RtBillMtr5minQty a, s, i * (-1), ( RtAvgDispatch5minQty a, s, i - RtAvgRegDnSp5minQty a, s, i ) ) )
(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
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RtRegAdjHrlyAmt a, s, h =
RtRegAdj5minAmt a, s, i
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The credit amount is calculated as follows: RtRegAdjDlyAmt a, s, d =
RtRegAdjHrlyAmt a, s, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegAdjAoAmt a, m, d =
RtRegAdjDlyAmt a, s, d
s
(5) 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: RtRegAdjMpAmt m, d =
RtRegAdjAoAmt a, m, d
a
(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Regulation Deployment Adjustment $ per Dispatch Interval for each Asset Owner as follows: (a)
#EqrRtRegAdj5minPrc a, s, i = (-1) * RtRegAdj5minAmt a, s, i
(b)
IF #EqrRtRegAdj5minPrc a, s, i < > 0 THEN #EqrRtRegAdj5minQty a, s, i = 1
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtRegAdj5minAmt a, s, i
$
Dispatch Interval
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
Real-Time Regulation Deployment Adjustment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Energy associated with Regulation deployment at Resource Settlement Location s for the Dispatch Interval. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.
$/MW
Dispatch Interval
Real-Time LMP - The value defined under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.
$
Dispatch Interval
Real-Time Regulation-Up Service Deployment Adjustment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Energy associated with Regulation-Up Service deployment at Resource Settlement Location s for the Dispatch Interval. Real-Time Regulation-Up Service Deployment MW per AO per Settlement Location per Dispatch Interval – The integrated MW of Regulation-Up Service Deployment deployment associated with AO a’s Resource at Settlement Location s in Dispatch Interval i.
RtLmp5minPrc
s, i
RtRegUpAdj5minAmt a, s, i
RtRegUpDepl5minQty a, s, i
Version 23.a
MW
Dispatch Interval
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Comment [MPRR102.1031]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1032]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1033]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1034]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtRegUpDepl5minCostRate a, s, i
Unit
Settlement Interval
$/MW
Dispatch Interval
Definition Comment [MPRR102.1035]: MPRR102 Awaiting implementation. #ER13-1748
Real-Time Regulation-Up Deployment Service Cost Rate per AO per Settlement Location per Dispatch Interval – The cost, in $/MW, associated with RtRegUpDepl5minQty a, s, i for AO a’s Resource at Settlement Location s in Dispatch Interval i. The cost is calculated as Stop
RTBM As Dispatched Energy Offer Curve
/
Start
RtRegDnAdj5minAmt a, s, i
RtRegDnDepl5minQty a, s, i
Version 23.a
$
MW
Dispatch Interval Dispatch Interval
(RtRegUpDepl5minQty a, s, i) , where Stop = Min ( RtAvgSetpoint5minQty a, s, i, (-1) * RtBillMtr5minQty a, s, i ) Start = ( Stop - RtRegUpDepl5minQty a, s, i ) Real-Time Regulation-Down Service Deployment Adjustment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Energy associated with Regulation-Down Service deployment at Resource Settlement Location s for the Dispatch Interval. Real-Time Regulation-Down Service Deployment MW per AO per Settlement Location per Dispatch Interval – The integrated MW of Regulation-Down Service Deployment associated with AO a’s Resource at Settlement Location s in Dispatch Interval i.
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Comment [MPRR102.1036]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1037]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1038]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1039]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtRegDnDepl5minCostRate a, s, i
Unit
Settlement Interval
Definition
$/MW
Dispatch Interval
Real-Time Regulation-Down Service Deployment Cost Rate per AO per Settlement Location per Dispatch Interval – The cost, in $/MW, associated with RtRegDnDepl5minQty a, s, i for AO a’s Resource at Settlement Location s in Dispatch Interval i. The cost is calculated as
Comment [MPRR102.1040]: MPRR102 Awaiting implementation. #ER13-1748
Stop
RTBM As Dispatched Energy Offer Curve
/
Start
(RtRegDnDepl5minQty a, s, i) , where Start = Max ( RtAvgSetpoint5minQty a, s, i , (-1)*RtBillMtr5minQty a, s, i) Stop = ( Start + RtRegDnDepl5minQty a, s, i ) RtAvgDispatch5minQty a, s, i
MW
Dispatch Interval
RtAvgRegUpSp5minQty a, s, i
MW
Dispatch Interval
Version 23.a
Real-Time Average Dispatch Instruction MW per AO per Settlement Location per Dispatch Interval – The average Dispatch Instruction as calculated as the average of the Dispatch Instruction in current Dispatch Interval i and the Dispatch Instruction for the previous Dispatch Interval i for AO a’s Resource at Settlement Location s in Dispatch Interval i. Real-Time Average Regulation-Up Service Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The average of the portion of the Resource Setpoint Instruction associated with RegulationUp Service deployment as calculated using the Resource’s applicable ramp rate used by the RTBM SCED to calculate the Dispatch Instruction for Energy and the amount of RTBM cleared Regulation-Up Service for AO a’s Resource at Settlement Location s in Dispatch Interval i.
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Comment [MPRR102.1041]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1042]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1043]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
RtAvgRegDnSp5minQty a, s, i
ControlStatus5minFlg a, s, i
Unit
Settlement Interval
Definition
MW
Dispatch Interval
Real-Time Average Regulation-Down Service Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The average of the portion of the Resource Setpoint Instruction associated with Regulation-Down Service deployment as calculated using the Resource’s applicable ramp rate used by the RTBM SCED to calculate the Dispatch Instruction for Energy and the amount of RTBM cleared Regulation-Down Service for AO a’s Resource at Settlement Location s in Dispatch Interval i. Control Status per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8. Real-Time Regulation Deployment Adjustment Amount per AO per Resource Settlement Location per Hour - The amount to AO a for Energy associated with Regulation deployment at Resource Settlement Location s for the Hour h. Real-Time Regulation Deployment Adjustment Amount per AO per Resource Settlement Location per Operating Day - The amount to AO a for Energy associated with Regulation deployment at Resource Settlement Location s for the Operating Day d. Real-Time Regulation Deployment Adjustment Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for Energy associated with Regulation deployment for the Operating Day d. Real-Time Regulation Deployment Adjustment Amount per MP per Operating Day - The amount to MP m for Energy associated with Regulation deployment for the Operating Day d.
None
Dispatch Interval Hourly
RtRegAdjHrlyAmt a, s, h
$
RtRegAdjDlyAmt a, s, d
$
Operating Day
RtRegAdjAoAmt a, m, d
$
Operating Day
RtRegAdjMpAmt m, d
$
Operating Day
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Comment [MPRR102.1044]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1045]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1046]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
EqrRtRegAdj5minPrc a, s, i
$
Dispatch Interval
EqrRtRegAdj5minQty a, s, i
MWh
Dispatch Interval
Real-Time Electric Quarterly Reporting Regulation Deployment Adjustment Amount per AO per Settlement Location per Dispatch Interval - The Regulation Deployment Adjustment charge/credit to AO a for Dispatch Interval i at Resource Settlement Location s for use by AO a in reporting such charges/credits to FERC in accordance with FERC EQR requirements.. Real-Time Electric Quarterly Reporting Regulation Deployment Adjustment Quantity per AO per Settlement Location per Dispatch Interval – This value is set equal to 1 if EqrRtRegAdj5minPrc a, s, c > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.. An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. An Operating Day. A Market Participant.
a s h i d m
Version 23.a
none none none none none none
none none none none none none
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Market Protocols for SPP Integrated Marketplace
4.5.9.20
Comment [MPRR212.1047]: MPRR212 Awaiting FERC filing
Real-Time Over-Collected Losses Distribution Amount
(1) The Marginal Losses Component of the Day-Ahead Market LMP and RTBM LMP that results from the economic market solution which considers the cost of marginal losses, congestion costs and incremental Energy costs creates an over collection (or under collection as a result of the Real-Time deviation accounting) related to payment for losses (“RTBM Over-Collected Losses”) that must be accounted for. A RTBM credit or charge is calculated for each hour at each Settlement Location for which an Asset Owner has a net RTBM Energy withdrawal in a Loss Pool that contributed positively to the over collection or under collection or paid a charge for Real-Time Pseudo-Tie Losses at the Settlement Location of the Sink of the Pseudo-Tie path for use of the SPP Transmission system. Each Loss Pool’s contribution to the RTBM Over-Collected Losses is calculated based upon the Settlement Locations contained within the Loss Pool. There are two types of Loss Pools: (a) Loss Pools defined by all Settlement Locations within a Settlement Area (“Settlement Area Loss Pool”); and (b) a single Loss Pool defined by all Hub and External Interface Settlement Locations (“System-Wide Loss Pool”). Injection/withdrawal amounts associated with Settlement Locations spanning multiple Settlement Area Loss Pools are allocated pro rata using the billable metering values submitted at the associated Meter Data Submittal Locations. A loss rebate factor is calculated for each withdrawal Settlement Location as the sum of i) the difference between the Marginal Loss Component at a withdrawal Settlement Location and the injection weighted average Marginal Loss Component for the Loss Pool, multiplied by the net RTBM Energy withdrawal at that Settlement Location and ii) the sum of charges for Real-Time Pseudo-Tie Losses at the Settlement Location of the Sink of the pseudo-tie path. The injection weighted average MLC for the Loss Pool is calculated assuming that injection in the Loss Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools which do not have sufficient injection to meet all withdrawal. The sum of the Settlement Location loss rebate factors (positive value only, negative values are ignored) is a measure of that Loss Pool’s payment for losses on a marginal basis. The Loss Pool sum of the Settlement Location loss rebate factors are then normalized to allocate a prorata portion of the total over collection or under collection in the hour to each Loss Pool. Within a Loss Pool, each Asset Owner is allocated a portion of the Loss Pool subtotal at each Settlement Location based on a ratio share of its net RTBM Market Energy withdrawal to that of the Loss Pool in total. Asset Owners with GFA Carve Out energy transactions are not qualified to receive loss rebates associated with the GFA Carve Out transactions. The amount is calculated as follows:
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Comment [MPRR212.1048]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1049]: MPRR212 Awaiting FERC filing Comment [MPRR212.1050]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1051]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1052]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1053]: MPRR212 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
#RtOclDistHrlyAmt a, s, lp, h = RtAoSlLpLrsHrlyFct a, s, lp, h * RtNormLpRbtHrlyFct
lp, h
* (RtIncrOclHrlyAmt h + DaOclHrlyAmt h ) * (-1)
RtIncrOclHrlyAmt h =
RtIncrOcl5minAmt i
Comment [MPRR212.1054]: MPRR212 Awaiting FERC filing
Where, (a)
i
(a.1)
#RtIncrOcl5minAmt i =
[ ( RtLmp5minPrc s, i – RtMcc5minPrc s, i )
s
a
* ( ( RtBillMtr5minQty a, s, –
– DaClrdHrlyQty a, s, h )
i
DaClrdVHrlyQty a, s, h, t
t
+
RtImpExp5minQty a, s, i, t –
t
DaImpExp5minQty a, s,
i, t
) ] / 12
t
+ RtNetInadvertentSpp5minAmt i + RtPseudoTieLossSpp5minAmt i (a.2)
RtPseudoTieLossSpp5minAmt i =
a
(a.3)
RtPseudoTieLoss5minAmt a, source, sink, i
source sin k
#DaOclHrlyAmt h =
Field Code Changed
a
[(DaLmpHrlyPrc s, h - DaMccHrlyPrc s, h )
Field Code Changed
s
* ( DaClrdHrlyQty a, s, h +
DaClrdVHrlyQty a, s,
Field Code Changed
h, t
t
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+
i
DaImpExp5minQty a, s,
i, t
Comment [MPRR212.1055]: MPRR212 Awaiting FERC filing
/ 12 )]
t
Field Code Changed Field Code Changed
(b)
IF RtSppRbtHrlyFct h = 0 THEN RtNormLpRbtHrlyFct
lp, h
=0
ELSE #RtNormLpRbtHrlyFct
lp, h
Max ( 0, RtLpRbtHrlyFct (b.1)
RtSppRbtHrlyFct h =
=
lp, h
) / RtSppRbtHrlyFct h
RtLpRbtHrlyFct
lp, h
lp
(b.2)
RtLpRbtHrlyFct lp, h =
Max ( 0, RtSlRbtHrlyFct s, lp, h )
s
(b.3) RtSlRbtHrlyFct
s, lp, h
=
RtSlRbt5minFct
s, lp, i
i
(b.4)
#RtSlRbt5minFct
s, lp, i
= { [ RtLpIntSupply5minFct lp, i
* ( RtMlc5minPrc s, i – RtLpIwaMlc5minPrc lp, i ) + ( 1 – RtLpIntSupply5minFct lp, i ) * (RtMlc5minPrc s, i – RtSppIwaMlc5minPrc i ) ] * RtSlWdr5minQty
s, lp, i
}
+ SltoLp5minMap s, lp, i *
RtPseudoTieLoss5minAmt a, source, sink (s), i
source
(b.5)
Version 23.a
RtSlWdr5minQty s, lp, i =
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Max (0,
SltoLp5minMap s, lp, i * ( RtBillMtr5minQty a, s, i
a
– DaClrdHrlyQty a, s,
h
–
DaClrdVHrlyQty a, s,
Comment [MPRR212.1056]: MPRR212 Awaiting FERC filing
h, t
t
+
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt )
t
Comment [MPRR212.1057]: MPRR212 Awaiting FERC filing
– DaImpExp5minQty a, s, i, t ) ) / 12 t
(b.6)
RtLpWdr5minQty lp, i =
RtSlWdr5minQty s, lp, i
s
(b.7)
IF RtLpWdr5minQty lp, i = 0 THEN RtLpIntSupply5minFct lp, i = 0 ELSE RtLpIntSupply5minFct lp, i = Min [ 1, RtLpInj5minQty lp, i / RtLpWdr5minQty lp, i ]
(b.8)
RtSlInj5minQty s, lp, i = (–1) * { Min ( 0,
SltoLp5minMap s, lp, i *
a
[ RtBillMtr5minQty a, s, –
i
– DaClrdHrlyQty a, s,
DaClrdVHrlyQty a, s,
h Comment [MPRR212.1058]: MPRR212 Awaiting FERC filing
h, t
t
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+
RtImpExp5minQty a, s,
i, t
* (1 – RsgCrdFlgt )
t
–
DaImpExp5minQty a, s,
i, t
Comment [MPRR212.1059]: MPRR212 Awaiting FERC filing
] ) } / 12
t
(b.9)
RtLpInj5minQty lp, i =
RtSlInj5minQty s, lp, i
s
(b.10) IF RtLpInj5minQty lp, i = 0 THEN RtLpExtSupply5minFct lp, i = 0 ELSE RtLpExtSupply5minFct lp, i = Max [ 0, ( 1 – (RtLpWdr5minQty lp, i / RtLpInj5minQty lp, i ) ) ] (b.11) IF RtLpInj5minQty lp, i = 0 THEN RtLpIwaMlc5minPrc lp, i = 0 ELSE RtLpIwaMlc5minPrc lp, i =
[RtSlInj5minQty s, lp, i * RtMlc5minPrc s, i ]
s
/ RtLpInj5minQty lp, i
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(b.12) RtSppIwaMlc5minPrc i =
[ RtLpExtSupply5minFct lp, i
lp
*
( RtSlInj5minQty s, lp, i
a, s, lp, i
* RtMlc5minPrc s, i ) ]
s
/
[ RtLpExtSupply5minFct lp, i * RtLpInj5minQty lp, i ]
lp
(c)
RtAoSlLpLrsHrlyFct a, s, lp, h = RtAoSlWdrHrlyQty a, s, lp, h / RtAoLpWdrHrlyQty lp, h
(c.1)
RtAoSlWdrHrlyQty a, s, lp, h =
Max ( 0, SltoLp5minMap s, lp, i * { [ ( RtBillMtr5minQty a, s, i
i
– DaClrdHrlyQty a, s, h +
Comment [MPRR212.1060]: MPRR212 Awaiting FERC filing
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt )
t
– DaImpExp5minQty
+ (IF RtIncrOclHrlyAmth < 0
a, s, i, t
Comment [MPRR212.1061]: MPRR212 Awaiting FERC filing
t
THEN 0 ELSE 1) *
-
source
RtEnFinHrlyQty a, s, h, t -
t
-
Comment [MPRR212.1062]: MPRR212 Awaiting FERC filing
RtPseudoTie5minQty a, source, sink(s), i ) ]
RtNEnFinHrlyQty a, s, h, t
t
DaEnFinHrlyQty a, s, h, t -
t
DaNEnFinHrlyQty a, s, h, t }
t
Comment [MPRR212.1063]: MPRR212 Awaiting FERC filing Field Code Changed Field Code Changed
/ 12)
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(c.2) RtAoLpWdrHrlyQty lp, h =
a
RtAoSlWdrHrlyQty a, s, lp, h
s
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtOclDistDlyAmt a, s, lp, d =
RtOclDistHrlyAmt a, s, lp, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtOclDistAoAmt a, m, d =
s
RtOclDistDlyAmt a, s, lp, d
lp
(4) 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: RtOclDistMpAmt m, d =
RtOclDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtOclDistHrlyAmt a, s, lp, h
$
Hour
RtPseudoTieLossSpp5minAmt i
$
Dispatch Interval
RtPseudoTie5minQty a, source, sink, i
MW
Dispatch Interval Dispatch Interval
Real-Time Over Collected Losses Distribution Amount per AO per Settlement Location in Loss Pool lp per Hour - The amount to AO a for AO a’s share of total over/under collection due to marginal losses at Settlement Location s in Loss Pool lp for the Hour. Real-Time SPP Total Pseudo-Tie Losses Amount per Dispatch Interval - The total amount for losses on Pseudo-Ties in Dispatch Interval i. Real-Time Pseudo-Tie Quantity per Asset Owner per source-sink path per Dispatch Interval – The value described under Section 4.5.9.26. Real-Time Pseudo-Tie Losses Amount per Asset Owner per sourcesink path per Dispatch Interval - The value described under 4.5.9.27 for AO a on path source to sink in Dispatch Interval i. For the purpose
RtPseudoTieLoss5minAmt
a, source,
$
sink,(s), i
of its inclusion in the calculation of the Loss Rebate Factor the sink (s) notation is an indication that value is collected at the sink Settlement Location.
none
Hour
RtSlRbtHrlyFct s, lp, h
$
Hour
RtSlRbt5minFct
$
Dispatch Interval
$
Hour
RtNormLpRbtHrlyFct
s, lp, i
RtSppRbtHrlyFct h
Version 23.a
lp, h
Real-Time Normalized Loss Rebate Factor per Loss Pool per Hour – The percentage of RtIncrOclHrlyAmt h allocated to Loss Pool lp for the Hour. Real-Time Loss Rebate Factor per Settlement Location per Loss Pool per Hour – The sum of RtSlRbt5minFct s, lp, i at Settlement Location s in Loss Pool lp for the Hour. Real-Time Loss Rebate Factor per Settlement Location per Loss Pool per Dispatch Interval– The amount of marginal loss dollars calculated at Settlement Location s in Loss Pool lp for the Dispatch Interval. Real-Time Loss Rebate Factor per Hour – The SPP total of RtLpRbtHrlyFct lp, h for the Hour.
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Variable
Unit
Settlement Interval
Definition
RtLpRbtHrlyFct lp, h
$
Hour
RtIncrOclHrlyAmt h
$
Hour
DaOclHrlyAmt h
$
Hour
RtIncrOcl5minAmt i
$
Dispatch Interval
RtLpIntSupply5minFct lp, i
none
Dispatch Interval
RtLpExtSupply5minFct lp, i
none
Dispatch Interval
RtLpIwaMlc5minPrc lp, i
$/MWh
Dispatch Interval
RtSppIwaMlc5minPrc i
$/MWh
Dispatch Interval
MW
Dispatch Interval
Real-Time Loss Rebate Factor per Loss Pool per Hour – The amount of marginal loss dollars collected in Loss Pool lp for the Hour. Real-Time Incremental Over Collected Losses Amount per Hour – The sum of RtIncrOcl5minAmt i for the Hour. Day-Ahead Over Collected Losses Amount per Hour – The amount of over collection in the DA Market due to marginal losses for the Hour. Real-Time Incremental Over Collected Losses Amount per Dispatch Interval – The amount of over/under collection in the RTBM due to marginal losses for the Dispatch Interval. Real-Time Loss Pool Internal Supply Factor per Loss Pool per Dispatch Interval – A ratio indicating the percentage of Loss Pool lp’s net withdrawals that are being served by net RTBM Energy injections inside of Loss Pool lp in Dispatch Interval i. Real-Time Loss Pool External Supply Factor per Loss Pool per Dispatch Interval – A ratio indicating the percentage of Loss Pool lp’s net RTBM Energy injections that are in excess of Loss Pool lp’s net RTBM Energy withdrawals in Dispatch Interval i. Real-Time Loss Pool Injection Weighted Average Marginal Loss Component per Loss Pool per Dispatch Interval - The weighted average RtMlc5minPrc s, i for all net RTBM Energy injections in loss pool lp in Dispatch Interval i. Real-Time SPP Injection Weighted Average Marginal Loss Component per Dispatch Interval - The weighted average of RtMlc5minPrc s, i for all loss pool net RTBM Energy injections in excess of loss pool net RTBM Energy withdrawals in Dispatch Interval i. Real-Time Net Injection Quantity per Loss Pool per Dispatch Interval – The net RTBM Energy injection quantity in Loss pool lp in Dispatch Interval i.
RtLpInj5minQty , lp, i
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtSlInj5minQty s, lp, i
MWh
Dispatch Interval
RtLpWdr5minQty
MW
Dispatch Interval
None
Hour
RtAoSlWdrHrlyQty a, s, lp, h
MWh
Hour
RtAoLpWdrHrlyQty lp, h
MWh
Hour
RtSlWdr5minQty s, lp, i
MWh
Dispatch Interval
SltoLp5minMap s, lp, i
none
Dispatch Interval
$/MWh
Dispatch Interval
Real-Time Net Injection Quantity per Settlement Location per Loss Pool per Dispatch Interval – Settlement Location s’s net RTBM Energy injection quantity in Loss pool lp in Dispatch Interval i. Real-Time Net Withdrawal Quantity per Settlement Location per Loss Pool per Dispatch Interval – The net RTBM Energy withdrawal quantity in Loss pool lp in Dispatch Interval i. Real-Time Loss Pool Load Ratio Share per AO per Settlement Location per Loss Pool per Hour – The ratio of AO a’s The net RTBM Energy withdrawal at Settlement Location s to the total The net RTBM Energy withdrawals in Loss pool lp in Hour h. Real-Time Net Market Energy Asset Owner Withdrawal per AO per Settlement Location per Loss Pool per Hour – The positive value of the sum of the difference between AO a’s RTBM Energy and its DA Market Energy instruments at Settlement Location s in Loss pool lp in Hour h. Real-Time Net Market Energy Withdrawal per Loss Pool per Hour – The sum of net RTBM Energy Asset Owner withdrawal in Loss pool lp in Hour h. Real-Time Net Withdrawal Quantity per Settlement Location per Loss Pool per Dispatch Interval – Settlement Location s’s net RTBM Energy withdrawal quantity in Loss Pool lp in Dispatch Interval i. Settlement Location to Loss Pool Map per Settlement Location per Loss Pool per Dispatch Interval - The portion of injection or withdrawal at Settlement Location s associated with Loss Pool lp for Dispatch Interval i. Real-Time LMP – The value described under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.
lp, i
RtAoSlLpLrsHrlyFct a, s, lp, h
RtLmp5minPrc s, i
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Variable
RtMcc5minPrc
s, i
DaLmpHrlyPrc s, h DaMccHrlyPrc
Unit
Settlement Interval
Definition
$/MWh
Dispatch Interval
$/MWh
Hour
Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of Real-Time LMP at Settlement Location s for Dispatch Interval i. Day-Ahead LMP – The value described under Section 4.5.8.1 at Settlement Location s for Hour h. Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The value described under Section 4.5.8.14 at Settlement Location s for Hour h. Real-Time Marginal Losses Component of Real-Time LMP – The Marginal Losses Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i. Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.1 for AO a at Settlement Location s for Hour h. Non-Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.2 for AO a at Settlement Location s for Hour h. Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h. Day-Ahead Non-Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h. Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1 for AO a at Settlement Location s for Hour h.
$/MWh
s, h
Hour
$/MWh
Dispatch Interval
MWh
Hour
RtNEnFinHrlyQty a, s, t, h
MWh
Hour
DaEnFinHrlyQty a, s, h, t
MWh
Hour
DaNEnFinHrlyQty a, s, h, t
MWh
Hour
RtMlc5minPrc s, i
RtEnFinHrlyQty a, s,
DaClrdHrlyQty a, s, h
Version 23.a
t, h
MWh
Hour
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Comment [MPRR212.1065]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1066]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1067]: MPRR212 Awaiting FERC filing
Comment [MPRR212.1068]: MPRR212 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
MWh
Hour
DaImpExp5minQty a, s, i, t
MW
Dispatch Interval
RtImpExp5minQty a, s,
MW
Dispatch Interval
none
none
Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Transaction per Hour in the DA Market – The value described under Section 4.5.8.3 for AO a at Settlement Location s in for transaction t for Hour h. Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.8.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i. Real-Time Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.9.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.
MW
Dispatch Interval
MW$
Dispatch Interval
RtOclDistDlyAmt a, s, lp, d
$
Operating Day
RtOclDistAoAmt a, m,
$
Operating Day
DaClrdVHrlyQty a, s,
h, t
i, t
RsgCrdFlgt
(Not Available on Settlement Statement) RtBillMtr5minQty a, s,
i
RtNetInadvertentSpp5minAmt i
Version 23.a
d
Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for AO a at Settlement Location s in for Dispatch Interval i. Real-Time SPP Net Inadvertent Energy Amount per Dispatch Interval – The value calculated under Section 4.5.12. Real-Time Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool Operating Day - The amount to AO a for AO a’s share of total over/under collection due to marginal losses at Settlement Location s in Loss Pool lp for the Operating Day. Real-Time Over Collected Losses Distribution Amount per AO per Operating Day- The amount to AO a associated with Market Participant m for AO a’s share of total over/under collection due to marginal losses for the Operating Day.
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
$
Operating Day
a s h i t
none none none none none
none none none none none
d lp m
none none none
none none none
Real-Time Over Collected Losses Distribution Amount per MP per Operating Day- The amount to MP m for MP m’s share of total over/under collection due to marginal losses for the Operating Day. An Asset Owner. A Settlement Location. An Hour. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. An Operating Day. A Loss Pool. A Market Participant.
RtOclDistMpAmt m, d
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4.5.9.21
Real-Time Joint Operating Agreement Amount
(1) A RTBM credit or charge for RTBM congestion management coordination between SPP and JOA counterparties will be calculated for each Asset Owner counterparty as specified in the applicable JOA and distributed/collected from Market Participants through the RNU charge type as described under Section 4.5.12. Charges and credits for this activity will be represented under the following charge type: #RtJoaHrlyAmt a, h, f = JOA Calculated Charge or Credit
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The above variables are defined as follows: Variable
RtJoaHrlyAmt a, h, f
a h f
Version 23.a
Unit
Settlement Interval
$
Hour
none none none
none none none
Definition
Real-Time Joint Operating Agreement Amount per Asset Owner per Hour - The RTBM amount to SPP from the JOA counterparty AO or from SPP to the JOA counterparty AO for the calculated JOA congestion management coordination amount in Hour h. Note use of the Asset Owner subscript for the counterparty does not require that counterparty to become a Market Participant or be represented by a Market Participant. This is only required in this case to effectuate an automated billing mechanism. An Asset Owner. An Hour. A flowgate identified in the applicable JOA.
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4.5.9.22 (1)
Real-Time Reserve Sharing Group Amount
An RTBM credit or charge for requested assistance provided between Reserve Sharing Group following a Resource contingency will be calculated for each RSG Asset Owner counterparty to account for differences between LMP at the External Interface Settlement Location and the contract rate between the applicable RSG member and SPP. Import transactions will include external RSG member transmission charges. Charges and credits for this activity will be calculated as follows: IF RsgCrdFlgt = 1 THEN #RtRsg5minAmt a, s, i, t = RtImpExp5minQty a, s, i, t * Max ( 0, RsgContractPrc a, i, t - RtLmp5minPrc s, i ) / 12 + RsgTransAmt a, t, i
(2)
For each RSG Asset Owner, an hourly amount is calculated at the applicable External Interface Settlement Location between the RSG member and SPP. The amount is calculated as follows: RtRsgHrlyAmt a, s, h =
i
(3)
For each RSG Asset Owner, a daily amount is calculated. The daily amount is calculated as follows: RtRsgDlyAmt a, d =
RtRsgHrlyAmt a, s, h h
(4)
( RtRsg5minAmt a, s, i, t )
t
s
For each RSG Market Participant, a daily amount is calculated representing the sum of RSG Asset Owner amounts associated with that RSG Market Participant. The daily amount is calculated as follows: RtRsgMpAmt m, d =
RtRsgDlyAmt a, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Dispatch Interval
RsgCrdFlgt
None
None
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgContractPrc a, i, t
$/MWh
Dispatch Interval
RsgTransAmt a, t, i
$/MWh
Dispatch Interval
Real-Time Reserve Sharing Group Agreement Amount per RSG Asset Owner per Settlement Location per Dispatch Interval per Reserve Sharing Event Transaction - The RTBM amount to SPP from the RSG counterparty AO for assistance provided by SPP or the RTBM amount from SPP to the RSG counterparty AO for assistance provided by the RSG counterparty for Reserve Sharing Event transaction t at interface Settlement Location s in Dispatch Interval i. Note use of the Asset Owner subscript for the counterparty does not require that counterparty to become an actual Market Participant. This is only required in this case to effectuate an automated billing mechanism. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8. Real-Time Interchange Transaction Quantity per RSG AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2 associated with RSG schedules. Reserve Sharing Group Contract Price per AO per Dispatch Interval per Transaction – The Energy price specified in the RSG Agreement to be applied to RSG Energy Schedules for assistance provided by SPP BA to an External RSG member and assistance provided by an External RSG member to the SPP BA. Reserve Sharing Group Transmission Charge per AO per Dispatch Interval per Transaction – The transmission charge in the RSG Agreement to be applied to RSG Energy Schedules for assistance provided by an External RSG member to the SPP BA.
RtRsg5minAmt a, s, i, t
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtRsgHrlyAmt a, s, h
$
Hour
RtRsgDlyAmt a, d
$
Operating Day
RtRsgMPAmt m, d
$
Operating Day
none none none
none none none
Real-Time Reserve Sharing Group Agreement Amount per Asset Owner per Settlement Location per Hour - The RTBM amount to SPP from the RSG counterparty AO for assistance provided by SPP or the RTBM amount from SPP to the RSG counterparty AO for assistance provided by the RSG counterparty at interface Settlement Location s in Hour h. Note use of the Asset Owner subscript for the counterparty does not require that counterparty to become an actual Market Participant. This is only required in this case to effectuate an automated billing mechanism. Real-Time Reserve Sharing Group Agreement Amount per RSG Asset Owner per Operating Day - The RTBM amount to SPP from the RSG counterparty AO for assistance provided by SPP or the RTBM amount from SPP to the RSG counterparty AO for assistance provided by the RSG counterparty in Operating Day d. Note use of the Asset Owner subscript for the counterparty does not require that counterparty to become an actual Market Participant. This is only required in this case to effectuate an automated billing mechanism. Real-Time Reserve Sharing Group Agreement Amount per RSG Market Participant per Operating Day - The RTBM amount to SPP from the RSG counterparty MP for assistance provided by SPP or the RTBM amount from SPP to the RSG counterparty MP for assistance provided by the RSG counterparty in Operating Day d. Note use of the Market Participant subscript for the counterparty does not require that counterparty to become an actual Market Participant . This is only required in this case to effectuate an automated billing mechanism. An RSG Market Participant. An RSG Asset Owner. An Hour.
m a h
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Market Protocols for SPP Integrated Marketplace
Variable
i t
Version 23.a
Unit
Settlement Interval
Definition
none none
none none
A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction.
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4.5.9.23
Real-Time Reserve Sharing Group Distribution Amount
(1) A RTBM charge or credit will be calculated for each Asset Owner for each Settlement Location for each hour. The Asset Owner amount will be equal to the Asset Owner’s realtime load ratio share of the Real-Time Reserve Sharing Group Amount. The amount to each Asset Owner is calculated as follows: #RtRsgDistHrlyAmt a, s, h = RtRsgSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1) Where, RtRsgSppHrlyAmt h =
RtRsgHrlyAmt a, h
a
(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtRsgDistDlyAmt a, s, d =
RtRsgDistHrlyAmt a, s, h
h
(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRsgDistAoAmt a, m, d =
RtRsgDistDlyAmt a, s, d
s
(4) 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: RtRsgDistMpAmt
m, d
=
RtRsgDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
Ratio
Hour
RtRsgHrlyAmt a, h
$
Hour
RtRsgSppHrlyAmt h
$
Hour
RtRsgDistDlyAmt a, s, d
$
Operating Day
RtRsgDistAoAmt a, m, d
$
Operating Day
RtRsgDistMpAmt
$
Operating Day
Real-Time Reserve Sharing Group Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtRsgHrlyAmt a, h at Settlement Location s in Hour h. Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11. Real-Time Reserve Sharing Group Amount per AO per Hour – The value calculated under Section 4.5.9.22. Real-Time Reserve Sharing Group Amount per AO per Hour – The SPP total of the values calculated under Section 4.5.9.22 in Hour h. Real-Time Reserve Sharing Group Distribution Amount per AO per Settlement Location per Operating Day - The amount to AO a for total Reserve sharing group charges/credit in Operating Day d. Real-Time Reserve Sharing Group Distribution Amount per AO per Operating Day- The amount to AO a associated with Market Participant m for total Reserve Sharing Group charges/credits in Operating Day d. Real-Time Reserve Sharing Group Distribution Amount per MP per Operating Day The amount to MP m for total Reserve Sharing Group charges/credits in Operating Day d. An Asset Owner. A Settlement Location. An Hour. An Operating Day. A Market Participant.
RtRsgDistHrlyAmt a, s, h
RtLoadRatioShareHrlyFct a, s, h
a s h d m
Version 23.a
m, d
none none none none none
none none none none none
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Market Protocols for SPP Integrated Marketplace
4.5.9.24 (1)
Real-Time Demand Reduction Amount
A RTBM Market credit or charge associated with the difference between each actual Demand Response Resource output and amounts cleared in the Day-Ahead Market will be calculated for the Asset Owner associated with the host load Settlement Location which includes the associated Demand Response Load for each hour. This amount is required in order to remove the settlement impact of grossing up the host load by the amount of associated Demand Response Resource output (i.e. settlement of host load should reflect actual metered amount). The net amount is calculated as follows: #RtDR5minAmt a, s, i = (
RtLoadGrossUp5minQty a, s (host), ml, i - DaLoadGrossUpHrlyQty a, s (host), h ) ml
* RtLmp5minPrc s (host), i * (-1) / 12 (2)
For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtDRHrlyAmt a, s, h =
RtDR5minAmt a, s, i
i
(3)
For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtDRDlyAmt a, s, d =
RtDRHrlyAmt a, s, h
h
(4)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtDRAoAmt a, m, d =
RtDRDlyAmt a, s, d
s
(5)
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:
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Market Protocols for SPP Integrated Marketplace
RtDRMpAmt m, d =
RtDRAoAmt a, m, d
a
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545
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Hour
RtLoadGrossUp5minQty a, s, i
MW
Dispatch Interval
RtLoadGrossUp5minQty a, s, ml, i
MW
Dispatch Interval
DaLoadGrossUpHrlyQty a, s, h
MWh
Hour
RtLmp5minPrc s, i
$/MW
Dispatch Interval
Real-Time Demand Reduction Amount per AO per Settlement Location per Hour - The RTBM amount to AO a for Demand Reduction at Settlement Location s for Dispatch Interval i. Real-Time Load Gross-Up Quantity per AO per Settlement Location per Dispatch Interval - The sum of Demand Response deployed in the RTBM associated with AO a’s host load Settlement Location s in Dispatch Interval i. Real-Time Load Gross Up per AO per Meter Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 at Meter Data Submittal Location associated with host Settlement Location s for Dispatch Interval i. Day-Ahead Load Gross-Up Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.21 for AO a at host Settlement Location s for Hour h. Real-Time LMP - The value defined under Section 4.5.9.1 at host Settlement Location s for Dispatch Interval i.
RtDRHrlyAmt a, s, d
$
Operating Day
RtDRDlyAmt a, s, d
$
Operating Day
RtDRAoAmt a, m, d
$
Operating Day
RtDR5minAmt a, s, i
Version 23.a
Real-Time Demand Reduction Amount per AO per Settlement Location per Hour - The RTBM amount to AO a for Demand Reduction at Settlement Location s for Hour h. Real-Time Demand Reduction Amount per AO per Settlement Location per Operating Day - The RTBM amount to AO a for Demand Reduction at Settlement Location s for the Operating Day. Real-Time Demand Reduction Amount per AO per Operating Day The RTBM amount to AO a associated with Market Participant m for Demand Reduction for the Operating Day.
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Variable RtDRMpAmt m, d
a s h i d m
Version 23.a
Unit
Settlement Interval
$
Operating Day
none none none none none none
none none none none none none
Definition
Real-Time Demand Reduction Amount per Market Participant per Operating Day - The RTBM amount to Market Participant m for Demand Reduction for the Operating Day. An Asset Owner. A Settlement Location. An Hour. A Dispatch Interval. An Operating Day. A Market Participant.
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4.5.9.25 (1)
Real-Time Demand Reduction Distribution Amount
An RTBM Market charge or credit will be calculated for each Asset Owner for each Settlement Location for each hour in which a Demand Response Resource was dispatched in order to allocate the amounts calculated under Section 4.5.9.24. The Settlement Location amount will be equal to the distribution rate for Demand Reduction multiplied by the Settlement Locations’ actual real-time Energy withdrawals. The amount to each Settlement Location is calculated as follows: #RtDRDistHrlyAmt a, s, h = RtDRLoadHrlyQty a, s, h * RtDRDistHrlyRate h Where, (a)
#RtDRLoadHrlyQty a, s, h = [ Max ( 0,
RtBillMtr5minQty a, s, i )
i
+ Max ( 0,
i
RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt ) ) ] /12
t
The cost allocation rate is calculated by dividing the total of all demand reduction credits by the total of allocation quantities. (b)
#RtDRDistHrlyRate h = RtDRDistHrlyCost h / RtDRDistHrlyQty h
(b.1)
RtDRDistHrlyCost (
=
RtDRHrlyAmt a, s, h ) * -1 a
(b.2)
h
s
RtDRDistHrlyQty h =
a
Version 23.a
RtDRLoadHrlyQty a, s, h
s
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(2)
For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily amount is calculated as follows: RtDRDistDlyAmt a s, d =
RtDRDistHrlyAmt a, s, h
h
(3)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtDRDistAoAmt a m, d =
RtDRDistDlyAmt a, s, d
s
(4)
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: RtDRDistMpAmt m, d =
RtDRDistAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtDRDistHrlyAmt a, s, h
$
Hour
RtDRLoadHrlyQty a, s, h
MWh
Hour
RtDRDistHrlyRate h
$/MWh
Hour
RtDRDistHrlyCost h
$
Hour
RtDRDistHrlyQty h
MWh
Hour
RtDRHrlyAmt a, s, h
$
Hour
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
Real-Time Demand Reduction Distribution Amount per Hour - The amount to AO a for AO a’s share of RTBM Demand Reduction costs per Settlement Location per Hour. Real-Time Demand Reduction Load per AO per Settlement Location for Hour h – Asset Owner a’s load and Export Interchange Transactions in the RTBM at Settlement Location s for Hour h for use in Demand Reduction cost allocation. Real-Time Demand Reduction Distribution Rate per Hour – The rate applied to AO a’s Demand Reduction load in Hour h. Real-Time Demand Reduction Distribution Cost per Hour – The cost of Demand Reduction in Hour h. Real-Time Demand Reduction Distribution Quantity per Hour – The total zonal cost allocation quantity for Demand Reduction in Hour h. Real-Time Demand Reduction Amount per AO per Settlement Location per Hour - The value described under Section 4.5.9.24. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgCrdFlgt
none
none
$
Operating Day
(Not Available on Settlement Statement) RtDRDistAoAmt a, m, d
Version 23.a
Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8. Real-Time Demand Reduction Distribution Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for Demand Reduction for the Operating Day.
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Variable
Unit
Settlement Interval
RtDRDistMpAmt m, d
$
Operating Day
RtDRDistDlyAmt a, s, d
$
Operating Day
a
none
none
Real-Time Demand Reduction Distribution Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for Demand Reduction for the Operating Day. Real-Time Demand Reduction Distribution Amount per Settlement Location per Operating Day - The DA Market amount to Settlement Location a associated with AO a for Demand Reduction for the Operating Day. An Asset Owner.
s
none
none
A Settlement Location.
h
none
none
An Hour.
i
none
none
A Dispatch Interval.
d
none
none
An Operating Day.
m
none
none
A Market Participant.
Version 23.a
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4.5.9.26 (1)
Real-Time Pseudo-Tie Congestion Amount
An RTBM charge or credit will be calculated for each Resource or load, internal to the SPP footprint, that has pseudo-tied out of the SPP Balancing Authority for each Dispatch Interval of the Operating Day. The amount is calculated as follows: #RtPseudoTieCong5minAmt a, source, sink, i = RtPseudoTie5minQty a, source, sink, i * (RtMcc5minPrc sink, i – RtMcc5minPrc source, i ) / 12
(2)
For each Asset Owner, an hourly amount is calculated on each source to sink path. The amount is calculated as follows:
RtPseudoTieCongHrlyAmt a, source, sink, h =
RtPseudoTieCong5minAmt a, source, sink, i
i
(3)
For each Asset Owner, a daily amount is calculated on each source to sink path. The amount is calculated as follows: RtPseudoTieCongDlyAmt a, source, sink, d =
RtPseudoTieCongHrlyAmt a, source, sink, h
h
(4)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:
RtPseudoTieCongAoAmt a, m, d =
source
(5)
RtPseudoTieCongDlyAmt a, source, sink, d
sin k
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: RtPseudoTieCongMpAmt m, d =
RtPseudoTieCongAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtPseudoTieCong5minAmt a, source, sink, i
$
Dispatch Interval
MW
Dispatch Interval
RtMcc5minPrc source, i
$/MWh
Dispatch Interval
RtMcc5minPrc sink, i
$/MWh
Dispatch Interval
RtPseudoTieCongHrlyAmt a, source, sink, h
$
Hour
RtPseudoTieCongDlyAmt a, source, sink, d
$
Operating Day
RtPseudoTieCongAoAmt a, m, d
$
Operating Day
Real-Time Pseudo-Tie Congestion Amount per Asset Owner per source-sink path per Dispatch Interval - The amount for PseudoTie congestion on path source to sink for AO a in Dispatch Interval i. Real-Time Pseudo-Tie Quantity per Asset Owner per source-sink path per Dispatch Interval - The telemetered Pseudo-Tie flow on path source to sink for AO a in Dispatch Interval i. Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of the Real-Time LMP at the Settlement Location of the source point specified on the Pseudo-Tie path for Dispatch Interval i. Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of the Real-Time LMP at the Settlement Location of the sink point specified on the PseudoTie path for Dispatch Interval i. Real-Time Pseudo-Tie Congestion Amount per Asset Owner per source-sink path per Hour - The amount for Pseudo-Tie congestion on path source to sink for AO a in Hour h. Real-Time Pseudo-Tie Congestion Amount per Asset Owner per source-sink path per Operating Day - The amount for Pseudo-Tie congestion on path source to sink for AO a for the Operating Day Real-Time Pseudo-Tie Congestion Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie congestion on all paths for AO a associated with Market Participant m for the Operating Day.
RtPseudoTie5minQty a, source, sink, i
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Market Protocols for SPP Integrated Marketplace
Variable RtPseudoTieCongMpAmt m, d
Unit
Settlement Interval
Definition
$
Operating Day
Real-Time Pseudo-Tie Congestion Amount per Market Participant per Operating Day - The amount for Pseudo-Tie congestion on all paths for MP m for the Operating Day. An Asset Owner. The Settlement Location identified as the source point of a Pseudo-Tie. The Settlement Location identified as the sink point of a PseudoTie. An Hour. A Dispatch Interval. An Operating Day. A Market Participant.
a Source
none none
none none
Sink
none
none
h i d m
none none none none
none none none none
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Market Protocols for SPP Integrated Marketplace
4.5.9.27
Real-Time Pseudo-Tie Losses Amount
(1) An RTBM charge or credit will be calculated for each Resource or load, internal to the SPP footprint, that has pseudo-tied out of the SPP Balancing Authority for each Dispatch Interval of the Operating Day. The amount is calculated as follows: #RtPseudoTieLoss5minAmt a, source, sink, i = RtPseudoTie5minQty a, source, sink, i * (RtMlc5minPrc sink, i – RtMlc5minPrc source, i ) / 12
(2) For each Asset Owner, an hourly amount is calculated on each source to sink path. The amount is calculated as follows:
RtPseudoTieLossHrlyAmt a, source, sink, h =
RtPseudoTieLoss5minAmt a, source, sink, i
i
(3) For each Asset Owner, a daily amount is calculated on each source to sink path. The amount is calculated as follows: RtPseudoTieLossDlyAmt a, source, sink, d =
RtPseudoTieLossHrlyAmt a, source, sink, h
h
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:
RtPseudoTieLossAoAmt a, m, d =
source
RtPseudoTieLossDlyAmt a, source, sink, d
sin k
(5) 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: RtPseudoTieLossMpAmt m, d =
RtPseudoTieLossAoAmt a, m, d
a
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Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtPseudoTieLoss5minAmt a, source, sink, i
$
Dispatch Interval
MW
Dispatch Interval
RtMlc5minPrc source, i
$/MWh
Dispatch Interval
RtMlc5minPrc sink, i
$/MWh
Dispatch Interval
RtPseudoTieLossHrlyAmt a, source, sink, h
$
Hour
RtPseudoTieLossDlyAmt a, source, sink, d
$
Operating Day
RtPseudoTieLossAoAmt a, m, d
$
Operating Day
RtPseudoTieLossMpAmt m, d
$
Operating Day
Real-Time Pseudo-Tie Losses Amount per Asset Owner per source-sink path per Dispatch Interval - The amount for PseudoTie losses on path source to sink for AO a in Dispatch Interval i. Real-Time Pseudo-Tie Quantity per Asset Owner per source-sink path per Dispatch Interval - The telemetered Pseudo-Tie flow on path source to sink for AO a in Dispatch Interval i. Real-Time Marginal Losses Component of Real-Time LMP – The Marginal Losses Component of the Real-Time LMP at the Settlement Location of the source point specified on the PseudoTie path for Dispatch Interval i. Real-Time Marginal Losses of Real-Time LMP – The Marginal Losses Component of the Real-Time LMP at the Settlement Location of the sink point specified on the Pseudo-Tie path for Dispatch Interval i. Real-Time Pseudo-Tie Losses Amount per Asset Owner per source-sink path per Hour - The amount for Pseudo-Tie losses on path source to sink for AO a in Hour h. Real-Time Pseudo-Tie Losses Amount per Asset Owner per source-sink path per Operating Day - The amount for Pseudo-Tie losses on path source to sink for AO a for the Operating Day Real-Time Pseudo-Tie Losses Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie losses on all paths for AO a associated with Market Participant m for the Operating Day. Real-Time Pseudo-Tie Losses Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie losses on all paths for MP m for the Operating Day. An Asset Owner.
RtPseudoTie5minQty a, source, sink, i
A
Version 23.a
none
none
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Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Source
none
none
Sink
none
none
H I D M
none none none none
none none none none
Version 23.a
Definition
The Settlement Location identified as the source point of a Pseudo-Tie. The Settlement Location identified as the sink point of a PseudoTie. An Hour. A Dispatch Interval. An Operating Day. A Market Participant.
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Market Protocols for SPP Integrated Marketplace
4.5.9.28 (1)
Comment [MPRR204.1069]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount
A RTBM credit will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval when that Asset Owner is charged for Unused Regulation-Up Mileage at a rate that is in excess of the Asset Owner’s Regulation-Up Mileage Offer to the extent the Resource’s Regulation-Up Service margin is not sufficient to offset the charge induced by the difference in the two rates. The amount will be calculated as follows:
Comment [MPRR102.1175]: MPRR102 Awaiting implementation. #ER13-1748.
Comment [MPRR204.1070]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1071]: MPRR204 Awaiting FERC approval Docket #ER13-1748
#RtRegUpUnusedMileMwp5minAmt a, s, i = Where, (a)
DaRegUpUnusedMileMwp5minAmt a, s, i =
[ Max ( 0, DaRegUpMargin5minAmt a, s, i + PotDaRegUpMileMwp5minAmt a, s, i ) ] *(-1) (a.1)
#DaRegUpMargin5minAmt a, s, i = Min { 0, Cast h to i [ ( DaRegUpHrlyAmt a, h, s + IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND (
Field Code Changed
DaRegUpHrlyQty a, z, s, h <= DaFixedRegUpHrlyQty a, s, h)
z
THEN 0 ELSE DaRegUpAvailHrlyAmt a, h, s } ) / 12 ] -
Field Code Changed
[ Min [ 0, ( RtRegUp5minQty a, z, s, i
z
-
Field Code Changed
IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND
z
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Market Protocols for SPP Integrated Marketplace
(
Field Code Changed
DaRegUpHrlyQty a, z, s, h <= DaFixedRegUpHrlyQty a, s, h)
z
THEN 0 ELSE
Field Code Changed
DaRegUpHrlyQty a, z, s, h } ) ]
z
* ( RtRegUpMcp5minPrc z, i - DaRegUpOffer a, s, i ) / 12 ] } (a.2)
#PotDaRegUpMileMwp5minAmt a, s, i = Max [ 0, ( ( RtRegUpMileMcp5minPrc i - DaRegUpMileOffer5minPrc a, s, i ) * DaRegUpUnusedMile5minQty a, s, i ) ] / 12
(a.2.1)
DaRegUpUnusedMile5minQty a, s, i = RtRegUpUnusedMile5minQty a, s, i * { IF RtRegUp5minQty a, s, i = 0 THEN 1 ELSE Min ( 1, DaRegUpHrlyQty a, s, h / RtRegUp5minQty a, s, i ) }
(b)
RtRegUpUnusedMileMwp5minAmt a, s, i = [ Max (0, RtRegUpMargin5minAmt a, s, i + PotRtRegUpMileMwp5minAmt a, s, i ] * (-1)
(b.1) #RtRegUpMargin5minAmt a, s, i = Min { 0, ( RtRegUpRev5minAmt a, s, i + RtRegUpAvail5minAmt a, s, i ) / 12 ) } (b.3)
#PotRtRegUpMileMwp5minAmt a, s, i = Max( 0, RtRegUpMileMcp5minPrc i
Version 23.a
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Market Protocols for SPP Integrated Marketplace
- RtRegUpMileOffer5minPrc a, s, i ) * ( RtRegUpUnusedMile5minQty a, s, i - DaRegUpUnusedMile5minQty a, s, i ) / 12
Min ( 0, RtRegUpMileOffer5minPrc a, z, s, i - RtRegUpMileMcp5minPrc i )
z
* RtRegUpUnusedMile5minQty a, z, s, i
Comment [MPRR204.1072]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtRegUpUnusedMileMwpHrlyAmt a, s, h =
RtRegUpUnusedMileMwp5minAmt a, s,
i
Comment [MPRR204.1073]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1074]: MPRR204 Awaiting FERC approval Docket #ER13-1748
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The amount is calculated as follows: RtRegUpUnusedMileMwpDlyAmt a, s, d =
RtRegUpUnusedMileMwpHrlyAmt a, s, h
h
Comment [MPRR204.1075]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1076]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegUpUnusedMileMwpAoAmt a, m, d =
RtRegUpUnusedMileMwpDlyAmt a, s, d
s
Comment [MPRR204.1077]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1078]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(5) 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: RtRegUpUnusedMileMwpMpAmt m, d =
Comment [MPRR204.1079]: MPRR204 Awaiting FERC approval Docket #ER13-1748
RtRegUpUnusedMileMwpAoAmt a, m, d
Comment [MPRR204.1080]: MPRR204 Awaiting FERC approval Docket #ER13-1748
a
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(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Unused Regulation-Up Mileage Make Whole Payment quantity and Real-Time Unused Regulation-Up Mileage Make Whole Payment $ per Dispatch Interval for each Asset Owner as follows: (a)
EqrRtRegUpUnusedMileMwp5minPrc a, s, i =
Comment [MPRR204.1081]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(-1) * RtRegUpUnusedMileMwp5minAmt a, s, i (b)
Comment [MPRR204.1082]: MPRR204 Awaiting FERC approval Docket #ER13-1748
EqrRtRegUpUnusedMileMwp5minPrc a, s, i > 0
Comment [MPRR204.1083]: MPRR204 Awaiting FERC approval Docket #ER13-1748
THEN EqrRtRegUpUnusedMileMwp5minQty a, s, i = 1
Version 23.a
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561
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement
Definition
Interval RtRegUpUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
DaRegUpUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
RtRegUpUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
PotDaRegUpMileMwp5minAmt a, s, i
PotRtRegUpMileMwp5minAmt a, s, i
Version 23.a
$
$
Dispatch Interval
Dispatch Interval
Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval. Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i. Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i. Potential Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Day-Ahead Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i Potential Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Real-Time Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.
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Comment [MPRR204.1085]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1086]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1087]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1088]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1089]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1090]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval DaRegUpMargin5minAmt a, s, i
$
Dispatch Interval
MW
Hour
DaFixedRegUpHrlyQty a, s, h
DaClrdComStatHrlyFlg h, s, c
DaRegUpHrlyAmt a, s, h
Hour
$
Hour
DaRegUpAvailHrlyAmt a, s, h
$
Hour
RtRegUpMargin5minAmt a, s, h
$
Dispatch Interval
RtRegUpRev5minAmt a, s, i
RtRegUpAvail5minAmt a, s, i
Version 23.a
$
$
Dispatch Interval Dispatch Interval
Day-Ahead No Regulation-Up Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve Regulation-Up Service cleared in the Day-Ahead for Market AO a at Resource Settlement Location s for Dispatch Interval i Day-Ahead Fixed Regulation-Up Quantity per AO per Resource Settlement Location per Hour – The Fixed Regulation-Up MW specified in the Regulation-Up Offer associated with AO a’s Resource Settlement Location s in Hour h. Day-Ahead Commitment Status Hourly Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – The value described under Section 4.5.8.12 Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.4 Day-Ahead Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Hour - The value described under Section 4.5.8.12 Real-Time No Regulation-Up Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve net Regulation-Up Service cleared in the RTBM for Market AO a at Resource Settlement Location s for Dispatch Interval i Real-Time Regulation-Up Service Revenue Amount per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.8 Real-Time Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval - The amount calculated under Section 4.5.9.8
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Comment [MPRR204.1091]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1092]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1093]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1094]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1095]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1096]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1097]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1098]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval RtRegUpMileMcp5minPrc i
$/MW
Dispatch Interval
Real-Time MCP for Regulation-Up Mileage - The RTBM MCP for Excess Regulation-Up Mileage for Dispatch Interval i.
RtRegUpMileOffer5minPrc a, z, s, i
$/MW
Dispatch Interval
DaRegUpOffer a, s, i
$/MW
Dispatch Interval
Real-Time Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s RegulationUp Mileage Offer for Resource Settlement Location s for Dispatch Interval i in Reserve Zone z. Day-Ahead Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s RegulationUp Service Offer for Resource Settlement Location s for Dispatch Interval i Real-Time MCP for Regulation-Up Service per Reserve Zone The value described under Section 4.5.9.4
RtRegUpMcp5minPrc z, i DaRegUpMileOffer5minPrc a, s, i
$/MW $/MW
Dispatch Interval Dispatch Interval
RtRegUpUnusedMile5minQty a, z, s, i
MW
Dispatch Interval
DaRegUpUnusedMile5minQty a, s, i
MW
Dispatch Interval
RtRegUp5minQty a, z, s, i
MW
Dispatch Interval
DaRegUpHrlyQty a, z, s, h
MW
Hour
Version 23.a
Day-Ahead Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s RegulationUp Mileage Offer for Resource Settlement Location s for Dispatch Interval i. Real-Time Unused Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.4. Day-Ahead Unused Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Up Mileage associated with the Day-Ahead Market at Resource Settlement Location s for Dispatch Interval i. Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4 Day-Ahead Cleared Regulation-Up Quantity per AO per Settlement Location per Hour – The value described under
12/4/2014
564
Comment [MPRR204.1099]: MPRR204 Awaiting FERC filing Comment [MPRR204.1100]: MPRR204 Awaiting FERC filing
Comment [MPRR204.1101]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1102]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1103]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1104]: MPRR204 Awaiting FERC filing
Comment [MPRR204.1105]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1106]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval RtRegUpUnusedMileMwpHrlyAmt a, s, h
RtRegUpUnusedMileMwpDlyAmt a, s, d
RtRegUpUnusedMileMwpAoAmt a, m, d
RtRegUpUnsedMileMwpMpAmt m, d
EqrRtRegUpUnusedMileMwp5minQty a, s, i
Version 23.a
$
$
$
$
MW
Hour
Operating Day
Operating Day
Operating Day
Dispatch Interval
Section 4.5.9.5 Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Hour - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the hour. Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Operating Day - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Operating Day. Real-Time Unused Regulation-Up Make Whole Payment Amount per AO per Operating Day - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole for the Operating Day. Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day - The amount to Mp m for Undeployed Regulation-Up Mileage Make Whole Payments for the Operating Day. Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Make Whole Payment Quantity per AO per Settlement Location per Dispatch Interval– This value is set equal to 1 if EqrRtRegUpUnusedMileMwp5minPrc a, s, i > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements..
12/4/2014
565
Comment [MPRR204.1107]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1108]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1109]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1110]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1111]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1112]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1113]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1114]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1115]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1116]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1117]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1118]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval EqrRtRegUpUnsedMileMwp5minPrc a, s, i
a s h i Cast h to i d z m
Version 23.a
$/MW
none none none none none none none none
Dispatch Interval
none none none none none none none none
Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval – The Unused Regulation-Up Mileage make-whole amount to AO a for Dispatch Interval i at Resource Settlement Location s for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements. An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. A function which places the value of an hourly determinant into each of the intervals within the hour. An Operating Day. A Reserve Zone. A Market Participant.
12/4/2014
566
Comment [MPRR204.1119]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1120]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1121]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
4.5.9.29
Comment [MPRR204.1122]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount
(1) A RTBM credit will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval when that Asset Owner is charged for Unused Regulation-Down Mileage at a rate that is in excess of the Asset Owner’s Regulation-Down Mileage Offer to the extent the Resource’s Regulation-Down Service margin is not sufficient to offset the charge induced by the difference in the two rates. The amount will be calculated as follows:
Comment [MPRR204.1123]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1124]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1125]: MPRR204 Awaiting FERC approval Docket #ER13-1748
#RtRegDnUnusedMileMwp5minAmt a, s, i = DaRegDnUnusedMileMwp5minAmt a, s, i + RtRegDnUnusedMileMwp5minAmt a, s, i Where, (a)
DaRegDnUnusedMileMwp5minAmt a, s, i = [ Max ( 0, DaRegDnMargin5minAmt a, s, i
+ PotDaRegDnMileMwp5minAmt a, s, i ) ] * (-1) (a.1)
#DaRegDnMargin5minAmt a, s, i = Min { 0, Cast h to i [ ( DaRegDnHrlyAmt a, h, s + IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND (
Field Code Changed
DaRegDnHrlyQty a, z, s, h <= DaFixedRegDnHrlyQty a, s, h)
z
THEN 0 ELSE DaRegDnAvailHrlyAmt a, h, s } ) / 12 ] -
Field Code Changed
[ Min [ 0, ( RtRegDn5minQty a, z, s, i
z
Version 23.a
12/4/2014
567
Market Protocols for SPP Integrated Marketplace
-
Field Code Changed
IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND
z
(
Field Code Changed
DaRegDnHrlyQty a, z, s, h <= DaFixedRegDnHrlyQty a, s, h)
z
THEN 0 ELSE
Field Code Changed
DaRegDnHrlyQty a, z, s, h } ) ]
z
* ( RtRegDnMcp5minPrc z, i - DaRegDnOffer a, s, i ) / 12 ] } (a.2)
#PotDaRegDnMileMwp5minAmt a, s, i = Max [ 0, ( ( RtRegDnMileMcp5minPrc i - DaRegDnMileOffer5minPrc a, s, i ) * DaRegDnUnusedMile5minQty a, s, i ) ] / 12
(a.2.1)
DaRegDnUnusedMile5minQty a, s, i = RtRegDnUnusedMile5minQty a, s, i * { IF RtRegDn5minQty a, s, i =0, THEN 1 ELSE Min ( 1, DaRegDnHrlyQty a, s, h / RtRegDn5minQty a, s, i ) }
(b)
RtRegDnUnusedMileMwp5minAmt a, s, i = [ Max (0, RtRegDnMargin5minAmt a, s, i + PotRtRegDnMileMwp5minAmt a, s, i ] * (-1)
(b.1) #RtRegDnMargin5minAmt a, s, i = Min { 0, ( RtRegDnRev5minAmt a, s, i + RtRegDnAvail5minAmt a, s, i ) / 12 ) } (b.3)
Version 23.a
#PotRtRegDnMileMwp5minAmt a, s, i =
12/4/2014
568
Market Protocols for SPP Integrated Marketplace
Max( 0, RtRegDnMileMcp5minPrc i - RtRegDnMileOffer5minPrc a, s, i ) * ( RtRegDnUnusedMile5minQty a, s, i - DaRegDnUnusedMile5minQty a, s, i ) / 12
Min ( 0, RtRegDnMileOffer5minPrc a, z, s, i - RtRegDnMileMcp5minPrc i )
z
* RtRegDnUnusedMile5minQty a, z, s, i
Comment [MPRR204.1126]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:
RtRegDnUnusedMileMwpHrlyAmt a, s, h =
RtRegDnUnusedMileMwp5minAmt a, s,
i
Comment [MPRR204.1127]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1128]: MPRR204 Awaiting FERC approval Docket #ER13-1748
i
(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The amount is calculated as follows: RtRegDnUnusedMileMwpDlyAmt a, s, d =
RtRegDnUnusedMileMwpHrlyAmt a, s, h
h
Comment [MPRR204.1129]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1130]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(4) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRegDnUnusedMileMwpAoAmt a, m, d =
RtRegDnUnusedMileMwpDlyAmt a, s, d
s
(5) 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:
Version 23.a
12/4/2014
569
Comment [MPRR204.1131]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1132]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
RtRegDnUnusedMileMwpMpAmt m, d =
Comment [MPRR204.1133]: MPRR204 Awaiting FERC approval Docket #ER13-1748
RtRegDnUnusedMileMwpAoAmt a, m, d
Comment [MPRR204.1134]: MPRR204 Awaiting FERC approval Docket #ER13-1748
a
(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Unused Regulation-Down Mileage Make Whole Payment quantity and Real-Time Unused Regulation-Up Mileage Make Whole Payment $ per Dispatch Interval for each Asset Owner as follows: (a)
EqrRtRegDnUnusedMileMwp5minPrc a, s, i =
Comment [MPRR204.1135]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(-1) * RtRegDnUnusedMileMwp5minAmt a, s, i (b)
Comment [MPRR204.1136]: MPRR204 Awaiting FERC approval Docket #ER13-1748
EqrRtRegDnUnusedMileMwp5minPrc a, s, i > 0
Comment [MPRR204.1137]: MPRR204 Awaiting FERC approval Docket #ER13-1748
THEN EqrRtRegDnUnusedMileMwp5minQty a, s, i = 1
Version 23.a
12/4/2014
Comment [MPRR204.1138]: MPRR204 Awaiting FERC approval Docket #ER13-1748
570
Market Protocols for SPP Integrated Marketplace
The above variables are defined as follows: Variable
Unit
Settlement
Definition
Interval RtRegDnUnusedMileMwp5minAmt a, s, i
DaRegDnUnusedMileMwp5minAmt a, s, i
$
$
Dispatch Interval
Dispatch Interval
RtRegDnUnusedMileMwp5minAmt a, s, i
$
Dispatch Interval
PotDaRegDnMileMwp5minAmt a, s, i
$
Dispatch Interval
PotRtRegDnMileMwp5minAmt a, s, i
$
Dispatch Interval
Version 23.a
Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval. Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i. Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i. Potential Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Day-Ahead Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i Potential Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Real-Time Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.
12/4/2014
571
Comment [MPRR204.1139]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1140]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1141]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1142]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1143]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1144]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval DaRegDnMargin5minAmt a, s, i
$
Dispatch Interval
DaClrdComStatHrlyFlg h, s, c
None
Hour
DaFixedRegDnHrlyQty a, s, h
MW
Hour
DaRegDnHrlyAmt a, s, h
DaRegDnAvailHrlyAmt a, s, h
$
$
Hour
Hour
RtRegDnMargin5minAmt a, s, h
$
Dispatch Interval
RtRegDnRev5minAmt a, s, i
$
Dispatch Interval
Version 23.a
Day-Ahead No Regulation-Down Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve Regulation-Down Service cleared in the Day-Ahead for Market AO a at Resource Settlement Location s for Dispatch Interval i Day-Ahead Commitment Status Hourly Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – The value described under Section 4.5.8.12 Day-Ahead Fixed Regulation-Down Quantity per AO per Resource Settlement Location per Hour – The Fixed RegulationDown MW specified in the Regulation-Down Offer associated with AO a’s Resource Settlement Location s in Hour h. Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.5 Day-Ahead Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Hour - The value described under Section 4.5.8.12 Real-Time No Regulation-Down Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve net Regulation-Down Service cleared in the RTBM for Market AO a at Resource Settlement Location s for Dispatch Interval i Real-Time Regulation-Down Service Revenue Amount per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.8
12/4/2014
572
Comment [MPRR204.1145]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1146]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1147]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1148]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1149]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1150]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1151]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval RtRegDnAvail5minAmt a, s, i
$
Dispatch Interval
RtRegDnMileMcp5minPrc i
$/MW
Dispatch Interval
RtRegDnMileOffer5minPrc a, z, s, i
$/MW
Dispatch Interval
DaRegDnOffer a, s, i
$/MW
Dispatch Interval
RtRegDnMcp5minPrc z, i
$/MW
Dispatch Interval
$/MW
Dispatch Interval
RtRegDnUnusedMile5minQty a, z, s, i
MW
Dispatch Interval
DaRegDnUnusedMile5minQty a, s, i
MW
Dispatch Interval
DaRegDnMileOffer5minPrc a, s, i
Version 23.a
Real-Time Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval - The amount calculated under Section 4.5.9.8 Real-Time MCP for Regulation-Down Mileage - The RTBM MCP for Excess Regulation-Down Mileage for Dispatch Interval i. Real-Time Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s RegulationDown Mileage Offer for Resource Settlement Location s for Dispatch Interval i in Reserve Zone z. Day-Ahead Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s RegulationDown Service Offer for Resource Settlement Location s for Dispatch Interval i Real-Time MCP for Regulation-Down Service per Reserve Zone The value described under Section 4.5.9.5 Day-Ahead Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-Down Mileage Offer for Resource Settlement Location s for Dispatch Interval i. Real-Time Unused Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.5. Day-Ahead Unused Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Down Mileage associated with the Day-Ahead Market at Resource Settlement Location s for Dispatch Interval i.
12/4/2014
573
Comment [MPRR204.1152]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1153]: MPRR204 Awaiting FERC filing Comment [MPRR204.1154]: MPRR204 Awaiting FERC filing
Comment [MPRR204.1155]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1156]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1157]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1158]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval RtRegDn5minQty a, z, s, i
MW
Dispatch Interval
DaRegDnHrlyQty a, z, s, h
MW
Hour
RtRegDnUnusedMileMwpHrlyAmt a, s, h
RtRegDnUnusedMileMwpDlyAmt a, s, d
RtRegDnUnusedMileMwpAoAmt a, m, d
RtRegDnUnsedMileMwpMpAmt m, d
Version 23.a
$
$
$
$
Hour
Operating Day
Operating Day
Operating Day
Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5 Day-Ahead Cleared Regulation-Down Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.9.5 Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Settlement Location per Hour - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the hour. Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Settlement Location per Operating Day - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Operating Day. Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Operating Day - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole for the Operating Day. Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day - The amount to Mp m for Undeployed Regulation-Down Mileage Make Whole Payments for the Operating Day.
12/4/2014
574
Comment [MPRR204.1159]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1160]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1161]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1162]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1163]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1164]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1165]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1166]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1167]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1168]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement
Definition
Interval EqrRtRegDnUnusedMileMwp5minQty a, s, i
EqrRtRegDnUnsedMileMwp5minPrc a, s, i
MW
$/MW
Dispatch Interval
Dispatch Interval
a s h i Cast h to i
none none none none none
none none none none none
d z m
none none none
none none none
Version 23.a
Real-Time Electric Quarterly Reporting Unused RegulationDown Mileage Make Whole Payment Quantity per AO per Settlement Location per Dispatch Interval– This value is set equal to 1 if EqrRtRegDnUnusedMileMwp5minPrc a, s, i > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.. Real-Time Electric Quarterly Reporting Unused RegulationDown Mileage Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval – The Unused Regulation-Down Mileage make-whole amount to AO a for Dispatch Interval i at Resource Settlement Location s for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements. An Asset Owner. A Resource Settlement Location. An Hour. A Dispatch Interval. A function which places the value of an hourly determinant into each of the intervals within the hour. An Operating Day. A Reserve Zone. A Market Participant.
12/4/2014
575
Comment [MPRR204.1169]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1170]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1171]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1172]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR204.1173]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR204.1174]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Market Protocols for SPP Integrated Marketplace
4.5.10
ARR and TCR Auction Settlement
The charges and credits to ARR holders and TCR holders resulting from the annual and monthly TCR auctions described under Section 5 are calculated on a daily basis and included on the Settlement Statements consistent with the timing of the DA Market settlement and Real-Time Balancing Market settlement. (1)
(2)
(3)
TCR Bid and Offer Settlement from TCR Auction (a)
For each period and round in the Annual TCR Auction and each month and round in the Monthly TCR Auction, each Market Participant is charged or credited for each TCR purchased.
(b)
For each period and round in the Annual TCR Auction and each month and round in the Monthly TCR Auction, each Market Participant that sold a TCR is credited or charged for each TCR sold.
(c)
For each period, the amounts calculated above are divided by the numbers of days in the period and then included as daily charges and credits.
ARR Settlement from TCR Auction (a)
For each period in the Annual ARR Allocation, each Market Participant is credited (or charged) for each ARR awarded based on the source and sink Auction Clearing Prices for each round associated with the Annual TCR Auction and the Monthly TCR Auction.
(b)
For each period, the amounts calculated above are divided by the numbers of days in the period and then included as daily charges and credits.
Revenue Neutrality
Version 23.a
(a)
For each day, if net charges collected under TCR Settlements as described in (1) above are less than the net credits paid under ARR Settlements described in (2) above, the deficiency will be collected from ARR holders in proportion to absolute value of their ARR instrument economic values as described under (2)(a) above.
(b)
For each day, if net charges collected under TCR Settlements are greater than the net credits paid under ARR Settlements, the excess is carried forward to the end of the month and used to payback ARR holders from whom daily deficiency was
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576
Market Protocols for SPP Integrated Marketplace
collected in that month and any remaining excess is carried forward to the end of year. (c)
At the end of the year, excess carried forward from the monthly process is used to payback ARR holders from whom daily deficiency was collected in the year and that was not refunded during the monthly process.
(d)
To the extent that the net charges collected under TCR Settlements are greater than the net credits paid under ARR Settlements and ARR holders from whom daily deficiency was collected in the year have been fully reimbursed in the monthly and end-of-year processes, the excess is distributed to ARR holders in proportion to their ARR Nomination Caps.
The following subsections describe the ARR/TCR auction settlement charge types. For each charge type, the initial calculation is performed at the daily level for each Asset Owner and Market Participant for the sum of all ARRs and TCRs awarded. Each charge type calculation is described in the following subsections. 4.5.10.1
Transmission Congestion Rights Auction Transaction Amount
(1) A Transmission Congestion Rights auction charge or credit for each Asset Owner is calculated for each TCR instrument purchased or sold in the TCR auctions. The amount to each applicable Asset Owner for each auction and round is calculated as follows. #TcrAucTxnDlyAmt a, aid, d =
{ ( TcrAucQty a,
t ,aid, source, sink
* TcrAucPrc aid, source, sink )
t
* TcrAucBuySellFlg a, t / NumDaysInPeriod aid } Where, TcrAucPrc aid, source, sink = AuctionClearingPrice aid, source - AuctionClearingPrice aid, sink (2) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows:
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TcrAucTxnAoAmt a, m, d =
TcrAucTxnDlyAmt a, aid, d
aid
(3) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows: TcrAucTxnMpAmt m, d =
TcrAucTxnAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
TcrAucTxnDlyAmt a, aid, d
$
Operating Day
TcrAucQty a, t, aid, source, sink
MW
Month or Season
$/MW
Month or Season
TcrAucBuySellFlg a, t
none
Month or Season
NumDaysInPeriod aid
none
none
$/MW
Month or Season
$/MW
Month or Season
$
Operating Day
Transmission Congestion Right Auction Daily Amount per AO per Auction ID per Operating Day – The amount to AO a for purchases and sales of TCRs for Operating Day d for TCR auction ID aid. Transmission Congestion Right Quantity per AO per Transaction per Auction ID per Source and Sink – AO a’s TCR quantity purchased or sold for each transaction t in any TCR auction aid at the associated source and sink point. Transmission Congestion Right Auction Clearing Price per Auction ID – The TCR Auction clearing prices for TCR auction aid at the associated source and sink point. Transmission Congestion Right Auction Buy/Sell Flag per AO per Transaction – A flag indicating whether AO a’s TcrAucQty a, t, aid, source, sink was a purchase or a sale. This flag is set equal to +1 for purchases or to (-1) for sales. Number of Days in the Period associated per Auction ID – The number of Operating Days in month or seasons associated with TCR Auction ID aid. TCR Auction Clearing Price per Auction ID at the Sink - The Auction clearing prices for TCR auction aid at the associated sink point. Auction Clearing Price per Auction ID at the Source - The Auction clearing prices for TCR auction aid at the associated source point. Transmission Congestion Right Auction Daily Amount per AO per Operating Day – The amount to AO a for purchases and sales of TCRs for Operating Day.
TcrAucPrc
aid, source, sink
AuctionClearingPrice aid, sink
(Not Available on Settlement Statement) AuctionClearingPrice aid,
source
(Not Available on Settlement Statement) TcrAucTxnAoAmt a, m, d
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Variable
Unit
Settlement Interval
Definition
$
Operating Day
a t
none none
none none
aid m source
none none none
none none none
sink
none
none
Transmission Congestion Right Auction Daily Amount per MP per Operating Day – The amount to MP m for purchases and sales of TCRs in the annual and monthly TCR Auctions for Operating Day d. An Asset Owner. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. TCR Auction ID (separate ID for each round and type). A Market Participant. The Settlement Location identified as the source point for TCR t. The Settlement Location identified as the sink point for TCR t.
TcrAucTxnMpAmt m, d
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4.5.10.2
Auction Revenue Rights Funding Amount
(1) ARRs are valued at the prices from the annual and monthly TCR auctions during the lifetime of the instrument. The quantity of ARRs settled for each auction and round is a fraction of the instrument as a whole. These fractions are described under Section 5.6. An Auction Revenue Rights charge or credit for each Asset Owner for each auction and round is calculated as follows. #ArrAucTxnDlyAmt a, aid, d =
Source Sink
{ ( ( ArrQty a, aid, source, sink * TcrAucPrc
aid, source, sink
)
/ NumDaysInPeriod aid ) * (-1) } (2) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows: ArrAucTxnAoAmt a, m, d =
ArrAucTxnDlyAmt a, aid, d
aid
(3) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows: ArrAucTxnMpAmt m, d =
ArrAucTxnAoAmt a, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
$
Operating Day
MW
Month or Season
$/MW
Month or Season
none
none
ArrAucTxnAoAmt a, m, d
$
Operating Day
ArrAucTxnMpAmt m, d
$
Operating Day
a t
none none
none none
aid m
none none
none none
Auction Revenue Rights Daily Amount per AO per TCR Auction ID per Operating Day– The ARR revenue amount to AO a for Operating Day d for TCR Auction ID aid. Auction Revenue Right Quantity per AO per Transaction per Auction ID per Source and Sink – AO a’s total ARR award quantity on the associated source and sink that is subject to reduction for settlement purposes based on the rules listed under Section 5.6 for related TCR auction ID aid. Transmission Congestion Right Auction Clearing Price per Month per Auction Type per Transaction per Auction Round – The value defined under Section 4.5.10.1 Number of Days in the Month – The value defined under Section 4.5.10.1 Auction Revenue Rights Daily Amount per AO per Operating Day– The ARR revenue amount to AO a for Operating Day d. Auction Revenue Right Daily Amount per MP per Operating Day – The amount to MP m for all ARR awards for Operating Day d. An Asset Owner. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. TCR Auction ID (separate ID for each round and type). A Market Participant.
ArrAucTxnDlyAmt a, aid, d
ArrQty a, aid, source, sink
TcrAucPrc
aid,, source, sink
NumDaysInPeriod aid
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Variable
Unit
Settlement Interval
Definition
source
none
none
sink
none
none
The Settlement Location identified as the source point for TCR t. The Settlement Location identified as the sink point for TCR t.
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4.5.10.3
Auction Revenue Rights Uplift Amount
(1) A charge will be calculated for each Asset Owner holding ARRs for each auction and round for each Operating Day to the extent that TCR auction revenues collected in each auction and round over the Operating Day are not sufficient to fund the net of the total amounts calculated under Section 4.5.10.2 for each auction and round over the Operating Day. The amount is calculated as follows: #ArrUpliftDlyAmt a, aid, d = TcrArrUnderDlyAmt aid, d * [ ABS ( ArrAucTxnDlyAmt a, aid, d ) / ArrAucTxnSppDlyAmt aid, d ] Where, (a)
ArrAucTxnSppDlyAmt aid, d =
ABS (ArrAucTxnDlyAmt a, aid, d )
a
(b)
TcrArrUnderDlyAmt aid, d =
(-1) * Min ( TcrAucTxnDlyAmt a, aid, d + a
ArrAucTxnDlyAmt a, aid, d , 0 ) a
(2) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows: ArrUpliftAoAmt a, m, d =
ArrUpliftDlyAmt a, aid, d
aid
(3) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows: ArrUpliftMpAmt m, d =
ArrUpliftAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
ArrUpliftDlyAmt a, aid, d
$
Operating Day
TcrArrUnderDlyAmt aid, d
$
Operating Day
ArrAucTxnSppDlyAmt aid, d
$
Operating Day
ArrAucTxnDlyAmt a, aid, d
$
Operating Day
TcrAucTxnDlyAmt
$
Operating Day
ArrUpliftAoAmt a, m, d
$
Operating Day
ArrUpliftMpAmt
$
Operating Day
Auction Revenue Rights Daily Uplift Amount per AO per TCR Auction ID per Operating Day - The uplift amount to AO a associated with shortfalls in TCR auction revenues required to fully fund ARRs associated for Operating Day d and TCR auction ID aid. Auction Revenue Rights Under Funding Amount per TCR Auction ID per Operating Day – The amount by which the net amounts under Section 4.5.10.2 are underfunded in Operating Day d for TCR auction ID aid. Auction Revenue Rights Daily Amount per TCR Auction ID per Operating Day– The SPP total of the absolute value of the values calculated under Section 4.5.10.2. Auction Revenue Rights Funding Amount per AO per TCR Auction ID per Operating Day - The value calculated under Section 4.5.10.2. Transmission Congestion Right Auction Daily Amount per AO per TCR Auction ID per Operating Day – The value calculated under Section 4.5.10.1. Auction Revenue Rights Daily Uplift Amount per AO per Operating Day - The uplift amount to AO a associated with shortfalls in TCR auction revenues required to fully fund ARRs associated for Operating Day d. Auction Revenue Rights Daily Uplift Amount per MP per Operating Day - The uplift amount associated with shortfalls in TCR auction revenues required to fully fund ARRs to MP m for all AO’s associated with Market Participant m for Operating Day d.
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m, d
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Variable
a d aid m
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Unit
Settlement Interval
none none none none
none none none none
Definition
An Asset Owner. An Operating Day. TCR Auction ID (separate ID for each round and type). A Market Participant.
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4.5.10.4
Auction Revenue Rights Monthly Payback Amount
(1) A monthly credit or charge29 will be calculated for each Asset Owner receiving charges under Section 4.5.10.3 over the month in order to ensure full funding of ARRs to the extent possible. The amount is calculated as follows: #ArrPaybackMnthlyAmt a, mn = (-1) * Min { ArrUpliftAoMnthlyAmt a, mn , ARFMnthlyAmt mn * ArrUpliftAoMnthlyAmt a, mn / ArrUpliftSppMnthlyAmt mn } Where, (a)
ArrUpliftAoMnthlyAmt a, mn =
(b)
ArrUpliftSppMnthlyAmtmn =
a
(c)
ARFMnthlyAmt mn =
ArrUpliftDlyAmt a, aid, d
aid
d
d
ArrUpliftDlyAmt a, aid, d
aid
ARFDlyAmt d
d
(c.1)
ARFDlyAmt d = Max { 0,
a
[ ArrAucTxnDlyAmt a, aid, d + TcrAucTxnDlyAmt a, aid, d ] }
aid
(2) For each Market Participant, a monthly amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The monthly amount is calculated as follows: ArrPaybackMnthlyMpAmt m, mn =
ArrPaybackMnthlyAmt a, mn
a
29
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
ArrPaybackMnthlyAmt a, mn
$
Month
ARFMnthlyAmt mn
$
Month
ARFDlyAmt d
$
Operating Day
Auction Revenue Rights Monthly Payback Amount per AO per month - AO a’s share of the ARFMnthlyAmt mn in month mn limited to the amount required to fully fund AO a’s ARRs in month mn. Auction Revenue Fund Monthly Amount – The sum of ARFDlyAmt d in month mn. Auction Revenue Fund Daily Amount – The net excess between Auction Revenue Rights and TCR Auction collections for Operating Day d.
ArrAucTxnDlyAmt a, aid, d
$
TcrAucTxnDlyAmt a, aid, d
$
ArrUpliftDlyAmt a, aid, d
$
ArrUpliftAoMnthlyAmt a, mn
$
Operating Day Operating Day Operating Day Month
ArrUpliftSppMnthlyAmt mn
$
Year
ArrPaybackMnthlyMpAmt m, mn
$
Month
none none none none none
none none none none none
a d mn aid yr
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Auction Revenue Rights Funding Amount per TCR Auction ID per AO per Operating Day - The value calculated under Section 4.5.10.2. Transmission Congestion Right Auction Daily Amount per TCR Auction ID per AO per Operating Day – The value calculated under Section 4.5.10.1. Auction Revenue Rights Daily Uplift Amount per AO per TCR Auction ID per Operating Day - The value calculated under Section 4.5.10.3. Auction Revenue Rights Monthly Uplift Amount per AO per Month - The sum of AO a’s values calculated under Section 4.5.10.3 for month mn. Auction Revenue Rights Daily Uplift Amount per Year - The SPP total of the sum of all AO’s ArrUpliftAoMnthlyAmt a, yr for the year. Auction Revenue Rights Annual Payback Amount per MP per Year - MP a’s share of the ARFMnthlyAmt yr in year yr. limited to the amount required to fully fund MP m’s ARRs. An Asset Owner. An Operating Day. A month. TCR Auction ID (separate ID for each round and type). A year.
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Variable
m
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Unit
Settlement Interval
none
none
Definition
A Market Participant.
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4.5.10.5
Auction Revenue Rights Annual Payback Amount
(1) An annual credit or charge30 will be calculated for each Asset Owner receiving charges under Section 4.5.10.3 over the year that were not fully reimbursed in the monthly payback process in order to ensure full funding of ARRs to the extent possible. The amount is calculated as follows: #ArrPaybackYrlyAmt a, yr = (-1) * Min { ArrNetUpliftAoYrlyAmt a, yr , ARFYrlyAmt yr * ArrNetUpliftAoYrlyAmt a, yr / ArrNetUpliftSppYrlyAmt yr } Where, (a)
ArrNetUpliftAoYrlyAmt a, yr =
d
(b)
ArrUpliftDlyAmt a, aid, d +
aid
ArrPaybackMnthlyAmt a, mn
mn
ArrNetUpliftSppYrlyAmt yr =
ArrNetUpliftAoYrlyAmt a, yr
a
(c)
ARFYrlyAmt yr =
ARFMnthlyAmt mn +
mn
a
ArrPaybackMnthlyAmt a, mn
mn
(2) For each Market Participant, an annual amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The annual amount is calculated as follows: ArrPaybackYrlyMpAmt m, yr =
ArrPaybackYrlyAmt a, yr
a
30
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
ArrPaybackYrlyAmt a, yr
$
Year
ARFYrlyAmt yr
$
Year
ArrUpliftDlyAmt a, aid, d
$
ArrNetUpliftAoYrlyAmt a, yr
$
Operating Day Year
ArrNetUpliftSppYrlyAmt yr
$
Year
ArrPaybackYrlyMpAmt m, yr
$
Month
none none none none none
none none none none none
Auction Revenue Rights Annual Payback Amount per AO per year - AO a’s share of the ARFYrlyAmt yr in year yr limited to the amount required to fully fund AO a’s ARRs. Auction Revenue Fund Yearly Amount – The total excess TCR auction revenues remaining at the end of year yr after taking into account the total amounts paid under the monthly payback process in year yr. Auction Revenue Rights Daily Uplift Amount per AO per TCR Auction ID per Operating Day - The value calculated under Section 4.5.10.3. Auction Revenue Rights Net Uplift Amount per AO per Year - The total ARR uplift remaining to reimbursed for AO a in year yr. Auction Revenue Rights Net Uplift Amount per Year - The SPP total of the total ARR uplift remaining to reimbursed in year yr. Auction Revenue Rights Annual Payback Amount per MP per Year - MP a’s share of the ARFYrlyAmt yr in year yr. limited to the amount required to fully fund MP m’s ARRs. An Asset Owner. An Operating Day. A month. A year. A Market Participant.
a d mn yr m
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4.5.10.6
Auction Revenue Rights Annual Closeout Amount
(1) An annual credit or charge31 will be calculated for each Asset Owner with ARR Nomination Caps established under Section 5.1.3 to the extent that there are any funds remaining once all credits are paid under Section 4.5.10.4. The calculation for the Auction Revenue Rights Annual Closeout Amount for each Asset Owner with an ARR Nomination Cap can result in residual amounts due to rounding. The sum of the residual amounts due to rounding across Asset Owners can result in the Auction Revenue Rights not being revenue neutral for the year. The difference, whether a credit or charge, will be uplifted to the Asset Owners on a yearly basis. On Operating Day March 1, of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Owners. The Auction Revenue Rights Annual Closeout amount is calculated as follows: #ArrCloseoutYrlyAmt a, yr = (-1) * [ARFYrlyAmt yr + ArrPaybackSppYrlyAmt yr] * [ArrNominationCapAoYrlyQty a, yr / ArrNominationCapSppYrlyQty yr] Where,
ArrPaybackSppYrlyAmt yr =
ArrPaybackYrlyAmt a, yr
a
(2) For each Market Participant, an annual amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The annual amount is calculated as follows: ArrCloseoutYrlyMpAmt m, yr =
ArrCloseoutYrlyAmt a, yr
a
31
Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
ArrCloseoutYrlyAmt a, yr
$
Year
ArrPaybackYrlyAmt a, yr
$
Year
ArrNominationCapAoYrlyQty a, yr
MW
Year
ArrNominationCapSppYrlyQty yr
MW
Year
ArrPaybackSppYrlyAmt yr
$
Year
ARFYrlyAmt yr
$
Year
MW $
Operating Day Year
none none none none
none none none none
Auction Revenue Rights Annual Payback Amount per AO per Year - AO a’s share of any remaining ARFYrlyAmt mn in year yr. Auction Revenue Rights Annual Payback Amount per AO per Year - The value calculated under Section 4.5.8.17. ARR Nomination Cap per AO per Year – The sum of the values described under Section 4.5.8.18 for AO a for year yr. ARR Nomination Cap Total per Year – The value calculated under Section 4.5.8.18. Auction Revenue Rights Annual Payback Amount per Year - The value calculated under Section 4.5.8.18. Auction Revenue Fund Yearly Amount – The sum of ARFMthlyAmt mn in year yr. ARR Nomination Cap per AO per Operating Day – The value described under Section 4.5.8.18. Auction Revenue Rights Annual Payback Amount per MP per Year - MP a’s share of the ARFYrlyAmt yr in year yr. An Asset Owner. An Operating Day. A year. A Market Participant.
ArrNominationCapQty a, d ArrCloseoutYrlyMpAmt m, yr a d yr m
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4.5.11
Miscellaneous Amount
(1)
In certain circumstances, it may be necessary to recalculate or make changes to previously billed charges that cannot be handled though a standard final settlement or resettlement execution for that operating day. This is anticipated to occur only on an exception basis. SPP will manually calculate the adjustment and post as a manual adjustment to the initial, final, and/or resettlement statement, regardless of the Operating Day in question. A comment will be added to the Bill Statement to alert the reader to the reason for the adjustment and the effective Operating Day(s). SPP will post supporting documentation for the manual calculation of any miscellaneous charge to the Portal no later than the time the Settlement Statement including the miscellaneous charge has been posted. In some situations the charge or credit assessed must be excluded from Revenue Neutrality Uplift calculations such that SPP is left with a net receivable or payable amount for the settlement of the OD.
(2)
In addition, through Balancing Authority Agreements with adjacent external Balancing Authorities, SPP may supply Emergency Export Interchange Transactions when requested by the applicable external Balancing Authority or SPP may request, under SPP Emergency conditions, that applicable external Balancing Authorities supply Emergency Import Interchange Transactions to SPP. To the extent that such transactions are confirmed, credits to SPP for Emergency Export Interchange Transactions and charges to SPP for Emergency Import Interchange Transactions are included in this charge type.
(3)
In addition, a local transmission operator may require commitment, decommitment, or dispatch instructions to be issued to one or more Resources in order to solve a reliability issue. Payments to Resource Asset Owners as described under Sections 4.5.9.8, 4.5.9.9 and charges to Asset Owners as described under Section 4.5.9.10 associated with such commitment, decommitment, or dispatch instructions are included in this charge type.
(4)
In addition, SPP may impose penalties for noncompliance with the Day-Ahead Market must-offer requirement as described under Section 4.2.1.1.1. Any penalties assessed to noncompliant Asset Owners, and the distribution of those penalties by load-ratio share, excluding the noncompliant Asset Owners, are included in this charge type.
(5)
A miscellaneous charge type will be utilized for each distinct charge type and any other charges and credits not specifically accounted for under a distinct charge type. Miscellaneous charges and credits to the affected Asset Owners are represented for each Operating Day as follows:
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MiscDlyAmt a, ct, s, rnu, d (6)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows: MiscAoAmt a, m, d =
ct
(7)
s
MiscDlyAmt a, ct, s, rnu, d
rnu
For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows: MiscMpAmt m, d =
MiscAoAmt a, m, d
a
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The above variable is defined as follows: Variable
Unit
Settlement Interval
Definition
MiscDlyAmt a, ct, s, rnu, d
$
Operating Day
MiscAoAmt a, m, d
$
MiscMpAmt m, d
$
Miscellaneous Amount per AO per Settlement Location per Settlement Location per Operating Day – The miscellaneous amount to AO a for charge type ct at Settlement Location s in Operating Day d. Miscellaneous Amount per AO per Operating Day – The total miscellaneous amount to AO a in Operating Day d. Miscellaneous Amount per MP per Operating Day – The total miscellaneous amount to MP m in Operating Day d. Any charge type specified under Sections 4.5.8, 4.5.8.21 or 4.5.9.24 or any other miscellaneous charges not specifically accounted for under a distinct charge type. A Settlement Location.
ct
none
Operating Day Operating Day none
s rnu
none none
none none
d
none
none
Version 23.a
A flag which instructs the settlement system to include the amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N).
An Operating Day.
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4.5.12 (1)
Revenue Neutrality Uplift Distribution Amount A charge or credit will be calculated at each Settlement Location for each Asset Owner for each hour in order for SPP to remain revenue neutral. Contributors to revenue nonneutrality include: (c)
Rounding errors (related to the calculation of all Charges/Credits);
(d)
Inadvertent Interchange (as calculated as shown in equation b.3 below);
(e)
Joint Operating Agreement Charges/Credits;
(f)
RTBM congestion (as calculated as shown in equation b.4 below);
(g)
RTBM Regulation Deployment Adjustment;
(h)
Make-Whole payments for Out-of-Merit Energy; and
(i)
Miscellaneous Charges/Credits.
The amount will be determined by multiplying the Asset Owner hourly determinant by a daily Revenue Neutrality Uplift (RNU) rate. The Asset Owner hourly determinant is equal to the sum that Asset Owner’s actual generation MWh, actual load MWh, actual Interchange Transaction MWh, DA Market cleared Virtual Offer MWh and DA Market cleared Virtual Bid MWh for the Hour, where all of these values are assumed to be positive values. The calculation of the Revenue Neutrality Uplift (RNU) for each Asset Owner and Settlement Location in the SPP footprint can result in residual amounts due to rounding. The sum of the residual amounts due to rounding can result in SPP not being revenue neutral for the Operating Day. The residual amounts for each Operating Day will be summed on a yearly basis. The annual residual amount, whether a credit or a charge, will be uplifted to the Asset Owners and Settlement Locations. On Operating Day March 1 of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Owners and Settlement Locations. The amount to each applicable Asset Owner is calculated as follows. #RtRnuHrlyAmt a, s, h = ( RtRnuSppDistRate d * RtRnuDistHrlyQty a, s, h ) * (-1) Where,
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(a) #RtRnuDistHrlyQty a, s, h = (
ABS (RtBillMtr5minQty a, s, i ) / 12) + (
i
i
(RtImpExp5minQty a, s, i, t )/12) * (1 – RsgCrdFlgt ) ]) + (
[ (ABS
t
ABS (DaClrdVHrlyQty
t
a, s, h, t))
(b)#RtRnuSppDistRate d = ( DaRevInadqcSppAmt spp, d + RtRevInadqcSppAmt spp, d + RtOomSppAmt spp, d + RtRegAdjSppAmt spp, d + RtJoaSppAmt spp, d - RtNetInadvertentSppAmt spp, d + RtCongestionSppAmt spp, d ) / RtRnuDistSppQty spp, d Where, RtOomSppAmt spp, d =
RtOomMpAmt m, d
m
RtRegAdjSppAmt spp, d =
RtRegAdjMpAmt m, d
m
RtJoaSppAmt spp, d =
a
RtRnuDistSppQty spp, d =
h
a
(b.1)
RtJoaHrlyAmt a, h, f
f
s
RtRnuDistHrlyQty a, s, h
h
DaRevInadqcSppAmt spp, d =
( DaEnergyMpAmt m, d + DaNEnergyMpAmt m, d + DaVEnergyMpAmt m, d
m
+ DaGFACarveOutDistMpDlyAmt m, d
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+ DaRegUpMpAmt m, d + DaSpinMpAmt m, d + DaSuppMpAmt m, d + DaRegDnMpAmt m, d + DaRegUpDistMpAmt m, d + DaSpinDistMpAmt m, d + DaSuppDistMpAmt m, d + DaRegDnDistMpAmt m, d + DaMwpMpAmt m, d + DaMwpDistMpAmt m, d + TcrFundMpAmt m, d + TcrUpliftDlyMpAmt m, d + DaOclDistMpAmt m, d + TcrAucTxnMpAmt m, d + ArrAucTxnMpAmt m, d
Comment [MPRR212.1176]: MPRR212 Awaiting FERC filing
+ ArrUpliftMpAmt m, d + DaDRMpAmt m, d + DaDRDistMpAmt m, d ) ECFDlyAmt d - ARFDlyAmt d + GFARevInadqcSppAmt spp, d -
Comment [MPRR212.1177]: MPRR212 Awaiting FERC filing
DaOclHrlyAmt h
Field Code Changed
h
(b.2) RtRevInadqcSppAmt spp, d =
( RtEnergyMpAmt m, d + RtNEnergyMpAmt m, d + RtVEnergyMpAmt m, d
m
+ RtRegUpMpAmt m, d + RtRegDnMpAmt m, d + RtSpinMpAmt m, d + RtSuppMpAmt m, d + RtMwpMpAmt m, d + RtMwpDistMpAmt m, d + RtRegNonPerfMpAmt m, d + RtRegNonPerfDistMpAmt m, d + RtCRDeplFailMpAmt m, d + RtOclDistMpAmt m, d + RtCRDeplFailDistMpAmt m, d + RtRegUpDistMpAmt m, d + RtRegDnDistMpAmt m, d
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+ RtRegUpUnusedMileMwpMpAmt m, d
Comment [MPRR204.1178]: MPRR204 Awaiting FERC approval Docket #ER13-1748
+ RtRegDnUnusedMileMwpMpAmt m, d
Comment [MPRR204.1179]: MPRR204 Awaiting FERC approval Docket #ER13-1748
+ RtSpinDistMpAmt m, d + RtSuppDistMpAmt m, d
Comment [MPRR102.1180]: MPRR102 Awaiting implementation. #ER13-1748
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+ RtRsgDistMpAmt m, d + RtDRMpAmt m, d + RtDRDistMpAmt m, d + RtPseudoTieCongMpAmt m, d + RtPseudoTieLossMpAmt m, d +
RtRsgDlyAmt a, d )
a
+
c
a
{ IF rnu = 1, THEN MiscDlyAmt a, c, s, rnu, d , ELSE 0 } +
s
RtNetInadvertentSppAmt spp, d - RtCongestionSppAmt spp, d +
Comment [MPRR212.1181]: MPRR212 Awaiting FERC filing
DaOclHrlyAmt h
Field Code Changed
h
(b.3)
RtNetInadvertentSppAmt spp, d =
RtNetInadvertentSpp5minAmt
i
i
(b.3.1) #RtNetInadvertentSpp5minAmt i = ( ( RtNetActIntrchngSpp5minQty i - RtNetSchIntrchngSpp5minQty i ) * RtMec5minPrc i ) / 12 (b.4)
#RtCongestionSppAmt spp, d = RtPseudoTieCongSppAmt d +
a
+
s
( ( ( RtBillMtr5minQty a, s, i – DaClrdHrlyQty a, s, h )
i
(RtImpExp5MinQty a, s, i, t - DaImpExp5MinQty a, s, i, t )
t
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-
DaClrdVHrlyQty a, s, h, t ) * RtMcc5minPrc s, i ) / 12
t
(b.4.1)
RtPseudoTieCongSppAmt d =
RtPseudoTieCongMpAmt m, d
m
(2)
For each Asset Owner, a daily amount is calculated at each Settlement Location. The amount is calculated as follows: RtRnuDlyAmt a, s, d =
RtRnuHrlyAmt a, s, h
h
(3)
For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows: RtRnuAoAmt a, m, d =
RtRnuDlyAmt a, s, d
s
(4)
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: RtRnuMpAmt m, d =
RtRnuAoAmt a, m, d
a
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The above variables are defined as follows: Variable
Unit
Settlement Interval
Definition
RtRnuHrlyAmt a, s, h
$
Hour
RtRnuSppDistRate d
$/MW
Operating Day
RtRnuDistHrlyQty a, s, h
MWh
Hour
RtRnuDistSppQty spp, d
MWh
Operating Day
DaClrdVHrlyQty a, s, h, t
MWh
Hour
RtOomSppAmt spp, d
$
Operating Day
RtRegAdjSppAmt spp, d
$
Operating Day
RtJoaSppAmt spp, d
$
Operating Day
Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Hour – The amount for revenue neutrality to AO a at Settlement Location s in Hour h. Real-Time Revenue Neutrality Uplift SPP Distribution Rate per Operating Day – The rate applied to AO a’s RtRnuDistHrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d. Real-Time Revenue Neutrality Uplift Quantity per AO per Hour per Settlement Location – The total MWh RNU allocation determinant for AO a at Settlement Location s for Hour h. Real-Time Revenue Neutrality Uplift Quantity for SPP per Operating Day – The total MWh RNU allocation determinant for SPP on a system-wide basis. Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour – The value defined under Section 4.5.8.3. Real-Time Out-Of-Merit Make-Whole-Payment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.9. Real-Time Regulation Deployment Adjustment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.18. Real-Time Joint Operating Agreement Amount for SPP per Operating Day – The SPP system-wide total of the values calculated under Section 4.5.9.21.
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Variable
Unit
Settlement Interval
Definition
DaRevInadqcSppAmt spp, d
$
Operating Day
DaEnergyMpAmt m, d
$
Operating Day
Day-Ahead Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total DA Market charges and DA Market credits for Operating Day d. Day-Ahead Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.1.
DaNEnergyMpAmt m, d
$
Operating Day
Day-Ahead Non-Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.2.
DaVEnergyMpAmt m, d
$
Operating Day
Day-Ahead Virtual Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.3.
DaRegUpMpAmt m, d
$
Operating Day
Day-Ahead Regulation-Up Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.4.
Comment [MPRR102.1182]: MPRR102 Awaiting implementation. #ER13-1748
DaRegDnMpAmt m, d
$
Operating Day
Day-Ahead Regulation-Down Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.5.
Comment [MPRR102.1183]: MPRR102 Awaiting implementation. #ER13-1748
DaSpinMpAmt m, d
$
Operating Day
Day-Ahead Spinning Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.6.
DaSuppMpAmt m, d
$
Operating Day
Day-Ahead Supplemental Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.7.
DaRegUpDistMpAmt m, d
$
Operating Day
Day-Ahead Regulation-Up Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.8.
Comment [MPRR102.1184]: MPRR102 Awaiting implementation. #ER13-1748
DaRegDnDistMpAmt m, d
$
Operating Day
Day-Ahead Regulation-Down Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.9.
Comment [MPRR102.1185]: MPRR102 Awaiting implementation. #ER13-1748
DaSpinDistMpAmt m, d
$
Operating Day
Day-Ahead Spinning Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.10.
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Variable
Unit
Settlement Interval
Definition
DaSuppDistMpAmt m, d
$
Operating Day
Day-Ahead Supplemental Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.11.
DaMwpMpAmt m, d
$
Operating Day
Day-Ahead Make-Whole-Payment Amount per MP per Operating Day – The value calculated under Section 4.5.8.12.
DaMwpDistMpAmt m, d
$
Operating Day
Day-Ahead Make-Whole-Payment Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.13.
TcrFundMpAmt m, d
$
Operating Day
Transmission Congestion Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.8.14.
TcrUpliftDlyMpAmt m, d
$
Operating Day
Transmission Congestion Rights Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.8.15.
ECFDlyAmt d
$
Operating Day
Excess Congestion Fund Amount per Operating Day – The value calculated under Section 4.5.8.16.
ARFDlyAmt d
$
Operating Day
Auction Revenue Fund Amount per Operating Day – The value calculated under Section 4.5.10.4.
DaOclDistMpAmt m, d
$
Operating Day
Day-Ahead Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.8.19.
TcrAucTxnMpAmt m, d
$
Operating Day
Day-Ahead Incremental Over Collected Losses Amount per Hour – The value described under Section 4.5.9.20. Transmission Congestion Right Auction Daily Amount per MP per Operating Day – The value calculated under Section 4.5.10.1.
ArrAucTxnMpAmt m, d
$
Operating Day
Auction Revenue Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.10.2.
DaOclHrlyAmt h
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$
Hour
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Comment [MPRR212.1186]: MPRR212 Awaiting FERC filing Comment [MPRR212.1187]: MPRR212 Awaiting FERC filing
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
ArrUpliftMpAmt m, d
$
Operating Day
Auction Revenue Rights Funding Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.10.3.
DaDRMpAmt m, d
$
Operating Day
Day-Ahead Demand Reduction Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.24
DaDRDistMpAmt m, d
$
Operating Day
RtRevInadqcSppAmt spp, d
$
Operating Day
RtBillMtr5minQty a, s, i
MW
Dispatch Interval
Day-Ahead Demand Reduction Distribution Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.25 Real-Time Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total RTBM charges and RTBM credits. Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.
RtImpExp5minQty a, s, i, t
MW
Dispatch Interval
RsgCrdFlgt
none
none
DaClrdVHrlyQty a, s, h, t
MWh
Hour
DaClrdHrlyQty a, s, h
MWh
Hour
DaImpExp5MinQty a, s, i, t
MW
Dispatch Interval
(Not Available on Settlement Statement)
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Definition
Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2. Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8. Day-Ahead Virtual Energy Quantity per AO per Settlement Location per Hour per Transaction – The value described under Section 4.5.8.3. Day-Ahead Asset Energy Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.1. Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.8.2.
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Variable
Unit
Settlement Interval
Definition
$/MW
Dispatch Interval
RtEnergyMpAmt m, d
$
Operating Day
Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i. Real-Time Energy Amount per MP per Operating Day – The value described under Section 4.5.9.1.
RtNEnergyMpAmt m, d
$
Operating Day
Real-Time Non-Asset Energy Amount per MP per Operating Day – The value described under Section 4.5.9.2.
RtVEnergyMpAmt m, d
$
Operating Day
Real-Time Virtual Energy Amount per MP per Operating Day – The value described under Section 4.5.9.3.
RtRegUpMpAmt m, d
$
Operating Day
Real-Time Regulation-Up Service Amount per MP per Operating Day – The value described under Section4.5.9.4.
Comment [MPRR102.1188]: MPRR102 Awaiting implementation. #ER13-1748
RtRegUpUnsedMileMwpMpAmt m, d
$
Operating Day
Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 0.4.5.9.28 Real-Time Regulation-Down Service Amount per MP per Operating Day – The value described under Section 4.5.9.5.
Comment [MPRR204.1189]: MPRR204 Awaiting FERC approval Docket #ER13-1748
Comment [MPRR102.1192]: MPRR102 Awaiting implementation. #ER13-1748
RtMcc5minPrc s, i
RtRegDnMpAmt m, d
$
Operating Day
RtRegUpUnsedMileMwpMpAmt m, d
$
Operating Day
Comment [MPRR204.1190]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.1191]: MPRR102 Awaiting implementation. #ER13-1748
RtSpinMpAmt m, d
$
Operating Day
Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.254.5.9.29. Real-Time Spinning Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.6.
RtSuppMpAmt m, d
$
Operating Day
Real-Time Supplemental Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.7.
RtMwpMpAmt m, d
$
Operating Day
RUC Make-Whole-Payment Amount per MP per Operating Day – The value described under Section 4.5.9.8
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606
Comment [MPRR102.1196]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
RtOomMpAmt m, d
$
Operating Day
Real-Time Out-Of-Merit Make-Whole-Payment Amount per MP per Operating Day - The value described under Section 4.5.9.9.
RtMwpDistMpAmt m, d
$
Operating Day
RUC Make-Whole-Payment Distribution Amount per MP per Operating Day – The value described under Section 4.5.9.10.
RtRegNonPerfMpAmt m, d
$
Operating Day
Real-Time Regulation Non-Performance Amount per MP per Operating Day – The value described under Section 4.5.9.15.
RtCRDeplFailMpAmt m, d
$
Operating Day
RtRegAdjMpAmt m, d
$
Operating Day
Real-Time Contingency Reserve Deployment Failure Amount per MP per Operating Day – The value described under Section 4.5.9.17. Real-Time Regulation Deployment Adjustment Amount per MP per Operating Day - The value described under Section 4.5.9.19.
RtOclDistMpAmt m, d
$
Operating Day
Real-Time Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.9.20.
RtNetInadvertentSpp5minAmt i
$
Dispatch Interval
RtNetInadvertentSppAmt spp, d
$
Operating Day
RtCongestionSppAmt spp, d
$
Operating Day
RtNetActIntrchngSpp5minQty i
MW
RtNetSchIntrchngSpp5minQty i
MW
Dispatch Interval Dispatch Interval
Real-Time SPP Inadvertent Energy Amount per Dispatch Interval – SPP net Inadvertent Energy for Dispatch Interval i valued at the Real-Time LMP MEC. Real-Time SPP Inadvertent Energy Amount per Operating Day – The sum of RtNetInadvertentSpp5minAmt i for Operating Day d. Real-Time SPP Net Congestion Revenue Amount – The net amount of total Real-Time congestion revenue collected over Operating Day d. Real-Time SPP Net Actual Interchange per Dispatch Interval – SPP Net Actual Interchange in Dispatch Interval i. Real-Time SPP Net Scheduled Interchange per Dispatch Interval – SPP Net Scheduled Interchange in Dispatch Interval i.
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Definition
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Variable
RtMec5minPrc i
Unit
Settlement Interval
Definition
$/MW
Dispatch Interval Hour
Marginal Energy Component of Real-Time LMP per Dispatch Interval – The Real-Time LMP MEC in Dispatch Interval i. Real-Time Joint Operating Agreement Hourly Amount - The value calculated under Section 4.5.9.21. Real-Time Regulation Non-Performance Distribution Amount The value calculated under Section 4.5.9.16. Real-Time Contingency Reserve Deployment Failure Distribution Amount - The value calculated under Section 4.5.9.18.
RtJoaHrlyAmt a, h, f
$
RtRegNonPerfDistMpAmt m, d
$
RtCRDeplFailDistMpAmt m, d
$
RtRegUpDistMpAmt m, d
$
RtRegDnDistMpAmt m, d
$
RtSpinDistMpAmt m, d
$
RtSuppDistMpAmt m, d
$
RtRsgDistMpAmt m, d
$
RtDRMpAmt m, d
$
RtDRDistMpAmt m, d
$
RtRsgDlyAmt a, d
$
MiscDlyAmt a, c, d
$
Version 23.a
Operating Day Operating Day Operating Day Operating Day Operating Day Operating Day Operating Day Operating Day Operating Day Operating Day Operating Day
Real-Time Regulation-Up Service Distribution Amount – The value calculated under Section 4.5.9.11. Real-Time Regulation-Down Service Distribution Amount – The value calculated under Section 4.5.9.12. Real-Time Spinning Reserve Distribution Amount – The value calculated under Section 4.5.9.13. Real-Time Supplemental Reserve Distribution Amount – The value calculated under Section 4.5.9.14. Real-Time Reserve Sharing Group Distribution Amount – The amount calculated under Section 4.5.9.23. Real-Time Demand Reduction Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.24 Real-Time Demand Reduction Distribution Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.25. Real-Time Reserve Sharing Group Amount – The amount calculated under Section 4.5.9.22. Real-Time Miscellaneous Amount per AO per Charge Type per Operating Day – The miscellaneous amount to AO a for charge type c in Operating Day d as described under Section 4.5.10.4.
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Comment [MPRR102.1197]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR102.1198]: MPRR102 Awaiting implementation. #ER13-1748
Market Protocols for SPP Integrated Marketplace
Variable
Unit
Settlement Interval
Definition
RtRnuDlyAmt a, s, d
$
Operating Day
RtRnuAoAmt a, m, d
$
Operating Day
RtRnuMpAmt m, d
$
Operating Day
RtPseudoTieCongSppAmt d
$
Dispatch Interval
RtPseudoTieLossMpAmt m, d
$
Operating Day
RtPseudoTieCongMpAmt m, d
$
Operating Day
GFARevInadqcSppAmt spp, d
$
Operating Day
DaGFACarveOutDistMpDlyAmt m, d
$
Operating Day
Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Operating Day– The amount for revenue neutrality to AO a at Settlement Location s in Operating Day d. Real-Time Revenue Neutrality Uplift Amount per AO per Operating Day – The amount for revenue neutrality to AO a associated with Market Participant m in Operating Day d. Real-Time Revenue Neutrality Uplift Amount per MP per Operating Day – The amount for revenue neutrality to MP m in Operating Day d. Real-Time SPP Total Pseudo-Tie Congestion Amount per Dispatch Interval - The total amount for congestion on Pseudo-Ties for the Operating Day. Real-Time Pseudo-Tie Losses Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie losses on all paths for MP m for the Operating Day. Real-Time Pseudo-Tie Congestion Amount per Market Participant per Operating Day - The value described under 4.5.9. 26 for MP m for the Operating Day. Grandfathered Agreement Carve-Out Revenue Inadequacy Daily Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead OverCollected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount for Operating Day d. Day Ahead GFA Carve Out Distribution Daily Amount per MP per Operating Day – The value calculated under Section 4.5.8.26
A
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none
none
An Asset Owner.
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Variable
Unit
Settlement Interval
Definition
A Resource Settlement Location. An Hour. A Dispatch Interval. A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction. A flowgate identified in the applicable JOA. An Operating Day. A flag which instructs the settlement system to include the amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N). A Market Participant.
S h i t
none none none none
none none none none
f d rnu
none none none
none none none
m
none
none
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4.5.13
Settlement Statement Process
4.5.13.1
Meter Data Submittal
All meter data submitted by noon on the previous Business Day will be included in the Settlement(s) scheduled to be executed. Except in the case of a four day holiday as discussed in Section 4.5.13.7, reported values for an Operating Day must be received by noon according to the following schedule on the Business Day prior to: (1)
Day 5 calendar day for inclusion in Initial Settlement statement.
(2)
Day 45 calendar day for inclusion in Final Settlement statement.
(3)
Day 75 calendar day for inclusion in Resettlement 1 statement.
(4)
Day 105 calendar day for inclusion in Resettlement 2 statement.
(5)
Day 135 calendar day for inclusion in Resettlement 3 statement.
(6)
Day 165 calendar day for inclusion in Resettlement 4 statement.
(7)
Day 195 calendar day for inclusion in Resettlement 5 statement.
(8)
Day 225 calendar day for inclusion in Resettlement 6 statement.
(9)
Day 255 calendar day for inclusion in Resettlement 7 statement.
(10)
Day 285 calendar day for inclusion in Resettlement 8 statement.
(11)
Day 315 calendar day for inclusion in Resettlement 9 statement.
(12)
Day 345 calendar day for inclusion in Resettlement 10 statement.
(13)
Day 375 calendar day for inclusion in Resettlement 11 statement.
4.5.13.2
Daily Settlement Statement
The Settlement Statement(s) will be made available for each Operating Day and will be published for Market Participants and associated Asset Owners electronically through the Portal on Business Days. The Market Participant is responsible for accessing the information from the Portal once posted by SPP. In order to issue a Settlement Statement, SPP may use estimated, disputed or calculated meter data. An initial and final Settlement Statement will be created for each Operating Day. Resettlement Statements can be created for any given Operating Day having met the dispute-filing deadline and prior to twelve months elapsed time from the Operating Day. When actual validated data are available and all of the settlement and billing
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disputes raised by Market Participants during the validation process have been resolved, SPP shall recalculate the amounts payable and receivable by the affected Market Participant. For each Market Participant, Settlement Statement(s) will denote: (1)
Operating Day;
(2)
Associated Asset identifier;
(3)
Market Participant identifier;
(4)
Type of statement (Initial, Final or Resettlement);
(5)
Statement version number;
(6)
Unique Statement identification code; and
(7)
Market services settled.
Settlement Statements will include charges and credits by Asset Owner, appropriate Settlement Interval and Settlement Location. 4.5.13.3
Settlement Statement Access
Market Participants and associated Asset Owners can access all Settlement Statements pertaining to them electronically via the following steps: (1)
Secured entry on the Portal;
(2)
eXtensible Markup Language (XML) download.
4.5.13.4
Initial Settlement Statements
SPP will use settlement data to produce the initial Settlement Statements for each Market Participant for the given Operating Day. For non-holidays as shown in Exhibit 4-26, Initial Settlement Statements will be created at the end of the seventh (7th) calendar day following the Operating Day. If the seventh (7th) calendar day is not a Business Day, the initial Settlement Statement is issued no later than the next Business Day thereafter. For holidays, the Initial Settlement Statements will be created as shown in Exhibit 4-27. 4.5.13.5
Final Settlement Statements
SPP will use settlement data to produce the final Settlement Statements for each Market Participant for the given Operating Day. Final Settlement Statements will be created at the end of the forty-seventh (47th) calendar day following the Operating Day. If the forty-seventh (47th) calendar day is not a Business Day, the final Settlement Statement is issued on the next Business
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Day thereafter. The final Settlement Statement will reflect the net changes to settlement charges generated on the Operating Day’s initial Settlement Statement. 4.5.13.6
Resettlement Statements
A resettlement Settlement Statement will be produced using corrected settlement data due to resolution of disputes, or correction of data errors. Resettlements occurring prior to the production of the final Settlement Statement will be included in the final Settlement Statement. (1)
(2)
Resettlement Settlement Statements 1 through 9 will be created at the end of the following calendar days following the Operating Day. If the calendar day is not a Business Day, the respective resettlement Settlement Statement is issued on the next Business Day thereafter. Resettlement Settlement Statements 10 through 12 will be used only on an Ad Hoc basis. (a)
Resettlement 1
77 days after Operating Day
(b)
Resettlement 2
107 days after Operating Day
(c)
Resettlement 3
137 days after Operating Day
(d)
Resettlement 4
167 days after Operating Day
(e)
Resettlement 5
197 days after Operating Day
(f)
Resettlement 6
227 days after Operating Day
(g)
Resettlement 7
257 days after Operating Day
(h)
Resettlement 8
287 days after Operating Day
(i)
Resettlement 9
317 days after Operating Day
(j)
Resettlement 10
Ad Hoc
(k)
Resettlement 11
Ad Hoc
(l)
Resettlement 12
Ad Hoc
Any settlement and billing dispute of initial Settlement Statements resolved in accordance with Dispute Resolution process of the Tariff will be corrected on the final Settlement Statement for the Operating Day. In the event that the final Settlement Statement does not resolve a dispute from an initial Settlement Statement for a given Operating Day, SPP will resolve the dispute on a resettlement Settlement Statement for that Operating Day. Only Disputes for which the RTO is notified by the end of the time period for as defined under Section 4.5.15 will be considered for resettlement.
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(3)
Any dispute of initial and final Settlement Statements resolved subsequent to the final Settlement Statement, in accordance with the Dispute Resolution process of the Tariff, will be corrected on the next available invoice after the R2 resettlement Settlement Statement run has been executed.
(4)
Any dispute resolved subsequent to the R2 resettlement Settlement Statement, in accordance with the Dispute Resolution process of the Tariff, will be corrected on the next available invoice after the R4 resettlement Settlement Statement run has been executed.
(5)
Resettlement Settlement Statements R1 and R3 will be utilized only if Dispute Resolution for a Granted or Granted with Exception Dispute results in at least a 25% financial change in a Market Participant’s Settlement Statement for the operating date as compared with the most recent previous Settlement Statement for that operating date. Resettlement Settlement Statements R5 to R9 will only be used to resolve Disputes of previous resettlements, which are limited to incremental changes. Resettlement Settlement Statements R10 to R12 will be used only on an Ad Hoc basis to resolve any remaining disputes, in accordance with the Dispute Resolution process of the Tariff.
(6)
SPP shall post a resettlement schedule through the Portal indicating that a specific Operating Day will be resettled and the date the resettlement Settlement Statement will be issued by SPP.
4.5.13.7
Settlement Timeline
SPP shall create Settlement Statements and Settlement Determinant Reports daily for each Market Participant and associated Asset Owner, detailing each Market Participant’s and associated Asset Owners cost responsibility. Settlement Statements are published through the Portal on each Business Day. SPP shall prepare a Settlement Invoice each billing cycle for each Market Participant showing the net amount to be paid or received by the Market Participant. Settlement Determinant Reports shall provide sufficient detail to allow verification of the billing amounts and completion of the Market Participant’s internal accounting. SPP’s settlement systems shall allow Market Participants and associated Asset Owners to search for Settlement Statements by issuance date and invoice date and Settlement Determinant Reports by operating date. Settlement Statements shall be issued in accordance with the timelines shown in Exhibits 4-26 and 4-27.
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Exhibit 4-26: Settlements Timeline – Non Holiday Example
Sunday
Day 7
Monday
Tuesday
Wednesday Thursday
Day 1
Day2
Day 3
Day 4
Day 5
Day 6
Day 8
Day 9
Day 10
Day 11
Day 12
Day 13
ISS Day 3
ISS Day 4
ISS Day 5
ISS Day 1
Day 14
ISS Day 2
Friday
Day 15
Day 16
Day 17
Day 18
Day 19
ISS Day 6 ISS Day 7 ISS Day 8
ISS Day 9
ISS Day 10
ISS Day 11
ISS Day 12
Saturday
Day 20
Time Lapse for Day 21 to Day 48 Day 49
Day 50
Day 51
Day 52
Day 53
Day 54
ISS Day 41 ISS Day 42 ISS Day 43
ISS Day 44
ISS Day 45
ISS Day 46
ISS Day 47
FSS Day 6
FSS Day 7
FSS Day 8
FSS Day 9
Day 55
FSS Day 3 FSS Day 4 FSS Day 5
ISS-Initial Settlement Statement FSS-Final Settlement Statement
Exhibit 4-27 applies to all Thursday through Sunday holidays and similar logic will apply to other 4 day holiday weekend scenarios:
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Exhibit 4-27: Settlements Timeline –Holiday Example Sunday Nov 14
Monday
Tuesday
Wednesday
Thursday
Friday
Nov 15
Nov 16
Nov 17
Nov 18
Nov 19
MD (11/11)
MD (11/12)
MD (11/13)
MD (11/14)
MD (11/15)
Saturday Nov 20
MD (11/16) MD (11/17)
Nov 21
Nov 22
Nov 23
Nov 24
Nov 25
Nov 26
Nov 27
MD (11/18)
MD (11/19)
MD (11/21)
Holiday
Holiday
Holiday
MD (11/20)*
MD (11/22)
ISS (11/17) ISS (11/18) ISS (11/19)
Nov 28
Nov 29
Nov 30
Holiday
MD (11/23)
MD (11/25)
MD (11/24) *
MD (11/26)
ISS (11/20)
ISS (11/22)
ISS (11/21)
ISS (11/23)
Meter Data (MD) due by Noon on days indicated. * Meter Data due by 3:00 pm instead of normal noon deadline. Initial Settlement Statement (ISS)
4.5.14
Settlement Invoice
SPP prepares weekly Settlement Invoices from Settlements Statements. Settlement Invoices will be prepared on a net basis, with payments made to or from SPP. Invoices will be posted on the Portal by 8:00 a.m. CPT (see Section 4.5.14.3 Holiday Invoice Calendar for exceptions). The Market Participant is responsible for accessing the Settlement Invoice information via the Portal once posted by SPP. Each Market Participant with a net debit balance will pay any net debit whether or not there is any settlement and billing dispute regarding the amount. Each Market Participant with a net
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credit balance will receive the balance shown on the Settlement Invoice, adjusted for balances not collected from Market Participants with net debit balances. 4.5.14.1
Timing and Content of Invoice
SPP will electronically post for each Market Participant, an invoice based on any initial final, and resettlement Settlement Statements produced since the prior settlement invoice. SPP shall post the settlement invoices to the Market Participant in accordance with the Settlement Calendar. The Market Participant is responsible for accessing the information from the Portal once posted by SPP. Invoices will be issued on a weekly basis as defined in SPP invoice calendars described in Sections 4.5.14.2 and 4.5.14.3. The SPP invoice calendar will be posted monthly on the SPP Portal. Invoice items will be grouped by initial, final, and resettlement categories and will be sorted by Operating Day within each category. Each settlement invoice will contain: (1)
Market Participant ID – the name, address and contact information for the Market Participant being invoiced;
(2)
Net Amount Due/Payable – the aggregate summary of all charges owed or due by a Market Participant;
(3)
Amount Due/Payable by Asset Owner, Operating Date and Settlement Date — the aggregate of charges owed or due by an Asset Owner, listed by Operating Day which shall be identified by calendar date;
(4)
Time Periods – the time period covered for each settlement statement run date identified by a range of calendar dates;
(5)
Run Date – the date in which the invoice was created and published;
(6)
Invoice Reference Number – a unique number generated by the SPP applications for payment tracking purposes;
(7)
Settlement Statement ID– an identification code used to reference each Settlement Statement invoiced;
(8)
Payment Date and Time – the date and time that invoice amounts are to be paid or received;
(9)
Remittance Information Details – details including the account number, bank name and electronic transfer instructions of the SPP account to which any amounts owed by the
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Invoice Recipient are to be paid or of the Invoice Recipient’s account to which SPP shall draw payments due; (10) Overdue Terms – the terms that would be applied if payments were received late; (11) Late fees; and (12) Miscellaneous charges from tariff billing not otherwise covered above with details provided or referenced on what the miscellaneous charges include and how they are derived. 4.5.14.2
Invoice Calendar
Weekly invoices will be distributed every Thursday by no later than 8:00 a.m. CPT with the exceptions described in Section 4.5.14.3 for holidays. Weekly invoices will include the seven (7) daily Settlement Statements (initial, final & resettlements) produced for the previous Wednesday through Tuesday cycle. Market Participant balances owed to SPP are due by 5:00 p.m. (CPT) of the first (1st) Wednesday following the Thursday invoice date. Balances owed by SPP to Market Participants will be paid on the second (2nd) Friday following the invoice date by 5:00 p.m. (CPT). 4.5.14.3
Holiday Invoice Calendar
The Thursday invoice date and the following Wednesday and Friday payment dates as described in Section 4.5.14.2 will be changed to the next business day if the invoice date or payment date fall on a SPP Holiday. In those cases when a payment date falls on a bank holiday but not a SPP holiday, the payment date will be the next SPP business day. If there are two (2) consecutive SPP holidays, the following calendar will apply (all invoice dates assume the invoice will be made available to customers by 8:00 a.m. (CPT) on the date shown):
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Holiday
Invoice Date
Customer Pmt SPP Pmt Due Due Date Date
Mon-Tue
Previous Thu
Fri
Tue
Tue-Wed
Following Mon
Fri
Tue
Wed-Thu
Following Mon
Fri
Tue
Thu-Fri
Following Mon
Fri
Tue
Fri-Mon
Normal Sched
Fri
Tue
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4.5.15
Disputes
A Market Participant may dispute items set forth in any Settlement Statement (initial, final, or resettlement). The dispute must be filed on the Portal using the Request Management SystemContents of Notice dispute form as shown in Exhibit 4-28 with the following minimum content: (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (1)
Statement type (initial, final, resettlement 1-12); Charge type; Estimated dispute amount in dollars; Operating Day; Start interval; End interval; Statement ID; Transmission Customer ; Settlement Location; Long description; and Short description.Request type;
(2)
Subject;
(3)
Full Description;
(4)
Statement Type;
(5)
Charge Type;
(6)
Settlement Location;
(7)
Operating Day;
(8)
Start interval;
(9)
End Interval;
Comment [MPRR201.1199]: MPRR201 Awaiting FERC filing Comment [MPRR201.1200]: MPRR201 Awaiting FERC filing
(10) Dispute Amount; and Comment [MPRR201.1201]: MPRR201 Awaiting FERC filing
(11) Proposed Resolution
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Exhibit 4-28: Contents of Notice Dispute Form Comment [MPRR201.1202]: Deleted Picture
Comment [MPRR201.1203]: Deleted Picture
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Comment [MPRR201.1204]: MPRR201 Awaiting FERC filing
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4.5.15.1
Dispute Submission Timeline
A Market Participant may dispute settlement of any Operating Day as soon as the initial Settlement Statement for that Operating Day is issued, and up to 90 calendar days after the invoice date for the applicable final Settlement Statement that the Market Participant wishes to dispute for that Operating Day is issued. In the case of resettlement Settlement Statements, a Market Participant may only dispute incremental changes in settlement data that occur between issuance of the final Settlement Statement and the first resettlement Settlement Statement or between issuance of resettlement Settlement Statements. A dispute relating to a resettlement Settlement Statement must be filed within 30 calendar days following the issue date of the applicable invoice of the items contained in that resettlement Settlement Statement that the Market Participant wishes to dispute. In the event that the Portal is unavailable on the day prior to the deadline for submission of a dispute due to technical or other reasons, SPP shall extend the dispute submittal deadline by the number of Business Days equal to the sequential number of Business Days on which the Portal was unavailable. 4.5.15.2
SPP Dispute Processing
SPP shall determine if the dispute is accepted by verifying that the dispute was submitted within the specified time and contains at least the minimum required information as described in Attachment AE of the SPP OATT. (a)
SPP shall make reasonable attempts to remedy any informational deficiencies by working with the Market Participant(s);
(b)
Contents of Notice will be rejected if SPP determines required information is missing. The Dispute will be returned to the Market Participant with an explanation of the missing data no later than 30 days after the receipt of the original or resubmitted dispute. A Market Participant will be able to resubmit the dispute with additional information within 20 Business Days after the Dispute is returned to the Market Participant unless SPP grants an extension of this deadline for good cause. Once the Market Participant sends all required information and SPP determines the settlement and billing dispute is timely and complete, the dispute status will be considered “Open”;
(c)
SPP will issue a settlement and billing dispute resolution report containing information related to the disposition of the dispute;
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(d)
SPP will make all reasonable attempts to resolve all “Open” disputes relating to all Settlement Statements within 30 calendar days after the settlement and billing dispute due date as specified in the Settlement Calendar. SPP will post the necessary adjustments for resolved settlement and billing disputes on the next resettlement or final Settlement Statement process;
(e)
For settlement and billing disputes requiring complex research or additional time for resolution, and late disputes that can be reasonably processed, SPP will notify the Market Participant of the length of time expected to research and post those disputes and, if a portion or all of the dispute is granted, SPP will post the necessary adjustments on the next available Settlement Statement for the Operating Day, if any portion or all of the dispute is Granted. Market Participants have the right to proceed to the External Arbitration process in Dispute Resolution of the Tariff for timely filed disputes that cannot be resolved through the settlement and billing dispute process.
4.5.15.2.1 Dispute Status Each dispute will have a status as defined in the following paragraphs. Valid status designation includes: (1)
OPEN & CLOSED: A Dispute will be deemed “Open” when submitted in a timely and complete manner. “Closed” is the final status for all Disputes;
(2)
DENIED: The Dispute will be “Denied” if SPP concludes that the information used in the Dispute is incorrect. SPP will notify the Market Participant when a Dispute is “Denied”, and will document the supporting research for the denial. If the Market Participant is not satisfied with the outcome of a Denied Settlement and Billing Dispute, the Market Participant may proceed to External Arbitration as described in Dispute Resolution of the Tariff, Dispute Resolution of these Rules. If after 30 calendar days from receiving notice of a “Denied” dispute, the Market Participant does not begin External Arbitration, the dispute will be “Closed”;
(3)
GRANTED: SPP may determine a settlement and billing dispute is “Granted”. SPP will notify the Market Participant of the resolution, and will document the basis for resolution. Upon resolution of the issue, the settlement and billing dispute will be processed on the next prescribed Settlement Statement for the Operating Day. Once the necessary adjustments appear on the next prescribed Settlement Statement, the settlement and billing dispute is then “Closed”;
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(4)
GRANTED with EXCEPTIONS: SPP may determine a settlement and billing dispute is “Granted with Exceptions” when the information is partially correct and SPP will provide the exception information to the Market Participant. SPP will require an acknowledgement from the Market Participant of the dispute Granted with Exceptions within twenty Business Days. The acknowledgement must indicate acceptance or rejection of the documented exceptions to the dispute. If accepted, SPP will post the necessary adjustments on the next prescribed Settlement Statement for the Operating Day and will change the dispute status to “Closed”. If SPP does not receive a response from the Market Participant within 30 calendar days, the dispute will be considered accepted and “Closed”.
If the Market Participant rejects the SPP determination of a dispute, which is “Granted with Exceptions”, the dispute will be investigated further. After further investigation, if the settlement and billing dispute is subsequently granted, the dispute will be processed on the next prescribed Settlement Statement to be issued. The dispute is then “Closed”. If exceptions to the dispute still exist, the Market Participant may either accept the dispute for resolution as “Granted with Exceptions”, or begin External Arbitration according to Dispute Resolution of the Tariff, Dispute Resolution of these Rules.
4.5.16
Invoice Payment Process
4.5.16.1
Overview of Payment Process
Payments shall be made in a two-step process where: (1)
All Settlement Invoices due with net debits owed by Market Participant are paid by 5:00 p.m. (CPT) of the first Wednesday following the Thursday invoice date, and
(2)
All Settlement Invoices due with net credits owed to Market Participant are paid by 5:00 p.m. (CPT) of the second Friday following the invoice date
Payments due to SPP and payments due to Market Participant will be made by Electronic Funds Transfer (EFT) in U.S. Dollars. 4.5.16.2
Invoice Payments Due SPP
Each Market Participant owing monies to SPP shall remit the amount shown on its invoice so SPP receives this amount no later than 5:00 p.m. (CPT) on the first Wednesday following the Thursday invoice date. Payments due will be made by Electronic Funds Transfer (EFT) in U.S. Dollars. Payments will be made regardless of any settlement or invoice dispute regarding the
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amount of the debit. Payments not received by the due date will be subject to interest charges as approved by the Federal Energy Regulatory Commission. 4.5.16.3
SPP Payments to Invoice Recipients
On the first Thursday following the invoice date (or 1 day after payments are due from Market Participants), SPP shall calculate (via a payout report) the amounts for distribution to Market Participants with net credits and remit to those Market Participants no later than 5:00 p.m. (CPT) the next day. Once each payout report has been finalized, they will be posted to the Portal by 3:00 p.m. (CPT) on Thursday. At that time, Market Participants will be able to access information regarding their respective Friday payout amounts. The finalized payout calculations will also be provided to the SPP Customer Relations Department on Thursday afternoon by 3:00 p.m. (CPT) should Market Participants have any questions regarding the payout amounts posted to the Portal.
4.5.17
Billing Determinant Anomalies
Circumstances may occur where billing determinants received from system interfaces contain erroneous data anomalies that would have significant adverse financial impacts on Market Participants if these determinants were used to produce Settlement Statements. In these situations when certain billing determinants deviate beyond prescribed tolerance levels, SPP will work internally and with Meter Agents(s) to resolve the discrepancy and may modify data using actions including, but not limited to those in the following guideline to substitute data when the original data is deemed to be erroneous. (1)
Bad State Estimator (For resources dispatched in RTBM interval) – 5-minute interval value based on: (a)
If High Tolerance Band – Greater than 120% of the RTBM Resource Maximum Emergency Capacity Operating Limit; (i)
(b)
If Low Tolerance Band – Less than RTBM Resource Minimum Economic Capacity Operating Limit; (i)
(2)
Then substitution value – Energy Dispatch Instructions;
Then substitution value – Energy Dispatch Instructions.
Bad State Estimator (For resources not dispatched in RTBM interval) – 5-minute interval value based on: (a)
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(i) (b)
If Low Tolerance Band – Less than historic low value; (i)
(3)
If High Tolerance Band – Greater than 120% of the RTBM Resource Maximum Emergency Capacity Operating Limit; (i)
(b)
Then substitution value – State Estimator.
Bad Resource Meter Data Submittal – based on: (a)
If High Tolerance Band – Derived from historic high value; (i)
(b)
Then substitution value – State Estimator;
If Low Tolerance Band – Derived from historic low value; (i)
Then substitution value – State Estimator.
Bad Load Meter Data Submittal – based on: (a)
If High Tolerance Band – Derived from historic high value; (i)
(b)
Then substitution value – State Estimator;
If Low Tolerance Band – Derived from historic low value; (i)
(6)
Then substitution value – State Estimator;
If Low Tolerance Band – Less than Zero; (i)
(5)
Then substitution value – Zero or last known valid value.
Bad Average Set Point Instruction – 5-minute interval value based on: (a)
(4)
Then substitution value – Zero or last known valid value;
Then substitution value – State Estimator.
Bad Settlement Area Inter-Tie Meter Data Submittal – based on: (a)
If High Tolerance Band – Derived from historic high value; (i)
(b)
If Low Tolerance Band – Derived from historic low value; (i)
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Transmission Congestion Rights Markets Process
5.
The annual TCR Markets Process includes an annual LTCR allocation process, an annual and monthly ARR allocation process and annual and monthly TCR Auctions. LTCRs are multi-year instruments, ARRs are annual, monthly or seasonal instruments, and TCRs are monthly and seasonal financial instruments whose values are determined as part of the DA Market settlement based on the MW amount of the TCR (including LTCRs converted to TCRs) and the DA Market differential of the Marginal Congestion Component of LMP between specified sinks and sources. TCRs are of the obligation type which means they can result in a credit or a charge. They provide a financial hedge against congestion costs in the DA Market as long as the MCC of the TCR sink Settlement Location is greater than the MCC of the TCR source Settlement Location. If the MCC at the TCR sink Settlement Location is less than the MCC of the TCR source Settlement Location, the TCR holder is charged (this type of TCR is commonly referred to as a “Counter-Flow TCR”). Awarded LTCRs are directly converted into TCRs prior to the annual ARR allocation for the current allocation year. Auction Revenue Rights (ARRs) are obtained by Eligible Entities during the annual ARR allocation process and/or monthly ARR allocation process. LTCRs are automatically converted into ARRs and TCRs for modeling and settlement purposes. Holders of ARRs are entitled to receive the Annual and Monthly TCR Auction revenues associated with awarded TCR Bids. However, ARRs are of the obligation type which means they can result in the holder receiving a portion of the TCR auction revenues or contributing to the TCR auction revenues. TCRs are obtained by Market Participants through the annual LTCR allocation and the Annual and Monthly TCR Auctions. Optionally, ARR holders may convert their ARRs into TCRs in the Annual and Monthly TCR Auctions and either hold the TCRs or offer these TCRs for sale in the auctions. ARRs associated with LTCRs are automatically converted into TCRs which may be sold in the annual and Monthly TCR auctions. The TCR Markets Process is subject to review by the Market Monitor, consistent with Attachment AG of the SPP OATT. There are 87 key steps associated with obtaining an LTCR or TCR and/or offering an awarded LTCR or TCR for sale. (1)
Annual LTCR/ARR Verification Process;
(1)(2)
Comment [MPRR138.1205]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1206]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1207]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1208]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR171.1209]: MPRR171 Awaiting FERC Approval. #ER14-2553
Comment [MPRR171.1210]: MPRR171 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1211]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR171.1212]: MPRR171 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1213]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR171.1214]: MPRR171 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1215]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1216]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1217]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1218]: MPRR138 Awaiting FERC Approval. #ER14-2553
Annual LTCR Allocation Process;
Comment [MPRR138.1219]: MPRR138 Awaiting FERC Approval. #ER14-2553
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(2)(3)
Annual ARR Allocation Process;
(3)(4)
Annual TCR Auction Process;
(4)(5)
Monthly ARR Allocation Process;
(5)(6)
Monthly TCR Auction Process;
(6)(7)
ARR Allocation and TCR Auction Settlements; and
(7)(8)
TCR Secondary Markets.
Exhibit 5-1 provides an overall representative timeline related to the LTCR Allocation, ARR Allocation and TCR Auction processes and Exhibit 5-2 provides additional details related to auction timing and available transmission system capability of the TCR Auction processes.
Comment [MPRR138.1220]: MPRR138 Awaiting FERC Approval. #ER14-2553
Exhibit 5-1: LTCR/ARR Allocation/ and TCR Auction Processes Timeline
Comment [MPRR138.1221]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1222]: MPRR138 Awaiting FERC Approval. #ER14-2553
4/5 - 4/23 Annual ARR 5/3 - 5/23 Allocation 3/10 - 3/28 Annual Annual LTCR TCR Auction Allocation
6/1 - 9/30 Annual ARR Awards And TCR Auction Awards by Month On-Peak and Off-Peak
10/1 - 5/31 Annual ARR Awards And TCR Auction Awards by Season On-Peak and Off-Peak
6/1 - 5/31 Annual LTCR Awards
12/15 - 5/31 LTCR/ARR Allocation / TCR Auctions 1
2
3
4
5
6
7
8
9
10
11
12
1
12/15
MP Verification of Transmission Entitlements 2/3 - 3/4
2
3
4
5 5/31
TCR Monthly Auction for July Repeats for Each Month 6/8 - 6/18
Monthly TCR Auction Awards Month to Month On-Peak and Off-Peak 7/1 - 5/31
5/25 - 6/5 Monthly ARR Allocation and Awards. Repeats Each Month
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Exhibit 5-2: TCR Auction Processes Summary Auction Auction Month Type May Annual (System Capability %) Jun Monthly (System Capability %) Jul Monthly (System Capability %) Aug Monthly (System Capability %) Sep Monthly (System Capability %) Oct Monthly (System Capability %) Nov Monthly (System Capability %) Dec Monthly (System Capability %) Jan Monthly (System Capability %) Feb Monthly (System Capability %) Mar Monthly (System Capability %)
TCR Award Periods Jun (100) Jul (100) Aug (100) Sep (100) Oct (100) Nov (100) Dec (100) Jan (100) Feb (100) Mar (100) Apr (100)
32
October and November
33
December, January, February, March
34
April and May
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Jul (90)
Aug (90)
Sep (90)
Fall32 (60)
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Winter33 (60)
Spring34 (60)
TCR Products On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak On-Peak/ Off-Peak
Auction Rounds 1
Total Auctions 14
1
2
1
2
1
2
2
4
2
4
2
4
2
4
2
4
2
4
2
4
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Apr Monthly (System Capability %)
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May (100)
On-Peak/ Off-Peak
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4
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Key process and design assumptions of each of these eightseven (78) key steps are described in the following sub-sections.
Comment [MPRR138.1223]: MPRR138 Awaiting FERC Approval. #ER14-2553
5.1
Comment [MPRR138.1224]: MPRR138 Awaiting FERC Approval. #ER14-2553
Annual LTCR/ARR Verification Process
Only Eligible Entities are eligible to nominate candidate LTCRs and/or ARRs as described under Sections 5.2 and 5.4. Eligible Entities for ARRs are Transmission Customers with firm SPP transmission service and entities with firm non-SPP transmission service (commonly referred to as a “grandfathered agreement or GFA”) into, out of, within or through the SPP Region that has been confirmed prior to the Annual ARR Allocation Process. Eligible Entities for LTCRs are Transmission Customers with qualifying firm SPP transmission service and entities with qualifying firm non-SPP transmission service (commonly referred to as a “grandfathered agreement or GFA”) into, out of, within or through the SPP Region that has been confirmed prior to the Annual LTCR Allocation Process. Eligible Entities must verify such services with SPP during the Annual LTCR/ARR Verification Process in order to be eligible to nominate candidate LTCRs and/or ARRs. All Eligible Entities must be a Market Participant and/or Asset Owner. The following rules apply to verification of transmission service for conversion to LTCRs and/or ARRs.
5.1.1
Comment [MPRR138.1226]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1227]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1228]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1229]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1230]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1231]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1232]: MPRR138 Awaiting FERC Approval. #ER14-2553
Transmission Service Verification
In order for Eligible Entities to obtain candidate LTCRs and/or ARRs, SPP must first verify existing transmission service entitlements, including transmission service entitlements which have been renewed in accordance with rollover rights since their initial term. In order to qualify for candidate LTCRs, an Eligible Entity’s firm transmission service must contain rollover rights and must span the entire allocation year. In order to qualify for candidate ARRs in a particular month and/or season, an Eligible Entity’s transmission service must span the entire monthly or seasonal period within the applicable allocation year. For Transmission Service with rollover rights whose deadline for providing notice of rollover occurs after the annual LTCR/ARR verification but before June 1, the Transmission Provider shall assume that the rollover will occur and shall consider the Transmission Service entitlement to span the entire allocation year, provided, however, that, if rollover rights for such Transmission Service are not exercised by the applicable deadline, any ARRs, TCRs, or LTCRs associated with such Transmission Service shall revert to the Transmission Provider effective on the date such Transmission Service terminates. SPP will verify each Eligible Entity's existing transmission service entitlements as follows:
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Comment [MPRR171.1237]: MPRR171 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1238]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1239]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
(1)
For Eligible Entities taking Network Integration Transmission Service (NITS) and/or Firm Point-To-Point Transmission Service (FPTP) under the SPP Tariff: (a)
(b)
SPP will obtain source, sink and Reserved Capacity information from the SPP OASIS for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period for ARR purposes and for the annual period for the applicable year for LTCR purposes, or would if or when rolled over; Eligible Entities taking NITS with rollover rights shall be considered an LSE for purposes of LTCR allocation;
(a)(c) Eligible Entities taking FPTP service with rollover rights shall not be considered an LSE for that service unless the Eligible Entity provides an attestation to SPP confirming that the Eligible Entity is an LSE as defined in Attachment AE of the Tariff for such service; (b)(d) For a TSR with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate LTCRs and/or ARRs. Eligible Entities may create Resource specific TSRs that represent their current TSRs using the process described under Section 5.1.1.1; (e)
For a TSR with a source outside of the SPP Market, the interface Interface Settlement Location associated with the Balancing Authority of the source will be utilized as the source for candidate LTCRs and/or ARRs;
(c)(f) For a TSR with a sink outside of the SPP Market, the iInterface Settlement Location associated with the Balancing Authority of the sink will be utilized as the sink for candidate LTCRs and/or ARRs; (d)(g)
SPP will provide this information to each Eligible Entity for verification;
(e)(h) Eligible Entities will notify SPP within two (2) weeks following receipt of this information identifying and correcting inaccurate data. Otherwise, the SPP provided data will be considered verified. (2)
For Eligible Entities taking GFA service without Carve Out treatment:
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Comment [MPRR138.1245]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
(a)
If the transmission customer under the GFA desires to nominate ARRs associated with the GFA sources and sinks identified in the Grandfathered Agreement, the GFA Parties must register such GFA with SPP and provide sources, sinks and reserved capacity information. SPP will obtain source, sink and reservation capacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(b)
Eligible Entities taking the equivalent of SPP NITS with rollover rights shall be considered an LSE for purposes of LTCR allocation;
(a)(c) Eligible Entities taking the equivalent of SPP FPTP service with rollover rights shall not be considered an LSE for that service unless the Eligible Entity provides an attestation to SPP confirming that the Eligible Entity is an LSE as defined in Attachment AE of the Tariff for such service; (b)(d) For a GFA with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate LTCRs and/or ARRs; (c)(e) For a GFA with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source for candidate LTCRs and/or ARRs; (d)(f) For a GFA with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink for candidate LTCRs and/or ARRs; (e)(g) In addition, the parties to the GFA must agree that the transmission customer under the GFA is eligible to nominate the LTCRs and/or ARRs associated with the GFA and both parties must confirm such with SPP. To the extent that the transmission service specified in the GFA is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years. (3)
For entities that have been granted GFA Carve Out treatment: (a)
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Market Protocols for SPP Integrated Marketplace
5.1.1.1
(b)
The parties to the GFA must register the GFA with SPP, identify the GFA Responsible Entity, and provide source, sink and reserved capacity information. SPP will obtain source, sink and reserved capacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(c)
To the extent that the transmission service specified in the GFA Carve Out is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident annual peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years.
TSR Modification for Resource Specific Source Points
Eligible Entities may “breakout” their non-Resource specific transmission service that is inside the SPP Market footprint by placing individual Resource specific transmission service reservations on OASIS that will be used exclusively for the TCR Market. The original transmission service will remain on OASIS. For the master NITS breakout, Appendix 1 of the Market Participant’s current NITSA will be used to validate the process. For the breakout of non-Resource specific transmission service other than the master NITS, all Market Participants involved in the transmission service transaction will be responsible for determining which Resources and Resource capacities should be used during the breakout, as SPP is not aware which Resources the transmission service was intended to represent. The sum of all transmission service from each Resource must be less than or equal to the Maximum Capacity of the Resource. Eligible Entities must use the following process to initiate and complete the TSR modification. (1)
(2)
Submit the required Non-Resource Specific TSR Breakout Form, found on www.SPP.org, to SPP if more than one party is involved in the transmission service transaction; and Submit new transmission service requests with the new service code of “SPP FN-7 YEARLY NITS TCR”, “SPP F-7 YEARLY PTP TCR”, “SPP FN-7 MONTHLY NITS TCR”, or “SPP F-7 MONTHLY PTP TCR”, whichever is equivalent to the original transmission service type. (a) The only difference between the original TSR and the new TSR should be the source, the capacity, and the subclass.
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(i)
(ii) (b)
5.1.2
For Master NITS TSRs, the capacity should be the highest value per Resource found in Appendix 1 of the NITSA (including the comments column) rounded up to the nearest whole MW value. If the Eligible Entity feels that they are entitled to a different amount other than what is listed in the NITSA, they should contact the SPP Transmission Service Studies group to see about amending their NITSA. If the capacity in the NITSA changes after the TSR has been granted, then this TSR may be recalled and a new TSR may be submitted to represent the new value in the NITSA. For other Non-Resource Specific TSRs, the capacity should be the amount the parties have agreed to.
Pre-confirm all submittals to allow for immediate confirmation after acceptance by SPP. Comment [MPRR138.1251]: MPRR138 Awaiting FERC Approval. #ER14-2553
Candidate LTCRs/ARRs
Following verification of Eligible Entity transmission service, candidate LTCRs and ARRs associated with such transmission service are assigned as follows:
Comment [MPRR138.1252]: MPRR138 Awaiting FERC Approval. #ER14-2553
For each Eligible Entity with NITS, the Eligible Entity’s NITS Candidate LTCRs and/or ARRs from a specific source is then equal to the source Reserved Capacity.
Comment [MPRR138.1253]: MPRR138 Awaiting FERC Approval. #ER14-2553
(1)
(a)
An Eligible Entity may selectnominate NITS Candidate LTCRsARRs, as described under Section 5.2.65.2.1 from a specific source to one or more sinks up to the amount of its available NITS Candidate ARRs LTCRs associated with the source such that the total of such selections does not exceed the lesser of the sum of NITS Candidate LTCRs or the limit described under Section 5.1.3(1)(b) for that Eligible Entity subject to the total nomination limit described under Section 5.1.3;
(a)(b) An Eligible Entity may nominate NITS Candidate ARRs, as described under Section 5.3.1 from a specific source to one or more sinks up to the amount of its NITS Candidate ARRs associated with the source subject to the total nomination limit described under Section 5.1.3. (2)
For each Eligible Entity with FPTP service, the Eligible Entity’s FPTP Candidate LTCRs and/or ARRs for a specific source and sink is equal to the Reserved Capacity associated with that source and sink.
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Comment [MPRR138.1263]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
(a)
An Eligible Entity may select nominate FPTP Candidate LTCRsARRs, as described under Section 5.2.65.2.1, for this specific source and sink up to the amount of its available FPTP Candidate LTCRs such that the total of such selections does not exceed the total FPTP Candidate LTCRs available for that Eligible Entity. ARRs subject to the total nomination limit described under Section 5.1.3;
(a)(b) An Eligible Entity may nominate FPTP Candidate ARRs, as described under Section 5.3.1, for this specific source and sink up to the amount of its FPTP Candidate ARRs subject to the total nomination limit described under Section 5.1.3 (3)
For each Eligible Entity with equivalent NITS GFA service, the Eligible Entity’s GFA NITS Candidate LTCRs and/or ARRs from a specific source is equal to the source Reserved Capacity. (a)
An Eligible Entity may select nominate GFA NITS Candidate LTCRsARRs, as described under Section 5.2.6 5.2.1, from a specific source to one or more sinks up to the amount of its available GFA NITS Candidate such that the total of such selections does not exceed the lesser of the sum of GFA NITS Candidate LTCRs or the limit described under Section 5.1.3(3)(b) for that Eligible Entity ARRs LTCRssubject to the total nomination limit described under Section 5.1.3;
(a)(b) An Eligible Entity may nominate GFA NITS Candidate ARRs, as described under Section 5.3.1, for this specific source and sink up to the amount of its GFA NITS Candidate ARRs subject to the total nomination limit described under Section 5.1.3; (4)
For each Eligible Entity with equivalent FPTP GFA service, the Eligible Entity’s GFA FPTP Candidate LTCRs and/or ARRs for a specific source and sink is equal to the Reserved Capacity associated with that source and sink. (a)
An Eligible Entity may select nominate GFA FPTP Candidate LTCRARRs, as described under Section 5.2.65.2.1, for this specific source and sink up to the amount of its available GFA FPTP Candidate LTCRs such that the total of such selections does not exceed the total GFA FPTP Candidate LTCRs available for that Eligible EntityARRs subject to the total nomination limit described under Section 5.1.3.
Comment [MPRR138.1264]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1265]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1266]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1267]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR171.1268]: MPRR171 Awaiting FERC Approval. #ER14-2553
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(a)(b) An Eligible Entity may nominate GFA FPTP Candidate ARRs, as described under Section 5.3.1, for this specific source and sink up to the amount of its GFA FPTP Candidate ARRs subject to the total nomination limit described under Section 5.1.3.
5.1.3
Comment [MPRR138.1283]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1284]: MPRR138 Awaiting FERC Approval. #ER14-2553
ARR Nomination Cap
An Eligible Entity’s ARR Nomination Cap will be as follows: (1)
(2)
(3)
(4)
(5)
For NITS Transmission Customers, the NITS ARR Nomination Cap for a particular month or season is equal to the lesser of (a) the sum of NITS Candidate ARRs and NITS Candidate LTCRs for a particular month or season as calculated under Section 5.1.1.1 or (b) one hundred and three percent (103%) of the average of that customer’s three most recent annual peak Network Loads. This value will be adjusted by SPP as required to account for wholesale load shifts between Transmission Customers. In addition, NITS Candidate LTCRs and awarded NITS Candidate LTCRs associated with wholesale load shifts shall be transferred by SPP as applicable;
Comment [MPRR138.1285]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1286]: MPRR138 Awaiting FERC Approval. #ER14-2553
For FPTP Transmission Customers, the FPTP ARR Nomination Cap is equal to the sum of FPTP Candidate ARRs and FPTP Candidate LTCRs as calculated under Section 5.1.1.1;
Comment [MPRR138.1287]: MPRR138 Awaiting FERC Approval. #ER14-2553
For GFA customers taking the equivalent of SPP NITS, the GFA NITS ARR Nomination Cap for a particular month or season is equal to the lesser of (a) the sum of GFA NITS Candidate ARRs and GFA NITS Candidate LTCRs as calculated under Section 5.1.1.1 or (b) one hundred and three percent (103%) of the average of that GFA customer’s three most recent annual peak Network Loads;
Comment [MPRR138.1288]: MPRR138 Awaiting FERC Approval. #ER14-2553
For GFA customers taking the equivalent of SPP FPTP, the GFA FPTP ARR Nomination Cap is equal to the sum of GFA FPTP Candidate ARRs and GFA FPTP Candidate LTCRs as calculated under Section 5.1.1.1; An Eligible Entity’s ARR Nomination Cap is equal the sum of its NITS ARR Nomination Cap, FPTP ARR Nomination Cap, GFA NITS ARR Nomination Cap and GFA FPTP ARR Nomination Cap.
5.2
Annual LTCR Allocation Process
The Annual LTCR Allocation Process addresses how candidate LTCRs verified in the Annual LTCR/ARR Verification Process may be selected and awarded as LTCRs. The annual allocation
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process determines the portion of the candidate LTCRs that are simultaneously feasible and available to each Eligible Entity to select. 50% of the SPP Residual Transmission System Capability, as defined under Section 5.2.2(2), is made available during the Annual LTCR Allocation Process. Candidate LTCRs are evaluated on an annual basis in a two-step process. The first step evaluates LSE candidate LTCRs to determine LSE available LTCRs. The second step evaluates non-LSE candidate LTCRs associates. No later than five (5) Business Days prior to the start of the Annual LTCR Allocation Process, SPP will post the transmission system network topology data for the annual model, along with corresponding Parallel Flow assumptions, that SPP will use in the upcoming allocation process for use by Eligible Entities in developing their available candidate LTCR selection strategies. The following rules apply to the annual allocation of LTCRs.
5.2.1
LTCR Surrender
Eligible Entities may surrender previously awarded LTCRs in 0.1 MW increments. Prior to annual LTCR allocation, Eligible Entities submit the following information: (1)
Source (valid candidate LTCR source Settlement Location);
(2)
Sink (valid candidate LTCR sink Settlement Location);
(3)
Surrendered LTCR MW (cannot exceed previously awarded LTCR).
5.2.2
Candidate LTCR Simultaneous Feasibility for LSEs
A simultaneous feasibility test (SFT) is performed to determine the feasibility of all NITS Candidate LTCRs, FPTP Candidate LTCRs, GFA NITS Candidate LTCRs and GFA FPTP Candidate LTCRs identified as described under Section 5.1.2 for all LSEs. All LSE candidate LTCRs are modeled as a generation injection at the source and a corresponding load withdrawal at the sink. The feasibility analysis assures the modeling of the LSE candidate LTCRs does not violate any normal transmission line thermal ratings under normal system conditions and does not violate short-term Emergency transmission line thermal ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent with the transmission system loading analysis that is performed as part the Security Constrained Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow. (1)
The SPP Transmission System topology used in the SFT is the most up-to-date Network Model.
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(2)
(a)
For withdrawals at Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. prior year peak). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.
(b)
For injections at Market Hubs, SPP will distribute the hub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the hub is created.
Prior to assessing simultaneous feasibility, the normal and emergency ratings of all flowgates and monitored transmission system elements are adjusted as follows to arrive at an SPP Residual Transmission System Capability: (a)
Adjusted Monitored Transmission Line Rating (normal and Emergency) = (Monitored Transmission Line Rating [normal and Emergency – Parallel Flow impact])
(b)
Adjusted Flowgate Rating (normal and Emergency) = (Flowgate Rating – Parallel Flow impact)
(3)
The feasibility analysis evaluates the candidate LTCR feasibility by evaluating line flows against path limits in a single direction only without simultaneous consideration of line flows created by candidate LTCRs in the opposite direction (i. e. counter-flow will not act to increase the feasibility of candidate LTCRs).
(4)
The feasibility analysis uses an iterative process to ensure that previously awarded LTCRs that have not been surrendered as indicated pursuant to Section 5.2.1 continue to be available. (a) (b)
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For the initial feasibility analysis, no previously awarded LSE LTCRs or surrendered LSE LTCRs are modeled. Only candidate LSE LTCRs are modeled. Previously awarded LTCRs associated with qualified transmission service as verified under Section 5.1.1 and which were not surrendered, associated with nonLSEs are modeled as fixed injections and withdrawals. To the extent that these fixed injections and withdrawals are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility prior to assessing LSE LTCR availability. SPP will report back to the MWG when transmission line ratings had to be adjusted to ensure feasibility.
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(c)
5.2.3
If the results of the initial feasibility analysis show that the amount of LSE LTCRs feasible on specific paths are less than those LSE LTCRs previously awarded on those paths, net of any surrendered LSE LTCRs, the feasibility analysis is rerun with all previously awarded LSE LTCRs, net of any surrendered LSE LTCRs, on such paths modeled as fixed injections/withdrawals and all candidate LSE LTCRs on all other paths are modeled as in (a) above. To the extent that these fixed injections and withdrawals are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility. SPP will report back to the MWG when transmission line ratings had to be adjusted to ensure feasibility.
Annual LTCR Available for LSEs
If all of the candidate LSE LTCRs are confirmed feasible, all candidate LSE LTCRs are available. If candidate LSE LTCRs are not feasible, the amount of candidate LSE LTCRs available will be reduced using a weighted least squares method. The weighted least squares method minimizes the least squares deviation from the candidate LSE LTCR MW weighted by the reciprocal of the candidates resulting in a higher percentage LSE LTCR reduction for those candidates having the greatest impact on the constraints. LSE LTCR reductions associated with candidates that have an equal impact on the constraints are reduced by the same percentage.
5.2.4
Candidate LTCR Simultaneous Feasibility for Non-LSEs
A simultaneous feasibility test (SFT) is performed to determine the feasibility of all NITS Candidate LTCRs, FPTP Candidate LTCRs, GFA NITS Candidate LTCRs and GFA FPTP Candidate LTCRs identified as described under Section 5.1.2 for all non-LSEs. All non-LSE candidate LTCRs are modeled as a generation injection at the source and a corresponding load withdrawal at the sink. The feasibility analysis assures the modeling of the non-LSE candidate LTCRs does not violate any normal transmission line thermal ratings under normal system conditions and does not violate short-term Emergency transmission line thermal ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent with the transmission system loading analysis that is performed as part of the Security Constrained Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow. (1)
The SPP Transmission System topology used in the SFT is the most up-to-date Network Model.
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(2)
(a)
For withdrawals at Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. prior year peak). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.
(b)
For injections at Market Hubs, SPP will distribute the hub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the hub is created.
Prior to assessing simultaneous feasibility, the normal and emergency ratings of all flowgates and monitored transmission system elements are adjusted as follows to arrive at an SPP Residual Transmission System Capability: (a)
Adjusted Monitored Transmission Line Rating (normal and Emergency) = (Monitored Transmission Line Rating (normal and Emergency – Parallel Flow impact))
(b)
Adjusted Flowgate Rating (normal and Emergency) = (Flowgate Rating – Parallel Flow impact)
(3)
The feasibility analysis evaluates the candidate LTCR feasibility by evaluating line flows against path limits in a single direction only without simultaneous consideration of line flows created by candidate LTCRs in the opposite direction (i. e. counter-flow will not act to increase the feasibility of candidate LTCRs).
(4)
The feasibility analysis uses an iterative process to ensure that previously awarded LTCRs that have not been surrendered as indicated pursuant to Section 5.2.1 continue to be available. (a)
(b) (c)
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under Section 5.1.1 and which were not surrendered, net of any surrendered nonLSE LTCRs, the feasibility analysis is rerun with all previously awarded non-LSE LTCRs, net of any surrendered non-LSE LTCRs, on such paths modeled as fixed injections/withdrawals and all candidate non-LSE LTCRs on all other paths are modeled as in (a) above. To the extent that these fixed injections and withdrawals are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility prior to LSE LTCR availability. SPP will report back to the MWG when transmission line ratings had to be adjusted to ensure feasibility.
5.2.5
Annual LTCR Available for Non-LSEs
If all of the candidate non-LSE LTCRs are confirmed feasible, all candidate non-LSE LTCRs are available. If candidate non-LSE LTCRs are not feasible, the amount of candidate non-LSE LTCRs available will be reduced using a weighted least squares method. The weighted least squares method minimizes the least squares deviation from the candidate non-LSE LTCR MW weighted by the reciprocal of the candidates resulting in a higher percentage non-LSE LTCR reduction for those candidates having the greatest impact on the constraints. Non-LSE LTCR reductions associated with candidates that have an equal impact on the constraints are reduced by the same percentage. The Transmission Provider will post the amounts of candidate non-LSE LTCRs which are available for the non-LSE Eligible Entity's selection.
5.2.6 (1)
(2)
LTCR Selections and Awards All previously awarded LTCRs associated with qualified transmission service as verified under Section 5.1.1 and which were not surrendered, as described under Section 5.2.1, are automatically awarded as LTCRs for the current allocation year. Additional available candidate LTCRs are selected and awarded in a single-round process. Eligible Entities may select: (a) Available LTCRs from their NITS Candidate LTCRs as described under Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs plus any surrendered LTCRs associated with NITS Candidate LTCRs; (b) Available LTCRs from their FPTP Candidate LTCRs as described under Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs plus any surrendered LTCRs associated with FPTP Candidate LTCRs;
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(c)
(3)
(4)
Available LTCRs from their GFA NITS Candidate LTCRs as described under Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs plus any surrendered LTCRs associated with GFA NITS Candidate LTCRs; (d) Available LTCRs from their GFA FPTP Candidate LTCRs as described under Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs plus any surrendered LTCRs associated with GFA FPTP Candidate LTCRs; Eligible Entities must submit the following information in order to select LTCRs: (a) Source (valid candidate LTCR source Settlement Location); (b) Sink (valid candidate LTCR sink Settlement Location); (c) Selected LTCR MW (total LTCR MW nominated from a source Settlement Location cannot exceed the source candidate available LTCR MW as previously determined under Section 5.2.3 or Section 5.2.5, less previously awarded LTCRs plus surrendered LTCRs); All selected LTCRs are automatically awarded, and these awarded LTCRs and those awarded as described under (1) above are directly converted to TCRs prior to the Annual ARR Allocation Process for the current allocation year.
5.25.3
Comment [MPRR138.1291]: MPRR138 Awaiting FERC Approval. #ER14-2553
Annual ARR Allocation Process
The Annual ARR Allocation Process addresses how candidate ARRs verified in the Annual LTCR/ARR Verification Process may be nominated and converted to ARRs. Eligible Entities may nominate the candidate ARRs that they wish to receive up to their ARR Nomination Caps less any LTCRs awarded plus any LTCRs surrendered. Any candidate LTCRs not awarded in the Annual LTCR Allocation Process and surrendered LTCRs become candidate ARRs. The annual allocation process determines the portion of the nominated candidate ARRs that are simultaneously feasible to allocate to each Eligible Entity. 100% of the SPP Residual Transmission System Capability, as defined under Section 5.2.2(2), is made available during the Annual ARR Allocation Process. Candidate ARRs are nominated on a monthly and seasonal basis in a three-round process. No later than five (5) Business Days prior to the start of the Annual ARR Allocation Process, SPP will post the transmission system network topology data for each of the monthly and seasonal on-peak and off-peak models, along with corresponding Parallel Flow, prohibited collocated and electrically equivalent Settlement Location pairs, and transmission line outage assumptions, that SPP will use in the upcoming allocation process for use by Eligible Entities in developing their candidate ARR nomination strategies. Exhibit 5-3 provides a representative timeline of the three-round annual ARR allocation process.
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Comment [MPRR138.1293]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
Exhibit 5-3: Annual ARR Allocation Process Timeline
6/1 - 9/30 Annual ARR Awards by Month On-Peak and Off-Peak
4/5 - 4/23 Annual ARR Allocation
10/1 - 5/31 Annual ARR Awards by Season On-Peak and Off-Peak
12/15 - 5/31 ARR Allocation 1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
12/15
4
5 5/31
4/5 - 4/6 Eligible Entities Submit Round 1 Nominations
4/11 - 4/12 Eligible Entities Submit Round 2 Nominations
4/17 - 4/18 Eligible Entities Submit Round 3 Nominations
4/5 - 4/23 Three Round ARR Allocation Process
4/5
4/23 SPP Performs Round 1 ARR Allocation 4/7 - 4/10
SPP Performs Round 2 ARR Allocation 4/13 - 4/16
SPP Posts Round 1 Results 4/10
SPP Posts Round 2 Results 4/16
SPP Performs Round 3 ARR Allocation 4/19 - 4/22 SPP Posts Round 3 Results 4/22
The following rules apply to the annual allocation of ARRs.
5.2.15.3.1 ARR Nominations For each month and season included in the Annual ARR Allocation Process period, Eligible Entities may nominate candidate ARRs in 0.1 MW increments for specific source to sink pairs that total up to their ARR Nomination Caps as calculated under Section 5.1.3. Nominations occur separately for On-Peak and Off-Peak periods (8 separate transmission system models created representing each month in an annual allocation period and on-peak and off-peak periods within each month and 6 separate transmission system models created representing each season in an annual allocation period and on-peak and off-peak periods within each season). Prior to each ARR nomination round, Eligible Entities submit the following information:
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(1)
Source (valid candidate ARR source Settlement Location for Rounds 1 and 2, any source Settlement Location for Round 3);
(2)
Sink (valid candidate ARR sink Settlement Location for Rounds 1 and 2, any sink Settlement Location for Round 3);
(3)
Class (on-peak or off-peak);
(4)
Period (month or season);
(5)
Nominated ARR MW. (a)
(b)
In Round 1 and Round 2, the total candidate ARR MW nominated from a source Settlement Location cannot exceed the source candidate ARRs less awarded source LTCRs.
Comment [MPRR138.1294]: MPRR138 Awaiting FERC Approval. #ER14-2553
In Round 3, any source to sink path may be nominated, subject to the limitation described under Section 5.3.2(3).
5.2.25.3.2 ARR Allocation ARRs are allocated in a three-round process as follows: (1)
In Round 1, Eligible Entities may nominate: (a)
(b)
(c)
(d)
(2)
ARRs from their NITS Candidate ARRs that total to no more than the greater of (i) zero or (ii) 50% of their NITS ARR Nomination Cap less the sum of their awarded LTCRs from their NITS Candidate LTCRs;
Comment [MPRR138.1295]: MPRR138 Awaiting FERC Approval. #ER14-2553
ARRs from their GFA NITS Candidate ARRs that total to no more than the greater of (i) zero or (ii) 50% of their GFA NITS ARR Nomination Cap less the sum of their awarded LTCRs from their GFA NITS Candidate LTCRs;
Comment [MPRR138.1297]: MPRR138 Awaiting FERC Approval. #ER14-2553
ARRs from their FPTP Candidate ARRs that total to no more than the greater of (i) zero or (ii) 50% of their FPTP ARR Nomination Cap less the sum of their awarded LTCRs from their FPTP Candidate LTCRs; and ARRs from their GFA FPTP Candidate ARRs that total to no more than the greater of (i) zero or (ii) 50% of their GFA FPTP ARR Nomination Cap less the sum of their awarded LTCRs from their GFA FPTP Candidate LTCRs.
In Round 2, Eligible Entities may nominate:
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Comment [MPRR138.1298]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1299]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1300]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1301]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1302]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
(a)
(b)
(c)
(d)
(3)
ARRs from their NITS Candidate ARRs that total to no more than the greater of (i) zero or (ii) 100% of their NITS ARR Nomination Cap less any nominated NITS Candidate ARRs awarded in Round 1 and less the sum of their awarded LTCRs from their NITS Candidate LTCRs; ARRs from their GFA NITS Candidate ARRs that total to no more than the greater of (i) zero or (ii) 100% of their GFA NITS ARR Nomination Cap less any nominated GFA NITS Candidate ARRs awarded in Round 1 and less the sum of their awarded LTCRs from their GFA NITS Candidate LTCRs; ARRs from their FPTP Candidate ARRs that total to no more than the greater of (i) zero or (ii) 100% of their FPTP ARR Nomination Cap less any nominated FPTP Candidate ARRs awarded in Round 1 and less the sum of their awarded LTCRs from their FPTP Candidate LTCRs; and ARRs from their GFA FPTP Candidate ARRs that total to no more than the greater of (i) zero or (ii) 100% of their GFA FPTP ARR Nomination Cap less any nominated GFA FPTP Candidate ARRs awarded in Round 1 and less the sum of their awarded LTCRs from their GFA FPTP Candidate LTCRs.
In Round 3, Eligible Entities may nominate ARRs from any source to sink that total to no more than the greater of (i) zero or (ii) 100% of their ARR Nomination Cap less any nominated candidate ARR amounts awarded in Rounds 1 and 2 and less the sum of their awarded LTCRs. In Round 3, a Market Participant is limited to a maximum combined submittal of 2000 ARR Nominations per product for each Asset Owner it represents. Market Participants may not nominate candidate ARRs between Settlement Locations that are collocated and electrically equivalent.
Exhibit 5-4 provides an example of valid Round 1 NITS Candidate ARR nominations for a NITS Transmission Customer with a three year average historical annual peak load of 1942 MW and total Candidate ARRs of 2400 MWs and 300 MWs of LTCRs.
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Round 1 ARR Nomination Limit
NITS Candidate ARR MW
Source
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Sink
LTCR
Comment [MPRR138.1304]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1305]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1306]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1307]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1308]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1309]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1310]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1311]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1312]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1313]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1314]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1315]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1316]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1317]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1318]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1319]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1320]: MPRR138 Awaiting FERC Approval. #ER14-2553
Exhibit 5-4: Candidate ARR Nomination for NITS NITS ARR Nomination Cap
Comment [MPRR138.1303]: MPRR138 Awaiting FERC Approval. #ER14-2553
Nominated NITS Candidate ARR MW
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NITS ARR Nomination Cap 2000 MW35
Round 1 ARR Nomination Limit 1000 MW36
NITS Candidate ARR MW
Total
Source
Sink
LTCR
1200
G1
L1
200
800
G2
L1
100
400
G3
L1
0 300
2400
Nominated NITS Candidate ARR MW 800600 200100 0 Comment [MPRR138.1321]: MPRR138 Awaiting FERC Approval. #ER14-2553
1000700
5.2.35.3.3 Simultaneous Feasibility A Simultaneous simultaneous Feasibility feasibility Test test (SFT) analysis is performed in each round to ensure that the nominated candidate ARRs, with nominated candidate ARR MW modeled as generation injection at the source and a corresponding load withdrawal at the sink, do not violate any normal transmission line thermal ratings under normal system conditions and do not violate short-term Emergency transmission line thermal ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent with the transmission system loading analysis that is performed as part the Security Constrained Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow. 100% of the SPP Residual Transmission System Capability, as defined under Section 5.2.2(2), is made available during the analysis. (1)
The SPP Transmission System topology used in the SFT is the most up-to-date Network Model for all allocation periods, updated for forecasted transmission topology changes including planned maintenance outages. (a)
For withdrawals at Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June, July, August, September, Fall, Winter and Spring). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.
35
Lesser of (1.03 * 1942 MW) or 2400 MW
36
50% of ARR Nomination Cap
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Comment [MPRR138.1323]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1324]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Protocols for SPP Integrated Marketplace
(2)
(2)
(b)
For injections at Market Hubs, SPP will distribute the hub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the hub is created.
(c)
For GFA Carve Outs that will be nominated, an injection at the source and a corresponding withdrawal at the sink will be included in the Annual ARR Allocation Process and will be subject to SFT. The capacity used in the allocation will be the maximum allowable nomination as defined in section 5.3.2.
All previously awarded TCRs associated with LTCRs that have not been surrendered are modeled as fixed injections/withdrawals. To the extent that these fixed injections and withdrawals are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility. SPP will report back to the MWG when and which transmission line ratings had to be adjusted, and the magnitude of each adjustment, to ensure feasibility.
Comment [MPRR171.1325]: MPRR171 Awaiting FERC Approval. #ER14-2553
Comment [MPRR171.1326]: MPRR171 Awaiting FERC Approval. #ER14-2553
Prior to assessing simultaneous feasibility, the normal and emergency ratings of all flowgates and monitored transmission system elements are adjusted as follows to arrive at an SPP Residual Transmission System Capability: (a)
Adjusted Monitored Transmission Line Rating (normal and Emergency) = (Monitored Transmission Line Rating (normal and Emergency – Parallel Flow impact)
(b)
Adjusted Flowgate Rating (normal and Emergency) = (Flowgate Rating – Parallel Flow impact)
Comment [MPRR138.1327]: MPRR138 Awaiting FERC Approval. #ER14-2553
Every six (6) months for the first two (2) years after implementation of the Integrated Marketplace, SPP will analyze the net funding of TCRs through the Day-Ahead Market and report to the MWG. In the event the cumulative funding is at or below 90% or above 100%, MWG may approve an additional adjustment of all subsequent monthly auctions and the month of June in the annual auction of the normal and emergency ratings of all flowgates and monitored transmission system elements in (2) above.
5.2.45.3.4 Annual ARR Awards All LTCR awards are automatically converted to ARR awards which are then automatically selfconverted to TCRs in the Annual TCR Auction. If all of the nominated candidate ARRs are confirmed feasible, all nominated candidate ARRs are awarded. If the nominated candidate
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Market Protocols for SPP Integrated Marketplace
ARRs are not feasible, the amount of nominated candidate ARRs to be awarded will be reduced using a weighted least squares method. The weighted least squares method minimizes the least squares deviation from the nominated candidate ARR MW weighted by the reciprocal of the nominations resulting in a higher percentage ARR reduction for those nominations having the greatest impact on the constraints. ARR reductions associated with nominations that have an equal impact on the constraints are reduced by the same percentage.
5.35.4
Annual TCR Auction
The Annual TCR Auction Process is the mechanism through which Market Participants may obtain annual TCRs through submission of TCR Bids to purchase TCRs and/or through conversion of ARRs into TCRs through self-conversion. Various percentages of the SPP Residual Transmission System Capability, as calculated under Section 5.2.3 5.3.3is made available during the Annual TCR Auction Process as shown in Exhibit 5-2. TCRs in the annual auction are auctioned in a single round process for all months and seasons. TCRs that originated as LTCRs may be sold during this single round process. If there are any changes to the transmission system topology, Parallel Flow data, or prohibited collocated and electrically equivalent Settlement Location pairs after the conclusion of Annual ARR Allocation Process, SPP will post such changes no later than three (3) Business Days prior to the start of the Annual TCR Auction Process. Exhibit 5-5 provides a representative timeline of the two-round and single round annual TCR auction process. Exhibit 5-5: Annual TCR Auction Processes Timeline
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Comment [MPRR138.1331]: MPRR138 Awaiting FERC Approval. #ER14-2553
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5/3 - 5/23 Annual TCR Auction
6/1 - 9/30 Annual TCR Auction Awards by Month On-Peak and Off-Peak
10/1 - 5/31 Annual TCR Auction Awards by Season On-Peak and Off-Peak
12/15 - 5/31 TCR Auctions 1
2
3
4
5
6
7
8
9
10
11
12
1
2
12/15
3
4
5 5/31
5/3 - 5/6 MPs submit TCR Bids
5/3 - 5/23 Single-Round Annual TCR Auction
5/3
5/23 SPP Performs TCR Auction 5/7 - 5/14
The following rules apply to the Annual TCR Auction: Comment [MPRR138.1332]: MPRR138 Awaiting FERC Approval. #ER14-2553
5.3.15.4.1 TCR Bid and Offer Submittal (1)
Any Market Participant that has satisfied the applicable credit requirements may participate in the Annual TCR Auction;
(2)
Market Participants holding ARRs may elect to self-convert all or a portion of those ARRs into TCRs with the same source and sink by specifying the Self-Convert option as part of the TCR Bid submittal.; All ARRs associated with LTCRs are automatically converted to TCRs prior to the start of the Annual TCR Auction and these TCRs will be considered Self-Converted ARRs for the purposes of settlement. These Directly converted TCRs from LTCRs can then be offered for sale in the Annual TCR Auction.
(3)
For each month and season included in the Annual TCR Auction period, Market Participants may submit TCR Bids and TCR Offers in 0.1 MW increments separately, for On-Peak and Off-Peak periods (8 separate transmission system models created representing each month in an annual auction period and on-peak and off-peak periods within each month and 6 separate transmission system models created representing each season in an annual auction period and on-peak and off-peak periods within each season). The following information is submitted for a TCR Bid or a TCR Offer: (a)
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Market Protocols for SPP Integrated Marketplace
(4) (5)
(b)
Sink (any valid Settlement Location);
(c)
Class (on-peak or off-peak);
(d)
Period (month or season);
(e)
Type (Bid, or Self-Convert, Offer);
Comment [MPRR138.1339]: MPRR138 Awaiting FERC Approval. #ER14-2553
(f)
TCR MW;
Comment [MPRR138.1340]: MPRR138 Awaiting FERC Approval. #ER14-2553
(g)
TCR Price ($/MW); (i)
TCR Bids and Offers cannot exceed $100,000/MW-Month;
Comment [MPRR138.1341]: MPRR138 Awaiting FERC Approval. #ER14-2553
(ii)
TCR Bids and Offers cannot be less than ($100,000/MW-Month).
Comment [MPRR138.1342]: MPRR138 Awaiting FERC Approval. #ER14-2553
For each TCR Round, a Market Participant is limited to a maximum combined submittal of 2000 TCR Bids and/or TCR Offers for each Asset Owner it represents.
Comment [MPRR138.1343]: MPRR138 Awaiting FERC Approval. #ER14-2553
Market Participants may not submit offers to buy TCRs between Settlement Locations that are collocated and electrically equivalent.
5.3.25.4.2 Annual TCR Auction Process TCRs are auctioned in a single-round process for each month and season using the SPP Residual Transmission System Capability as defined under Section 5.2.3 5.3.3 as follows: (1)
100% of the SPP Residual Transmission System Capability is made available for the month of June, 90% of the SPP Residual Transmission System Capability is made available for the July-September period and 60% of the SPP Residual Transmission System Capability is made available for the Fall, Winter and Spring seasons;
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(a)
TCR Bids of the Self-Convert Type may be submitted for each source to sink pair that the Market Participant desires to convert the associated ARRs into TCRs. The Self-Convert Type option will convert ARRs associated with the specified source to sink pair into the TCR MW specified subject to simultaneous feasibility.
(b)
Only Eligible Entities holding ARRs may submit a Self-Convert TCR Bid.
(c)
All awarded ARRs from section 5.3.3(1)(c) that resulted from GFA Carve Outs will be automatically submitted to the TCR auction as self-convert TCR Bids.
(d)
The Self-Convert TCR Bid must specify the same source and sink as the associated ARR and the TCR MW must be less than or equal to the associated ARR MW.
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Market Protocols for SPP Integrated Marketplace
5.3.35.4.3 Annual TCR Auction Clearing and Simultaneous Feasibility The Auction is performed using a Linear Program algorithm with an objective function to maximize the total TCR auction value while ensuring that the cleared TCRs are also simultaneously feasible. (1)
(2)
The SFT is performed as described under Section 5.3.3 with TCR Bid MW modeled as an injection at the source and a corresponding withdrawal at the sink and TCR Offer MW modeled as an injection at the sink and a withdrawal at the source.
Comment [MPRR138.1345]: MPRR138 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1346]: MPRR138 Awaiting FERC Approval. #ER14-2553
The SPP Transmission System topology and Parallel Flow assumptions used in the SFT are normally the same as used in the Annual ARR Allocation process. However, unforeseen events that drastically impact transmission system topology that occur following the ARR Allocation but prior to the Annual TCR Auction will be accounted for in the models for the Annual TCR Auctions.
5.3.45.4.4 Annual TCR Awards Simultaneously feasible TCRs are awarded based upon the TCR Bid prices such that the total TCR auction value is maximized. TCRs associated with LTCRs result from ARRs that automatically become Self-Converted TCRs for settlement purposes. Self-Converted TCRs not associated with LTCRs are evaluated simultaneously with submitted TCR Bids and Offers. In the event there is a tie during the SFT, the competing bids and offers will be awarded pro rata based on their impact(s) to the constraint(s). Auction Clearing Prices (ACP) are calculated for each Settlement Location using the formula for the Marginal Congestion Component as K
described under Section 4.5.4.1.2 (MCCi = - (
Sensik * SPk )).
For example, if we assume a 3 bus system (Bus A, B and C) and Bus A is the Reference Bus, we can calculate the ACP at Bus B as follows:
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k 1
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Market Protocols for SPP Integrated Marketplace
Transmission Line B-C is at its limit with a Shadow Price = $40/MW Transmission Line A-C is at its limit with a Shadow Price = $30/MW Transmission Line A-B is not at its limit (Shadow Price = $0/MW) Shift Factor for Bus B on Line B-C is 30% Shift Factor for Bus B on Line A-C is -80% Then ACP at Bus B is equal to - [($40/MW * .3) + ($30/MW * (-.8))] = $12/MW A similar calculation is performed for Bus C based on Bus C Shift Factors. The ACP at Bus A is equal to zero since Bus A is the Reference Bus.
5.45.5
Monthly ARR Allocation Process
Eligible Entities with remaining candidate ARR capacities from the Annual ARR Allocation Process along with firm transmission service that has been confirmed following completion of the Annual TCR Auction Process and prior to the next Annual ARR Verification Process or with firm transmission service confirmed prior to the Annual ARR Verification Process that includes a partial season or transmission service that is made available due to upgrades are eligible to nominate candidate ARRs associated with such services. Any remaining candidate ARR capacities from the Annual ARR Allocation Process related to GFA Carve Outs will be included in the Monthly ARR Allocation Process. To the extent that the Eligible Entity’s firm transmission service term extends beyond the current Annual ARR Allocation Process period, such remaining service will be included in the next Annual ARR Verification Process. The following rules apply to verification of transmission service for conversion to incremental candidate ARRs.
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5.4.15.5.1 Monthly ARR Transmission Service Verification
Comment [MPRR138.1353]: MPRR138 Awaiting FERC Approval. #ER14-2553
In order for Eligible Entities to obtain incremental candidate ARRs, SPP must first verify existing transmission service entitlements. In order to qualify for incremental candidate ARRs in a particular month, an Eligible Entity’s transmission service must span the entire month within the applicable year. SPP will verify Eligible Entity existing transmission service entitlements as follows: (1)
SPP obtains that the source, sink and Reserved Capacity information from the SPP OASIS for the applicable month;
(2)
SPP will provide this information to each Eligible Entity for verification
(3)
Eligible Entities will notify the Transmission Provider within six (6) days following receipt of this information, identifying and correcting inaccurate data on the OASIS. Otherwise, the Transmission Provider provided data will be considered verified.
Five (5) days prior to the start of each applicable Monthly TCR Auction Process, Eligible Entities may nominate in a single round process (i) NITS Candidate ARRs in 0.1 MW increments along specific source to sink paths that total to no more than the difference between (1) their NITS ARR Nomination Cap and (2) the sum of (a) awarded ARRs associated with NITS Candidate ARRs awarded in the Annual ARR Allocation processand (b) directly converted TCRs from awarded LTCRs associated with NITS Candidate LTCRs awarded in the Aannual ARR Aallocation processes; (ii) FPTP Candidate ARRs in 0.1 MW increments along specific source to sink paths that total to no more than the difference between (1) their FPTP ARR Nomination Cap and (2) the sum of (a) awarded ARRs associated with FPTP Candidate ARRs and (b) directly converted TCRs from awarded LTCRs associated with FPTP Candidate LTCRs awarded in the Annual annual ARR Allocation allocation processes; (iii) GFA NITS Candidate ARRs in .1 MW increments along specific source to sink paths that total to no more than the difference between (1) their GFA NITS ARR Nomination Cap and (2) the sum of (a) awarded ARRs associated with GFA NITS Candidate ARRs and (b) directly converted TCRs from awarded LTCRs associated with GFA NITS Candidate LTCRs awarded in the Annual annual ARR Allocation allocation processes; and/or (iv) GFA FPTP Candidate ARRs in 0.1 MW increments along specific source to sink paths that total to no more than the difference between (1) their GFA FPTP ARR Nomination Cap and (2) the sum of (a) awarded ARRs associated with GFA FPTP Candidate ARRs and (b) directly converted TCRs from awarded LTCRs associated
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5.4.25.5.2 Monthly ARR Nominations
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Market Protocols for SPP Integrated Marketplace
with GFA FPTP Candidate LTCRs awarded in the Annual annual ARR Allocation allocation processes. Nominations occur separately for On-Peak and Off-Peak periods. Eligible Entities submit the following information:
Comment [MPRR171.1383]: MPRR171 Awaiting FERC Approval. #ER14-2553 Comment [MPRR138.1384]: MPRR138 Awaiting FERC Approval. #ER14-2553
(1)
Source (valid candidate ARR source Settlement Location);
Comment [MPRR171.1385]: MPRR171 Awaiting FERC Approval. #ER14-2553
(2)
Sink (valid candidate ARR sink Settlement Location);
Comment [MPRR171.1386]: MPRR171 Awaiting FERC Approval. #ER14-2553
(3)
Class (on-peak or off-peak);
Comment [MPRR171.1387]: MPRR171 Awaiting FERC Approval. #ER14-2553
(4)
ARR MW. (a)
The total ARR MW nominated from a source Settlement Location cannot exceed the source candidate ARRs less previously awarded source ARRs.
Comment [MPRR138.1388]: MPRR138 Awaiting FERC Approval. #ER14-2553
5.4.35.5.3 Simultaneous Feasibility The SFT to assess feasibility of nominated monthly candidate ARRs is performed as described under Section 5.3.3 with the following adjustments: (1)
The SPP Transmission System model used in the SFT will be the same model to be used in the upcoming Monthly TCR Auction Process which will include the most up-to-date Network Model updated for forecasted transmission topology changes, including planned maintenance outages, and updated Parallel Flow assumptions; (a)
Comment [MPRR138.1390]: MPRR138 Awaiting FERC Approval. #ER14-2553
For withdrawals at sink Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June for the month of July). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.
LTCRs awarded in the Annual LTCR Allocation process are not modeled as fixed injections/withdrawals as they have already been accounted for as part of the Annual TCR Auction process and are included as TCRs as described under (4) below; (2)
100% of the Residual SPP Transmission System Capability is made available; and
(3)
All TCRs previously awarded in the Annual TCR Auction Process, directly converted TCRs fromassociated with LTCRs that were awarded, and all remaining ARRs not accounted for in the Annual TCR Auction Process (as defined under Section 5.55.6), and for the applicable month are modeled as fixed injections at the specified sources and fixed withdrawals at the specified sinks. To the extent that these fixed injections and
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Market Protocols for SPP Integrated Marketplace
withdrawals are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility prior to assessing monthly ARR feasibility. SPP will report back to the MWG on a quarterly basis regarding the number of times that transmission line ratings had to be adjusted to ensure feasibility.
5.4.45.5.4 Monthly ARR Awards If all of the nominated candidate ARRs are confirmed feasible, all nominated candidate ARRs are awarded in the form of ARRs. If the nominated candidate ARRs are not feasible, the amount of ARRs to be awarded will be reduced using a weighted least squares method. The weighted least squares method minimizes the least squares deviation from the nominated candidate ARR MW weighted by the reciprocal of the nominations resulting in a higher percentage ARR reduction for those candidate ARR nominations having the greatest impact on the constraints. ARR reductions associated with candidate ARR nominations that have an equal impact on the constraints are reduced by the same percentage.
5.55.6
Monthly TCR Auction Processes
The Monthly TCR Auction Process is the mechanism through which Market Participants may obtain TCRs over and above those obtained in the Annual TCR Auction Process through submission of TCR Bids to purchase TCRs and/or through conversion of remaining ARRs awarded in the Annual ARR Allocation Process and/or ARRs awarded in the Monthly ARR Allocation Process into TCRs through Self-Conversion. All awarded monthly ARRs that resulted from GFA Carve Outs will be automatically submitted to the TCR auction as selfconvert TCR Bids for the maximum capacity allowable consistent with section 5.6.2. Market Participants may also offer for sale TCRs awarded in the Annual TCR Auction Process. 100% of the SPP Transmission System capability is made available during the Monthly TCR Auction Process. The remaining TCRs for the months of July through September are auctioned in a single-round process. The remaining TCRs for the months of October through May are auctioned in a two-round process. No later than three (3) Business Days prior to the start of the Monthly TCR Auction Process, SPP will post the transmission system network topology data, along with corresponding Parallel Flow, prohibited collocated and electrically equivalent Settlement Location pairs, and transmission line outage assumptions, that SPP will use in the upcoming Monthly TCR Auction Process for use by Market Participants in developing their TCR Bid, TCR Offer and/or TCR self-conversion strategies. Exhibit 5-6 provides a representative timeline of the single-round and two-round Monthly TCR Auction Processes.
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Exhibit 5-6: Monthly TCR Auction Processes Timeline 9/8 - 9/18 TCR Monthly Auction for October Repeats Remaining Months
10 - 5 Monthly TCR Auction Awards Month-to-Month On-Peak and Off-Peak
12/15 - 5/31 Monthly TCR Auctions 1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
12/15
5/31
6/8 - 6/9 Market Participants Submit TCR Bids and Offer
TCR Monthly Auction for July Repeats for Remaining Summer Months 6/8 - 6/18
Monthly TCR Auction Awards Month to Month On-Peak and Off-Peak 7/1 - 9/30 9/8 - 9/9 Market Participants Submit Round 1 TCR Bids and Offers
6/8 - 6/18 Monthly TCR Auction – Single Round
6/8
9/14 - 9/15 Market Participants Submit Round 2 TCR Bids and Offers
9/8 - 9/18 Monthly TCR Auctions – Two-Round
6/18 SPP Performs TCR Auction 6/10 - 6/13
9/8
SPP Performs Round 1 TCR Auction 9/10 - 9/13
SPP Posts Results 6/13
SPP Posts Round 1 Results 9/13
SPP Performs9/18 Round 2 TCR Auction 9/16 - 9/18
SPP Posts Round 2 Results 9/18
The following rules apply to the Monthly TCR Auction Processes:
5.5.15.6.1
TCR Bid and Offer Submittal
(1)
Any Market Participant that has satisfied the applicable credit requirements may participate in the Monthly TCR Auction Process;
(2)
Market Participants may submit TCR Bids and TCR Offers separately, for On-Peak and Off-Peak periods (two (2) separate transmission system models created). The following information is submitted for a TCR Bid or TCR Offer: (a) Source (any valid Settlement Location); (b) Sink (any valid Settlement Location); (c) Class (on-peak or off-peak);
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(d) Type (Bid, Offer or Self-Convert); (e) TCR MW (0.1 MW increments, may not exceed ARR MW held on path if SelfConvert Type selected); (f) TCR Price ($/MW);
(3)
(i)
TCR Bids and Offers cannot exceed $100,000/MW-Month;
(ii)
TCR Bids and Offers cannot be less than ($100,000/MW-Month).
For each TCR Round, a Market Participant is limited to a maximum combined submittal of 2000 TCR Bids and/or TCR Offers.
Market Participants may not submit offers to buy TCRs between Settlement Locations that are collocated and electrically equivalent.
5.5.25.6.2 Monthly TCR Auction Process TCRs are auctioned in a single-round process for the months of July through September and 100% of the SPP Residual Transmission System Capability, as calculated under Section 5.3.3 is made available. Any amounts of ARRs awarded in the Monthly ARR Allocation Process plus: the lesser of (i) 10% of the ARRs obtained in the Annual ARR Allocation Process or (ii) the difference between the ARRs obtained in the Annual ARR Allocation Process and the amount of Self-Converted TCRs awarded in the Annual TCR Auction Process may be Self-Converted during this single-round auction and any TCRs obtained in the Annual TCR Auction may be offered for sale.
Comment [MPRR138.1398]: MPRR138 Awaiting FERC Approval. #ER14-2553
TCRs are auctioned in a two-round process for the months of October through May. In the tworound process: (1)
Round 1 - 50% of the Residual SPP Transmission System Capability remaining following the Annual TCR Auction, as calculated under Section 5.3.3 is made available; (a)
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TCR Bids of the Self-Convert Type for any remaining ARRs may be submitted in this round for each source to sink pair that the Market Participant desires to convert that were obtained in the Annual ARR Allocation Process and/or ARRs obtained in the Monthly ARR Allocation Process into TCRs. The Self-Convert Type option will convert ARRs associated with the specified source to sink pair into the TCR MW specified subject to simultaneous feasibility;
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(b) (2)
(i)
Only Eligible Entities holding ARRs obtained in the Annual ARR Allocation Process and/or Monthly ARR Allocation Process may submit a Self-Convert TCR Bid.
(ii)
The Self-Convert TCR Bid must specify the same source and sink as the associated ARR and the TCR MW must be less than or equal to the associated ARR MW.
(iii)
The lesser of: (i) 40% of the ARRs obtained in the Annual ARR Allocation Process or (ii) the difference between the ARRs awarded in the Annual ARR Allocation Process and the quantity of Self-Converted TCRs awarded in the Annual TCR Auction Process, plus all ARRs awarded in the Monthly ARR Allocation Process may be submitted for SelfConversion;
Any TCRs awarded in the Annual TCR Auction may be offered for sale.
Round 2 - The remaining 50% of the Residual SPP Transmission System Capability, as calculated under Section 5.3.3 is made available; (a)
(b)
TCR Bids of the Self-Convert Type for any remaining ARRs may be submitted in this round for each source to sink pair that the Market Participant desires to convert where such remaining ARRs are determined as described under Section 5.7(2)(c).
Comment [MPRR138.1401]: MPRR138 Awaiting FERC Approval. #ER14-2553
Comment [MPRR138.1402]: MPRR138 Awaiting FERC Approval. #ER14-2553
Any TCRs awarded in Round 1 or the Annual TCR Auction, including SelfConverted TCRs, may be offered for sale.
5.5.35.6.3 Monthly TCR Auction Clearing and Simultaneous Feasibility The Auction is performed using a Linear Program algorithm to maximize the total TCR auction value while ensuring that the cleared TCRs are also simultaneously feasible: (1)
The SPP Transmission System topology used in the SFT will be the most up-to-date Network Model updated for forecasted transmission topology changes, including planned maintenance outages, for the auction month; (a)
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For withdrawals at Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June for the month of July). These load distribution
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Market Protocols for SPP Integrated Marketplace
percentages are calculated using the methodology described under Section 4.1.2.1.6. (b)
(2)
For injections at Market Hubs, SPP will distribute the hub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the hub is created.
The SFT is performed as described under Section 5.3.3 except that LTCRs awarded in the Annual LTCR Allocation process are not modeled as fixed injections/withdrawals since they have already been awarded as self-converted TCRs. with TCR Bid MWs are modeled as an injection at the source and a corresponding withdrawal at the sink. TCR Offers associated with the sale of an existing TCRs are modeled as an injections at the sink and a withdrawals at the source. Residual SPP Transmission System Capability includes the most up to date Parallel Flow assumptions. (a)
(b)
For Round 1, all TCRs awarded in the Annual TCR Auction for the month are modeled as fixed injections and withdrawals. To the extent that the fixed injections and withdrawals representing TCRs awarded in the Annual TCR Auction are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility prior to the Round 1 auction. SPP will report back to the MWG on a quarterly basis regarding the number of times that that transmission line ratings had to be adjusted to ensure feasibility; For Round 2, all TCRs previously awarded for the month are modeled as fixed injections and withdrawals prior to clearing the TCR Bids and Offers.
5.5.45.6.4 Monthly TCR Awards Simultaneously feasible TCRs are awarded based upon the TCR Bid and Offer prices such that the total TCR auction value is maximized. Self-Converted TCRs are evaluated simultaneously with submitted TCR Bids and Offers. Auction Clearing Prices (ACP) are calculated as described under Section 5.4.4.
5.65.7
ARR Allocation/TCR Auction Settlements
The charges and credits to ARR holders and TCR holders will be calculated on a daily basis and included on the settlement statements consistent with the timing of the Energy and Operating Reserve Markets settlement as described under Section 4.5.9.24. For the purposes of calculating charges and credits to ARR holders, the following amounts of ARR awards will be used:
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Market Protocols for SPP Integrated Marketplace
(1)
ARR Settlement for Annual TCR Auction by path:
(2)
(a)
For the month of June, 100% of annual ARR award;
(b)
For the months of July through September, the greater of (i) 90% of annual ARR award or (ii) Self-Convert TCR award;
(c)
For the Fall, Winter and Spring season, the greater of (i) 60% of annual ARR award or (ii) Self-Convert TCR award.
ARR Settlement for Monthly TCR Auction:
5.75.8
(a)
For the months of July through September, remaining ARRs not accounted for in ARR Settlement in the Annual TCR Auction as described in (1)(b) above plus all ARR awards;
(b)
For the months of October through May for Round 1, the greater of (i) (50% of ARR awards plus: (50% of the difference between the annual ARR award and the ARRs accounted for in the Annual TCR Auction as described in (1)(c) above) or (ii) Self-Convert TCR awards; and
(c)
For the months of October through May for Round 2, the difference between: (i) the sum of annual ARR awards and ARR awards and (ii) the sum of ARR MW accounted for under Section (1)(c) above and the ARR MW accounted for under Section (2)(b) above.
TCR Secondary Market
SPP will facilitate a secondary market for previously awarded TCRs as follows: (1)
Bilateral trading of existing TCRs is facilitated through a bulletin board system;
(2)
TCRs may be broken down into 0.1 MW increments that total the original TCR;
(3)
TCRs may be traded daily, for On-Peak and/or Off-Peak periods;
(4)
Trades must be completed no later than two (2) calendar days prior to the applicable Operating Day to which the TCR instrument applies;
(5)
The TCR purchaser pays TCR seller directly;
(6)
TCRs may not be reconfigured (path must remain the same);
(7)
SPP accounts for transfer of TCR ownership; and
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(8)
Both Purchaser and seller must be a Market Participant that has met applicable credit requirements.
5.85.9
Interim TCR Markets Schedule
The interim production schedule for March 1, 2014 through May 31, 2014 shall be as follows: (1)
Interim candidate ARR Verification: 10.18.2013 – 10.31.2013
(2)
Interim 3-round ARR Allocation: 11.1.2013 – 11.22.2013
(3)
Interim 1-round TCR Auction: 12.3.2013 – 12.13.2013
(4)
Monthly ARR Allocation and Monthly TCR Auction (a)
March: 2.3.2014 – 2.14.2014
(b)
April: 3.17.2014 – 3.28.2014
(c)
May: 4.7.2014 – 4.18.2014
The interim ARR Allocation and TCR Auction processes shall include: (1)
March, April, and May periods
(2)
On-peak and off-peak products
(3)
March, April, and May 3-round ARR Allocation: 100% system capacity
(4)
March, April, and May 1-round TCR Auction: 90% system capacity
The ARR Monthly Allocation and Monthly TCR Auction processes shall include: (1)
March, April, and May periods
(2)
On-peak and off-peak products
(3)
March, April, and May 1-round ARR Allocation: 100% system capacity
(4)
March, April, and May 1-round TCR Auction: 100% system capacity
Exhibit 5-7: Interim Process Detail Calendar
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Pre-verification Candidate ARR Verification Nomination Window Run ARR Post ARR Bid Window Run TCR Post TCR
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6.
Market Registration
All Market Participants must register their loads and Resources, excluding Behind the Meter Generation less than 10 MW, prior to participation in the SPP Integrated Marketplace. Registration is accomplished by entering the required information via the SPP Market Registration Portal. In addition, each Market Participant is required to execute the service agreement specified in Tariff Attachment AH. Registration identifies each load and/or Resource to Asset Owners, associated Market Participants and Settlement Locations, Meter Agents, and settlement responsibilities. A Market Participant may represent one or more Asset Owners and may appoint a Designated Agent to perform its functions under these protocols. Assets are the registered loads and Resources to an Asset Owner at specific Settlement Locations and have a designated Meter Agent. Market Participants have the legal relationship with SPP. The Market Participants may participate in the SPP Integrated Marketplace as any combination of Resource entities, load serving entities, Meter Agents, and/or power marketers. The Market Participant is also responsible for insuring that SPP receives Settlement Location data from the Meter Agent in a suitable electronic format. Registration data is used for operation and settlement of the SPP Integrated Marketplace, identifying responsibilities and identifying discrete entities. The registration data is also used in the interaction of SPP Customer Relations personnel with Market Participants. Exhibit 6-1 provides an overview of how the registration data is used in developing settlement related items in the Commercial Model. Please note the diagram does not show all of the Node to Meter Settlement Location to Meter Data Submittal Location relationships, only a sample subset. Each Meter Data Submittal Location will have a minimum of a single PNode (Meter Settlement Location) associated with it and each PNode will have a single Node associated with it.
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Exhibit 6-1: Commercial Model and Network Element Relationships Reserve Zones RZN
RZN DRL
DRL
Common Bus
Settlement Locations (pricing / settlement)
Meter Data Submittal Locations
Gen
Gen
Gen
Gen
Gen
Load
Load
MDSL
MDSL
MDSL
MDSL
MDSL
MDSL
MDSL
MDSL
SA
SA
Meter Settlement Locations
Network Model Link –
PNode
PNode
PNode
PNode
Node
Node
Node
Node
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DDR
Intf
MDSL
MDSL
Tie Line
Hub
Tie Line
Settlement Areas (residual / calibration) Commercial Model Network Model
665
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Market Protocols for SPP Integrated Marketplace
6.1
Registration of Resources
Any Market Participant operating Resources within SPP or representing Asset Owners that are not Market Participants that are operating Resources within SPP must register with SPP via the SPP Market Registration Portal and be capable of performing the functions of a Resource as described herein. Resources are registered on a nodal basis to Settlement Locations. Resources at the same physical and electrically equivalent injection point to the transmission grid may register at the unit or plant level. Failure or refusal to register a Resource will result in SPP filing an unexecuted version of the service agreement as specified in Tariff Attachment AH for that Resource with FERC under the name of the generation interconnection customer under an interconnection agreement with SPP or the applicable TO. In the case of a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility, such registration will not require the Qualifying Facility to participate in the Integrated Marketplace or subject the Qualifying Facility to any charges or credits related to the Integrated Marketplace. The Integrated Marketplace charges and payments associated with the Qualifying Facility will be handled in accordance with Attachment AE to the SPP Tariff.
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;
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(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”);
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.
6.1.2
Energy Production Prior to Completion of Market Registration
Market Participants and associated Asset Owners will be allowed to generate energy prior to the effective date of a submitted market registration packet under the following conditions: (1)
The Market Participant, or its agent, has submitted a completed registration packet so that the Resource will be registered and recognized in the SPP market systems on the next model update;
(2)
If real-time data is not being provided via telemetry to SPP BA, the Market Participant or its agent shall provide hourly updates of current output and expected output for each 5minute interval of the upcoming hour. The actual five (5) minute output for the previous hour shall also be provided;
(3)
If the energy production is expected to contribute to any real-time reliability issues on the transmission grid, interruption must occur within 15 minutes upon directive from the SPP BA;
(4)
Energy shall be limited to a maximum of 10 MW, or a greater amount agreed to by the SPP Balancing Authority and interconnect Transmission Owner;
(5)
Energy generated under these provisions will not be settled in the SPP. SPP will not be responsible for making any compensation to the generation owner or any Market Participant for the energy produced.
6.1.3
Common Bus
Asset Owners of Resources located at an electrically equivalent bus may elect Common Bus treatment for these Resources. SPP will verify that the specified Resources are located at an
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electrically equivalent bus prior to creating the Common Bus relationship in the Commercial Model.
6.1.4
Dispatchable Demand Response Resource
In addition to the responsibilities described under Section 6.1.1, Asset Owners registering a Dispatchable Demand Response (DDR) Resource must: (1)
Identify an associated Demand Response Load Asset;
(2)
Identify an associated Dispatchable Controllable Load Settlement Location;
(3)
Specify one of the following two options for calculation of the DDR Resource output as described under Section 4.2.2.5.1:
(4)
(a)
Submitted Resource Output;
(b)
Calculated Resource Output.
Certify that the Calculated Resource Output method, if selected, is consistent with the retail tariff or agreement under which the load is purchasing energy from its retail provider, and SPP will notify the applicable retail provider and the relevant electric retail regulatory authority of the registration and the expected level of participation.
6.1.5
Block Demand Response Resource
In addition to the responsibilities described under Section 6.1.1, Asset Owners registering a Block Demand Response (BDR) Resource must: (1)
Identify an associated Demand Response Load Asset;
(2)
Identify an associated Block Controllable Load Settlement Location; and
(3)
Certify that the Calculated Resource Output method that must be used for a BDR is consistent with the retail tariff or agreement under which the load is purchasing energy from its retail provider, and SPP will notify the applicable retail provider and the relevant electric retail regulatory authority of the registration and the expected level of participation.
6.1.6
Jointly Owned Resource
In addition to the responsibilities described under Section 6.1.1, Market Participants wishing to model each ownership share as a separate Resource must choose one of the two options
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described below and provide the specified additional information. A Resource registered as a Combined Cycle Resource may not register as a JOU. 6.1.6.1
Individual Resource Option
Under the Individual Resource Option, each ownership share is modeled as a separate Resource for the purposes of commitment and dispatch and each Resource may be committed independent of the other Resource shares. In order to qualify for this option, all Asset Owners must certify that if their ownership share Resource is the only Resource committed, that their ownership share is greater than or equal to the minimum physical capacity operating limit of the Physical JOU Resource. The following additional information must also be provided and/or specified: (1)
(2)
Specification of a single Asset Owner that will be responsible for submittal of the following operating data representing the physical operating characteristics of entire JOU Resource for use in data validation as described under Section 4.2.2.5.4; (a)
JOU maximum physical capacity operating limit;
(b)
JOU minimum physical capacity operating limit; and
(c)
Maximum physical 10-minute response from an off-line state.
Specification of each Asset Owner and Settlement Location associated with each individual ownership share.
The default presumption is that the operating owner’s Meter Agent will be the Meter Agent for that JOU Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of the Resource. 6.1.6.2
Combined Resource Option
Under the Combined Resource Option, each ownership share is modeled as a separate Resource for the dispatch purposes but commitment related parameters are submitted representing the entire physical Resource. Under this option, the commitment decision is made assuming that all Resource shares must be committed or none at all. This option must be selected if the eligibility criteria stated under the Individual Resource Option cannot be met. The following additional information must also be provided (1)
Specification of a single Asset Owner (“designated Asset Owner”) that will be responsible for submittal by or on its behalf of all unit commitment related data and the
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following operating data representing the physical operating characteristics of entire JOU Resource for use in data validation as described under Section 4.2.2.5.4;
(2)
(a)
JOU maximum physical capacity operating limit;
(b)
JOU minimum physical capacity operating limit; and
(c)
Maximum physical 10-minute response from an off-line state.
Specification of each Asset Owner, JOU Ownership Percent Share and Settlement Location associated with each individual ownership share JOU Resource. (a)
Submitted JOU Ownership Percent Shares must add up to 100%.
The default presumption is that the operating owner’s Meter Agent will be the Meter Agent for that JOU Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of the Resource.
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 combined Cycle cycle Resource shall register their Resources for Commercial Modeling purposes using one of the three four options described below. (1)
(2)
Each combustion turbine and steam turbine may be registered as a separate Resource asset. Each individual Resource asset will be assigned a unique Settlement Location and each Resource asset must be registered to the same Asset Owner. (a)
Each Resource asset will be committed and dispatched as an independent Resource. Each individual Resource asset will be settled at its Settlement Location. Telemetering and Settlement meter data must be submitted for each registered Resource asset.
(b)
The Market Participant may optionally request that all Resource assets be registered at a Common Bus.
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;
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(c) (3)
(4)
Telemetering must be submitted for each component of the aggregate Resource that is modeled in the Network Model.
The Combined combined Cycle 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.
The combined cycle Resource may be registered as separate Resources, each representing a valid operating configuration. (a)
Market Participants using the combined cycle configuration based modeling option shall register the physical units that are part of the combined cycle resource as well as the logical operational configuration modes representing a “logical unit” of the combined cycle Resource. Each logical unit is treated as a separate Resource in the Commercial Model 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 combined cycle Resources that can operate in more than one mode. SPP may limit the number of logical operational configurations that can be submitted per combined cycle Resource if needed to address software performance issues.
(c)
Market Participants shall supply operating characteristics for each logical operational configuration of a combined cycle Resource, including, but not limited to: location of physical Resource, Legal owner, Resource type set to combined cycle (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;
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(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
Configuration
Configuration
Configuration
1
2
3
4
Startup (Yes/No):
Yes
No
Yes
No
Shutdown (Yes/No):
Yes
No
No
No
(e)
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.
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Exhibit 6-3: Combined Cycle Configuration Transition Cost Matrix From > To
Configuration 1
Configuration 1
Configuration 2
Configuration 3
Configuration 4
300
2,000
600
1,500
3,000
Configuration 2
0
Configuration 3
0
0
Configuration 4
0
0
(f)
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Market Participants shall submit a Configuration Capability Array. 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 a 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 6-4: Combined Cycle Configuration Capability Array 3x1 CC Configuration Capability Array
CT-1
1
2
3
P
P
P
P
P
CT-2
(g)
CT-3
A
A
P
ST-1
P
P
P
Market Participants may optionally define groups of operational configurations to which a Group Minimum Run Time will apply. The Group Minimum Run Time, if defined, will be used in addition to the Plant Minimum Run Time for more accurate operational modeling of the plant. Exhibit 6-5 shows an example of how a group definition might be defined for a 2 x 1 plant. Configuration 1 is CT1; Configuration 2 is (CT1, ST); Configuration 3 is (CT2, ST) and Configuration 4 is (CT1, CT2, ST). Exhibit 6-5: Combined Cycle Configuration Group Definition
1
Group Definition 2
Group 1
3 Yes
4 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 6-6: Combined Cycle Configuration Group Definition
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6.1.8
Dispatchable Variable Energy Resource
All Wind-powered Variable Energy Resources must register as a Dispatchable Variable Energy Resource except for (i) Variable Energy Resources with an interconnection agreement executed on or prior to May 21, 2011 and that commenced Commercial Operation before October 15, 2012 or (ii) a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility. VERs included in (i) above may register as Dispatchable Variable Energy Resources if they are capable of being incrementally dispatched by the Transmission Provider. A Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility may register as a Dispatchable Variable Energy Resource if it is capable of being incrementally dispatched by the Transmission Provider and will be subject to the DVER market rules including Uninstructed Resource Deviation Charges. Non-wind (e.g. solar, run-of-the-river hydro, biomass) Variable Energy Resources shall not be required to register as a Dispatchable Variable Energy Resources unless they choose to register as such. Any Resource that has previously registered as a Dispatchable Variable Energy Resource shall not subsequently register as a NonDispatchable Variable Energy Resources. (1)
A Dispatchable Variable Energy Resource is eligible to submit Offers for RegulationDown if that Resource qualifies to provide Regulation-Down by passing the test described under Section 6.1.11.3.
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(2)
A Dispatchable Variable Energy Resource is not eligible to submit Offers for RegulationUp, Spinning Reserve or Supplemental Reserve;
(3)
Dispatchable Variable Energy Resources are committed and dispatched the same as any other Resource in the Day-Ahead Market.
(4)
For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.5.
(5)
Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.
6.1.9
Non-Dispatchable Variable Energy Resource
Variable Energy Resources that qualify may register as a Non-Dispatchable Variable Energy Resource. The Market Participant registering a Non-Dispatchable Variable Energy Resource must provide documentation to SPP verifying that it meets one or more of the exceptions in Section 6.1.8. Otherwise, the Resource must be registered as a Dispatchable Variable Energy Resource. NDVERs are committed and dispatched the same as any other Resource in the DayAhead Market. For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.6. Non-Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.
6.1.10
Resources External to the SPP BA
6.1.10.1
External Dynamic Resources
A Market Participant registers an EDR for the purposes of accounting for importing of Operating Reserve that is sourced external to the SPP BA. An External Dynamic Resource that is modeled in the Eastern Interconnection may either represent a single Resource or a fleet of Resources and is not subject to Energy dispatch, only clearing and deployment of the Operating Reserve products that the EDR is qualified to provide, except that an associated Dynamic Schedule for Energy may be used for the purposes of providing Regulation-Down Service which must be specified at registration. An EDR that is associated with a DC tie-line is modeled as a single Resource and may be available for Energy dispatch and/or Operating Reserve clearing which must be specified at registration. See Section 4.2.2.5.7 for specific modeling details.
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6.1.10.2
Resources External to the SPP BA Pseudo-Tying In
Market Participants with Resources external to the SPP BA, other than External Dynamic Resources, wishing to participate in the SPP Integrated Marketplace with those Resources must pseudo-tie those Resources into the SPP Balancing Authority (BA) utilizing the SPP OATT Attachment AO or equivalent agreement approved by SPP. (a)
In addition to the responsibilities outlined in the Attachment AO agreement, the Market Participant representing the Resource will be responsible for registering and performing all responsibilities that are required of any other Resource in the SPP Integrated Marketplace.
(b)
The Market Participant representing the Resource must be the Meter Agent or contract with designate a Meter Agent that will be responsible for submittal of settlement meter data as described under Section 7.1 of Appendix D.
(c)
Firm transmission service from the Resource to the SPP border is required.
(d)
Market Participants may remove or add pseudo-tied in Resources in accordance with the timelines described under Section 6.4
6.1.10.3
Resources Internal to the SPP BA Pseudo-Tying Out
Market Participants with Resources interconnected to the SPP transmission system not wishing to participate in the SPP Integrated Marketplace with those Resources have the option to pseudotie those Resources out of the SPP Balancing Authority (BA) utilizing the SPP OATT Attachment AO or equivalent agreement approved by SPP. (a)
The Market Participant representing the Resource must be registered in the SPP Integrated Marketplace for the purposes of accounting for congestion and loss costs incurred within the SPP BA resulting from the Pseudo-Tied Resource output.
(b)
The Market Participant will not be allowed to offer the Resource in the DA Market, RUC, or RTBM.
(c)
Firm Transmission service is required from the Resource to the SPP border.
(d)
Market Participants may remove or add pseudo-tied out Resources in accordance with the timelines described under Section 6.4.
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6.1.11
Operating Reserve Certification
A Market Participant’s Resource must meet the following certification requirements in order to be eligible to submit Operating Reserve Offers for use in the SPP Integrated Marketplace. 6.1.11.1
Spin Qualified Resources
There are no specific testing requirements for a Resource to become a Spin Qualified Resource. A Market Participant will self-certify that its Resource is capable of deploying Spinning Reserve or on-line Supplemental Reserve during the registration process. In such case, that Resource will become a Spin Qualified Resource. However, in order to verify that any cleared Spinning Reserve or on-line Supplemental Reserve is capable of being deployed, SPP may perform on-line Contingency Reserve deployment tests as follows: (1)
SPP will issue an Out-Of-Merit-Energy instruction to the Resource to get a stable dispatch prior to the start of the test;
(2)
SPP will modify the Out-Of-Merit-Energy instruction to the Resource being tested as follows:
(3)
(a)
If this is a random on-line Contingency Reserve deployment test, SPP will issue an Out-Of-Merit-Energy instruction equal to the amount of online Contingency Reserve cleared on the Resource.
(b)
If this is a retest requested by a Market Participant, SPP will issue an Out-OfMerit-Energy instruction equal to the amount of online Contingency Reserve available to be cleared on the Resource without the cap enforced as a result of the previously failed test.
Simultaneously with the beginning and end of the on-line Contingency Reserve deployment test (which will span a period equivalent to the Contingency Reserve Deployment Period), SPP will take a snapshot of the Resource MW output. The difference between the Resource MW output at the end of the test and the Resource MW output at the beginning of the test will be equal to the Resource response.
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(a)
SPP will communicate the results of the test to the Market Participant associated with the affected Asset Owner no later than 60 minutes following the end of the test.
(b)
If the Resource response is greater than or equal to 75% of the MW specified in the deployment instruction, the Resource has passed the test, and the Out-Of-
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Merit-Energy instruction and any previous online Contingency Reserve caps will be released.
(c)
(i)
For settlement purposes, this instruction shall be considered a Manual Dispatch Instruction and the Resource will be eligible for compensation for Out-Of-Merit-Energy as described under Section 4.5.9.9.
(ii)
If this test was a retest requested by the Market Participant as described under (c) below, the Resource will not be eligible for compensation for Out-Of-Merit-Energy as described under Section 4.5.9.9.
If the Resource response is less than 75% of the MW specified in the deployment instruction, the Resource has failed the test and the following actions will be taken: (i)
The Resource will not be eligible for compensation for Out-Of-MeritEnergy as described under Section 4.5.9.9;
(ii)
SPP will cap the amount on-line Contingency Reserve available to be cleared on that Resource to the Resource response observed in the test or zero, whichever is larger, until such time that the Resource requests and passes a retest;
(iii) The Market Participant that registered the Resource must obtain SPP approval regarding the timing of the retest; (iv) The Out-Of-Merit-Energy instruction will be released. 6.1.11.2
Supplemental Qualified Resources
There are no specific testing requirements for an off-line Resource to become a Supplemental Qualified Resource. A Market Participant will self-certify that its off-line Resource is capable of deploying Supplemental Reserve during the registration process. In such case, that Resource will become a Supplemental Qualified Resource. However, in order to verify that any cleared Supplemental Reserve is capable of being deployed, SPP may perform Supplemental Reserve deployment tests as follows: (1)
SPP will only perform a Supplemental Reserve deployment test on an off-line QuickStart Resource that has cleared Real-Time Supplemental Reserve;
(2)
SPP will issue an Out-Of-Merit-Energy instruction to the Resource being tested as follows:
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(3)
(a)
If this is a random Supplemental Reserve deployment test, SPP will issue an OutOf-Merit-Energy instruction equal to the amount of off-line Supplemental Reserve cleared on the Resource.
(b)
If this is a retest requested by a Market Participant, SPP will issue an Out-OfMerit-Energy instruction equal to the amount of off-line Supplemental Reserve available to be cleared on the Resource without the cap enforced as a result of the previously failed test.
Simultaneously with the end of the Supplemental Reserve deployment test (which will span a period equivalent to the Contingency Reserve Deployment Period), SPP will take a snapshot of the Resource MW output. The Resource MW output at the end of the test will be equal to the Resource response. (a)
SPP will communicate the results of the test to the Market Participant associated with the affected Asset Owner no later than 60 minutes following the end of the test.
(b)
If the Resource response is greater than or equal to 75% of the MW specified in the deployment instruction, the Resource has passed the test and the Out-OfMerit-Energy instruction will be released and any previous Contingency Reserve caps will be released.
(c)
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(i)
For settlement purposes, this instruction will be considered as an SPP commitment and the Resource will be eligible for RUC Make-WholePayment compensation as described under Section 4.5.9.8.
(ii)
If this test was a retest requested by the Market Participant as described under (c) below, the Resource will not be eligible for RUC Make-WholePayment compensation as described under Section 4.5.9.8.
If the Resource response is less than 75% of the MW specified in the deployment instruction, the Resource has failed test and the following actions will be taken: (i)
The Resource will not be eligible for compensation for RUC MakeWhole-Payment compensation as described under Section 4.5.9.8;
(ii)
SPP will cap the amount off-line Supplemental Reserve available to be cleared on that Resource to the Resource response observed in the test until such time that the Resource requests and passes a retest;
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(iii) The Market Participant that registered the Resource must obtain SPP approval regarding the timing of the retest; (iv) The Out-Of-Merit-Energy instruction will be released. 6.1.11.3
Regulation Qualified Resources
There are specific testing requirements for a Resource to become a Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource: (1)
A resource may be certified as a Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource only after it achieves three consecutive Regulation Test Scores of 75% or above through the testing procedures described under Section (7);
(2)
The first of these tests may be performed internally by the Asset Owner. Notification to perform a regulation test must be made to SPP at least 20 minutes before the test;
(3)
SPP makes the final determination about whether a regulation test can be performed;
(4)
Only one test may be performed on a Resource each Operating Day;
(5)
SPP may perform a regulation test on any Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource to verify continued certification;
(6)
A Market Participant may request a re-test if it’s Resource was disqualified as a Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource by SPP as described under Section 4.4.3.1. The Resource must attain a test score of 75 % or greater in order to be re-qualified;
(7)
After initial certification, a Compliance Rating of 75% or above must be maintained as described under Section 6.1.11.3.3.
6.1.11.3.1 Regulation Testing Procedures The Regulation test to verify both Regulation-Up Service and Regulation-Down Service capability is run during a continuous 40-minute period. The Regulation test to verify either Regulation-Up Service Capability capability or Regulation-Down Service capability is run during a continuous 20-minute period. Such tests are run when, in the judgment of the SPP test administrator, economic or other conditions do not otherwise change the Dispatch Instruction of the Resources that are being tested. Changes in Dispatch Instructions for a Resource during the
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test period invalidate the test for that Resource. During the Regulation test, the Setpoint Instruction is fixed in each of two or four consecutive 10-minute periods. The following steps describe the implementation of the test. It is assumed that the Regulation-Up Service deployment is positive and Regulation-Down Service deployment is negative. A test may start with either a Regulation-Up Service deployment (if certifying as Regulation Qualified Resource or Regulation-Up Qualified Resource) or a Regulation-Down Service deployment (if certifying as Regulation Qualified Resource or Regulation-Down Qualified Resource) but the steps below assume that the test starts with a Regulation-Up deployment. (1)
(2)
(3)
(4)
(5)
Step One: T0-T10 — During this time period, the stepped Setpoint Instruction is equal to the Dispatch Instruction (i.e. Regulation-Up Service or Regulation-Down Service deployment is equal to zero). This is the initiation of the Regulation test. This ten-minute period is provided so that the Resource settles at its Dispatch Instruction. At T10, the actual loading is sampled and the resulting value defines the Base Loading for that Resource which is shown as the zero axis in Exhibit 6-1. Step Two: T10-T20 — At the start of this 10 minute period, the stepped Setpoint Instruction is increased by 5 times the Resource’s Regulation Ramp Rate to simulate the maximum amount of Regulation-Up Service deployment available on the Resource (Note that this step is skipped for Regulation-Down Qualified Resource certification). Step Three: T20-T30 —At the start of this 10 minute period, the stepped Setpoint Instruction is returned back to the Resource’s Base Loading level (i.e., the Regulation-Up Service deployment is set to zero). Note that for a Resource that is only certifying to provide Regulation-Up Service only, this step constitutes the end of the test. Step Four: T30-T40 — At the start of this 10 minute period, the stepped Setpoint Instruction is reduced by 5 times the Resource’s Regulation Ramp Rate to simulate the maximum amount of Regulation-Down Service deployment available on the Resource. Note that for a Resource that is only certifying to provide Regulation-Down Service only, this step constitutes the beginning of the test. Step Five: T40 — At this time, the stepped Setpoint Instruction is returned back to the Resource’s Base Loading level to terminate the test at T50.
Exhibit 6-5 illustrates these five steps.
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Exhibit 6-7: Regulation Testing Procedure Regulation-Up Deployment Ideal Response
30
35
40 0
45
50 0 T
0 10 0
15 0
20 0
25
Stepped Setpoint Instruction Ramped Setpoint Instruction Regulation-Down Deployment
6.1.11.3.2 Regulation Testing Scoring Scoring the Regulation Test Score is based on the average of two independent test scores: Rate of Response Compliance test score and Regulation Mismatch Compliance test score. (1)
Rate of Response Compliance — The rate of response compliance is a measure of a Resource‘s ability to achieve its Regulation deployment within five (5) minutes. The Rate of Response Compliance is an average of four37 compliance calculations corresponding to the end of each of the four (4) 5-minute ramping periods (T15, T25, T35 and T45)38 during the test and is determined as follows:
(2)
At T15, a snapshot of Resource output is taken. This value is called AG15. The Rate of Response Compliance at time T15 (RORC15) is: RORC15 = 100 – [ [ ABS [ Ramped Setpoint Instruction – AG15 ] / Ramp-Rate-Up * 5 ] *100 ]
37
For Resources only certifying to supply Regulation-Up or Regulation-Down, this value is equal to two.
38
For Resources only certifying to supply Regulation –Up, only T15 and T25 are used. For Resources only certifying to supply Regulation-Down, only T35 and T45 are used.
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(3)
The calculation is repeated at T25, T35 and T45, yielding RORC25, RORC35 and RORC45.
(4)
The Rate of Compliance is then equal to: Rate of Compliance = [RORC15 + RORC25 + RORC35 + RORC45 ] / 4
(5)
Regulation Mismatch Compliance — The Regulation mismatch compliance is a measure of a Resource‘s ability to maintain its actual output at a constant desired level for five minutes. The Regulation Mismatch Compliance is an average of four39 mismatch calculations, corresponding to samples taken during four, five minute periods when the Resource response yields an actual loading equal to the ramped Setpoint Instruction. These time periods are T15-T20, T25-T30, T35-T40 and T45-T5040. During these time periods, the actual loading is sampled. (d)
During the time period T15-T20, a number of Resource output snapshots, n, of actual loading, AG1, AG2, AGn, are taken. The Regulation Mismatch Compliance for the T15-T20 period (RMRC20) is: RMRC20 = {
{ 100 – [ [ ABS [ Ramped Setpoint Instruction – AGn ]
n
/ Ramp-Rate-Up * 5 ] *100 ] } } / n (e)
The calculation is repeated for T25-T30, T35-T40 and T45-T50 yielding RMRC30, RMRC40 and RMRC50.
(f)
The Regulation Mismatch Compliance is then equal to: Regulation Mismatch Compliance = [RMRC20 + RMRC30 + RMRC40 + RMRC50 ] / 4
(6)
Regulation Test Score — The Regulation Test Score is calculated as the average of the Rate of Compliance test score and the Regulation Mismatch Compliance test score: Regulation Test Score = [Rate of Compliance + Regulation Mismatch Compliance] /2
39
For Resources only certifying to supply Regulation-Up or Regulation-Down, this value is equal to two.
40
For Resources only certifying to supply Regulation–Up, only T15-T20 and T25-T30 are used. For Resources only certifying to supply Regulation-Down, only T35-T40 and T45-T50 are used.
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6.1.11.3.3 Regulation Qualified Resource Compliance Rating A Resource‘s Regulation Test Score is defined as the sliding average of the five highest Regulation Test Scores (as described in the previous section) of the last seven valid regulation tests, weighted by MW of Regulation-Up Service, Regulation-Down Service or the sum of Regulation-Up Service and Regulation-Down Service cleared as applicable. If a Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource has a limited number of available Regulation Test Scores, the Regulation Test Score calculation can use a minimum of three test scores as follows: (1)
For a Resource with only three valid Regulation Test Scores, no tests are excluded from the compliance rating calculation;
(2)
For a Resource with only four valid Regulation Test Scores, exclude the lowest test score from the compliance rating calculation;
(3)
For a resource with five or six valid Regulation Test Scores, exclude the two lowest test scores from the compliance rating calculation.
The Resource’s average Compliance Rating is then calculated as follows: Compliance Rating = [ Regulation Test Score * Cleared Regulation MW] / Cleared Regulation MW
6.1.12
Resource Auxiliary Load Modeling
In addition to the responsibilities described under Section 6.1.1, Market Participants registering a Resource shall register its Resource for real-time and settlement metering purposes using one of the three options described below relating to modeling and reporting of auxiliary load. (1)
Gross – Two values shall be reported to SPP via ICCP: gross Resource output (positive value) and auxiliary load consumption (positive value). The gross Resource output does not include reductions for auxiliary load. The Market Participant shall include the auxiliary load of the Resource in the instantaneous load reported to SPP through ICCP whether the Resource is online or offline. The Resource’s gross output into the SPP BA will be reported separately through ICCP.
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(2)
(3)
Net with Aux – Two values shall be reported to SPP via ICCP: net Resource output (positive value) and auxiliary load consumption (positive value). The Market Participant shall report the net value of the Resource’s gross output and auxiliary load to SPP through ICCP while the gross output is greater than the auxiliary load. When the Resource’s gross output is less than or equal to the auxiliary load, the Market Participant shall include the auxiliary load less gross output in the instantaneous load that is also reported to SPP through ICCP and report the Resource’s output as zero MWs. Net without Aux – One value shall be reported to SPP via ICCP: net Resource output (positive or negative). The Market Participant shall report the net value of the Resource’s gross output and auxiliary load to SPP through ICCP. When the Resource’s gross output is less than the auxiliary load, the net Resource output will be negative and viewed as negative generation.
For options (1) or (2) above, if the auxiliary load for the Resource is registered by the Market Participant as a separate PNode, and that PNode is part of a larger load Settlement Location, then meter data for the auxiliary load will be included in the meter data for the larger load Settlement Location. However, if the auxiliary load for that Resource is registered by the Market Participant as a separate PNode at a separate Settlement Location, then the auxiliary load must be submitted for that separate Settlement Location and not as a part of a larger load Settlement Location. For option (3), the auxiliary load must not be registered by the Market Participant as a separate PNode or Settlement Location.
6.2
Registration of Load
Any Market Participant with load within SPP must register with SPP via the SPP Market Registration Portal and be capable of performing the functions of load as described herein. Loads are registered at Settlement Locations within Settlement Areas. Loads may choose to be registered at a Settlement Location consisting of either a single Meter Settlement Location (PNode) or multiple Meter Settlement Locations (APNode). For each load registered, the Asset Owner must specify whether Settlement Meter Data will be submitted on an hourly basis or on a 5-minte basis. An APNode load Settlement Location is not limited by Settlement Area boundaries.
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6.2.1
Responsibilities of the Load
Each Market Participant shall be responsible for conducting its operations in accordance with all applicable SPP market rules and guidelines. The Market Participant is responsible for ensuring that settlement meter data is submitted to SPP.
6.2.2
Non-Conforming Load
Each Asset Owner must identify any Non-Conforming Load asset that the Asset Owner specifically forecasts and the PNode or Aggregate PNode (APNode) at which it resides. A NonConforming Load may only be represented by an APNode if the load is in the same location (e.g. a single industrial process served by more than one bus). For the purposes of this registration requirement, any Non-Conforming Load of 50 MW or greater must be identified.
6.2.3
Demand Response Load Asset
As part of the registration of a Dispatchable Demand Response Resource or a Block Demand Response Resource, the Asset Owner must also identify a corresponding Demand Response Load Asset and its associated PNode or APNode at which the load will be reduced. A Demand Response Load Asset may only be represented by an APNode if the load is in the same location (e.g. a single industrial process served by more than one bus). The PNode or APNode of the Demand Response Load Asset must be contained within the associated Dispatchable Controllable Load or Block Demand Response Settlement Location definition and have a single Meter Data Submission Location. The Demand Response Load Asset is only used by SPP to identify the actual load reduction to verify DDR and BDR compliance with Dispatch Instructions and Operating Reserve deployment instructions.
6.2.4
Dispatchable Demand Response Load Settlement Location
As part of the registration of a Dispatchable Demand Response Resource, the Asset Owner must also identify a corresponding load Settlement Location in which the associated Demand Response Load resides. The Dispatchable Demand Response Load is used by SPP for settlements.
6.2.5
Block Demand Response Load Settlement Location
As part of the registration of a Block Demand Response Resource, the Asset Owner must also identify a corresponding load Settlement Location in which the associated Demand Response Load resides. The Block Demand Response Load is used by SPP for settlements.
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6.2.6
Loads External to the SPP BA Pseudo-Tying In
Market Participants with Load external to the SPP BA wishing to participate in the SPP Integrated Marketplace with that Load must pseudo-tie that Load into the SPP Balancing Authority (BA) utilizing the SPP OATT Attachment AO or equivalent agreement approved by SPP. (a)
In addition to the responsibilities outlined in the Attachment AO agreement, the Market Participant representing the Load will be responsible for registering and performing all responsibilities that are required of any other Load in the SPP Integrated Marketplace.
(b)
The Market Participant representing the Load must be the Meter Agent or contract with a Meter Agent that will be responsible for submittal of settlement meter data as described under Section 7.1 of Appendix D.
(c)
Firm transmission service from the Load to the SPP border is required.
(d)
Market Participants may remove or add pseudo-tied in Load in accordance with the timelines described under Section 6.4.
6.2.7
Loads Internal to the SPP BA Pseudo-Tying Out
Market Participants representing Load interconnected to the SPP transmission system wishing not to participate with that Load in the SPP Integrated Marketplace have the option to pseudo-tie that Load out of the SPP Balancing Authority (BA) utilizing the SPP OATT Attachment AO or equivalent agreement approved by SPP.
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The Market Participant representing the Load will be responsible for registering in the SPP Integrated Marketplace for the purposes of accounting for congestion and loss costs incurred within the SPP BA resulting from the pseudo-Tied Load consumption
(b)
The Market Participant representing the Load will not be permitted to Demand Bids in the Day-Ahead Market associated with that Load.
(c)
Firm Transmission from the Load to the SPP border is required.
(d)
Market Participants may remove or add pseudo-tied out Load in accordance with the timelines described under Section 6.4.
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6.2.8
Loads Transfers Relating to Bilateral Contracts
A Market Participant that is selling firm power to another Market Participant under a bilateral contract may, with the agreement of the buyer, register all or a portion of the buyer’s load as its load asset as described under Section 2.2(11) of Attachment AE to the Tariff. For the purposes of Section 4.2.1.1, such registration of the buyer’s load by the seller shall be accounted for by including such load in the seller’s Reported Load and not including such load in the buyer’s Reported Load, as described under Section 4.2.1.1(A)(1), and such associated bilateral contracts shall not be included in either the buyer’s or seller’s net resource capacity described under Section 4.2.1.1(A)(4).
6.3
Registration of Meter Agent
All Meter Agents (MA) providing meter data under SPP Tariff must register with SPP via the SPP Market Registration Portal. To become registered, MA must be able to demonstrate to SPP that it is capable of performing the functions as described herein. Meter data will be provided with the content and format prescribed in these protocols. The Market Participant is also responsible for insuring that SPP also receives Settlement Location Data from the Meter Agent in a suitable electronic format.
6.4
Network and Commercial Model Updates
Exhibit 6-6 shows the Model Update Timeline. Existing Market Participant Registration related model changes take place as outlined in the table below. New Market Participant Registration related model changes take place three times per year as indicated in the table below. Exceptions to this process can be made on a case-by-case basis as determined by SPP. Detailed model update timing relating to registration of new assets and changes to existing asset is included in Appendix E. Exhibit 6-8: Model Update Timeline
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Production Model Upload Effective Date*
Existing MP Market Reliability with Assets -related Registratio model n related changes model changes
January 1st
X
February 1st
X
March 1st
X
April 1 May 1
st
st
June 1st July 1
st
X
New MP with Assets Registration PRODUCTIO N model changes
X X
New MP with Assets Registration Packets / Projects Due
MP with No Assets (Financial Only) New PROD Registration Documentation Due
X (for August prod)
X (for August prod)
X (for December prod)
X (for December prod)
X (for April prod)
X (for April prod)
X
X
X
X
X
August 1st
X
September 1st
X
October 1st
X
November 1st
X
December 1st
X
X
X
X
X
X
*Note: Model changes will be available seven (7) days prior to the effective date to allow participants to submit necessary market data as applicable in preparation for the effective date.
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6.5
Registration of External Participants in the Reserve Sharing Group
Any external entity participating in the RSG shall complete the Reserve Sharing Group (RSG) registration process through the SPP Customer Relations Department to capture data for SPP’s Integrated Marketplace settlements system, and to establish RSG member access to the Settlements interface of the SPP Marketplace Portal. The Marketplace Settlements system is the mechanism used for financial settlement of RSG activities with SPP as specified in the SPP Tariff.
6.6
TCR/ARR Related Network and Commercial Model Updates
Exhibit 6-4 shows the TCR/ARR Related Model Update Timeline. TCR/ARR related model changes for existing Market Participants take place as outlined in the table below. New Market Participant related model changes take place three times per year as indicated in Exhibit 6-3. TCR/ARR related model additions for new MPs will be implemented as part of the applicable New MP Registration PRODUCTION Model Updates. Detailed model update timing information for the implementation of TCR/ARR related model updates for new and existing MPs, new assets, and changes to existing assets is included in Appendix E. Modification or termination of a Settlement Location with an active TCR/ARR can only be completed after the expiration of applicable TCR/ARR. Requests to modify or terminate a Settlement Location with an active TCR/ARR must follow the timing requirements outlined in Exhibit 6-4.
Exhibit 6-9: TCR Related Model Update Timeline TCR Annual Production Reliability only Commercial Changes Model Effective Date Changes Due Due June 1
February 1st (120 days December 15th (165 prior to June 1st) days prior to June 1st)*
TCR Monthly Production Model Effective Date
Reliability only Changes Received By
Commercial Changes Received By
July 1
May 15
April 15
August 1
June 15
April 15
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September 1
July 15
June 15
October 1
August 15
June 15
November 1
September 15
August 15
December 1
October 15
August 15
January 1
November 15
October 15
February 1
December 15
October 15
March 1
January 15
December 15
April 1
February 15
December 15
May 1
March 15
February 15
*Commercial Model Changes to be included in the TCR Annual Production Model must be included in the February YYYY Model Update with and Effective Date of either February 1st or March 1st. Therefore, the applicable Commercial changes are due to SPP by December 15th of the previous year in order to be included in the February Model Update.
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7.
Market System Outage and Error Handling
7.1
Market System Outages
In the event that the Day-Ahead Market system or the RTBM system incurs an outage that prevents LMPs and MCPs from being calculated for use in settlement, SPP will use the following procedures to calculate prices for use in settlement.
7.1.1
Day-Ahead Market System Outages
In the event that SPP is not able to solve the Day-Ahead Market resulting in no Day-Ahead Market MCCs being produced for use in TCR settlement, SPP will use Real-Time Balancing Market MCCs and Real-Time Balancing Market congestion dollars to settle TCRs. Settlement of TCRs will still occur as part of the Day-Ahead Market settlement. In the event that SPP is not able to solve the Day-Ahead Market, The Day-Ahead Market LMP, MLC, and MCP will be set to zero. Day-Ahead Market MCCs will be replaced by hourly Real-Time Balancing Market MCCs for the purposes of calculating the TCR Funding Amount described under Section 4.5.8.14. Resulting charges calculated under the TCR Daily Uplift Amount described under Section 4.5.8.15 will be reversed and included as a miscellaneous adjustment and included under the Revenue Neutrality Uplift Amount described under Section 4.5.12. This charge reversal will allow any RTBM congestion revenue excess or shortfall amounts to be accounted for within the Revenue Neutrality Uplift Amount. For a Resource Settlement Location, the hourly substitute Day-Ahead MCC will be equal to the Resource output weighted average of the Dispatch Interval MCCs for that Settlement Location in the hour. For a load Settlement Location, the hourly substitute Day-Ahead MCC will be equal to the load consumption weighted average of the Dispatch Interval MCCs for that Settlement Location in the hour. For an Interface or a Market Hub Settlement Location, the hourly substitute Day-Ahead MCCs will be equal to the average of the Dispatch Interval MCCs at that Settlement Location in the hour. Day-Ahead Market Settlement of physical and virtual Energy, Operating Reserve and Bilateral Settlement Schedules will not be performed. Settlement of physical Energy and Operating Reserve will occur in the RTBM only and the Day-Ahead RUC process will be performed assuming that there are no Day-Ahead Market commitments available.
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7.1.2
SPP-Wide Real-Time Balancing Market System Outages
Outages of the Real-Time Balancing Market can result in the loss of Real-Time Balancing Market pricing data for use in settlements. The following rules will apply to the calculation of RTBM LMPs and MCPs during RTBM system outages: (1)
For RTBM outages of twelve (12) Dispatch Intervals or less, LMPs, MCCs, MLCs and MCPs will be set equal to the set of LMPs, MCCs, MLCs and MCPs from the last successful RTBM execution.
(2)
For RTBM outages of more than twelve (12) Dispatch Intervals, SPP will recalculate LMPs, MCCs, MLCs and MCPs using the best data available, including but not limited to actual system load, actual system topology, Resource mitigated Offers and actual Setpoint Instructions issued to Resource’s during the RTBM system outage, to develop input data for use in an off-line RTBM system. To the extent that SPP is unable to recalculate RTBM LMPs, MCCs, MLCs and MCPs, SPP will use the LMPs, MCCs, MLCs and MCPs generated in the Day-Ahead Market for RTBM settlement.
7.1.3
Islanded Real-Time Balancing Market System Outages
If reliability related events cause a portion of generation and load to separate from the SPP Balancing Authority, creating an island situation, SPP will recalculate LMPs within the island using the best data available, including but not limited to actual system load, actual generation and actual system topology within the island and Resource mitigated Offers for Resources within the island, to develop input data for use in an off-line RTBM system. To the extent that input data cannot be obtained to perform the calculation of LMPs within the island, SPP will use the LMPs generated in the Day-Ahead Market within the island for RTBM settlement and make whole payments will be calculated using mitigated RTBM Offers. No clearing of Operating Reserve will occur within the island and MCPs within the island will be set equal to zero. To the extent that 1) this situation extends beyond the next Day-Ahead Market Offer submittal deadline or 2) Resources are self-committed to resolve the situation, and SPP is unable to calculate LMPs for use in settlement, SPP shall inform stakeholders and an alternative method for settlement shall be determined at that time.
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7.2
Procedures for Correcting LMPs and/or MCPs Resulting From Market Software and Data Input Errors
SPP shall monitor for possible market software errors that do not accurately reflect the application of the Tariff, and data input errors in the DA Market and/or RTBM that result in inaccurate LMPs and/or MCPs. Events that may result in data input errors include, but are not limited to: (1)
Bad or missing SCADA (RTBM);
(2)
Load Forecast Error (RTBM) due to bad or missing SCADA;
(3)
Missing Intervals (RTBM);
(4)
Operator/Human Error (DA Market and RTBM).
The occurrence of any of these events may warrant a revision to LMPs and/or MCPs and are flagged by SPP. SPP will investigate all such events and determine if a price revision is necessary.
7.2.1
Procedure for Evaluating and Correcting Market Software and Data Input Errors
In any instance in which SPP makes price corrections, it shall, as soon as possible thereafter, correct the market software and data input errors that resulted in incorrect prices. SPP shall undertake this work in consultation and cooperation with Market Participants and jurisdictional agencies, as appropriate and as time permits.
7.2.2
Procedures for Revising Prices in Response to Market Software and Data Input Errors
SPP shall revise LMPs and MCPs when they deviate from what would be produced absent an identified market software and/or data input error. 7.2.2.1
Notice to Market Participants and the Public
If SPP determines that a data or software error has occurred during an Operating Day that requires a correction of one or more LMPs and/or MCPs, SPP must post on its OASIS and website a description of its proposed price correction and shall notify Market Participants as soon as reasonably practicable. In any event, SPP must post a description of the proposed price correction no later than 5:00pm five (5) Calendar Days after the Operating Day.
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7.2.2.2
Price Corrections Identified After the End of the Notice Period
If SPP identifies a market software and/or data input error requiring a price correction subsequent to the issuance of the Final Settlement Statement, but does not (a) post a notice of price correction or (b) post a description of the proposed price correction within the required time periods, SPP shall request a Tariff waiver from FERC to perform the necessary price correction. SPP shall utilize the following process for requesting such Tariff waiver: (1)
First, SPP shall review with the appropriate SPP organizational group the need for the price correction and the schedule for fixing the market software and/or data input error causing the need for price correction;
(2)
Second, SPP shall seek approval of the SPP Board of Directors for filing a price correction Tariff waiver request at FERC. Prior to seeking the Board’s approval, SPP shall submit its request proposal to the SPP Market Working Group and the SPP Markets and Operations Policy Committee for approval; and
(3)
Third, after approval by the SPP Board of Directors, SPP shall file the price correction Tariff waiver request at FERC as soon as reasonably practicable.
This process ensures that SPP stakeholders are consulted prior to the implementation of any price correction that does not occur within the allotted time frame for such corrections. 7.2.2.3
Process for Recalculating DA Market Cleared Amounts and Prices
SPP shall recalculate LMPs, MCPs and DA Market cleared amounts in a manner that reflects, as closely as practicable, the DA Market results that would have resulted but for the market software and/or data input error while maintaining the original DA Market unit commitment, and shall perform a resettlement using these recalculated values, if required. Such recalculated DA Market results shall be provided to Market Participants in the same manner as LMPs and MCPs determined in the ordinary course of business (i.e. in a programmatically downloadable file). 7.2.2.4
Process for Recalculating RTBM Prices
SPP shall recalculate LMPs and/or MCPs while maintaining the original cleared Operating Reserve amounts and shall perform a resettlement using these recalculated values, if required. Such recalculated LMPs and/or MCPs shall be provided to Market Participants in the same manner as LMPs and MCPs determined in the ordinary course of business (i.e. in a programmatically downloadable file).
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7.2.2.5
Compensatory Payments to Market Participants
For cases in which RTBM prices have been recalculated, compensation to Market Participants shall be as follows: (1)
For instances where the recalculated RTBM LMP is less than a Resource’s Energy Offer Curve price, compensation shall be as described under Section 4.5.9.9(1)(a);
(2)
For instances where a Resource’s recalculated RTBM LMP is greater than the DA Market LMP and the Market Participant is buying back its DA Market position as a result of an SPP Dispatch Instruction, compensation shall be as described under Section 4.5.9.9(1)(b) except that, the MW amount eligible for compensation shall be equal to the difference between the Resource’s DA Market MW position and the greater of that Resource’s actual MW output in the Dispatch Interval or the Resource’s average Setpoint Instruction in the Dispatch Interval;
(3)
For instances where a Resource’s recalculated RTBM MCP is greater than the DA Market MCP and the Market Participant is buying back its DA Market Operating Reserve product position resulting from SPP clearing all or a portion of that Operating Reserve product on a different Resource in the market solution, compensation shall be as described under Section 4.5.9.9(1)(c).
7.2.3
Disputes and Resettlement Provisions
If a Market Participant does not agree with a price correction made by SPP, the Market Participant may use the dispute and resettlement mechanism provided in Section 4.5.15 to resolve such disagreement.
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8.
Market Monitoring and Mitigation
Market monitoring and mitigation is intended to provide for the monitoring by the SPP Market Monitor of the SPP Integrated Marketplace and other services provided under the SPP OATT (“SPP Markets and Services”) and mitigation by the Transmission Provider of the potential exercise of horizontal and vertical market power by Market Participants. Market monitoring and mitigation are essential functions for Regional Transmission Organizations (RTOs) and are required by FERC’s Order 2000.
8.1
Market Monitoring Plan
8.1.1
Purpose and Objective
The objective of the Market Monitoring Plan is to provide for the independent, impartial, and effective monitoring of (a) the SPP Markets and Services for abuses of horizontal and vertical market power and (b) the efficiency and implementation of the SPP Markets and Services. The Market Monitor will work to ensure that their functions and activities are implemented fairly and consistently, and that they protect and foster competition while minimizing interference with open and competitive markets. Correcting market inefficiencies and preventing the exercise of market power in advance rather than punishing offenders afterward shall be the preferred approach. The Market Monitor will evaluate existing and proposed market rules, Tariff provisions, and market design elements and recommend proposed rules and tariff changes to the Transmission Provider, the Commission’s Office of Energy Market Regulation (or its successor organization) staff, and other interested entities such as state commissions and Market Participants. The Market Monitor will limit distribution of its identifications and recommendations to the Transmission Provider and the Commission’s Office of Energy Market Regulations (or its successor organization) staff in the event that the Market Monitor believes that broader dissemination could lead to exploitation, with an explanation of why further dissemination should be avoided. The Market Monitor will review the performance of the wholesale market and provide an annual report on the state of the market as provided in Section 7 of Attachment AE of the of the SPP OATT.
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8.1.2
Resolution of Conflicts
In the event there is a conflict between this Section 8 of the Market Protocols and Attachment AG of the SPP Tariff or any other provision of the Tariff, Attachment AG will control.
8.1.3
Independent Market Monitor
The Market Monitor shall be granted complete independence to perform those activities necessary to provide impartial and effective market monitoring within the scope of the Protocols. No person or entity may screen, alter, delete or delay the findings, conclusions and recommendations developed by the Market Monitor that fall within the scope of the market monitoring responsibilities contained in the SPP Tariff and these Protocols. 8.1.3.1
Staffing and Resources
The Market Monitoring function for SPP will be staffed by internal employees. FERC in an order, 109 FERC ¶ 61, 009 in October 2004 granting RTO status to SPP states that: “In addition, we note that Order No. 2000’s market monitoring requirements may be satisfied with various market monitoring unit structures. If SPP determines that another structure to meeting its market monitoring obligations is appropriate, such as through an internal market monitoring unit, SPP may propose such a market monitoring unit consistent with what the Commission has approved for other RTOs.” The SPP Market Monitoring Unit (MMU) is responsible for all functions and shall be an organization within SPP reporting to the Board of Directors, excluding any SPP management representatives serving on the Board of Directors. 8.1.3.2
Relationships and Notifications
As a general principle, the Market Monitor may obtain input from the MWG, FERC Staff, SPP Staff, the RSC, and affected state regulatory authorities for the purpose of executing its duties. The Market Monitor shall bring any instances of market behavior that may require investigation (including, but not limited to, suspected Tariff violations, suspected violations of Commissionapproved rules and regulations, suspected market manipulation, and inappropriate dispatch) to the attention of the Board, the officers of SPP, FERC’s Office of Enforcement (or its successor organization) staff, and other affected state regulatory authorities, as the Market Monitor may deem necessary or appropriate. After any initial inquiry, the Market Monitor shall also provide notification to the Board of Directors, the President of SPP, and FERC’s Office of Enforcement (or its successor organization) staff, and other interested entities such as relevant state regulatory
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commissions and Market Participants, as soon as practicable in the event it identifies a significant market problem that may require (a) further review, (b) a change in SPP’s tariffs or market rules, or (c) referral to FERC. In the event the Market Monitor believes broader dissemination could lead to exploitation, it may limit distribution of its identifications and recommendations to the Board of Directors, the President of SPP, and FERC Staff with an explanation of why further dissemination should be avoided at that time. The MMU shall also interface with FERC Staff and other RTO and ISO market monitors in adjacent regions as needed for the purpose of addressing electricity market issues in a comprehensive manner. The Market Monitor shall report to the SPP Board of Directors. 8.1.3.3
Standards of Conduct
The MMU shall abide by SPP’s Standards of Conduct, which shall be appropriate for establishing the professional and financial independence of the MMU. The MMU shall certify compliance with such policies to the Board. Consistent with Order No. 719 requirements for MMU ethics standards, the Market Monitor and its employees shall comply with those standards outlined in Section 3.3 of Attachment AG of the SPP OATT.
8.1.4
Market Monitoring
The primary purposes of market monitoring are to (a) obtain objective information about the SPP Markets and Services, (b) assess the behavior of Market Participants, and (c) assess the behavior of other markets and services that impact the performance of the SPP Markets and Services. Key aspects of such market monitoring are (a) assessing the design and structure of the SPP Markets and Services to ensure market efficiency, (b) determining Market Participants’ compliance with market rules and (c) preventing the exercise of horizontal and/or vertical market power, which includes whether a Market Participant is affecting SPP’s ability to provide reliable and nondiscriminatory service. 8.1.4.1
Markets to be Monitored
The Market Monitor will monitor the SPP Markets and Services provided under its OATT. The Market Monitor will not monitor bilateral energy, transmission or capacity markets and services not administered, coordinated or facilitated by SPP, except to assess the effect of these markets and services on the SPP Markets and Services, or the effects of the SPP Markets and Services on these unmonitored markets. Similarly, the Market Monitor will not monitor the energy, transmission or capacity markets and services in regions adjacent to SPP except to assess the
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effect of these markets and services on the SPP Markets and Services, or the effects of the SPP Markets and Services on these adjacent markets. 8.1.4.2
Monitoring Activities
The Market Monitor will implement the market monitoring protocols and will monitor SPP’s Markets and Services by reviewing and analyzing market data and information including, but not limited to: (1)
Resource Registration data required under Section 6;
(2)
Resource Offer data and other Resource offer parameters required for use in either the DA Market or RTBM;
(3)
Demand Bids for the purchase of Energy in the DA Market;
(4)
Virtual Energy Bids and Offers for the purchase or sale of Energy in the DA Market;
(5)
Export Interchange Transaction Bids and Import Interchange Transaction Offers for the purchase or sale of Energy in the DA Market or RTBM;
(6)
Actual commitment and dispatch of Resources, including but not limited to Resource MW capability and output, MVAR capability and output, status, and outages;
(7)
Additional generation and transmission facility outage data not otherwise provided for in (6) above;
(8)
Locational Marginal Prices and Market Clearing Prices at all nodes and designated Settlement Areas in or affecting any of the SPP Markets and Services;
(9)
SPP Balancing Authority Area data, including but not limited to demand, area control error, net scheduled interchange, actual total net interchange, and forecasts of operating reserves and peak demand;
(10) Conditions or events both inside and outside the SPP Balancing Authority Area affecting the supply and demand for, and the quantity and price of, products or services sold or to be sold in the SPP Markets and Services; (11) Information regarding transmission services and rights, including the estimating and posting of Available Transfer Capability (“ATC”) or Available Flowgate Capability (“AFC”), administration of SPP’s tariff, the operation and maintenance of the transmission system, any auctions or other markets for transmission rights, and the reservation and scheduling of transmission service;
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(12) Information regarding the nature and extent of transmission congestion in the region and, to the extent practicable, transmission congestion on any other system that affects the SPP Markets and Services, including but not limited to causes of, costs of and charges for transmission congestion, transmission facility loading, MVA capability, line status and outages; (13) Settlement data for the SPP Markets and Services; (14) Any information regarding collusive or other anticompetitive or inefficient behavior in or affecting any of the SPP Markets and Services; (15) Generation resource operating cost data for estimating Resource incremental cost, including fuel input costs, heat rates where applicable, start-up fuel requirements, environmental costs and variable operating and maintenance expenses; (16) Logs of Transmission Service requests and Generation Interconnection requests along with the disposition of the request and the explanation of any refused requests ; (17) Ramp reservation usage. In addition to the monitoring of market data and information, the Market Monitor may communicate with SPP Staff and Market Participants at any time for the purpose of monitoring and assessing market conditions. 8.1.4.3
Instances of Market Power
The Market Monitor will analyze market data with regard to Instances of Market Power and refer possible cases to FERC when there is sufficient credible information to warrant such action. When the case is referred to FERC, the Market Monitor is required to desist from any further action independent of FERC’s investigation into the case. The Market Monitor will keep SPP and Interested Government Agencies apprised of the potential for and the implications of abusive market power behavior, and make recommendations as to how to remove the potential for and ability to exercise market power. Specific monitoring activities regarding physical and economic withholding shall include but not be limited to assessment on (a) availability of Resources, (b) artificial barriers to entry, (c) impact of the use of Resources for reliability versus energy purposes, (d) market response to price spikes, and (e) analysis of bidding patterns. On an ongoing basis, the Market Monitor will consult with the MWG on examining other areas for instances of market power.
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8.1.4.4
Market Participant Behavior Warranting Possible Mitigation
The Market Monitor shall monitor SPP’s Markets and Services for potential abuse associated with the following categories of Market Participant behavior: (1)
Economic Withholding;
(2)
Uneconomic Production;
(3)
Physical Withholding;
(4)
Uneconomic Virtual Bids and Offers.
The mitigation measures and monitoring metrics for each of the Market Participant behaviors in (1)-(4) are fully developed in Section 8.2. When the Market Monitor determines there is sufficient credible information about a specific abusive practice, the issue will be referred to the Commission’s Office of Enforcement for further review. Nothing in this section shall limit the Market Monitor’s obligation to refer other suspected market violations to the Commission’s Office of Enforcement, even where suspected behavior does not fall explicitly within the abovementioned categories or descriptions.
8.1.5
Inquiries
8.1.5.1
Requests
Any Market Participant or Interested Government Agency may submit in writing a complaint or request for inquiry to the Market Monitor. Upon receipt of such complaint or request, the Market Monitor will decide whether an inquiry should be conducted. As an initial screen, the Market Monitor should not pursue any complaint pertaining to issues not related to the SPP Markets and Services or monitored and overseen by the Market Monitor. An inquiry will be conducted if either Market Monitor determines it should be conducted. Requests by Market Participants and Interested Government Agencies for the Market Monitor to conduct an inquiry can be made confidentially. The Market Monitor shall keep the identity of the requestor confidential and shall keep the existence of any inquiry conducted confidential from all uninvolved parties and from involved parties, other than the requesting party, to the extent practicable. Nothing in this section should be interpreted as preventing the Market Monitor from conducting inquiries, either confidentially or publicly, without first receiving a complaint from a Market Participant or Interested Government Agency. The Market Monitor may initiate inquiries into
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any matter at any time that pertains to the SPP Markets and Services that is part of their market monitoring or market power mitigation obligation. 8.1.5.2
Conducting Inquiries
Market Participants shall cooperate fully with the Market Monitor during any inquiry. The process flow chart for conducting an inquiry is shown below.
Market Participant Inquiry Process Market Participant
Revised 1 April 2006 5.0
Written Request from Market Participant (or Government Agency)
Subject Party Rebuttal
1.0 Administrative Processing
Complaint subject to SPP Tarrif
2.0 Stage 1 Analysis (Data Provided with Complaint)
Yes 7.0
MMU/IMM
Final Report Review & Distribution
No Are there corrective actions?
information valid and have merit?
No
6.0 Stage 4 Analysis (Assess Rebuttal & Develop Final Report)
Refer Request to FERC
No
Notify Complainant
Notify Complainant
Yes No Yes
Subject Party Data Required?
Yes
No
No Notify Inquiry Subject Party
Follow Business Process for Market Design Changes Yes Yes
3.0 Stage 2 Analysis (Internal SPP Data & Public Data)
8.1.5.3
Is this a Market Design Issue?
4.0 Stage 3 Analysis (Subject Party Provided Data)
Are there corrective actions?
Reporting
The Market Monitor is responsible for notifying the requesting party of the results. The Market Monitor will coordinate reporting of the results of inquiry to the Board, FERC and the RSC, as necessary. If the findings of the inquiry directly relate to any Market Participant other than the requesting party, the designated market monitoring contact of the affected Market Participant will be notified of the findings regarding his or her company. A summary of inquiries conducted and/or requested and an assessment of inquiry issues and trends will be presented in the Annual
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State of the Market Report were appropriate and consistent with inquiry procedures approved by the Board.
8.1.6
Compliance and Corrective Actions
8.1.6.1
Compliance
The Market Monitor shall administer SPP’s Market Monitoring Plan as described in SPP’s OATT Attachment AG and report any actual or potential abuse of market power or market design inefficiencies as part of its monitoring process. However, such enforcement is limited to matters that (i) are expressly set forth in SPP’s OATT; (ii) involve objectively-identifiable behavior; and (iii) do not subject the Market Participant to sanctions or other consequences other than those expressly approved by the Commission and set forth in the OATT. Other enforcement matters shall be subject to Commission determination in the first instance. As part of the inquiry process, the Market Monitor may issue a demand letter requesting Market Participants causing the issue to arise to change actions as the Market Monitor deem proper to achieve compliance. The Market Monitor may also engage in discussions with persons or entities other than Market Participants that they deem may have information that may be helpful to any investigatory or compliance process. 8.1.6.2
Corrective Actions for Market Design
If the Market Monitor discerns any weaknesses or failures in market design and protocols, including the determination that the SPP Markets and Services are not resulting in just and reasonable prices or providing appropriate incentives for investment in needed infrastructure, either in the aggregate or in any portion or location thereof, the Market Monitor shall notify the appropriate Organizational Group of SPP, the SPP President, the RSC, appropriate state authorities, FERC Staff, and relevant Market Participants. In the event the Market Monitor believes providing such information could lead to exploitation, it will restrict such notification to the President of SPP, the Chairman of the SPP Oversight Committee, and FERC Staff, and will provide a justification for such limited notification. Should the appropriate SPP Organizational Group not respond within 60 days, the Market Monitor may recommend changes in market design and protocols to the Board, FERC and the RSC as needed. If the appropriate SPP Organizational Group responds, but does not recommend changes to market design and market rules that are acceptable to the Market Monitor, the Market Monitor shall report to the Board, and the appropriate regulatory body or bodies as needed, and then SPP or the Market Monitor
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may file a petition or submission seeking appropriate action from FERC or any other appropriate enforcement agency. The Market Monitor shall also make recommendations for changes to SPP’s OATT, Criteria, and Market Protocols as necessary to correct weaknesses or failures in SPP’s Markets and Services. In the event that any weaknesses or failures in market design require immediate corrective action to ensure just and reasonable prices, the Market Monitor may request the SPP President to authorize an immediate FERC filing requesting implementation of a corrective action while the appropriate Organizational Group of SPP responds to the Market Monitor’s notification as described above. The requested immediate corrective action should be the method least intrusive or disruptive to the SPP Markets and Services necessary to resolve the market weakness or failure as determined by the Market Monitor. Prior to making such a request to the SPP President, the Market Monitor will make reasonable efforts to discuss with affected Market Participants and the Staff of affected Interested Government Agencies the market weakness or failure potentially requiring immediate corrective action, unless the Market Monitor determines that such discussion would lead to exploitation.
8.1.7
Reporting
The Market Monitor, with the support of the MWG, SPP Staff, and any other SPP Organizational Group, is responsible for producing (a) an Annual State of the Market Report and (b) Monthly, Quarterly and Annual Metrics Reports for assessing the efficiency, effectiveness and competitiveness of SPP markets and Services as requested by the SPP Board of Directors or required by FERC. The Market Monitor shall have complete independence in developing and producing reports, and no person or entity may screen, alter, delete or delay the Market Monitor’s findings, conclusions and recommendations. SPP and Market Participants may comment on any report made pursuant to this section, through the appropriate stakeholder process. The Market Monitor shall be free to disregard suggestions with which it disagrees. 8.1.7.1
Annual State of the Market Report
The Annual State of the Market Report shall assess the performance of the SPP Markets and Services as discussed in Section 8.1.1. Such report will discuss the progress made on the development of SPP Markets and Services and inter-RTO coordination and will include any recommendations of the Market Monitor for the improvement of the SPP Markets and Services, or of the monitoring, reporting and other functions undertaken pursuant to these Protocols. The
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report where appropriate will also include a summary of requests for inquiries and the resolution or disposition thereof. The report will be rendered to the Board, the Transmission Provider, Market Participants, and other interested entities. The report shall be submitted to FERC. Copies of the report shall be provided to the RSC and other appropriate state regulatory authorities on request and made publicly available by SPP through a posting of the document on the SPP website. Confidential information will be subject to redaction or other measures necessary for the protection of Confidential Information. 8.1.7.2
Monthly, Quarterly and Annual Metrics Reports
The Market Monitor will prepare Monthly, Quarterly and Annual Metrics Reports. The purpose of these metrics is to provide transparency of the SPP Markets and Services and to provide a standardized basis to evaluate the performance of SPP’s market structure and market power mitigation over time. This information will also be used to compare the performance of the SPP Markets and Services with that of other RTOs and ISOs. Copies of the reports shall be made publicly available by SPP through posting on the SPP website, subject to redaction or other measures necessary for the protection of Confidential Information. 8.1.7.3
Communication of Market Monitoring Reports
Conference calls related to the Market Monitor reports may be attended by the Transmission Provider, the Board of Directors, FERC Staff and other affected regulatory authorities, Regional State Committee, and Market Participants regardless of which party initiates the conference call. The Market Monitor shall make one or more of its staff members available for regular conference calls. 8.1.7.4
Other Reports
The Market Monitor shall prepare other reports or briefings on matters within their responsibility as may be requested by the Board or FERC, or as they deem necessary.
8.1.8
Performance Indices, Metrics and Screens
Performance indices, metrics and screens form the necessary objective basis for observing the functioning of the SPP Markets and Services, including the conduct of Market Participants in such markets, and for providing reports and market analyses.
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8.1.8.1
Development
The Market Monitor, with the assistance and input of the MWG and the RSC, will develop performance indices, metrics and screens for reviewing market data and other information collected. Consideration should be given to the inter-RTO metrics in use by other RTOs, ISOs and the FERC during such development.
8.1.9
Referrals to the Commission
The Market Monitor shall report suspected Market Violations, as defined in 18 CFR 35.28(b)(8), to FERC’s Office of Enforcement (or its successor organization) staff in accordance with the FERC’s reporting protocols for referral by market monitors as specified in 18 CFR 35.28(g)(3)(iv) in a timely manner. Any such reports by the Market Monitor to FERC Staff shall be on a confidential basis, and all information and documents included in such reports will not be released to any other party except to the extent FERC directs or authorizes such release, unless such information and documents are already in the public domain. Where applicable, the Market Monitor shall follow the Market Participant Inquiry Process as set forth in Section 8.1.5.2.
8.1.10
Market Manipulation
The Market Monitor will monitor the SPP Markets and Services for potential instances of market manipulation. Such actions or transactions that are without a legitimate business purpose and that are intended to or foreseeable could manipulate market prices, market conditions, or market rules for electric energy or electric products are prohibited. Potential behavior activities of concern include: (a) wash trades, (b) submission of false data, (c) actions to cause artificial congestion, and (d) collusive acts. The Market Monitor will report to FERC any potential market manipulation in the SPP Markets and Services in a timely manner when there is sufficient credible information to warrant such action.
8.1.11
Monitoring for Potential Transmission Market Power Activities
The Market Monitor shall monitor the SPP Markets and Services for suspected exercise of transmission market power by reviewing and analyzing data and information related to the availability of transmission facilities that impact access particularly with respect to the withholding of transmission facilities or transmission capacity, including activities such as but not limited to, the following:
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(1)
Physical withholding by Transmission Owners by providing improper information related to the availability of transmission, such as information related to the capability or other modeling data used by SPP for use in system operations;
(2)
Economic withholding by Transmission Owners through the use of methods and data for estimating costs of interconnection and system upgrades that is not comparable for affiliates and non-affiliates;
(3)
Unavailability of transmission facilities through planned and unplanned maintenance outages that routinely exceed historical baselines;
(4)
Withholding of transmission capacity by transmission users through excess reservations that are not actually used.
The Market Monitor shall refer any instance(s) of perceived market design flaws and recommend tariff language changes to the Commission’s Office of Energy Market Regulation (or its successor office/organization). Additionally, the Market Monitor shall refer any instance(s) of suspected exercise of transmission market power directly to the Commission’s Office of Enforcement (or its successor organization) utilizing the protocols for referral to the Commission for suspect potential instances of the exercise of market violations (such as manipulation) as found in 18 CFR 35.28(g)(3)(iv), when there is sufficient credible information to warrant such action. Where appropriate, the Market Monitor shall also provide the FERC with an estimate of damages equal to (i) the effect on prices multiplied by (ii) the affected energy produced by the Transmission /Generation Owner. All such referrals by the Market Monitor to FERC will be on a confidential basis, and all information and documents included in such reports will not be released to any other party except to the extent FERC directs or authorizes such release.
8.1.12
Data Access, Collection and Retention
SPP shall regularly collect and maintain Data and Information necessary for monitoring the SPP Markets and Services and implementing mitigation protocols. 8.1.12.1
Confidentiality
The Market Monitor is subject to and will abide by the confidential rules as delineated in the SPP OATT.
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8.1.12.2
Access to SPP Data and Information
The Market Monitor shall have access to all Data and Information gathered or generated by SPP in the course of its operations. This Data and Information shall include, but not be limited to, that listed in Section 8.1.4 of these Protocols. All Data and Information listed in Section 8.1.4 shall be retained by SPP for a minimum period of three years. 8.1.12.3
Access to Market Participant Data and Information
Market Participants shall retain all Data and Information listed below, and in Section 8.1.4 of the Market Monitoring Plan as applicable, that is in the custody and control of Market Participants, for a minimum of three years and will promptly provide any such Data and Information to the Market Monitor upon request. Market Participants shall be capable, upon request, of providing the Data in native format and a description of the format used by the Market Participant. If necessary, due to proprietary format restrictions, the MP shall be capable of providing the data in a non-proprietary format, such as CSV or XML format. Data and Information to be retained by Market Participants and provided to the Market Monitor upon request: (1) All Data and Information relating to the costs of operating a Resource, including but not limited to, heat rates, start-up fuel requirements, fuel purchase costs, environmental costs, and operating and maintenance expenses; (2) All Data and Information regarding opportunity costs of a Resource, including but not limited to, regulatory, environmental, technical, or other restrictions that limit the runtime or other Resource operating characteristics; (3) All Data and Information relating to the operating status of a Resource, including Resource logs showing the generating status of a specified unit, including information relating to a forced outage, planned outage or derating of a Resource; (4) All Data and Information relating to the operating status of a transmission facility, a contingency, or other operating consideration, including forced outages, planned outages or derating of a transmission system component; (5) All Data and Information relating to transmission system planning, including studies, reports, plans, models, analyses, and filings with FERC or any state regulatory commission;
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(6) All Data and Information relating to the ability of a Market Participant or its Affiliate to determine the pricing or output level of generating capacity owned by another entity, including but not limited to any document setting forth the terms or conditions of such ability. (7) All Data and Information used in the course of business operations in arriving at a decision by a Reserve Sharing Group (RSG) member to call an Operating Reserve Contingency and request assistance. If any additional Data and Information not listed above or in the Market Monitoring section of these protocols is required from Market Participants by the Market Monitor for the purpose of fulfilling its responsibilities, the Market Monitor may request such Data and Information from Market Participants. Such Data and Information shall be provided in a timely manner by Market Participants. Any such request shall be accompanied by an explanation of the need for such data or other information, a specification of the form or format in which the data is to be produced, and an acknowledgement of the obligation of the Market Monitor to maintain the confidentiality of the data. If a Market Participant receiving a request for Data and Information not listed above or in the Market Monitoring section of these protocols believes that production of the requested Data and Information would impose a substantial burden or expense, or would require the party to produce information that is not relevant to achieving the purposes or objectives of these market monitoring protocols, the Market Participant receiving the request shall promptly so notify the Market Monitor. The Market Monitor shall review the request with the receiving Market Participant to determine whether, without unduly compromising the objectives of these market monitoring protocols, the request can be narrowed or otherwise modified to reduce the burden or expense of compliance, and if so shall so modify the request. No party that is the subject of a data request shall be required to produce any summaries, analyses or reports of the data that do not exist at the time of the data request. If the Market Monitor determines that the requested Data and Information has not or will not be provided in a timely manner, the Market Monitor may utilize (a) SPP’s dispute resolution procedures in its OATT or Bylaws as applicable or (b) a filing with the appropriate regulatory or enforcement agency to compel the production of the requested information.
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8.1.12.4
Data Created by the Market Monitor
Any data created by the Market Monitor, including any reconfiguration of Data and Information obtained from SPP or Market Participants, will remain within the Market Monitor’s exclusive control. Such data may be shared with SPP and Market Participants at the Market Monitor’s sole discretion and on a non-discriminatory basis, subject to the confidentiality provisions specified in the SPP’s OATT Section 8.1 of Attachment AG and Section 8 of Attachment AE.
8.1.13
Miscellaneous Provisions
8.1.13.1
Rights and Remedies
This Plan does not restrict SPP and Market Participants from asserting any rights they may have under state and federal regulation and laws, including initiating proceedings before the FERC regarding any matter which is subject to this Plan. 8.1.13.2
Disputes
Disputes as to the implementation of, or compliance with, this Plan shall be subject to the dispute resolution procedures under the SPP Tariff or under the SPP Bylaws as applicable or subject to review by FERC. 8.1.13.3
Review of Market Monitor
The activities of the Market Monitor shall be reviewed from time to time by the Board of Directors.
8.2
Market Power Mitigation and Monitoring
8.2.1
Purpose and Objectives
The Transmission Provider shall implement these Market Mitigation Protocols in conjunction with the Market Mitigation Plan in Attachment AF of the SPP OATT. There are two basic themes with regard to market power mitigation. First, mitigation measures must offer the opportunity for extensive intervention in energy markets, if necessary, to suppress price spikes resulting from the exercise of market power. Mitigation measures are meant to block generators with the potential for market power abuse from bidding above the price level that would otherwise prevail in a competitive market. Second, that intervention must explicitly be balanced with the goal of assuring system reliability in the long term.
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8.2.2
Economic Withholding
This section develops the market power mitigation measures that are applied to the Day-Ahead and the Real-Time Balancing Energy Markets, collectively referred to as the SPP Energy Markets. 8.2.2.1
Mitigate Only in the Presence of Local Market Power
The electricity marketplace in the SPP Region is workably competitive, with an adequate supply of electricity and diversity of suppliers, absent reliability conditions or congestion on the transmission system that create the potential for abuse of local market power. Therefore, mitigation will be applied only at the time of, and in places with, a congested transmission element or facility, or a local reliability issue not represented by a flowgate constraint. 8.2.2.2
Mitigation Measures
The following Resource Offer parameters are subject to mitigation measures in the DA Market, RTBM, and the RUC processes: the Energy Offer Curves and Operating Reserve Offers that are used for SCED calculations; and the Energy Offer Curves, Operating Reserve Offers, Start-Up Offers, and No-Load Offers used to determine commitment costs during the SCUC calculations. A determination of Resources that have local market power is described in Section 8.2.2.7. A Resource with mitigation measures applied to its Energy Offer Curve shall have an effective energy offer no higher than the Resource’s Mitigated Energy Offer Curve. A Resource with mitigation measures applied to one of its Operating Reserve Offers shall have an effective offer no higher than the Resource’s corresponding Operating Reserve mitigated offer. A Resource with mitigation measures applied to its Start-Up Offer or No-Load Offer shall be capped at the Mitigated Start-up Offer or No-Load Offer, respectively, in the calculation of an effective commitment cost for the SCUC. The effective energy and Operating Reserve Offers and commitment cost are used by the Market Operating System to determine unit commitment, prices, and dispatch instructions. The effective energy and Operating Reserve Offers and commitment cost are also used in the determination of DA and RUC Make-Whole-Payments. Whenever a Market Participant has a Resource(s) where a mitigation measure has been applied to the Market Participant’s offer(s), the Transmission Provider shall identify the market offer(s) that have been mitigated and whether the offer(s) were mitigated in SCUC and/or SCED. The Transmission Provider will supply the Market Participant with the reason for mitigation, (local market power failure test, FCA failure test, or other test failures) where a mitigation measure has been applied. If the mitigation is associated with the Local Market Power Test, the Transmission
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Provider shall also provide the Market Participant, when applicable, with the binding transmission constraint and Resource-to-Load Distribution factor. 8.2.2.3 (1)
(2)
Comment [MPRR182.1436]: MPRR182 Awaiting Implemenation
Mitigation Measures for Energy Offer Curves Mitigated energy offer curves shall be submitted on a daily basis by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The mitigated energy offer curve may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated energy offer curve may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated energy offer curve submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating day; for all other Resources the mitigated energy 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 and the RTBM on the Operating Day. The Energy Offer Curve conduct thresholds are as follows: (a) For Resources with local market power as described in Section 8.2.2.7(3) committed to address a Local Reliability Issue, the threshold is a 10% increase above the Mitigated Energy Offer Curve; (b)
For Resources located in a Frequently Constrained Area and not subject to the threshold in Section 8.2.2.3(2)(1a), the threshold is a 17.5% increase above the Mitigated Energy Offer Curve.
Comment [MPRR194.1438]: MPRR194 Awaiting FERC filing
(c)
(3)
For all other Resources the threshold is a 25% increase above the Mitigated Energy Offer Curve. The Transmission Provider shall apply mitigation measures by replacing the Energy Offer Curve with the Mitigated Energy Offer Curve if: (a) The Resource’s Energy Offer Curve exceeds the Mitigated Energy Offer Curve by the applicable conduct threshold; and (b) The Resource has local market power as determined in Section 8.2.2.7; and (c) The Resource either: (i) Fails the Market Impact Test as described in Section 8.2.2.9, or (ii) Has local market power as described in Section 8.2.2.7(3) Is manually committed by the Transmission Provider or by a local transmission operator.
Comment [MPRR194.1437]: MPRR194 Awaiting FERC filing
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(4)
(5)
(6)
(7)
An Energy Offer below $25/MWh will not be subject to mitigation measures for economic withholding. The Mitigated Energy Offer Curve shall be the resource’s short-run marginal cost of producing energy as determined by the unit’s heat rate, fuel costs and the costs related to fuel usage, such as transportation and emissions costs (“total fuel related costs”), and variable operations and maintenance costs (VOM) as detailed in the Mitigated Offer Development Guidelines. The formula for Mitigated Energy Offer Curves can be found in Appendix G Section 2.5. Opportunity costs may be reflected in the total fuel related costs and/or the VOM under the following circumstances: (a) Externally imposed environmental run-hour restrictions; or (b) Physical equipment limitations on the number of starts or run-hours; or (c) Fuel supply limitations. The Market Participant shall submit heat rates and the methods for determining fuel costs, fuel related costs including emissions costs, opportunity costs, and variable operation and maintenance costs to the Market Monitoring Unit. The information will be sufficient for replication of the Mitigated Energy Offer Curve and shall include, among other data, the following information: (a) For fuel costs, Market Participants shall provide the Market Monitoring Unit with an explanation of the Market Participants’ fuel cost policy, indicating whether fuel purchases are subject to a fixed contract price and/or spot pricing and specifying the contract price and/or referenced spot market prices. Any included fuel transportation and handling costs must be short-run marginal costs only, exclusive of fixed costs. (b) For emissions costs, Market Participants shall report the emissions rate of each of their units and indicate the applicable emissions allowance cost. (c) For VOM costs, Market Participants shall submit VOM costs, calculated in adherence with the Appendix G of the Market Protocols, reflecting short-run marginal costs, exclusive of fixed costs. Further details associated with the development and validation of these costs are included in SPP’s Mitigated Offer Development Guidelines. For Demand Response Resources with behind the meter generation the Mitigated Energy Offer Curve shall be developed in the same manner, described above, as any other generating Resource. For load response Demand Response Resources, the mitigated
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Energy Offer Curve shall reflect the quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage. (8) For Dispatchable Variable Energy Resources, the mitigated Energy Offer Curve may include, but shall not exceed, any quantifiable costs that vary by MWh output, including short-run incremental VOM. Mitigation will not apply to Non-Dispatchable Variable Energy Resources in the Real-Time Balancing Market; monitoring for Energy Offers of Non-Dispatchable Variable Energy Resources will occur. (9) Intra-day changes to the Mitigated Energy Offer Curve are allowed under the following conditions: (a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process; or (b) A Resource must switch fuels due to unforeseen operating conditions; (b)(c) The Resource is employing the Quick-Start Resource logic described in Section 4.4.2.3.1 in accordance with Appendix G, Section 6.4. In which case, the Mitigated Energy Offer Curve may be changed after the DA RUC clears on the day before the operating day. Intra-day changes to the Mitigation Energy Offer Curve must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor. (10) In all cases under this Section 8.2.2.3, cost data submitted for the development of mitigated offers, including opportunity cost data, shall be subject to the confidentiality provisions set forth in Section 11 of Attachment AE to the Tariff.
8.2.2.4 (1)
Mitigation Measures for Start-Up and No-Load Offers A Mitigated Start-up Offer and a Mitigated No-load Offer shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The Mitigated Start-up and No-load Offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource in not committed by the DA Market, the Mitigated Start-up and No-load Offers may be updated until the Day-Ahead RUC process begins. The Mitigated Start-up and No-load Offers 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.
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(2)
The Start-Up and No-Load Offer conduct thresholds are as follows: (a)
(b) (3)
For Resources with local market power as described in Section 8.2.2.7(3) committed to address a Local Reliability Issue , the threshold is a 10% increase above the mitigated offer for the applicable offer; For all other Resources the threshold is a 25% increase above the mitigated offer for the applicable offer.
The Transmission Provider shall apply mitigation measures by replacing the Start-Up or No-Load Offer with the applicable Mitigated Start-up or mitigated Mitigated No-load Offer if: (a) The Resource’s Start-Up or No-Load Offer exceeds the mitigated offer by the applicable threshold; and (b) The Resource has local market power as determined in Section 8.2.2.78.2.2.6; and (c) The Resource either: (i) fails Fails the Market Impact Test as described in Section 8.2.2.9, or (i)(ii) the Resource has local market power as described in Section 8.2.2.7(3)Is manually committed by the Transmission Provider or by a local transmission operator.
(4)
The mitigated Start-Up Offer shall represent the cost per start as determined from start fuel usage and the costs related to that fuel usage, electrical costs (station service), maintenance costs attributed to starts, and additional labor costs, if required above normal station manning levels. The formula for mitigated Start-Up Offers can be found in Appendix G Section 2.6:
(5)
The mitigated Start-Up Offer for Demand Response resources shall be the cost to shut down or curtail load for a given period, which does not vary with output, or the start cost of a behind the meter generator.
(6)
The mitigated Start-Up Offer for Variable Energy Resources shall be zero.
(7)
The mitigated No-Load Offer shall be the hourly fixed cost required to create a monotonically increasing mitigated Energy Offer Curve. It shall be calculated according to either of two methods found in Appendix G Section 2.7 which are No-Load Fuel Approach and No-Load Cost Approach.
(8)
The Mitigated No-Load Offer for behind the meter Demand Response resources shall adhere to the same definition above as a generating Resource. For load response Demand
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Response Resources, the Mitigated No-Load Offer shall not exceed the quantifiable ongoing hourly costs associated with manufacturing process changes associated with a reduction in load consumption. (9)
The mitigated No-Load Offer for Variable Energy Resources shall be zero.
(10) The Market Participant shall submit documentation of the method for calculating mitigated Start-Up and mitigated No-Load Offers that is adequate to permit the MMU to verify submitted offers. Further details associated with the development of these costs are included in SPP’s Mitigated Offer Development Guidelines. (11) Intra-day changes to the Mitigated Start-Up and Mitigated No Load Offers are allowed under the following conditions: (a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process; (b) A Resource must switch fuels due to unforeseen operating conditions; or (c) The Resource is employing the Quick-Start Resource logic described in Section 4.4.2.3.1 in accordance with Appendix G, Section 6.4. Intra-day changes to the Mitigated Start-Up and Mitigated No Load Offers must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor. (10)(12) In all cases under this Section 8.2.2.4, cost data submitted for the development of mitigated offers, including opportunity cost data, shall be subject to the confidentiality provisions set forth in Section 11 of Attachment AE to the Tariff. 8.2.2.5 (1)
Mitigation Measures for Operating Reserve Offers A mitigated offer for each Operating Reserve product shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The mitigated operating reserve offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated operating reserve offers may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated operating reserve offers submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating Day; for all other Resources, the mitigated operating reserve offers submitted
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(2)
(3) (4)
at the time the Day-Ahead RUC process begins will apply to the RTBM on the Operating Day. The offer conduct thresholds for each of the Operating Reserve products are as follows: (a) For Resources with local market power as described in Section 8.2.2.7(3) committed to address a Local Reliability Issue, the threshold is a 10% increase above the mitigated offer for the applicable Operating Reserve Offer; (b) For all other Resources the threshold is a 25% increase above the mitigated offer for the applicable Operating Reserve Offer. Any Operating Reserve Offer exceeding the applicable threshold, except offers below $10/MW, will be deemed excessive. The Transmission Provider shall apply mitigation measures by replacing the relevant Operating Reserve Offer with the applicable mitigated operating reserve offer if: (a) The Resource’s Operating Reserve Offer exceeds the mitigated offer by the applicable conduct threshold and; (b) The Resource has local market power as determined in Section 8.2.2.7; and (c) The Resource either: (i) Fails the Market Impact Test as described in Section 8.2.2.9, or (ii) Is manually committed by the Transmission Provider or by a local transmission operatorHas local market power as described in Section 8.2.2.7(3).
(5)
The mitigated Spinning Reserve Offer shall be equal to zero for Resources other than CTs and Hydro Resource with synchronous condenser capability. No known incremental costs are incurred for providing Spinning Reserves from other resource types. Mitigated Spinning Reserve Offers for CTs and Hydro Resources with synchronous condenser capability are calculated as described in Appendix G, Sections 6 and 7.
(6)
The mitigated Supplemental Reserve Offer shall not exceed any fuel related costs and labor costs necessary for the unit to be prepared for deployment. The formula for mitigated Supplemental Reserve Offer can be found in Appendix G Section 2.9.
(7)
The mitigated Regulation-Up Offer and Regulation-Down Offer shall not exceed the sum of the cost increase due to:
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(a)
The heat rate increase during non-steady state operation;
(b)
The cost increase in variable operations and maintenance costs due to non-steady state operation; and
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(c)
Uncompensated costs
The formula for mitigated Regulation-Up and Regulation-Down Offers can be found in Appendix G Section 2.10 (8)
Further details associated with the development of the exact costs specified in the formulas above are included in Appendix G.
(9)
The Market Participant may include in the calculation of its mitigated Operating Reserve Offer an amount reflecting the Resource-specific opportunity costs if the Market Participant is able to demonstrate to the satisfaction of the SPP Market Monitoring Unit that such costs are legitimate and verifiable and not otherwise included in market outcomes. To the extent such costs include run-time restrictions, such run-time restrictions shall be updated at least weekly with more frequent updating to occur the fewer hours that remain available. The formulas and instructions in the price forecast model for any such opportunity costs shall be determined by the SPP Market Monitoring Unit and published in Appendix G as part of the Mitigated Offer Development Guidelines, updated, as needed, by the SPP Market Monitoring Unit. Opportunity costs for mitigated Operating Reserve Offers shall not include Energy and Operating Reserve Markets revenues associated with forgone Energy or other types of Operating Reserve production to the extent that such costs are included in market outcomes
(10) All cost data and cost calculation descriptions are subject to the review and approval of the SPP Market Monitoring Unit to ensure reasonableness and consistency across Market Participants. The information will be sufficient for replication of the mitigated Operating Reserve Offers and shall include, among other data, the following information:
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(a)
For fuel costs, Market Participants shall provide the Market Monitoring Unit with an explanation of the Market Participants’ fuel cost policy, indicating whether fuel purchases are subject to a fixed contract price and/or spot pricing and specifying the contract price and/or referenced spot market prices. Any included fuel transportation and handling costs must be short-run marginal costs only, exclusive of fixed costs.
(b)
For emissions costs, Market Participants shall report the emissions rate of each of their units and indicate the applicable emissions allowance cost.
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(c)
For VOM costs, Market Participants shall submit VOM costs, calculated in adherence with the Appendix G of the Market Protocols, reflecting short-run marginal costs, exclusive of fixed costs.
(11) Intra-day changes to the Mitigated Operating Reserve Offers are allowed under the following conditions: (a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process; (b) A Resource must switch fuels due to unforeseen operating conditions; or (c) Intra-day changes to the Mitigated Regulation-Up and Mitigated RegulationDown Offers are allowed after the DA RUC clears on the day before the operating day under the following condition: (i) The Resource incurs the uncompensated cost in (7)(c) above, for which the mitigated offer calculation is described in Appendix G Section 2.10.3. Intra-day changes to the Mitigated Operating Reserve Offers must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.
Comment [MPRR199.1449]: MPRR199 Awaiting FERC filing
(11)(12) In all cases under this Section 8.2.2.5, cost data submitted for the development of mitigated offers, including opportunity cost data, shall be subject to the confidentiality provisions set forth in Section 11 of Attachment AE to the Tariff. 8.2.2.6
Comment [MPRR101.1450]: MPRR101 awaiting FERC filing
Mitigation Measures for Transition State Offers
The mitigation measures in this section apply only to Resources registered using the combined cycle configuration based modeling option as described in Section Error! Reference source not found.(4). 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 DA Market. In the case a Resource in not committed by the Day-Ahead Market, the Mitigated Transition State Offer may be updated until the DayAhead RUC process begins. The Mitigated Transition State Offer submitted at the time the DayAhead 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. The Transition State Offer threshold is a 25% increase above the Mitigated Transition State Offer.
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The Transmission Provider shall apply mitigation measures by replacing the Transition State Offer with the applicable Mitigated Transition State Offer if: (1) The Resource’s Transition State Offer exceeds the applicable threshold; and (1)(2) The Resource is subject to mitigation measures as determined in Section 8.2.2.2; and (3) The Resource fails the Market Impact Test as described in Section 8.2.2.9. 8.2.2.68.2.2.7
Local Market Power Test
A Resource satisfying at least one of the following conditions is determined to have local market power: (1)
The Resource is located in a Frequently Constrained Area, as described in Section 8.2.2.7.1, and one or more of the transmission constraints that define the Frequently Constrained Area is binding or the Reserve Zone that defines the area is binding;
(2)
The Resource is not in a Frequently Constrained Area and
(3)
(a)
Has a Resource-to-Load-Distribution factor less than or equal to negative five percent (-5%) relative to a binding transmission constraint; or
(b)
Is located in a binding Reserve Zone;
The Resource is manually committed to address a Local Reliability Issueby the Transmission Provider or selected for commitment by a local transmission operator as described in Sections 4.2.6.2, 4.2.6.3, 4.3.1.2, 4.3.2.2(3)(c)-(e), and 4.4.1.2(3)(c)-(d).
8.2.2.6.18.2.2.7.1
Frequently Constrained Areas
A Frequently Constrained Area is an electrical area identified by the Market Monitor that is defined by one or more binding transmission constraints or binding Reserve Zone constraints that are expected to be binding for at least five-hundred (500) hours during a given twelve (12)month period and within which one (1) or more suppliers are pivotal. A supplier is pivotal when the energy output or provision of operating reserves by any of its Resources, or some of its Resources jointly, must be increased or decreased to resolve the binding transmission constraint or binding Reserve Zone constraint during some or all hours. This will be determined utilizing transmission load flow cases or RTBM market cases reflecting a variety of market conditions.
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These load flow or market cases will be used to estimate: (i) the Generation Shift Factors for all Transmission Provider and relevant non-Transmission Provider Resources relative to each potentially constrained flowgate; (ii) the capability of all Transmission Provider Resources to meet the requirements of each binding Reserve Zone Constraint; (iii) the base loadings of Resources; (iv) the base allocation of Operating Reserves on Resources; and (v) the base flows on each flowgate. A supplier is pivotal when a binding transmission constraint or a binding Reserve Zone constraint cannot be relieved by changing the base loadings for other suppliers’ Resources. The Frequently Constrained Areas will be defined prior to the start of the Integrated Marketplace and will be reevaluated annually or more frequently if the Market Monitor deems it necessary. The Transmission Provider may propose an area’s designation as a Frequently Constrained Area be designated or undesignated as a Frequently Constrained Area if the Market Monitor determines that conditions have changed with respect to the binding transmission constraint or binding Reserve Zone constraints that define the Frequently Constrained Area. The Market Monitor will seek comments from the Market Participants before designating or undesignating any area as a Frequently Constrained Area. Subject to any applicable confidentiality requirements, the Market Monitor will provide any interested Market Participants with a description of its supporting analysis to allow comment on proposed designation changes. The Transmission Provider shall obtain the prior approval of the Commission for the designation of any new area as a Frequently Constrained Area, and for any change or removal of such a designation other than an expectation that there will be insufficient hours of constraint. The Transmission Provider shall submit to the Commission the analysis supporting any such change. To ensure the Frequently Constrained Area designations are available to Market Participants, the Frequently Constrained Area designations and the associated conduct test thresholds set forth in Section 8.2.2.3(2) will be posted on the Transmission Provider’s website. 8.2.2.78.2.2.8 Parameters
Additional
Mitigation
Measures
for
Resource
Offer
Competitive outcomes can also be distorted by submitting offers that do not reflect the physical capabilities of Resources. The mitigation measures in this section are intended to provide the Transmission Provider with the means to mitigate the effects of physical parameter offers that are inconsistent with competitive conduct. The mitigation measures in this section apply to all Offer parameters in Section 4.2.2.1 expressed in units other than dollars and will only apply in the presence of local market power as described in Section 8.2.2.78.2.2.6.
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A reference level for each Offer parameter that reflects the physical capability of the Resource shall be determined prior to the start of the Market by one or a combination of the following methods: (i) the reference levels will be determined through consultation with the Market Participant and the Market Monitor; (ii) the reference levels will be based on averages of Offer parameters from similar resources. This methodology for setting reference levels for Offer parameters shall apply to all Resources at the start of the market and to all new Resources that join the Market subsequent to the start of the Market. The Transmission Provider’s output forecast for a wind-powered Variable Energy Resource shall be used as the reference maximum output limit for the wind-powered Variable Energy Resource. The following thresholds shall be used by the Transmission Provider to identify Resource Offers that may warrant mitigation and shall be determined with respect to the corresponding reference level: Time-based Offer parameters: An increase of three (3) hours, or an increase of six (6) hours in total for multiple time-based Offer parameters. Offer parameters expressed in units other than time or dollars: A 100 percent increase for Offer parameters that are minimum values, or a 50 percent decrease for Offer parameters that are maximum values. Minimum Economic Capacity Operating Limit threshold for Resources committed to address a Local Reliability Issuemanually committed by the Transmission Provider or selected for commitment by a local transmission operator as described in Sections 4.2.6.2, 4.3.2.2(3)(c), and 4.4.1.2(3)(c)-(d): a 25 percent increase. In the case that a Resource Offer fails the thresholds described above, the Market Monitor shall determine the impact on prices or make-whole payments. If an impact exceeds the LMP, MCP, or make whole payment thresholds in Section 8.2.2.9, the Market Monitor will initiate a discussion with the Market Participant concerning an explanation of the parameter changes. The Market Monitor will inform the Transmission Provider of any potential issue. If the Transmission Provider, in consultation with the Market Monitor, concludes that the Market Participant has demonstrated the validity of the submitted Resource Offer parameter, no further action will be taken. If not, the Transmission Provider shall replace the Resource Offer parameter with the corresponding reference level. Mitigation measures will remain in place until such time that the Market Participant demonstrates the validity of the Resource Offer parameter or the Market Participant notifies the Market Monitor that the Resource Offer parameter has been changed to a value that is within the applicable threshold range, and the Market Monitor has
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verified that this change has occurred. In the event that the Market Participant submits a dispute, the mitigation measure will remain in place until the resolution of the dispute. 8.2.2.88.2.2.9
Market Impact Test
The Transmission Provider will apply a market impact test to determine if offers should be mitigated. The Transmission Provider will apply the following market impact test in the DA Market, RUC and RTBM: During times of congestion, a market solution with no mitigation in place is compared to a market solution with the appropriate mitigation applied. If a Settlement Location LMP or MCP without mitigation exceeds the corresponding price from the mitigated solution by at least the applicable impact test threshold, then the mitigated solution is used for dispatch, commitment, and settlement purposes. In addition, if the makewhole payment (MWP) for any Resource increases by at least the MWP impact test threshold, then the mitigated market solution will be used for dispatch, commitment, and settlement purposes. The impact test thresholds are as follows: At market start, the LMP impact threshold is $5/MWh, the MCP impact threshold is $5/MWh, and the MWP impact threshold is $5/MW per hour. At the beginning of each six month (one hundred eighty day) period after the market start, the LMP and MCP impact thresholds will be increased $10/MWh and the MWP impact threshold will be increased by $10/MW per hour unless the Market Monitor finds market behavior that warrants keeping the threshold constant for the next one hundred eighty (180) days. The periodic increases will continue until the LMP impact threshold is $25/MWh, the MCP impact threshold is $25/MWh, and the MWP impact threshold is $25/MW per hour. 8.2.2.98.2.2.10
Mitigated Offer Development Guidelines
A Mitigated Offer Development Subgroup of the Market Working Group, in coordination with the Market Monitor and the Transmission Provider, shall develop and maintain Mitigated Offer Development Guidelines in Appendix G, describing the standards for determining cost components for products and services provided to the SPP market that are subject to mitigation. The Mitigated Resource Offer Parameters, as defined in Sections 8.2.2.3, 8.2.2.4, and 8.2.2.5, are intended to capture the short-run marginal cost, including the appropriate application of opportunity costs, of providing each service to the SPP Energy and Operating Reserve Markets. The Mitigated Offer Development Guidelines shall describe all relevant cost components for
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defining Mitigated Start-Up Offers, Mitigated No-Load Offers, Mitigated Energy Offer Curves, and Mitigated Operating Reserve Offers, by resource-type. Exceptions to the Mitigated Offer Development Guidelines may be submitted to the Market Monitor. The Market Monitor shall respond with a resolution to such a request within 15 calendar days of receipt. The Market Monitor shall review the costs included in the mitigated Resource Offer Parameters of a Resource in order to ensure that the Market Participant has correctly applied the definitions in Sections 8.2.2.3, 8.2.2.4, and 8.2.2.5 and the Mitigated Offer Development Guidelines and that the level of the mitigated offer is otherwise acceptable. If the mitigated offer determined by the Market Monitor and the Market Participant differ, the mitigated offer calculated by the Market Monitor shall be used. If a Market Participant submits a dispute over its mitigated offer, the previously approved mitigated offer shall be used from the time the dispute is submitted until the dispute is resolved. SPP shall remedy mitigated offer disputes resolved in favor of the Market Participant by providing make whole payments, as necessary, to the Market Participant whose mitigated offer was improperly determined by the Market Monitor. The Market Monitor shall gather and keep confidential detailed data on the costs of generation of electric power transmitted in the SPP Region in order to assist the performance of its duties under the SPP Tariff. To achieve this objective, the Market Monitoring Unit shall maintain on its website a mechanism that allows Market Participants to conveniently and confidentially submit such data. In addition the Market Monitoring Unit shall develop a manual in consultation with stakeholders that describes the nature of and procedure for data collection. Market Participants registering a Resource or otherwise subject to a commitment to provide service to SPP shall provide data to the Market Monitoring Unit. 8.2.2.108.2.2.11
Participant Requested Mitigation Exceptions
The Market Monitor shall, as soon as practicable and if warranted in light of the information available to the Market Monitor, contact the Market Participant to request an explanation of the conduct in cases when the Market Participant’s offer has exceeded the conduct and impact levels. If a Market Participant anticipates submitting an offer that will exceed the relevant conduct threshold, it may contact the Market Monitor to provide an explanation of the changes in its offer. If the Market Participant’s explanation indicates to the Market Monitor that the questioned behavior is consistent with competitive behavior; in such instances, the Transmission Provider will not conduct mitigation with respect to that offer unless and until circumstances
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appear to warrant it, and the Transmission Provider or the Market Monitor so notifies the Market Participant. The Market Monitor will record instances where, after Market Participants have notified the Market Monitor with an explanation of the offer prior to submitting an offer that will fail the conduct test, the offer subsequently fails the conduct and impact screens but, due to consultation, the Market Monitor has determined that mitigation would not be appropriate. The Market Monitor will report on such instances to the Commission’s Office of Enforcement every three months during the first year of Integrated Marketplace operations, and yearly thereafter. To the extent that the report contains sensitive data, the Market Monitor should include any such data in a non-public version of the report.
8.2.3
Uneconomic Production
The Market Monitor will monitor for cases where uneconomic production by an Asset Owner’s Resources causes congestion on transmission facilities or price separation between Reserve Zones that is not justified by reliability concerns. The provisions of this Section 8.2.3 will not apply to Demand Response Resources. (1)
Potential uneconomic production will be indicated, and subject to further analysis as described in Section 8.2.3(2), when the Resource has a positive Resource-to-Load Distribution Factor, the LMP at the Resource Settlement Location is less than 50 percent of the applicable Resource energy offer curve reference level, and any of the following
Comment [MPRR202.1455]: MPRR202 Awaiting FERC filing
conditions are met: (a)
a Resource is identified with an incremental energy offer price less than 50 percent of the applicable reference level; or
(b)
a Resource is determined to be generating outside of its Operating Tolerance; or
(c)
a Resource with a time-based or other resource offer parameter (non-time and non-dollar based) that violates any of the thresholds specified in Section 8.2.2.8time-based or other (non-time and non-dollar) offer parameters contribute to congestion on transmission facilities or price separation between Reserve Comment [MPRR202.1456]: MPRR202 Awaiting FERC filing
Zones. (2)
For any Resource meeting the conditions described in Section 8.2.3(1), the Market Monitor shall determine whether: (i) the MW impact from uneconomic production
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associated with such Resource is exacerbating the transmission congestion or binding a Reserve Zone; and (ii) the uneconomic production is not obviously justified by reliability or other operational concerns. The Market Monitor will conduct evaluations as specified in (a) to (c) and other related assessments to determine if there is sufficient credible information to justify referral to the Commission.
8.2.4
Measures and Mitigation for Virtual Energy Bids and Offers
The Market Monitor will monitor the level of divergence between the DA Market LMP and the RTBM LMP. This section defines the monitoring metric and thresholds, as well as the mitigation measures to be imposed by the Transmission Provider when the Virtual Energy Bids or Offers of one or more Market Participants are shown to have caused excessive LMP divergence. 8.2.4.1
Metric and Threshold Specifications
The Market Monitor will compute the hourly LMP deviation between the DA Market and RTBM using the following formula: (LMP RTBM / LMPDA Market) – 1. The average hourly LMP deviation is computed over a rolling four week period or any other period length that the Market Monitor determines is appropriate to achieve the desired purpose. If the four week rolling average is below negative 10% or in excess of 10%, then the divergence is considered excessive and additional studies are required. 8.2.4.2
Excessive Divergence and Mitigation Measures
If a determination is made that excessive divergence exists and the divergence is the result of the Virtual Energy Bids or Offers of one or more Market Participants, then mitigation measures shall be imposed by the Transmission Provider. The mitigation measures will restrict the Market Participants that caused the divergence from submitting any Virtual Energy Bids or Offers at the settlement locations where the Market Participant’s Virtual Energy Bids or Offers caused the excessive divergence . The mitigation measures shall be imposed for a period of three months at which time the restriction will no longer apply.
8.2.5
Offer Caps and Floors
Submission of Energy Offer Curves and Operating Reserve Offers by Market Participants for use in the DA Market and the RTBM will be limited by the following offer caps and floors.
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(1)
Safety-Net Energy Offer Cap = $1000/MWh;
(2)
Regulation-Up Service Offer Cap = (Regulation-Up Offer + Regulation-Up Mileage Offer) = $500/MW;
(2)(3) Regulation-Down Service Offer Cap = (Regulation-Down Offer + RegulationDown Mileage Offer) = $500/MW;
Comment [MPRR102.1457]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.1458]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.1459]: MPRR102 Awaiting implementation. #ER13-1748
(3)(4)
Contingency Reserve Offer Cap = $100/MW;
Comment [MPRR204.1460]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(4)(5)
Energy Offer Floor = Negative $500/MWh;
Comment [MPRR102.1461]: MPRR102 Awaiting implementation. #ER13-1748
(6)
Regulation-Up Service Offer Floor = (Regulation-Up Offer + Regulation-Up Mileage Offer) = Negative $500/MW;
(7)
Regulation-Down Service Offer Floor = (Regulation-Down Offer + Regulation-Down Mileage Offer) = Negative $500/MW;
(8)
Regulation-Up Mileage Offer Floor = $0;
Comment [MPRR102.1462]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.1463]: MPRR204 Awaiting FERC approval Docket #ER13-1748 Comment [MPRR102.1464]: MPRR102 Awaiting implementation. #ER13-1748 Comment [MPRR204.1465]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(5)(9)
Regulation-Down Mileage Offer Floor = $0;
Comment [MPRR204.1466]: MPRR204 Awaiting FERC approval Docket #ER13-1748
(6)(10)
Contingency Reserve Offer Floor = Negative $100/MW;
Comment [MPRR102.1467]: MPRR102 Awaiting implementation. #ER13-1748
(7)(11)
Start-Up Offer Floor = $0.0;
(8)(12)
No-Load Offer Floor = $0.0.
8.2.6
Physical Withholding
The Market Monitor will monitor for physical withholding of capacity from the Energy and Operating Reserve Markets, and unavailability of transmission facilities. Physical withholding may include, (1)
Declaring that a Resource has been derated, forced out of service or otherwise been made unavailable for technical reasons that are untrue or that cannot be verified;
(2)
Refusing to provide offers or schedules for a Resource when it would otherwise have been in the economic interest to do so without market power;
(3)
Operating a Resource in real-time to produce an output level that is less than the Dispatch Instruction minus the Resource’s Operating Tolerance defined in Section 4.4.4.1 and the Resource is not exempt from URD under Section 4.4.4.1.1dispatch instruction;
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(4)
Derating a transmission facility for technical reasons that are not true or verifiable; and
(5)
Operating a transmission facility in a manner that is not economic and that causes a binding transmission constraint or binding reserve zone or reliability issue.
Market Participants will not be deemed to be physically withholding if they are following the directions of the SPP Consolidated Balancing Authority or applicable reliability standards. In addition, Market Participants will not be determined to have physically withheld if they are selling into another market at a higher price. Variable Energy Resources will not be determined to be physically withheld in the Day-Ahead Market under the conditions in 8.2.6 (1) – (2).
Comment [MPRR173.1469]: MPRR173 Awaiting FERC filiing
Thresholds for Identifying Physical Withholding of Resource Capacity
8.2.6.1
A Market Participant is deemed to be physically withholding capacity in a Frequently Constrained Area if the following conditions hold: (1)
One or more of the transmission constraints or Reserve Zone constraints that define the Frequently Constrained Area are binding;
(2)
The Market Participant controls or owns a Resource located in the Frequently Constrained Area that satisfies condition 8.2.6(1), 8.2.6(2), or 8.2.6(3) and is located in the Frequently Constrained Area identified in (1);
(2)(3) The Market Monitoring Unit determines that the withheld capacity has impacts on prices or make-whole payments that exceed the Market Impact Test thresholds in Section 8.2.2.9.
Comment [MPRR173.1470]: MPRR173 Awaiting FERC filiing Comment [MPRR173.1471]: MPRR173 Awaiting FERC filiing
Comment [MPRR173.1472]: MPRR173 Awaiting FERC filiing
A Market Participant is deemed to be physically withholding capacity in an area not designated as a Frequently Constrained Area if the following conditions hold: (1)
One or more transmission constraints are binding or a Reserve Zone is binding; and
(2)
The Market Participant owns or controls one or more Resources that has local market power as defined in Section 8.2.2.7; and
(1)(3) The Market Participant owns or controls a Resource where either Either of (a) or (b) hold;
Comment [MPRR173.1473]: MPRR173 Awaiting FERC filiing
(a) The total capacity withheld, by the Resources identified in (2) that satisfy condition 8.2.6(1) or 8.2.6(2) exceeds the lower of 5 percent of the total capability owned or controlled by the Market Participant or 200 MW;
Comment [MPRR173.1474]: MPRR173 Awaiting FERC filiing
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(b) The real-time output of the a Resource identified in (2) is less than the Dispatch Instruction minus the Resource’s Operating Tolerance defined in Section 4.4.4.1 and the Resource is not exempt from URD under Section 4.4.4.1.1; (4) The Market Monitoring Unit determines that the withheld capacity has impacts on prices or make-whole payments that exceed the Market Impact Test thresholds in Section 8.2.2.9.
Comment [MPRR173.1476]: MPRR173 Awaiting FERC filiing Comment [MPRR173.1477]: MPRR173 Awaiting FERC filiing Comment [MPRR173.1478]: MPRR173 Awaiting FERC filiing
Comment [MPRR173.1479]: MPRR173 Awaiting FERC filiing
Thresholds for Identifying Physical Withholding of Transmission Facilities
8.2.6.2
A transmission facility shall be deemed physically withheld if the following conditions hold: (1)
Either of (a) or (b) hold:
8.2.6.3
(a)
The Market Monitor identifies a pattern of scheduling outages resulting in increased market costs compared to an alternative and lower cost impact outage schedule;
(b)
The transmission facility satisfies a condition in Section 8.2.6(4) or 8.2.6(5)
Sanctions for Physical Withholding
The Market Monitor will record instances where Market Participants have failed the physical withholding screens in Sections 8.2.6.1 and 8.2.6.2. and The Market Monitor will notify the Commission’s Office of Enforcement, or successor organization, of suspected physical withholdingsuch behavior. In the event the Market Monitor determines there is credible evidence of a market violation, the Market Monitor shall make a referral to the Commission as described in Section 8.1.9.
8.2.7
Sanctions for Noncompliance with the Day-Ahead Market Must Offer Requirement
In the case that a Market Participant with registered load is found to be noncompliant for an Asset Owner associated with that registered load as determined by the conditions set forth in Sections 4.2.1.1, the Market Participant shall be assessed a penalty for that Asset Owner as described in 4.2.1.1.1 (1)(a). The penalty amount shall be equal to the Day Ahead Market LMP associated with the withheld capacity as described in Section 4.2.1.1.1(1)(b).
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The Market Monitor will monitor for, and report to the Commission’s Office of Enforcement (“OE”), manipulative behavior associated with Day Ahead Offers, including (but not limited to) monitoring load-serving Market Participants who purposefully underestimate peak loads. The Market Monitor will also report to OE any locational problems, such as deliverability issues, associated with load-serving Market Participants’ offers in the Day Ahead market, any identified efforts by Market Participants to raise prices in the real-time market by limiting Day Ahead offers, and the effects of any such efforts upon make whole payments.
8.2.8
Maintenance and Implementation of the Mitigation Protocols
The Transmission Provider is responsible for implementing the market power mitigation measures as approved by FERC. The Transmission Provider is also responsible for periodically reviewing and recommending revisions to the mitigation protocols and supporting SPP Regulatory Staff in obtaining approval from FERC for any such updates with input and support from the MWG.
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Protocol Revision Request Process
9.
A request to make additions, edits, deletions, revisions, or clarifications to these Protocols, including any attachments and exhibits to these Protocols, except for Appendix F, is called a “Protocol Revision Request” (PRR). Appendix F contains Settlement Examples and will be updated by SPP as necessary. Unless specifically provided in other Sections of these Protocols, this Section shall be followed for all PRRs.
9.1
Submission of a Protocol Revision Request
The following Entities may submit a PRR: (1)
Any Market Participant;
(2)
Any Transmission Customer;
(3)
Any Entity that is an SPP Member;
(4)
Any staff member of a governmental authority having jurisdiction over the SPP or any member company;
(5)
SPP Staff;
(6)
SPP Market Monitor; and
(7)
Any SPP Committee or Working Group.
9.2
Protocol Revision Procedure
Exhibit 9-1 provides an overview of the protocol revision process.
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Exhibit 9-1: Process Flow Chart for Protocol Revision Requests
Submit PRR Request via protocols revisions@spp. org
Submit Corrected PRR to Market Design
No
Accurately Completed?
Vendor Manager MWG
MWG Review
ORWG/RTWG Review
Impact Analysis?
No
Working Group Review
MOPC
Notify Submitter within 5 days for Completion & Re-submittal
Receive & Review Request for Accuracy
Market Design
Qualified Entity
Process Flowchart for Protocol Revision Request
MOPC Review
Yes
Yes
Post Within 3 Days & Set 14-Day Comment Period
To Market Design for submittal with PRR to MWG
Notify VM for Impact Analysis
Request Vendor Assessment
Collaboration to determine system Impact for assessment
VM & OPS
OPS
Complete Vendor Assessment
Completed Impact Assessment
Tariff Implications?
No
Approval of PRR without Tariff Changes or IA
Approval of PRR
No
Impact Analysis
Action by MOPC Posted Within 3 Days
Yes
Protocols Update
Appealed to MOPC Action Submitted Within 10 days
Project Coord./ Project Mgmt.
BOD/FERC
Yes
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Yes
Submit to Regulatory for FERC Preparation
FERC Review
PRR Approval
Protocols Update
BOD Decision on PRR
Initiate Project Request
Communicate with Project Business Owner
PRPC Review and Ranking
Submit Resource Request to PMO
Project Completion
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A description of the process is provided in the following subsections.
9.2.1
Review and Posting of Protocol Revision Requests
PRRs shall be submitted electronically to SPP by completing the designated form provided at the SPP website (PRR Request/Comment Forms). All PRRs are to be submitted to the email address found on the SPP website (
[email protected]). Any PRRs not submitted appropriately will not be processed. The PRR shall include the following information: (1)
Description of requested revision;
(2)
Reason for the suggested change;
(3)
Impacts and benefits of the suggested change on SPP market structure, SPP operations, and Market Participants, to the extent that the submitter may know this information;
(4)
PRR Impact Analysis (IA) (developed and submitted by SPP Staff);
(5)
List of affected Protocol Sections and subsections;
(6)
List of affected Tariff, Business Practice or Criteria sections;
(7)
General administrative information (organization, contact name, etc.); and
(8)
Suggested language for requested revision.
SPP shall evaluate the PRR for completeness and shall notify the submitter, within five (5) Business Days of receipt, if the PRR is incomplete, including the reasons for such status. SPP may provide information to the submitter that will render it complete. An incomplete PRR shall not receive further consideration until it is completed. In order to pursue the revision requested, a submitter must submit a completed version of the PRR with the deficiencies corrected. If a submitted PRR is complete or once a PRR is corrected, SPP shall post a complete PRR to the SPP website and distribute the PRR to the MWG within three (3) Business Days. The PRR will be reviewed at the next regularly scheduled meeting of the MWG after the official comment period of the PRR. The “next regularly scheduled meeting” shall mean the next regularly scheduled meeting for which required notice can be timely given regarding the item(s) to be addressed, as specified in the appropriate Board, committee, or working procedures.
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All decisions of the Market Working Group (MWG), the Operating Reliability Working Group (ORWG), the Regional Tariff Working Group (RTWG), the Market and Operations Policy Committee (MOPC) and the SPP Board of Directors (BOD) with respect to any PRR shall be posted to the SPP website within three (3) Business Days of the date of the decision. All such postings shall be maintained on the SPP website until the PRR is closed. A PRR is considered closed if it has been implemented in the Protocols, rejected, or withdrawn.
9.2.2
Comments on a PRR
Any interested entity may comment on a PRR. Comments on the PRR should be delivered electronically to SPP using the comment form provided on the SPP website within fourteen (14) days from the date of posting/distribution of the PRR. If an entity proposes language changes to the PRR, the entity shall submit a comment form with the proposed revisions to the original PRR language. Comments submitted after the due date of the fourteen (14) day comment period may be considered at the discretion of MWG. All comments received in the proper format will be posted to the SPP website within two (2) Business Days of receipt. The comments shall include identification of the commenting entity. MWG may review the PRR at its next regularly scheduled meeting after the end of the fourteen (14) day comment period unless the fourteen (14) day comment period ends less than three (3) days prior to the next regularly scheduled MWG meeting. In that case, the PRR may be reviewed at the subsequent regularly scheduled MWG meeting.
9.2.3
Impact Analysis
A Protocol Revision Request Impact Analysis (IA) should assess the impact of the proposed PRR on SPP computer systems, operations, or business functions and shall contain the following information: (1)
An estimate of any cost and budgetary impacts to SPP for both implementation and ongoing operations;
(2)
The estimated amount of time required to implement the revised Protocol language;
(3)
The identification of alternatives to the original proposed language that may result in more efficient implementation; and
(4)
The identification of any manual workarounds that may be used as an interim solution and estimated costs of the workaround.
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SPP shall perform an IA or indicate one is not necessary. The results of the evaluation will be documented on an IA form and posted in the applicable PRR folder for review. It will be at the discretion of the MWG to review and/or take action on a PRR contingent upon review of a completed IA. Upon completion of the IA, the MWG may review or modify actions taken on a PRR prior to the completion of the IA. A PRR will not be submitted for review to the ORWG, RTWG, or MOPC before the completion of the IA. If MWG approves a PRR contingent upon review of an IA, SPP shall prepare an IA based on the PRR Recommendation Report. Unless a longer review period is warranted due to the complexity of the proposed PRR Recommendation Report or the quantity of approved PRRs, SPP shall issue the IA for the recommended PRR within twenty-five (25) days after MWG approval of the PRR. SPP shall post the results of the completed IA on the SPP website. If a longer review period is required for SPP Staff to complete a full IA, SPP Staff shall submit a schedule for completion of the IA to the MWG chair.
9.2.4
Market Working Group Review and Action
The MWG is to review and recommend action to the MOPC on PRRs. The MWG will submit PRRs to the RTWG and ORWG, and other working groups/committees as appropriate, prior to the MWG recommendation to the MOPC. The MWG may take action on the PRR to: (1)
Recommend approval as submitted or modified, which approval may be subject to review of a IA or updated IA if such review is determined by MWG to be necessary;
(2)
Reject. A PRR shall be considered rejected if a majority of MWG members fail both to reject and approve the PRR, either as submitted or modified;
(3)
Defer action on the PRR; or
(4)
Refer the PRR to a workgroup, or task force it deems appropriate. The PRR may be referred to a task force created by MWG and/or to one or more existing working groups or task forces of MOPC for review and comment on the PRR. Suggested modifications—or alternative modifications if a consensus recommendation is not achieved by a non-voting working group or task force—to the PRR should be submitted by the chair or the chair’s designee on behalf of the working group or task force as comments on the PRR for consideration by MWG. However, the MWG shall retain ultimate responsibility for the processing of all PRRs.
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Within seven (7) days after MWG takes action to approve, approve with modifications, or reject the PRR, SPP shall post a report (“PRR Recommendation Report”) to the SPP web site reflecting the MWG action. The MWG staff secretary notifies the SPP staff secretaries of appropriate organizational groups of the posting of PRR recommendation reports and applicable IAs. A PRR recommendation report shall contain the following items: (1)
Identification of submitter;
(2)
Modified Protocol, Criteria and Tariff language proposed by the MWG;
(3)
Comments submitted;
(4)
Proposed effective date(s) of the PRR;
(5)
MWG rating and rank for any PRRs requiring a system change project; and
(6)
Recommended action: approval, approval with modified language.
The MWG Chair shall notify MOPC of PRRs rejected by MWG.
9.2.5
Operations Reliability Working Group Review
Upon notification of the posting of a PRR Recommendation Report, the ORWG shall review the recommended changes to determine if the proposed change conflicts with requirements outlined in the SPP Criteria. In the event the ORWG identifies what it believes are conflicts with the SPP Criteria, which have not previously been identified by the MWG, or issues concerning the proposed changes, the ORWG will submit comments to the PRR to be considered by MWG at its next regularly scheduled meeting or by MOPC during its review of the Recommendation Report.
9.2.6
Regional Tariff Working Group Review
Upon notification of the posting of a PRR Recommendation Report, the RTWG shall review the recommended changes to determine if the proposed change conflicts with requirements outlined in the Tariff. The RTWG shall review and provide comments on any proposed Tariff changes included in the Recommendation Report. In the event the RTWG identifies what it believes are conflicts with the Tariff, which have not previously been identified by the MWG, or issues regarding the proposed changes, the RTWG will submit comments to the PRR to be considered by the MWG at its next regularly scheduled meeting or by the MOPC during its review of the Recommendation Report.
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9.2.7
Market and Operations Policy Committee Action
MOPC shall consider any PRRs that MWG has submitted to MOPC for consideration for which a final PRR Recommendation Report has been posted on the SPP website for at least six (6) days or those accepted for urgent treatment by the MOPC. The following information must be included for each PRR considered by MOPC: (1)
The PRR Recommendation Report and IA, if any; and
(2)
Any comments timely received in response to the PRR Recommendation Report.
MOPC shall take one of the following actions regarding the PRR Recommendation Report: (1)
Approve the PRR as recommended in the PRR Recommendation Report or as modified by MOPC;
(2)
Reject the PRR. A PRR shall be considered rejected if MOPC members fail both to reject or approve the PRR, either as submitted or modified; or
(3)
Remand the PRR to the MWG with instructions.
If the PRR Recommendation Report is approved by the MOPC, as recommended by MWG or modified, the MOPC shall review and approve or modify the proposed effective date. The MOPC’s decision regarding approval or rejection of a PRR shall be posted on the SPP website within three (3) Business Days after the MOPC’s decision. If the MOPC rejects a PRR, the submitter may file an appeal with the SPP Board. If the MOPC approves a change or changes to the Protocols, such change(s) shall be incorporated into the Protocols posted on the SPP website as soon as practicable, but no later than one (1) day before the effective date of the changes. Where a PRR does not take effect immediately, the PRR shall be shown in the Protocols in gray-boxed text that indicates the anticipated effective date of the PRR.
9.2.8
SPP Board of Directors Review and Action
If the PRR requires Criteria or Tariff revisions, after a PRR has been approved by the MOPC, it must be submitted to the SPP Board of Directors (BOD) for review and action. The BOD will review the PRR at the next regularly scheduled meeting and take one of the following actions: (1)
Approve the PRR as recommended in the PRR Recommendation Report or as modified by the SPP Board of Directors;
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(2)
Reject the PRR. A PRR shall be considered rejected if SPP BOD fail both to reject or approve the PRR, either as submitted or modified; or
(3)
Remand the PRR to the MOPC with instructions.
9.2.9
Withdrawal of Protocol Revision Request
Upon notice to the MWG, the submitter of a PRR may withdraw the PRR at any time prior to approval of the PRR by the MWG. SPP shall post a notice of the submitter’s withdrawal of a PRR on the SPP website within one (1) Business Day of the submitter’s notice to MWG. If a PRR is approved by the MWG it cannot be withdrawn except with approval of the MWG.
9.2.10
Expedited Review Requests
The party submitting a PRR may request that the PRR be considered for Expedited Review when the submitter is requesting action from the MWG on a PRR that has not met the minimum comment period described in Section 9.2.2. A valid motion in a regularly scheduled meeting of the MWG is required to waive the minimum comment period and treat a PRR with Expedited Review status. If approved for Expedited Review by the MWG, the PRR will be treated the same as one that has met the minimum comment period. If the request for Expedited Review is rejected, the PRR will be considered by the MWG after the minimum period; in most cases at the next regularly scheduled MWG meeting.
9.2.11
Urgent Action Requests
The party submitting a PRR may request that the PRR be considered for Urgent Action. Urgent Action Requests should be reserved for instances when existing Protocol is impairing or could imminently impair SPP System reliability or wholesale or retail market operations, or is causing or could imminently cause a discrepancy between any of SPP’s governing documents. The MWG shall consider the Urgent Action PRR at its earliest regularly scheduled meeting or at a special meeting called by the MWG chair. In some cases, an Urgent Action Request will occur concurrently with an Expedited Review Request. A valid motion and vote of the MWG are required to designate the PRR for Urgent Action. After approval, Urgent Action PRRs shall be given priority high enough to ensure implementation within the timeline necessary to mitigate concerns about SPP system reliability or market operations under the unmodified language, or any other significant issues identified in the PRR.
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If approved, SPP shall submit an Urgent Action PRR Recommendation Report to the chair and staff secretary of the MOPC, RTWG, and ORWG within two (2) Business Days to address the urgency of the PRR. The MOPC, RTWG and ORWG chairs may request action from the working groups to address the urgency of the PRR.
9.2.12
Appeal of Decision
If MWG rejects the PRR, any entity eligible to submit a PRR may appeal directly to the MOPC. Such appeal to the MOPC must be submitted to SPP within ten (10) Business Days after the date of the relevant decision. Appeals made after this time shall be rejected. Appeals to the MOPC shall be posted on the SPP website within three (3) Business Days and placed on the agenda of the next available regularly scheduled MOPC meeting, provided that the appeal is provided to SPP at least eleven (11) days in advance of the MOPC meeting; otherwise the appeal will be heard by the MOPC at the next regularly scheduled MOPC meeting. If MOPC rejects the PRR, any entity eligible to submit a PRR may appeal directly to the SPP Board. Such appeal to the SPP Board must be submitted to SPP within ten (10) Business Days after the date of the relevant decision. Appeals made after this time shall be rejected. Appeals to the SPP Board shall be posted on the SPP website within three (3) Business Days and placed on the agenda of the next available regularly scheduled SPP Board meeting, provided that the appeal is provided to the SPP General Counsel at least eleven (11) Business days in advance of the Board meeting; otherwise the appeal will be heard by the Board at the next regularly scheduled Board meeting. In the event FERC rejects the tariff modifications associated with a PRR, the PRR will be deemed rejected by FERC action. In the event FERC accepts with changes the tariff modifications associated with a PRR, the SPP staff will prepare a PRR to conform the Market Protocols with the FERC order.
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Market Process and System Change Process
10.
This section outlines the methods that govern SPP System changes that directly impact members’ processes, systems, or interfaces with SPP systems. The intent of this section is to ensure there is transparency when member-impacting changes occur to SPP processes and/or systems. (1)
(2)
The SPP CWG (Change Working Group) is the group responsible for monitoring and coordinating all planned member-impacting system or process changes that meet one or more of the following criteria: (1)
The change will result in members having to make changes to their internal systems or interfaces;
(2)
The change will require members to coordinate testing with SPP prior to the change being released to Production systems;
(3)
The change will cause members to change their internal processes;
(4)
The change modifies or creates a system interface between SPP and its members;
(5)
The risk associated with the change justifies inclusion as a member-impacting change.
The CWG and SPP will develop and maintain a plan outlining member-impacting change initiatives. This plan will be updated at least quarterly and posted to the CWG page on the SPP Corporate website. The plan will reflect the relative priority of all memberimpacting change initiatives. These priorities will be determined based on the PRR ranking process conducted by the SPP Market Working Group (MWG) as well as internal project prioritization processes in place at SPP. System changes that cannot be implemented according to the requested priority will be identified and communicated to the MWG, after coordination with the CWG. The plan will include, at a minimum, the following: (1)
Listing and description of planned member-impacting projects;
(2)
Updated current status of planned member-impacting projects;
(3)
Identifiable milestones of planned member-impacting projects, including, but not limited to: (a)
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(3)
(b)
Schedule of Testing and Training;
(c)
Communication of Expectations / Specifications;
(d)
Release of Required Documentation;
(e)
System Release Dates.
All member-impacting change initiatives are classified as minor, medium, major or emergency changes. The classification of these initiatives will be routinely reviewed and discussed by the Change Working Group and alternative timelines will be recommended, depending on the scope of the individual projects. SPP will maintain a list of system changes and their associated classifications for discussion and coordination with the CWG.
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(a)
Minor Change – a change to an SPP system that corrects or changes existing functionality but does not require members to make any changes to their systems, nor test the new functionality in a coordinated fashion with SPP. An example of a minor member-impacting change would be an enhancement to member accessible web page that includes adding newly available options or functionality. For minor member-impacting changes, SPP staff is required to notify the membership at least two (2) weeks prior to implementation in production.
(b)
Medium Change - a change to an SPP system that involves changes to system interfaces between SPP and its members, such as changes to XML file specifications or Application Programmable Interfaces (API). The process for interface changes must allow sufficient time for members to assess the impact of the change to their systems, make appropriate revisions, and complete testing in an offline environment, where applicable. SPP staff is required to notify the membership at least six (6) weeks prior to implementation in production, or as defined and agreed to by the CWG.
(c)
Major Change - a change to an SPP system that introduces a new member-facing application, major system functionality or wholesale process changes. These changes will always be managed by SPP as projects, with milestones defined on the plan that is updated quarterly, and will include member participation, coordination, and testing throughout the project phases. For major changes that require the development of new applications or interfaces by members, SPP staff is required to coordinate the project schedule by means of the Change Working
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Group to determine the appropriate lead times for documentation, testing, and implementation. (d)
Emergency Change – a member-impacting change to an SPP system that is required to immediately restore or correct existing functionality. If changes to member systems or processes are required as a result of an Emergency Change, where appropriate, SPP staff will: (a)
10.1
Communicate the need for the change with SPP members via an emergency conference call. The communication will include a discussion of impacts, risks, and timelines.
Root Cause Analysis
Within 30 calendar days of any unplanned system outage, in which Market Participants were instructed by SPP to hold their deployment levels for a period of time, SPP staff will perform a root cause analysis of the event and publish an executive summary of its findings to the CWG distribution list, and other applicable SPP member distribution lists. Staff will provide bi-weekly updates (via e-mail) to the CWG on the progress associated with the root cause analysis. The analysis will outline the root cause of the event, describe remediation actions to prevent future reoccurrences, and specify if changes or workarounds that may have been put into place, will remain in production on a permanent or temporary basis.
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Appendix A – Registration Portal Reserved for screen shots/directions on how to use Registration Portal, to be completed at a later date.
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Appendix B - XML Specifications Detailed XML specifications to be completed at a later date.
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Appendix C - Meter Technical Protocols
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Scope
1.
This document will serve as a definitive technical resource concerning the expected duties, responsibilities, processes, standards, and liabilities with regards to the Metering Parties for the SPP Integrated Marketplace metering implementation.
Purpose
2.
This document will provide the metering technical standards for installation, maintenance and validation of facilities by which the Metering Parties will participate in the SPP Integrated Marketplace.
Definitions
3.
The terms used in this document are defined as defined in Section 1 of the Market Protocols.
Applicable Standards
4.
ANSI C12.1
American National Standard For Watthour Meters, Code For Electricity Metering ANSI C12.7 American National Standard Requirements for Watthour Meter Sockets ANSI C12.9 American National Standard For Test Switches for Transformer-Rated Meters ANSI C12.10 American National Standard For Watthour Meters ANSI C12.11 American National Standard For Instrument Transformers For Revenue Metering, 10kV BIL through 350 kV BIL ANSI C12.16 American National Standard For Solid State Electricity Meters ANSI C12.20 American National Standard For 0.2 and 0.5 Accuracy Class ANSI C 93.1 Standard Requirements for Power Line Coupling Carrier Capacitors and Coupling Capacitor Voltage Transformers IEEE Std 100 The New IEEE Standard Dictionary of Electrical and Electronic Terms IEEE C57.13 IEEE Standard Requirement for Instrument Transformers IEEE C37.90.1 IEEE Standard Surge Withstand (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus NFPA 70 National Electrical Code® 2011 edition, Chapter 1 General, Section II. 600 Volts, Nominal, or Less, Article 110.26 Spaces About Electrical Equipment.
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5.
General
5.1
Introduction
This Appendix will apply to SPP metering facilities including specifications and practices required to provide accurate metering of electrical quantities for settlement. These guidelines are not applicable to measurements intended for local monitoring, station relaying, control, or operation.
5.2
Existing Facilities
Existing meter facilities as of January 1, 2006 are acceptable for SPP market transactions ("grandfathered"), as long as the following criteria is met: (1)
Market Participant is capable of providing at least hourly MWh interval data information;
(2)
The Metering Parties mutually agree that the existing metering facilities are acceptable;
(3)
Meets other SPP transmission tariff requirements.
5.3
Physical Location of Meter
The Market Participant metering facility shall be designed to sustain an environment within the limits of the operating characteristics of the meter and metering devices as stated by the meter manufacturer. A clear space shall be provided in front and to the side of the meter as outlined in The National Electric Code, Article 110.26, Spaces About Electrical Equipment. Adequate lighting should be provided at the meter’s location for testing, maintenance, and adjustment.
5.4
Metering of Net Interchange
Sufficient metering between Settlement Areas, and between Settlement Areas and external Balancing Authorities, as defined in Section 7, shall be installed for the purposes of reporting hourly metered interchange for use in settlement calibration as described under Section 4.5.9.1.
5.5
Metering for Resources
Sufficient metering, as defined in Section 7 of this Appendix, shall be installed for Resources either at the Resource terminals or at the Meter Settlement Location in accordance with the terms
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of the applicable Interconnection Agreement or Network Operating Agreement. All metered Resource data values are to be supplied to SPP as net generation and compensated to the SPP Transmission Tariff Facilities (Node).
5.6
Metering for Loads
Sufficient metering, as defined in Section 7 of this Appendix, shall be installed for the settlement of Loads in accordance with the terms of the applicable Interconnection Agreement or Network Operating Agreement.
5.7
Measurement Quantity Verification
Measurement quantity verification shall be accomplished by reading the appropriate register of the meter.
5.8
Measurement Governance
The owner/operator of the meter shall provide the measurement quantity at the meter connection. The measurement quantity may contain loss compensation, if performed within the meter.
6.
Timing Standard
6.1
Remote Terminal Unit (RTU) Freeze Contact or Signal
When an RTU requires a freeze contact or signal to synchronize an accumulator reading, the timing contact shall be provided by either the EMS system or RTU whose timing element meets the accuracy requirement of Section 6.4 or a meter whose timing element meets the accuracy requirement of Section 6.3.
6.2
Accumulators / Register Values
Accumulators / meter register values will be synchronized to the end of the timing interval. This can be done by providing a frozen register value from the meter, by providing the last recorded interval reading from the interval data recorder in the meter, or an RTU frozen accumulator reading at the end of the interval.
6.3
Accuracy - Meter
When the timing element of the meter is used to send a freeze contact closure or signal to the RTU, freeze a meter register reading, and/or control the interval data recorder timing, the time
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clock shall be within +/- 1 minute per any 30 day period. If the timing element is found to exceed this value, it will be resynchronized to Central Standard Time from a NIST source.
Accuracy – EMS/RTU
6.4
When the timing element of the EMS/RTU is used to provide a freeze contact closure or signal to the RTU, the time clock shall be within +/- 1 minute per any 30 day period. If the timing element is found to exceed this value, it will be resynchronized to Central Standard Time from a NIST source.
7.
Meters
7.1
Measurement Quantities
The meter shall be capable of reporting watthours (Wh) and varhours (VARh) for 4 quadrants. (1)
Quadrant 1 shall measure active power and reactive power delivered by the SPP network.
(2)
Quadrant 2 shall measure active power received by the SPP network and reactive power delivered by the SPP network.
(3)
Quadrant 3 shall measure active power and reactive power received by the SPP network.
(4)
Quadrant 4 shall measure active power delivered by the SPP network and reactive power received by the SPP network.
The Wh and VARh may be expressed in kilo or mega values as agreed to by the Metering Parties. Refer to Appendix E for reporting requirements.
7.2
Measurement Configuration
Metering shall be installed and configured in such a manner as to comply with the following: (1)
Current transformers shall be installed, one in each phase, for metering which is connected to a four-wire wye neutral grounded system or in two phases for metering which is connected to a three-wire ungrounded system. Voltage transformers for a fourwire wye neutral grounded system (three single phase units or one three phase unit) shall be installed, one from each phase conductor to the circuit neutral. Voltage transformers (two single phase units) for a three-wire ungrounded system shall be installed from phase to common phase.
(2)
For three wires delta connected power transformers connected to a four wire wye grounded source at a Transmission level voltage two element metering is acceptable. The
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equipment owner shall ensure that no single-phase Loads are connected between the metering transformers and the three-wire delta connected power transformer. Voltage Table 1 transformers (two single phase units) shall be installed from phase to common phase.
7.3
Accuracy
Meters shall meet the following minimum percent tolerances. If the test results exceed these tolerances, the meter must be calibrated to bring it within the acceptable tolerance range as defined in Table 1.
% Test Amp
Power Factor
Tolerance %
100
1.0
±0.2%
10
1.0
±0.2%
100
0.5 lagging
±0.3%
The individual elements shall be tested for balance before or at time of installation to within ±0.3%. A final Series Test as defined by ANSI C12.1 shall be made after any calibration.
7.4
Testing
7.4.1
Testing Equipment
All meter testing equipment shall be traceable back to National Institute of Standards and Technology (NIST) as per ANSI C12.1 Appendix B. Specifically, the reference standard used to perform the comparison test on the meter shall be of the accuracy class that meets or exceeds ± 0.05% so as to achieve a 4 to 1 Accuracy Ratio between the standard and the meter.
7.4.2
Acceptance Testing
All meters shall meet the applicable sections in ANSI C12.1 and ANSI 12.20.
7.4.3
In-Service Testing
The accuracy of all meters required to transact energy services shall be verified by tests conducted by the equipment owner. The test interval shall be determined by agreement between the affected Market Participants but in all cases it shall never be more than 1 year. The metering equipment owner shall provide reasonable advance notification to the other metering parties of
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this periodic test and provide the test results to them. If such test identifies or other indications show a meter is out of service or inaccurate, the Market Participant must take action to restore the meter to correct operation within a reasonable period of time. In the interim, backup metering or integrated real time metering may be used as mutually agreed by the Metering Parties involved. However in no case shall the reasonable period of time exceed a period of 30 days from the date of discovery, or from a date mutually agreed upon by the Metering Parties. If equipment installation or replacement is required to resolve the inaccuracy, all equipment must be correctly operating at a date mutually agreed upon by the Metering Parties. SPP will be notified of the inaccuracy, interim procedures, and resolution for auditing purposes. Periodic accuracy compliance testing may be requested by SPP member agreement groups, as required. Authentication of existing meter systems and validation of newly installed or repaired meter systems are required as described in Section 7.11 of this Appendix.
7.4.4
Verification Records and Retention
The Control Area Operator and/or Wires Facilities owner(s) shall maintain sufficient documentation to verify the integrity and accuracy of a Settlement Location. All meter records and associated documentation must be retained by the Market Participant for a period of seven years for independent auditing purposes by the SPP. This documentation shall include but is not limited to the following: (1)
Schematic drawings (both detailed and one-line) of the Settlement Location. Such drawings shall be dated, bear the current drawing revision number, and show all wiring, connections, and devices in the circuit.
(2)
The results of all accuracy testing listed in Section 7.4.1 through 7.4.3 of this Appendix. The accuracy values shall be calculated based on Method 1 of ANSI C12.1.
7.5
Real Time Metering
7.5.1
General
If the metering should fail, the real time metering may be used, if available, to estimate the usage as long as the same voltage and current transformers are used. The real time metering is normally accomplished using a watt transducer. The MW quantity from this device will be integrated over the hour that the meter has failed, which will produce the estimated MWh. To the extent that real time metering is installed and used as above, the standards are indicated in this section.
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7.5.2
Measurement Configuration
The transducer shall be installed and configured in such a manner as to comply with the following: (1)
Current transformers shall be installed, one in each phase, for metering which is connected to a four-wire wye neutral grounded system or in two phases for metering which is connected to a three-wire ungrounded system. Voltage transformers for a fourwire wye neutral grounded system (three single phase units or one three phase unit) shall be installed, one from each phase conductor to the circuit neutral. Voltage transformers (two single phase units) for a three-wire ungrounded system shall be installed from phase to common phase.
(2)
For three wire delta connected power transformers connected to a four wire wye grounded source at a Transmission level voltage, two element metering is acceptable. The equipment owner shall ensure that no single-phase Loads are connected between the metering transformers and the three-wire delta connected power transformer. Voltage transformers (two single phase units) shall be installed from phase to common phase
7.5.3
Accuracy
The transducer shall meet the following minimum percent tolerances. If the test results exceed these tolerances, the transducer must be calibrated to bring it within the acceptable tolerance range as defined in Table 2. Table 2 % Calibration Watts
Power Factor
Tolerance %
100
1.0
±0.2
7.5.4
Testing
7.5.4.1
Testing Equipment
All transducer testing equipment shall be traceable back to National Institute of Standards and Technology (NIST).
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7.5.4.2
Acceptance Testing
The transducer shall pass Section 4.7.3.1 Test 15, Section 4.7.3.2 Test 16, Section 4.7.3.3 Test 17, Section 4.7.3.11 Test 25, Section 4.7.3.14 Test 28, Section 4.7.3.16 Test 30, and Section 4.7.3.17 Test 31 as specified in ANSI C12.1. These shall be done in series. The transducer shall have been deemed to pass if it meets the criteria specified in section 4.6.2.1 of ANSI C12.1 7.5.4.3
Operating Conditions
A transducer will maintain the accuracy as shown in Table 2 under the following conditions: (1)
Temperature Range:
-20°C to +70°C
(2)
Humidity:
0 to 95% non condensing
(3)
Potential Range:
70 to 130% of nominal input voltage rating
(4)
Current Range:
0 to 200% of nominal current rating
7.5.4.4
Output Characteristics
The transducer will be able to measure 99% of the true measured value in no more than 400 milliseconds. The AC Component of the output shall be no more than 0.5% peak of the rated output. 7.5.4.5
In Service Testing
The accuracy of all transducers required for real time metering to transact energy services shall be verified by tests conducted by the equipment owner at time of commissioning or with a certified factory test. If there are indications that show that a transducer is out of service, the Market Participant must take action to restore the transducer to correct operation within a reasonable period of time. However in no case shall the reasonable period of time exceed a period of 30 days from the date of discovery, or from a date mutually agreed upon by the Metering Parties. If equipment installation or replacement is required to resolve the inaccuracy, all equipment must be correctly operating at a date mutually agreed upon by the Metering Parties. SPP will be notified of the inaccuracy, interim procedures, and resolution for auditing purposes. Periodic accuracy compliance testing may be requested by SPP member agreement groups, as required. Authentication of existing real time metering and validation of newly installed or repaired real time metering is required as described in Section 7.11 of this Appendix.
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7.5.4.6
Verification Records and Retention
The Control Area Operator and/or Wires Facilities owner(s) shall maintain sufficient documentation to verify the integrity and accuracy of a Settlement Location. This documentation shall include but is not limited to the following: (1)
Schematic drawings (both detailed and one-line) of the Settlement Location. Such drawings shall be dated, bear the current drawing revision number, and show all wiring, connections, and devices in the circuit.
(2)
The transducer manufacturer’s original test specifications shall be sufficient to verify the accuracy of this device.
7.6
New Current and Voltage Sensing Technologies
Fiber optic current and voltage transformers are considered technologies that shall be periodically tested until proven to provide stable accuracy. SPP may determine that this testing is not required once these devices after testing have shown themselves to be stable. If these devices have shown themselves to be unstable, then the participant shall discontinue the use of these devices for settlement purposes. Fiber optic sensors, at a minimum are to provide the same accuracy class as wire wound devices. Until there is general agreement that the proven accuracy of the optical sensors is the same as wire wound devices, the frequency of accuracy testing of the fiber optic sensors is to be at least every five years. Once long term accuracy data is developed, routine field calibration may no longer be required to ensure the ANSI 0.3% accuracy class.
7.7
Current Transformers
7.7.1
Nameplate
The nameplate data shall include but is not limited to the following information: Manufacturer, Serial Number or Identification Number, Type, Current Transformer Ratios, Accuracy class and Burden Rating, Rating Factor, and BIL. Current transformers shall comply with ANSI 0.3 accuracy class or better for B0.1 through B1.8. If the current transformers are not accessible due to energized components or extensive disassembly is required that may impact asset availability, note the unavailability and request the Market Participant to identify a scheduled outage when the current transformer nameplate may be accessed safely. If a nameplate doesn’t exist showing the ANSI 0.3 accuracy class, testing as described in IEEE C57.13 shall be performed to establish
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this level of accuracy and a nameplate created. This nameplate shall be affixed to the current transformer or the device in which it is included.
7.7.2
Polarity
The polarity marks on all current transformers shall follow the same convention, (e.g., all facing the line or all facing the Load). If there is more than one primary conductor passing through the current transformer, then all conductors shall be of the same phase. If the current transformers are not accessible due to energized components or extensive disassembly is required that may impact asset availability, note the unavailability and request the Market Participant to identify a scheduled outage when the current transformers polarity may be verified safely. If current transformers polarity markings don’t exist, testing as described in IEEE C57.13 shall be performed to establish terminal polarity. The terminals shall be permanently marked with this information.
7.7.3
Burden Testing
The current transformer burdens shall be kept as small as practicable and the metering circuit shall be limited to billing meters and transducers. Relays shall not be connected to the metering circuit. Current transformers shall comply with ANSI 0.3 accuracy class for B0.1 through B1.8 or better. During annual testing, the total current transformer burden shall be checked by the addition of a known burden to determine that the specified burden capability of the current transformer is not exceeded.
7.7.4
Paralleling
Paralleling of current transformers is not recommended. However, when it is necessary, the following guidelines shall be adhered to. (1)
All current transformers must have the same nominal rating regardless of the circuits in which they are connected.
(2)
All current transformers which have their secondaries paralleled must be connected to the same phase of the primary circuits.
(3)
The secondary circuits shall be connected in a configuration to allow for testing of individual instrument transformers. The secondary circuits shall be paralleled at the meter test switch.
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(4)
There shall be only one ground per isolated secondary of all paralleled current transformers. It is recommended that the ground be located at the meter or at the nearest terminal block to the meter.
(5)
The secondary circuits must be so designed that the maximum possible burden on any current transformer will not exceed its rating.
(6)
A common voltage must be available for the meter. This condition is met if the circuits share a common bus that is normally operated with closed bus ties.
(7)
The meter must have sufficient current capacity to carry the sum of the currents from all the current transformers to which it is connected.
7.8
Coupling Capacitor Voltage Transformers
7.8.1
General
Coupling Capacitor Voltage Transformers are not to be used on new installations. For existing installations, Coupling Capacitor Voltage Transformers shall be tested at least every five years to ensure revenue class accuracy. If this device shows itself to be unstable, the SPP may require the participant to discontinue the use of this device for Settlement purposes. Coupling Capacitor Voltage Transformers at a minimum are to provide the same accuracy class as wire wound devices.
7.8.2
Nameplate
The nameplate data shall include but is not limited to the following information: Manufacturer, Serial Number or Identification Number, Type, Voltage Transformer Ratios, Accuracy Class and Burden Rating, and BIL. Coupling Capacitor Voltage Transformers shall comply with ANSI 0.3 accuracy class or better for W, X, M, Y, Z, and ZZ burden levels. If the Coupling Capacitor Voltage transformers are not accessible due to energized components or extensive disassembly is required that may impact asset availability, note the unavailability and request the participant to identify a scheduled outage when the voltage transformer nameplate may be accessed safely. If a nameplate doesn’t exist showing the ANSI 0.3 accuracy class, testing as described in ANSI C93.1 shall be performed to establish this level of accuracy and a nameplate created. This nameplate shall be affixed to the Coupling Capacitor Voltage Transformer.
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7.8.3
Polarity
The polarity marks on all Coupling Capacitor Voltage Transformers shall follow the same convention as the current transformers, (e.g., all facing the line or all facing the Load). If the voltage transformers are not accessible due to energized components or extensive disassembly is required that may impact asset availability, note the unavailability and request the Market Participant to identify a scheduled outage when the voltage transformers polarity may be verified safely. If Coupling Capacitor Voltage Transformers polarity markings don’t existing, testing as described in ANSI C93.1 shall be performed to establish terminal polarity. The terminals shall be permanently marked with this information.
7.8.4
Burden
The Coupling Capacitor Voltage Transformer burdens should be kept as small as practical. The total burden/volt-ampere rating on the voltage transformer secondary shall not exceed the accuracy burden listed on the nameplate of the voltage transformer. This burden shall include the meter, the secondary leads, and any equipment connected in the circuit.
7.9
Wire Wound Voltage Transformers
7.9.1
Nameplate
The nameplate data shall include but is not limited to the following information: Manufacturer, Serial Number or Identification Number, Type, Voltage Transformer Ratios, Burden Rating, thermal rating, BIL, and Class. Voltage transformers shall comply with ANSI 0.3 accuracy class or better for W, X, M, Y, Z, and ZZ burden levels. If the voltage transformers are not accessible due to energized components or extensive disassembly is required that may impact asset availability, note the unavailability and request the Market Participant to identify a scheduled outage when the voltage transformer nameplate may be accessed safely. If a nameplate doesn’t exist showing the ANSI 0.3 accuracy class, testing as described in IEEE C57.13 shall be performed to establish this level of accuracy and a nameplate created. This nameplate shall be affixed to the voltage transformer or the device in which it is included
7.9.2
Polarity
The polarity marks on all voltage transformers shall follow the same convention as the current transformers, (e.g., all facing the line or all facing the Load). If the voltage transformers are not accessible due to energized components or extensive disassembly is required that may impact asset availability, note the unavailability and request the Market Participant to identify a
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scheduled outage when the voltage transformers polarity may be verified safely. If voltage transformers polarity markings don’t exist, testing as described in IEEE C57.13 shall be performed to establish terminal polarity. The terminals shall be permanently marked with this information.
7.9.3
Burden
The voltage transformer burdens should be kept as small as practical. The total burden/voltampere rating on the voltage transformer secondary shall not exceed the accuracy burden listed on the nameplate of the voltage transformer. This burden shall include the meter, the secondary leads, and any equipment connected in the circuit.
7.10
Ancillary Devices
7.10.1
Wiring
7.10.1.1
Phase Wiring
The integrity of the secondary wiring of the current and voltage transformers shall be verified. No other ancillary device other than SPP Settlement Location metering shall be installed in the CT circuit. The VT circuit may have an ancillary device installed in it, if mutually agreed upon by the metering parties. The integrity of the secondary wire shall include but is not limited to the following items. (1)
Each current and voltage transformer shall have its own polarity conductor.
(2)
No splices will be allowed in the current or voltage transformer secondary circuit except through the use of terminal block connections.
7.10.1.2
Neutral Returns
A separate common return conductor shall be utilized for each set of isolated current transformer secondary windings and a separate common return conductor for each set of isolated voltage transformer secondary windings. The common terminals of each set of current transformers and voltage transformers shall be grounded at only one point. It is recommended that the ground connection be located at the meter or at the nearest terminal block to the meter. This ground lead shall be of the same wire size as the leads used for the polarity and common that connects to the meter.
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7.10.1.3
Induced Voltage on Wiring
Secondary circuits should be routed so as to mitigate the possibility of induced voltages and the effects of high ground fault voltages. The secondary circuit should be designed to minimize these effects. Suitable protection against the effects of fault and switching generated overvoltages should be provided in the metering equipment (Refer to IEEE C37.90.1). 7.10.1.4
Fusing
Monitoring of the voltage circuit is required, if fusing of the secondary circuit is necessary. This can be accomplished by the meter or an external device. If the voltage transformer is shared by a relay group, the fusing shall be done after the metering branch point. Fusing is not allowed in any primary or secondary circuit of a current transformer. 7.10.1.5
Test Switches
Test switches shall be installed in the instrument transformer secondary circuits to provide a means to measure quantities required to certify the facility and allow the application of test quantities to the meter. Test switches shall be capable of handling parallel currents. Test switches shall conform to ANSI C12.9.
7.11
Metering Site Procedures
7.11.1
General
Except in those cases where the involved Metering Parties agree to the contrary, the equipment owner shall be responsible for any maintenance and calibration. The equipment owner may modify the following procedures and any other procedure herein as it deems necessary to meet efficient and proper test procedures and methodology as found by practice. When the Meter Settlement Location meter is being tested, care should be taken to minimize the potential impact on operations. The Metering Parties shall be notified of these procedures with sufficient time to be present and shall have the right to witness these procedures.
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7.11.2
Site Verification Procedure
These procedures will be completed at the commissioning of the Settlement Location metering site or if the wiring or instrument transformers are modified. The site verification procedure that will be completed by the equipment owner shall include but is not limited to the following items. (1)
Verification that the documentation and drawings accurately represents the equipment and circuits installed at the specific location.
(2)
Inspection of the primary and secondary connections of all instruments transformers so as to verify that the polarity marks on all instrument transformers are following the same convention (i.e. all polarity marks connected using the same convention, e.g., facing the same source).
(3)
The instrument transformers nameplate data shall match the drawings.
(4)
A burden test shall be performed on the metering circuit to determine that the circuit burdens do not exceed the burden rating of the instrument transformers.
(5)
The magnitude and phase angles for each of the phase voltages and currents at the meter test switch shall be measured to ensure the proper metering connection.
(6)
The meter shall meet the accuracy tests as stated in Sections 7.4.2 and 7.4.3 of this Appendix for watthour functions for both Quadrant 1 and 2. For auxiliary metered Loads only the Quadrant 1 watthour function need be tested.
Upon request, the Transmission Owner(s), Transmission Customer(s) and the Transmission Provider shall be provided with a copy of all of the equipment owner’s documentation and drawings for the specific location.
7.11.3
Periodic Test Procedure
These procedures will be completed during the meter’s Periodic Test or if the meter is exchanged. The Periodic Test procedure that will be completed by the equipment owner shall include but is not limited to the following items: (1)
A burden test shall be performed on the metering circuit to determine that the circuit burdens do not exceed the burden rating of the instrument transformers.
(2)
The magnitude and phase angles for each of the phase voltages and currents at the meter test switch shall be measured to insure the proper metering connection.
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(3)
The meter shall meet the accuracy tests as stated in Sections 7.4.2 and 7.4.3 of this Appendix for watthour functions for both Quadrant 1 and 2. For auxiliary metered Loads, only the Quadrant 1 watthour function need be tested.
Upon request, the Transmission Owner(s), Transmission Customer(s) and Transmission Provider shall be provided with a copy of all of the equipment owner’s documentation for the specific location.
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7.12
Node Loss Compensation
7.12.1
General
M
NODE & Meter Settlement Location
M
NODE & Meter Settlement Location
M
A2 A1
NODE & Meter Settlement Location
A3 Transmission Owner Network
Transmission Owner Network
Transmission Owner Network
M
An Transmission Owner Network
SPP Transmission System A1 = Generation Injection Value A2…An = Generation Injection Value with Node Loss Compensation.
Node Loss Compensation is a combination of any or all of the following to the Generation Node Point. (1)
Transformer No Load Loss;
(2)
Transformer Full Load Losses;
(3)
Distribution Losses;
(4)
Transmission losses other than SPP Transmission System losses.
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SPP Transmission System Transmission Owner Network
L1 M
Transmission Owner Network
L2 NODE & Meter Settlement Location
Transmission Owner Network
L3
Y1 NODE & Meter Settlement Location
Transmission Owner Network
Ln Yn
Y2
M
NODE & Meter Settlement Location
M
M
L1...Ln = Load Withdrawal Value Y1..Yn = Load Withdrawal Node Value with Node Loss Compensation.
Node Loss Compensation is a combination of any or all of the following to the load Node Point. (1)
Transformer No Load Loss;
(2)
Transformer Full Load Losses;
(3)
Distribution Losses;
(4)
Transmission losses other than SPP Transmission System losses.
7.12.2
Methods for Compensation
7.12.2.1
Flat Percentage Adjustment
This adjustment is made on the value delivered from the Meter to an external system and not in the meter. The percentage will be an agreed upon value between the Metering Parties and applied as shown below:
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Gen _ Injection _ Node _ value meter _ value 1 adjustment _ percentage
Load _ Withdrawal _ Node _ value meter _ value 1 adjustment _ percentage 7.12.2.2
Engineered Adjustment with Assumptions
This type of adjustment is made on the meter quantities received by the external system using the formulas shown below:
Gen _ Injection _ Node _ value meter _ value 1 FLWL% NLL _ const
Load _ Withdrawal _ Node _ value meter _ value 1 FLWL% NLL _ const NLL _ const NLWLMTR 1hour
The variables that are used in these formulas shall be calculated as described in Section 7.12.3 by either an engineer or a metering professional. 7.12.2.3
Engineered Adjustment
The loss compensated Generation Injection Node value or loss compensated Load Injection Node value shall be calculated internally in the meter. This will be done using the meter manufacturer’s recommended procedures. The compensation percentages as presented in Section 7.12.3.7 shall be used in the meter. These shall be calculated as described in Section 7.12.3 by either an engineer or metering professional.
7.12.3
Node Loss Compensation Variables and Calculations
7.12.3.1
Transformer Test Data Transformer Test Information
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Units
Rating of the Transformer or the 3 Transformer Bank** (TVA)
MVA
Rated Primary Voltage (line to line)
(RPV)
kV
Rated Secondary Voltage (line to line)
(RSV)
V
No Load Watts Loss at X°C*
(NLWLT) kW
Full Load Watts Loss at X°C*
(FLWLT)
kW
Impedance at X°C*
(IZ%)
Decimal
Exciting Current at Rated Voltage and X°C*
(%I)
Decimal
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*The temperature that these values are reported must be at the same temperature base. X is usually either 75°C or 85°C. **This is the same rating at which the losses are measured. 7.12.3.2
Calculating data not supplied with Transformer Test Data
Calculate the full Load amps (FLA) at rated secondary voltage. FLA
TVA 1000 RSV 3 1000
Calculate the Full Load VAr Loss (FLVL) at rated secondary voltage.
FLWL FLVLT sin arccos [TVAx1000 xIZ %] TVA 1000 IZ % Calculate the No Load VAr Loss (FLVL) at rated secondary voltage.
NLWL NLVLT sin arccos [TVAx1000 x % I ] TVA 1000 % I 7.12.3.3
Transmission line losses
Transmission line losses are the result of series resistance, inductance, and shunt capacitance. The following items are required to calculate this value. Transmission Line Loss Components
Units
Series resistance
Ohms / mile
(rTL)
The effective series reactance The length of the line
(LTL)
(xTL)
Ohms / mile mile
Calculation of the transmission load line watts loss.#
#
The Full Load Amperage (FLA) shall be used unless the load is served using the arrangement illustrated by Y2 of Section 7.12.1. If this is the case, the maximum amperage used is the value obtained by multiplying the primary current rating of the Current Transformer by the rating factor at 25ºC of this Current Transformer.
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RSV FLA2 rTL LTL RPV 1000 FLWLTL 1000
Calculation of the transmission load line VAr loss. #
RSV FLA2 xTL LTL RPV 1000 FLVLTL 1000 Calculation of the transmission no load line watts loss. @ 2
NLWLT RPV 3 rTL LTL NLWLTL 1000 Calculation of the transmission no load line VAr loss. @ 2
NLWLT RPV 3 xTL LTL NLVLTL 1000
7.12.3.4
Secondary line losses
Secondary line losses are the result of series resistance, inductance, and shunt capacitance. The following items are required to calculate this value.
Secondary Line Loss Components
Units
Series resistance
Ohms / mile
(rSL)
The effective series reactance The length of the line
@
(LSL)
(xSL)
Ohms / mile mile
The No Load Watts Transformer Losses (NLWLT) shall be used unless the load is served using the arrangement illustrated by Y2 of Section 7.12.1. If this is the case, the No Load Watts Transformer Losses shall be multiplied by the ratio of the total yearly energy for the metering point and the total yearly energy for the transformer for the previous year.
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7.13
Record Retention
The Market Participant must maintain sufficient documentation of the meter process and values in order to verify the integrity and accuracy of the reported data. This documentation shall include but is not limited to the following: (1)
Loss percentages as agreed to by Metering Parties for each meter;
(2)
Compensation methodology;
(3)
SPP Transmission Tariff Facilities (Node) values;
(4)
Meter testing documents;
(5)
Meter and supporting equipment change history [to the extent that change history includes sufficient documentation of the modification, the obsolete substation/plant drawings are not required].
The records must be retained for a period of six (6) years.
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Appendix D - Settlement Metering Data Management Protocols
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1.
Scope
This document will serve as a definitive resource concerning the expected responsibilities, duties, standards, processes, and liabilities with regard to the Market Participants for the SPP Integrated Marketplace settlement meter data.
2.
Purpose
This document will provide the standards by which the Meter Agent, on behalf of the Market Participants, consistent with other sections of the Market Protocols and the Open Access Transmission Tariff of SPP will collect, calculate, document, and report settlement meter data for the SPP Integrated Marketplace.
3.
Definitions
The terms used in this document are defined in Section 1 of the Market Protocols.
4.
Market Participants
This document will define what is expected of the Market Participant with regards to their Meter Data Submittal Locations.
4.1
Responsibilities
The Market Participant is responsible for the quality, accuracy and timeliness of meter data submitted to SPP for the purposes of, and use in, the execution of the SPP Integrated Marketplace settlements. At all times, SPP maintains a financial, legal and operational relationship with the Market Participant, and not the Meter Agent.
4.2
Meter Agent(s) Designation
The Market Participant must designate a Meter Agent for each of its Meter Data Submittal Location. The Market Participant will be responsible for any and all data supplied by its designated Meter Agent. The Market Participant can have more than one Meter Agent, but only one designated Meter Agent per Meter Data Submittal Location.
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SPP will at all times use the data provided by the Meter Agent until such time as the Market Participant revokes the designation of an entity as its Meter Agent and replaces that entity with a substitute entity. Any dispute between the Meter Agent and the Market Participant concerning the accuracy of values reported to SPP shall be resolved between the two parties absent the involvement of SPP.
Meter Agent
5.
The Meter Agent is expected to fulfill the Market Participant’s responsibility for submitting Meter Data Submittal Location data for which it is responsible and registered. The Meter Agent will adhere to the standards for calculating and reporting settlement data as defined in this Appendix. The Meter Agent will act on behalf of the Market Participant to provide settlement meter data to SPP, the Market Participant, and the entity responsible for Residual Load.
Data Format
6.
The settlement data must be submitted according to the following conventions.
6.1
Unit of Measure
The following rules apply to the submittal of meter data: (1)
Settlement meter data must be submitted, at a minimum, in hourly intervals;
(2)
Settlement meter data may be submitted in 5-minute intervals for Resources and/or load if this option is specified during market registration;
(3)
Megawatt-hour (MWh) is the standard unit of service measurement. Service may be measured in kilowatt-hours (kWh) if required by the specific service, local or state regulations, host utilities, service providers, or as are mutually agreed upon by the parties involved. Service information provided in kWh must be converted to MWh before submission to SPP;
(4)
Settlement Location data can be submitted in fractional MWhs; and
(5)
Hourly metered interchange between Settlement Areas must be submitted in whole MWhs.
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6.2
Sign Convention of Data
Meter Data Submittal Locations:
Net Injection into the SPP Transmission System will be negative [-].
Net Withdraws out of the SPP Transmission System will be positive [+].
Meter Data Submittal Location between Settlement Areas:
Hourly metered interchange will be reported based on the Settlement Area perspective.
Into the Settlement Area will be reported as negative [-].
Out of the Settlement Area will be reported as positive [+].
6.3
Meter Technical Standards
Any data supplied to SPP from existing metering or other equipment must comply with the meter data technical standards specified under Appendix C. The metering used for data submission must meet all SPP interconnect guidelines.
6.4
Data Submission Standards
Settlement Data must be communicated to SPP in electronic format in order to ensure timely settlement. Please refer to the Meter Data Submission Standards (Appendix B) for electronic format of submissions.
Settlement Meter Data Types
7.
There are three basic types of interval settlement data required for the SPP Integrated Marketplace. Meter Data Submittal Locations: (1)
Resources (generation)
(2)
Loads
(3)
Settlement Area Interchange: (Hourly metered interchange between Settlement Areas, and between Settlement Areas and external Balancing Authorities including pseudo-ties)
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7.1
Resource Metering
Resource data must be submitted in either 5-minute or hourly intervals as indicated during market registration and must be consistent with the Resource’s registration as described in Section 6.1.12. If a Resource is registered with the Net without Aux option selected, as described in Section 6.1.12, according to the sign convention, a negative [-] value will indicate a net injection, where a positive [+] value will indicate a net withdrawal (e.g., auxiliary Load not covered by generation gross output) for that MDSL. The “net” shall be determined by the “gross” output (reflected as a negative number) plus the unit auxiliary power (a positive value) and applicable losses (a positive value). If a Resource is registered with either the Gross option or the Net with Aux option selected, as described in Section 6.1.12, then the Resource meter value will always be negative [-] indicating an injection.
7.1.1
Joint Owned Unit (JOU) Generation
JOU Meter Data Submittal Location data reporting must be consistent with the JOU registration outlined in Section 6.1.6.
7.1.2
Generation Loss Compensation
Metering for a Resource must be loss compensated, when the meter is not at the SPP Node. Please reference to Section 9 of this Appendix for the complete loss compensation requirements.
7.2
Load Metering
7.2.1
General
Load data must be submitted in either 5-minute or hourly intervals according to the sign convention. All Loads should be reported as a positive [+] value to indicate a net withdrawal at the SPP Node.
7.2.2
Load Loss Compensation
Metering for a Load must be compensated for any distribution and transmission losses up to the point of interconnection with the SPP Transmission System (Node). Submitted meter data for Load, other than Residual Load, does not include SPP Transmission System losses. Please reference Section 7.12 of Appendix C for the complete loss compensation requirements.
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7.2.3
Residual Load
Residual Load in a Settlement Area is the sum of the hourly metered interchange adjusted for pseudo-ties out of the Settlement Area, plus the sum of all Resource Meter Data Submittal Locations less all other load Meter Data Submittal Location as reported separately under Section 7.2.2 for that Settlement Area. Residual Load is submitted by the Meter Agent representing the Market Participant responsible for Residual Load in the same manner as other Meter Data Submittal Locations for loads. SPP adjusts the submitted Residual Load for transmission system losses as described under Section 4.5.9.1.
7.3
Hourly Metered Interchange
Each Meter Agent that is responsible for the calculation of total Settlement Area load shall report hourly metered interchange between each Settlement Area and each external Balancing Authority with which its Settlement Area is interconnected and pseudo-tie out interchange associated with each Settlement Area and external Balancing Authority. If a Settlement Area interconnection point is not at the meter location, loss compensation is needed unless all Metering Parties have agreed to another method. This meter data must be submitted in hourly intervals according to the sign convention. Hourly metered interchange is reported based on the Settlement Area’s prospective. See Section 6: Data Format for sign convention. The hourly metered interchange is needed for the calibration function of settlements (See Section 4.5.9.1 for a description of the calibration calculation).
SPP Settlement Area C SPP Settlement Area A SPP Settlement Area D
Non-SPP Control Area 1 SPP Settlement Area B
Sum of all Points of Interconnection between Settlement A and all other Settlement/Control Areas
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7.3.1
Substitution for Missing Data
In the event that a Meter Agent fails to submit Settlement Area hourly metered interchange data or pseudo-tie interchange data, SPP will initially use the value calculated by the State Estimator until the actual value is submitted prior to final settlement.
8.
Settlement Location Anatomy
8.1
General
These sections describe standards for providing meter data under the following conditions: (1)
The actual meter location can be on a distribution voltage system or transmission voltage system.
(2)
The physical meter is not at the defined Meter Location.
(3)
Aggregation of multiple Meter Settlement Locations for reporting a Meter Data Submittal Locations.
(4)
Each physical meter value will need to have applicable losses applied to the meter data to determine Meter Settlement Location. The applicable losses only include losses up to a single SPP Meter Settlement Location.
(5)
A Node will be at the point of interchange with the facilities under the SPP Transmission Tariff.
(6)
A Meter Data Submittal Location includes one or more Meter Settlement Locations. A Settlement Location includes one or more Meter Data Submittal Locations which may be located in multiple Settlement Areas. A Settlement Area includes one or more Meter Data Submittal Location(s). Meter Data Submittal Location(s) meter data is a component of the settlement billing process.
(7)
Meter Data Submittal Location meter data reported is effectively at a Resource bus (including transmission losses).
8.2
Making of a Settlement Location
A Settlement Location is made up of one or more Meter Data Submittal Locations. A Meter Data Submittal Location is made up of one or more Meter Settlement Locations. A Meter Settlement Location is made of only one Node. A Node is made up of only one meter. A Meter
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Settlement Location is simply a single meter compensated for losses, if applicable. compensation methods will be addressed later in this document.
8.2.1
Loss
Resource and Load Settlement Locations
The diagrams in Section 7.12.1 of Appendix C provide one-line views of the build up to a Resource or load Meter Settlement Location. The following diagram illustrates the components of the Settlement Location for either a Resource or load. Each component is manipulated to achieve the next value. It is very important that each step of this methodology is completed in order in your calculations.
Meter A
Meter B
Meter n
Actual Load or Resource meter interval data Increase (load) or decrease (generation) for losses as needed to represent the point of interface with the SPP Transmission System and should coorespond to a pricing point (LMP)
SPP node
SPP node
SPP node
SPP Transmission System Point of Interchange SPP Market pricing point (LMP)
Meter Settlement Location (MSL) A
Meter Settlement Location (MSL) B
Meter Settlement Location (MSL) n
MSL represents the settlement value for a single meter in the SPP Market
Meter Data Submittal Location (MDSL)
Meter Data Submittal Location (MDSL)
The sum of one or many MSLs that will be reported for a single MDSL. If Truncate and Carry is required apply after aggregation and before submittal at the MDSL Settlement Location is the point of entry for Market Settlement charge type calculations, based on whole or fractional MWhs. Aggregation of multiple MDSLs to a single SL occurs within SPP systems.
Settlement Location (SL)
Note that generators may only be aggregated within a single substation voltage level
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8.2.2
Overview of Settlement Area Load Settlement Locations
Multiple Meter Agents may use a single Meter Settlement Location as part of their calculations of a Settlement Location. This requires coordination and method agreement between all Metering Parties and Market Participants involved in that joint Meter Settlement Location. The following diagram illustrates all Load Settlement Locations within a Settlement Area. Load D is the Residual Load. Table 1 – Load Inclusion and Coordination
3 F
Load D (Residual)
Load B
B
1
4
C
A
Load A
E D
Load C 2
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Load A
B C D
Actual Meters 4
2 2 8
Residual
Meters included in Coordination on Methods used with all entities Settlement Location for Load x for meter x A, B, C, D Load B Meter C Load C
Meter D
Load D
Meter A and B
Load A
Meter C
Load D
Meter F
Load A
Meter D
Load D
Meter E
A, B, E, F,
Load A
Meter A and B
1, 2, 3, 4
Load B
Meter F
Load C
Meter E
Others
Meters 1, 2, 3, 4
C, F D, E
Load
Others: defined as another Load Settlement Location and seam with another RTO/ISO Settlement Area Boundary would be equal to the sum of meters 1, 2, 3, and 4.
9.
Loss Compensation
9.1
General
The Meter Agent will submit Meter Data Submittal Location data for Resources and Loads with the applicable compensations for the applicable Meter Settlement Location. Load Meter Settlement Locations may have line losses, transformer step-downs, shared metering, etc. Resource Meter Settlement Locations may have transformer losses, auxiliary Loads, shared metering between units, commercial Load off generation bus, etc. These sections cannot cover all possible situations; therefore, fair business practices with the Metering Parties will hold as the common sense rule. The Market Participants along with their Meter Agent will be responsible for appropriate meter data adjustments and submissions. Loss Compensation methods are described under Section 7.12 of Appendix C.
9.2
Loss Compensation Examples
There are several elements that can require loss compensation prior to the Meter Settlement Location. A couple of examples of this are: 1) Meter is located on the distribution system and
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needs to be adjusted to the Node and 2) Meter is located on the transmission system not at the Node and needs to be adjusted to the Node. Formula for calculation of Meter Settlement Location will be taking known actual meter value divided by (1- Loss %). This formula will be used for all calculations of the Meter Settlement Location. Actual meter value divided by (1-Loss %).
9.2.1
Loss Compensation to Node when Meter is on Distribution System
SPP Meter
Load
Node
12kV 69-12kV Transformer
69kV*
Losses across Transformer = 5%
Loss Compensation to Node – Example 1 Assumptions: (1)
Meter is on distribution system @ 12 kV
(2)
Transformer between distribution and transmission system requires compensation for a transmission voltage at SPP Node.
(3)
Actual meter reads 20000 kWh.
(4)
Transformer loss is 5%.
(5)
Transmission owner has modeled their network with transmission voltage at 69kV.
Calculating from Meter to Node: (1)
Actual meter reads 20000 kWh divided by (1- 5%). 20000/(1–0.05) or 20000/0.9500
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(2)
SPP Node Value = 21052.631 kWh
(3)
All resolution below kWh of 21052 is dropped
(4)
This rule can be applied when distribution line losses are required along with transformer losses.
(5)
The Market Participant can apply the compensation process separately for each loss percentage or sum percentages together and then apply the process for the sum of losses to calculate the Node value.
Calculating Aggregation of Meter Settlement Locations to report Meter Data Submittal Location (1)
A Meter Agent can combine two or more Meter Settlement Locations for Loads within a Settlement Area to report the registered Meter Data Submittal Location.
(2)
A Meter Agent may combine two or more Meter Settlement Locations to report a Resource Meter Data Submittal Location as long as all the combined Meter Settlement Locations are electrically equivalent.
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9.2.2
Loss Compensation to Node when Meter and Node at Different Location
SPP Node
Meter
Load
69kV* Line Losses of 2%
Loss Compensation to Node – Example 2 Assumptions: (1)
Meter is on transmission system @ 69kV
(2)
The Node is not at the same location as the meter. (i.e. losses on line between meter and Node will be applied to provide the correct value at the Node)
(3)
Actual meter reads 20000 kWh.
(4)
Line losses between meter and SPP Node is 2%
(5)
This 69kV line starting at the Node is under the SPP Transmission Tariff.
Calculating from the Meter to the SPP Node value: (1)
Actual meter reads 20000 kWh divided by (1- 2%)
(2)
20000 / (1 – 0.02) or 20000 / 0.9800
(3)
SPP Node value = 20408.163 kWh
(4)
All resolution below kWh of 20408 is dropped
Calculating Aggregation of Meter Settlement Locations to report Meter Data Submittal Location (1)
A Meter Agent can combine two or more Meter Settlement Locations for Loads within a Settlement Area to report the registered Meter Data Submittal Location.
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(2)
A Meter Agent may combine two or more Meter Settlement Locations to report a Resource Meter Data Submittal Location as long as all the combined Meter Settlement Locations are electrically equivalent.
9.3
Meter Data Exchange and Submission
Settlement Location meter data shall be entered, modified and retrieved solely via the XML specification for submission of interval Settlement Data. The Settlement Location meter data will be available via the Portal and include the files uploaded from the Meter Agent. There will also be the capability of reviewing any rejected values with the specific errors associated with the attempt to process the rejected values. Values successfully processed shall also be available via the Portal for that Market Participant. Other parties may have access to Settlement Location data, as allowed by SPP.
9.3.1
Actual Meter Data (Idata)
If a meter is installed to include interval data capabilities, then the Meter Agent will always report this meter as Interval Data. There are three types of Interval Meter Data to be submitted as Channel 1 as outlined in the XML Data Submission Standards. (1)
(2)
Actual (A) - Actual meter interval data: (a)
This data is reported as (A)ctual;
(b)
There are three types of actual meter interval data: Telemetered pulses/register, Interval Data Recorder (IDR) data, and analog MW integrations (MWI);
(c)
Loss Compensation applies for all types of Actual meter interval data.
Estimated (E) - Estimated meter interval data: (a)
If actual meter interval data becomes unavailable, it is appropriate to estimate that data. This data is reported as (E)stimated;
(b)
See Section 11.2 for data estimation options;
(c)
Estimated data can be short-term or long-term; (i)
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actual data is obtained, it should be resubmitted as (A)ctual data, not (E)stimated. (ii)
(d) (3)
Long-term data would be a permanent estimate. This would include situations where the data cannot be obtained or retrieved and an estimate is the only option. In these cases, the data would remain as (E)stimated Data throughout all Settlement Statements.
Loss Compensation applies to all types of estimated meter interval data.
Missing (9) - Missing meter interval data: (a)
9.3.2
Do not use this type. If data is missing, estimate the data and submit as “E”.
Alternate Settlement Meter Data
Under circumstances where one or more Meter Agents fails to submit Settlement Location meter data in accordance with the timelines set forth for Settlement Statements, SPP will substitute missing Settlement Location meter data with the State Estimator data for that Settlement Location until Settlement Location meter data is provided. SPP will notify all MPs and Meter Agents when a Meter Agent fails to submit Settlement Location meter data. Refer to Market Protocols Section 4.5.9.1 for treatment of substitution data for calibration purposes.
Data Source and Estimating
10.
Primary source meter data must be used to calculate Settlement Locations, unless it becomes unavailable. When the primary data source is not available, use the following steps: (1)
Use another primary data meter source to replace the typically used primary data source,
(2)
Use a backup data source,
(3)
Use a meter data estimating option.
10.1
Actual Meter Data (Idata – Actual)
Actual data is sourced from the meter or electrical device(s) in the field. Actual data is reported to SPP as Idata “A”, see Section 9.4.1(1).
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10.1.1
Primary Data Sources
There are two primary sources for meter data: 1) Telemetered pulses/register and 2) Interval Data Recorder (IDR) Data. Telemetered pulses/register can be used as a primary data source, as long as a verification of that data is performed against the Meter (register or IDR). If the verification indicates any material differences, resubmission of the Settlement Location using the corrected data must be completed. If the Market Participant’s primary data source becomes unavailable, it is acceptable to use the other type primary source to replace the data. (Example: Market Participant typically uses telemetered pulses as primary data source, and then IDR data could be used when telemetered pulses are unavailable.)
10.1.2
Backup Data Sources
If backup data sources are available, they must be used when primary data sources are unavailable. These are reported as Idata “A”. Examples of Backup Data Sources are: MWI – Analog MW integration data: MWI is derived from a calculation of retrieved instantaneous (i.e. analog) data signals over an hour then integrated to an hourly value. Backup metering: If backup metering exists, they can also be used to replace the primary sources when they are not available.
10.2
Estimated Meter Data (Idata – Estimated)
10.2.1
Estimation Methods
The Market Participant must use one of the following methods to estimate missing Actual Idata when the actual meter data source values are not available. Estimated meter data is reported as Idata “E”. “E” for Estimated, reference Section 9.4.1(2). The following methods are in priority preference order for estimating missing actual meter data. The estimated meter value determined by this process below will be utilized by all parties to the meter for Settlement Location calculations. If the first option is not available, move to the next option until a data method is available for the use in estimating meter data: (1)
Existing Contracts or Operating Guidelines: If there is an existing contract or operating guidelines established for the interconnection location, those should be used.
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(2)
Alternative Metered Load(s) Integrated: If there are other load(s) and/or generator(s) that can be used to determine the interval value for the missing meter data, they can be integrated and used as estimates for the missing interval meter data.
(3)
State Estimator Integrated Data: If this data is available, it should be used for estimating the meter data.
(4)
Other: Data Shaping and Similar Hour (a)
Data Shaping: This method uses data from previous and/or subsequent hours around the missing data to estimate the use during the missing hours.
(b)
Similar Hour: This method uses data from a similar day to estimate the missing data. A Similar day can include one or more of these parameters: comparing temperatures, day of week (weekend, weekday, holiday considerations), and/or usage profile (knowledge of customer’s load and generator at time of missing data, such as behind the load meter generator on line, load switched to another circuit, etc.).
10.2.2
Replacing Estimated Meter Data
Resubmission of a Settlement Location value that used estimated meter data must be done once more accurate or actual interval data becomes available. If the actual interval data does not become available, the Settlement Location value will remain submitted as Estimated “E”.
11.
Verification Meter SL Values
Verification of meter data used as a component of Settlement Location value calculations shall be performed. Verification of meter data would be performed by the party responsible for the operations of that meter. The Market Participant needs to confirm that the verification process is conducted for all meters that they use in calculation of Settlement Location values. Verification can be done in various ways. Methods of verification are based on the type of data and communication technology used.
11.1
Data Types and Verification Methods
The listing that follows is not complete, but represents the majority of types with verification method.
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11.1.1
Telemetered Pulses via Remote Terminal Unit (RTU)
If the data used to calculate the Settlement Location value is obtained from Telemetered Pulse values which are transferred to a data collection system, then verification shall be performed against the meter Interval Data Recorder (IDR) values or meter’s register. If there is an IDR installed, then the telemetered data needs to be verified against the IDR’s data for the time period. If there is no IDR available, the meter register will be the verification source. The verification procedure would require a start reading and a stop reading of the register for the same period that the telemetered data was collected. The difference in meter reads would be compared to the total usage determined from the telemetered data. The meter read can be obtained remotely or at the meter location as the meter technology dictates.
11.1.2
Register Transfer via Other Communication Options
If the data used to calculate the Settlement Location values is using register values electronically transfer to an EMS, the meter register will be the verification source. The verification procedure would require a start reading and a stop reading of the register for the same period that the remote read was obtained. The difference in the meter reads would be compared to the total usage determined from the EMS meter reads. The meter read can be obtained remotely using a different communication path or at the meter location as the meter technology dictates.
11.1.3
Interval Data Recorder Collection System (IDRCS)
If the data used to calculate Settlement Location values is interval data from an IDRCS, then the meter register will be the verification source. The verification procedure would require a start reading and a stop reading of the register for the same period that the IDRCS read was obtained. The difference in the meter reads would be compared to the total usage determined from the IDRSC meter reads. The meter read can be obtained remotely or at the meter location as the meter technology dictates.
11.1.4
Inter Control Center Protocol (ICCP) Data
ICCP as specified in IEC Standard 870-6 is a protocol that enables the communication of interchange data over wide area networks (WAN) between a number of utilities and control center computer servers used to tabulate interchange data. This communication method can fail just like RTU data, Register Transfer, etc.
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The source of the ICCP would be one of the types listed above and the source would be responsible for the verification. Any new ICCP link or changes to an ICCP link must be requested as described in Appendix E. If the data is for Balancing Authority Ties, then the hourly checkout of the tie values between the Balancing Authorities would be sufficient verification for the receiving party of the data via this communication method. The Market Participant needs to confirm with the source of the meter data that one of the verification methods has been performed for any meter data they use from that source.
11.1.5
Alternate Data for Verification
Integrated Analog values that meet the accuracy and location requirements of Appendix D can also be used to confirm the quality of the data used. This is secondary verification option after the above listed.
11.2
Periodicity of Verification
11.2.1
Telemetered Pulses via Remote Terminal Unit (RTU)
Verification of telemetered meter data values shall be performed monthly.
11.2.2
Other Data Transfers
The register transfers and/or IDRCS type data is an interrogation of the meter’s register microprocessor. The data captured shall include register and interval data. Verification of this data should be performed monthly, due to the impacts to the Market Settlements.
11.3
Verification Uncovers Discrepancy
After the verification process is completed and a discrepancy is revealed, the verifier needs to determine the cause of the discrepancy, i.e. meter data, telemetered data, MV90 type data, etc.
11.3.1
Identify the Cause for the Discrepancy
Identification of the cause is critical in understanding what solution is needed to correct the data. All data sources can be incorrect due to data transfer issues and other equipment/software issues. Therefore, one source is not superior to another.
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11.3.2
Impact to Settlement Location Values Submitted
Once you have identified the cause, a decision needs to be made if a change is needed to the Settlement Location values already provided to SPP. 11.3.2.1
Settlement Data Values Correct
If the meter data source used to calculate the Settlement Location value reported is correct then there is no need to resubmit corrected data to SPP. 11.3.2.2
Settlement Data Values Incorrect
If the cause impacts the meter data source used to calculate the Settlement Location values, then editing the data is required and resubmission of the meter data will be required based on the following criteria. 11.3.2.2.1 Requirement for Resubmission If the Settlement Location value difference is greater than 100 MWhs over a verification period, then the Settlement Location values must be corrected. See Section 13: Settlement Location Value Corrections. 11.3.2.2.2 Good Utility Business Practices/Contractual Requirements If the error value is not greater than 100 MWhs over a verification period, then the verifier needs to consider other impacts. Many meters locations have interconnection agreements that outline when a correction of data is required. Therefore, the verifier needs to consider the need to update the Settlement Location data on those agreements and also consider the use of Good Utility Practices in their decision making. If it is determined that correction to the submitted Settlement Location values is required, then the resubmission need to follow the procedure in Section 13: Settlement Location Value Corrections.
Real Time Data Reporting to SPP Balancing Authority
12.
In addition to the data reporting requirements specified under SPP Criteria 7, all Resources, other than Demand Response Resources, are to submit the following data via ICCP to SPP. (1)
Unit power output (MW);
(2)
Unit MVar output;
(3)
Current on/off line status;
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(4)
Current AGC status (on/off).
Additionally, Resources that are registered under the combined cycle Resource configuration option in Section 4.2.2.5.3 (4) are required to submit the following information via ICCP to SPP: (1)
Unit power output for each physical individual component (with the exception of nontelemeterable pieces such as duct burners); (1)(2) The current configuration; (2)(3) Transition state status (in transition or not in transition).
13.
Record Retention
In addition to the record retention requirements listed under Section 7.13 of Appendix C, the Market Participant must maintain the following additional documentation of the meter process and values in order to verify the integrity and accuracy of the reported data. (1) Raw Meter values; (2) Truncate and Carry Process and Results; (3) Meter Settlement Location values; (4) Settlement Location values. The records must be retained for a period of six (6) years.
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Appendix E - Network and Commercial Model Update Timing Anticipated types of SPP System Changes with Typical Durations for Related Updates
*General Notes 1. The "Update Duration" starts when the completed Registration Package and all required technical information is received by SPP and ends when the change is fully implemented in all affected Model s, systems, and/or databases such that the change is effective in the Production (PROD) environment. 2. SPP will work to implement each Model Update as soon as possible and insure the updates are implemented in a period that is no later/longer than the applicable indicated update duration, unless otherwise noted. 3. SPP will inform MPs of the applicable scheduled periodic Model Update in which their requested model changes will be implemented and also the deadline for providing SPP with completed Registration Packages and required technical information for all requested changes in order for the changes to be included in the specific scheduled Model Update. st
4. Model changes will be effective on the 1 of the applicable month. The changes will be available at least seven (7) days prior to the effective date to allow participants to submit necessary mark et data as applicable in preparation for the effective date. 5. The “TCR Update Duration” starts when either the final approved reliability change or Market change becomes effective in the Reliability and Commercial Production Models and ends when the change is fully implemented and effective in all affected TCR PROD Models, systems, and/or databases such that the change is effective in the applicable monthly or annual TCR Auction. 6. Dates given for the TCR Update Duration are for day-ahead (Marketplace) data updates. Due to the commercial model update being bi-monthly and the TCR updates being monthly, the model update requests and related information for updates to be included in the monthly TCR Auction (optional) must be provided from at least 75 to 105 days prior to the requested Effective Date of the pertinent monthly TCR Auction in PROD. Model update requests and related information for the annual TCR Auction (optional) must be received at least 120 to 165 days prior to the applicable June 1st Effec tive Date of the annual TCR Auction in PROD. (Note "Reliability only” changes may be implemented and become effective in the TCR Auction in as soon as 45 days.)
System Update Type (Business Event) New Market Registration Transmission Customer
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* Update Duration
45 Days/ 2 months
* Comments
OASIS Change only if TC not a Market Participant. Access to OASIS is part of Process for Becoming a TC.
12/4/2014
*TCR Update Duration
Monthly Auction 30 - 45 Days / Annual Auction 75 – 105 days
* Comments
Monthly Auction - 30 to 45 days (TC not a MP); Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing
791
Market Protocols for SPP Integrated Marketplace
changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Market Participant
Register a New Market Participant with no physical assets (Financial Only)
Designated Agent
6 Months
A minimum of 6 Months for this addition, which is presumed to include adding all associated assets. (Especially if addition involves changes to Market Boundary.) Include in Applicable scheduled periodic Model Update.
4 Months
New MPs with no physical assets (Financial Only) A minimum of 4 Months for this addition, Include in applicable scheduled periodic Model Update
45 days / 4 Months
45 days if DA is current SPP TC. 4 months if a new DA that is not currently a SPP TC or MP.
1 Month
A minimum of 7 Months, which includes 6 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
N/A
N/A
30 to 45 Days/1 month / 75 to 105 days
Monthly Auction - 30 to 45 days (DA is current TC) / 1 month (DA is new TC or MP); Annual Auction - 75 to 105 days prior to June 1st (DA is new or existing TC or MP). The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Asset Owner Information
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Market Protocols for SPP Integrated Marketplace
Asset Owner Company
4 Months / 6 Months
Meter Agent (MA)
45 days / 4 Months
4 Months for this addition. (This for an addition to a current MP). 6 Months if ICCP connection is needed specifically for new AO. Include in Applicable scheduled periodic Model Update. A new Asset Owner under a new MP would follow the new MP duration of 6 months.
45 days if MA is current SPP TC. 4 months if a new MA that is not currently a SPP TC or MP.
1 Months / 1 Months (If applicable)
A minimum of 5 Months for an addition to existing MP, which includes 4 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. A minimum of 7 Months for the addition of a new AO to a new MP or if new ICCP connection is needed also includes 1 months to implement and publish applicable TCR changes. These changes will be included in the applicable Monthly and Annual Auctions,
N/A
N/A
30 - 45 Days/ 1 months / 75 – 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105
(Same as note above.)
Asset Information
Settlement Location
45 Days / 4 months
Plant
45 Days / 4 months
Unit
45 Days / 4 months
Version 23.a
45 Days for limited scope additions. 4 Months for Moderate to large scope additions. (This for an addition to a current MP.) (Include in applicable periodic Update)
(Same as note above.)
(Same as note above.)
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Market Protocols for SPP Integrated Marketplace
days Load
45 Days / 4 months
Load Pricing Zones
45 Days / 4 months
Settlement Area
4 Months / 6 Months
EIR Source (Via Trans Table)
2 weeks / ( 45 days if have associated TCR/ARR)
EIR Sink (Via Trans Table)
2 weeks / ( 45 days if have associated TCR/ARR)
External Dynamic Resource (EDR)
4 Months / 6 Months
Version 23.a
(Same as note above.)
(Same as note above.)
4 months if SA is in SPP BA. 6 months if a SA is a new SA not previously in SPP.
Include in scheduled and coordinated rolling type updates. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
(Same as note above.)
12/4/2014
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
1 Month / 1 Month
A minimum of 5 Months (SA in SPP BA) or 7 Months (SA new to SPP BA), which includes 4 months (SA in SPP BA) or 6 months (SA new to SPP BA), for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
(Same as note above.)
1 Month / 1 Month
A minimum of 5 Months (current MP) or 7 Months (new MP), which includes 4 months (current MP) or 6
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Market Protocols for SPP Integrated Marketplace
months (new MP),for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
4 Months if change involves current MP. 6 Months (minimum) if change involves a new Market Participant.
Market Registration Changes Contact Information Changes Market Footprint Changes
Move Footprint SA to 1st Tier
Move 1st Tier BA to Footprint
Version 23.a
2 weeks
6 Months
6 Months
Updated commercial model information is forwarded to billing and credit.
Implement in applicable scheduled seasonal/periodic update.
Implement in applicable scheduled seasonal/periodic update.
12/4/2014
N/A
N/A
1 Month
A minimum of 7 Months, which includes 6 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
1 Month
A minimum of 7 Months, which includes 6 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR
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Market Protocols for SPP Integrated Marketplace
related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions, Name Changes
Transmission Customer (Long Name)
Transmission Customer (EIR ID)
Market Participant or Asset Owner
Change registration data for a Market Participant with no physical assets (Financial Only)
Version 23.a
45 Days
Name change only - TC must submit new service agreements in new name. (Process should be shortened and improved for this task.)
30 - 45 Days / 75 – 105 days
45 Days
(Same as note above.)
30 - 45 Days / 75 -105 days
4 Months / 6 Months
45 Days
4 Months for typical scope changes. 6 Months (minimum) if involves changes to Market Boundary and/or changes to all associated assets.
Implement in applicable periodic update.
12/4/2014
1 Month / 1 Month
N/A
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates. (Same as note above.)
A minimum of 5 Months (typical scope) or 7 Months (large scope), which includes 4 months (typical scope) or 6 months (large scope),for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
N/A
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Market Protocols for SPP Integrated Marketplace
Market Participant with no physical assets (financial only) becoming an Asset Owning Market Participant
Designated Agent
4 Months / 6 Months
45 Days
4 Months for typical scope changes. 6 Months if establishing new ICCP connectivity and other technical issues are involved.
45 Days - DA change of responsibility for MP's Assets. (DA is a SPP TC.)
1 Month / 1 Month
A minimum of 5 Months (typical scope) or 7 Months (large scope), which includes the 4 to 6 Months for the additions of all associated assets in the applicable scheduled periodic Market Model Update and one month after for implementing and publishing applicable TCR related changes via scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions.
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days (DA is a SPP TC); Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
1 Month
A minimum of 5 Months, which includes 4 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
N/A
N/A
Asset Owner Changes
Asset Owner Company
4 Months / 6 Months
4 Months for typical scope changes. 6 Months if establishing new ICCP connectivity and other technical issues are involved. Implement in applicable periodic update.
Meter Agent
4 Months
Implement in applicable
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Market Protocols for SPP Integrated Marketplace
periodic update.
(MA) Asset Information Changes
30 - 45 Days/ 1 month / 75 - 105 days
Monthly Auction - 30 to 45 days (limited scope) / 5 months (moderate to large scope); Annual Auction 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
(Same as note above.)
30 - 45 Days/ 1 month / 75 - 105 days
(Same as note above.)
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 -105 days
(Same as note above.)
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 -105 days
(Same as note above.)
45 Days / 4 months
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. Note: A settlement location with a TCR/ARR cannot be modified or terminated until the TCR/ARR expires.
Plant
45 Days / 4 months
Unit
Load
Settlement Location
Load Pricing Zones
Settlement Area
Version 23.a
4 Months / 6 Months
4 Months for limited scope changes. 6 Months for Moderate to large scope changes.
12/4/2014
1 Month / 1 Month
A minimum of 5 Months (limited scope) or 7 Months (large scope), which includes 4 months (limited scope) or 6 months (large scope),for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in
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Market Protocols for SPP Integrated Marketplace
the applicable Monthly and Annual Auctions,
External Dynamic Resources (EDR)
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
4 months
4 Months to complete MP/AO relationship scope changes. (Typically this change would occur when an MP to AO change occurs; i.e. moving AO from one MP to another MP.)
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
45 Days / 4 months
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Very rare change, this should only occur if a Settlement Area change takes place.)
N/A
N/A
45 Days / 4 months
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Involves existing MP.)
Commercial Model Relationship Changes
Market Participant / Asset Owner
Meter Data Submittal Location / Settlement Area
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Meter Data Submittal Location / Meter Agent
Settlement Area / Meter Agent
EIR Source/Sink / Settlement Location
45 Days / 4 months
45 Days / 4 months
On the fly 1 week at most. Due to scheduling, MP needs to be notified when active.
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Must register Meter Agent if relationship change is not to existing Meter Agent.)
(Same as note above.)
Changes will occur “as needed” when updating registry information to SPP systems.
N/A
N/A
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate large scope); Annual Auction 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days / 75 – 105 days (If applicable)
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
De-aggregating a Plant to Individual Units
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Aggregating Individual Units
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75
Version 23.a
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Market Protocols for SPP Integrated Marketplace
to a Plant
Breaking out an Individual Unit from a Plant
IDC Mapping Changes
EIR Source/Sink Mapping Changes
Version 23.a
to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
45 Days
Implement in applicable periodic update.
45 Days
Changes are incorporated during periodic Model Updates. IDC data updated on monthly and Semi-annual bases -- Monthly changes accumulate for the month and are implemented one day per month (includes time to remap units to Market Systems). Semi-annual changes accumulate over six months and are implemented over four days twice a year. (June 1st and October 1st are the update times)
2 weeks / (45 days if have associated TCR/ARR)
Include in scheduled and coordinated rolling type updates. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
12/4/2014
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
N/A
N/A
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled
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Market Protocols for SPP Integrated Marketplace
Model updates.
DNR Designation Changes
Certification Changes
Resource Reasonable Limit MW Value Changes
Load Pricing Zone Changes
Version 23.a
2 weeks / (45 days if have associated TCR/ARR)
(Same as note above.)
45 Days
Implement in applicable periodic update.
1 Week
This change will impact various models. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
45 Days
Implement in applicable periodic update.
12/4/2014
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 to 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
N/A
N/A
30 - 45 Days / 75 - 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
802
Market Protocols for SPP Integrated Marketplace
Individual Loads to Load Aggregate Changes
45 Days / 4 months
45 Days for intra-CA/SA changes. 4 Months for Changes involving 2 or more CAs/SAs
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (Intra SA); / 1 month (2 or more SAs); Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (TC not a MP) / 1 month (TC is current MP with outstanding requests); Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
1 Month
A minimum of 5 Months, which includes 4 months for the termination of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
Market Termination Request
Transmission Customer
Market Participant
Version 23.a
1 Week (Minimum) / 4 Months
4 months
1 week for OASIS Change only if TC not a Market Participant. 4 Months if TC is MP (TC may have outstanding requests, cannot terminate until end of contract.)
Implement in applicable periodic update.
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Market Protocols for SPP Integrated Marketplace
Market Participant with no physical assets (Financial Only)
Designated Agent
45 Days
45 Days
Implement in applicable periodic update.
45 Days - DA change of responsibility for MP's Assets. (DA is a SPP TC.)
N/A
N/A
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Asset Owner
Asset Owner Company
Meter Agent (MA) Asset Information
Settlement Location
Version 23.a
4 months
Implement in applicable periodic update.
1 Month
A minimum of 5 Months, which includes 4 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
4 months
Implement in applicable periodic update.
N/A
N/A
30 - 45 Days/ 1 month / 75 - 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and
45 Days / 4 months
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Include in applicable periodic Update) Note: A settlement location with a TCR/ARR cannot be modified or terminated until
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Market Protocols for SPP Integrated Marketplace
the TCR/ARR expires.
publishing these changes in the TCR Models during the applicable scheduled Model updates.
Plant
45 Days / 4 months
(Same as note above.)
30 - 45 Days / 1 month / 75 - 105 days
(Same as note above.)
Unit
45 Days / 4 months
(Same as note above.)
30 - 45 Days / 1 month / 75 - 105 days
(Same as note above.)
45 Days / 4 months
(Same as note above.)
30 - 45 Days / 1 month / 75 - 105 days
(Same as note above.)
Load Pricing Zone Settlement Area
1st Tier CA/External Aggregate
4 months
45 Days / 4 months
EIR Source (via Translation Table)
2 Weeks / (45 days if have associated TCR/ARR)
EIR Sink (via Translation Table)
2 Weeks / (45 days if have associated TCR/ARR
Version 23.a
Implement in applicable periodic update.
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Include in applicable periodic Update)
Include in scheduled and coordinated rolling type updates. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
(Same as note above.)
12/4/2014
N/A
30 - 45 Days / 1 month / 75 – 105 days
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
N/A Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates. Monthly Auction - 30 to 45 days, Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
(Same as note above.)
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Market Protocols for SPP Integrated Marketplace
Add EMS NETMOM/ GENMOM/ SCADAMO M Equipment In Market Footprint
Asset Owner Company
4 months / 6 Months
4 Months for limited scope changes. 6 Months for Moderate to large scope changes. This change will also impact commercial reliability and other models. (Include in applicable periodic Update)
1 Month / 1 Month
A minimum of 5 Months (limited scope) or 7 Months (large scope), which includes 4 months (limited scope) or 6 months (large scope),for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
Units
45 Days / 4 months
(Same as note above.)
30 - 45 Days / 1 month / 75 - 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Loads
45 Days / 4 months
(Same as note above.)
30 - 45 Days / 1 month / 75 - 105 days
(Same as note above.)
Other Equipment ND, LD, LN,
45 Days / 4 months
30 - 45 Days / 1 month / 75 – 105 days
(Same as note above.)
Version 23.a
(Same as note above.)
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Market Protocols for SPP Integrated Marketplace
CAP, XFMR, ZBR, DCLN, CB, DSC, LS
Outside of Market Footprint
45 Days / 4 months
(Same as note above.)
30 - 45 Days / 1 month / 75 - 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days/ 1 month / 75 -105 days
(Same as note above.)
30 - 45 Days/ 1 month / 75 -105
(Same as note above.)
Modify EMS NETMOM/ GENMOM/ SCADAMO M Equipment Changes - In Market Footprint
Asset Owner Company
45 Days / 4 months
Units
45 Days / 4 months
Loads
45 Days / 4 months
Version 23.a
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Include in periodic Update)
(Same as note above.)
(Same as note above.)
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Market Protocols for SPP Integrated Marketplace
days Other Equipment ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC, LS All Other Changes
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 - 105 days
(Same as note above.)
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 - 105 days
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 - 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Remove EMS NETMOM/ GENMOM/ SCADAMO M Equipment In Market Footprint
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Include in periodic Update)
Asset Owner Company
45 Days / 4 months
Units
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
Loads
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
45 Days / 4 months
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days
(Same as note above.)
Other Equipment ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC, LS In 1st Tier Entity
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Market Protocols for SPP Integrated Marketplace
45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Include in periodic Update)
Control Area/EMS Company
45 Days / 4 months
Loads
45 Days / 4 months
Other Equipment ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC, LS
45 Days / 4 months
(Same as note above.)
45 Days / 4 months
(Same as note above.)
Beyond 1st Tier
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days (If applicable)
Monthly Auction - 30 to 45 days (limited scope) / 1 month (moderate to large scope); Annual Auction 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
30 - 45 Days / 1 month / 75 -105 days (If applicable)
(Same as note above.)
30 - 45 Days / 1 month / 75 – 105 days (If applicable)
(Same as note above.)
30 - 45 Days / 1 month / 75 – 105 days (If applicable)
(Same as note above.)
Add EMS Contingency
Both inside and outside of Market Footprint
2 weeks / (45 days if have associated TCR/ARR)
Include in scheduled and coordinated rolling type updates. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
Monthly Auction - 30 to 45 days, Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Remove EMS Contingency
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Market Protocols for SPP Integrated Marketplace
Both inside and outside of Market Footprint
2 weeks / (45 days if have associated TCR/ARR)
Include in scheduled and coordinated rolling type updates. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
30 - 45 Days / 75 - 105 days (For TCRs/ARRs, if applicable)
Monthly Auction - 30 to 45 days, Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Add New Flowgate In SPP Region
AFC
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Coordinated
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Reciprocal
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Temporary
On the fly.
Implement this type change as needed.
N/A
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates. (Same as note above.)
(Same as note above.) N/A
In Other Regions
Coordinated
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Implement in applicable periodic update.
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30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled
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Model updates. Reciprocal
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
(Same as note above.)
Modify Flowgate Data Changes - In SPP Region Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
AFC
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Coordinated
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
(Same as note above.)
Reciprocal
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
(Same as note above.)
Temporary
On the fly.
Implement this type change as needed.
N/A
N/A
Changes - In Other Regions
Coordinated
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Reciprocal
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates. (Same as note above.)
Remove Flowgate In SPP Region
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Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
AFC
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Coordinated
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
(Same as note above.)
Reciprocal
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
(Same as note above.)
Temporary
On the fly.
(Planned Function)
N/A
N/A
In Other Regions
Coordinated
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Reciprocal
45 Days
Implement in applicable periodic update.
30 - 45 Days / 75 – 105 days
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates. (Same as note above.)
Define New ICCP Inbound
In Market Footprint
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1 Week for basic ICCP/Scada Ref. additions. 6 Months for Generation and load related changes
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30 - 45 Days/ 1 month / 75 – 105 days (If applicable)
Monthly Auction - 30 to 45 days (basic additions) / 1 month (gen and load changes); Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well
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as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates. In Reliability Area
1 Week / 6 Months
PNODE
1 Week / 6 Months
EMS Equipment or Station Name
1 Week / 6 Months
IDC Bus or Machine ID
1 Week / 6 Months
(Same as note above.)
(Same as note above.)
30 - 45 Days/ 1 month / 175 – 105 days (If applicable)
(Same as note above.)
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days (If applicable)
(Same as note above.)
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days (If applicable)
(Same as note above.)
(Same as note above.)
30 - 45 Days/ 1 month / 75 – 105 days (If applicable)
Change ICCP Inbound
1 Week for basic ICCP/Scada Ref. additions. 6 Months for Generation and load related changes.
1 Month (If applicable)
A minimum of 5 Months, which includes 4 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
In Market Footprint
1 Week / 6 Months
In Reliability Area
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
PNODE
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
EMS Equipment or Station Name
1 Week / 6 Months
1 Month (If applicable)
(Same as note above.)
(Same as note above.)
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IDC Bus or Machine ID
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
Delete ICCP Inbound points
(Typical for any type ICCP Deletion)
1 Week / 5 Weeks
The max time for deletions is five weeks unless there is no impact to any other system (local or remote). If there is no impact, the request can be completed in the next ICCP model update.
30 - 45 Days / 75 – 105 days (If applicable)
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
1 Month (If applicable)
A minimum of 5 Months, which includes 4 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
Define New ICCP Outbound points
1 Week for basic ICCP/Scada Ref. additions. 6 Months for Generation and load related changes.
In Market Footprint
1 Week / 6 Months
In Reliability Area
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
PNODE
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
EMS Equipment or Station Name
1 Week / 6 Months
1 Month (If applicable)
(Same as note above.)
(Same as note above.)
IDC Bus or Machine ID
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
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Change ICCP Outbound points A minimum of 5 Months, which includes 4 months for the addition of all associated assets in the applicable scheduled periodic Market Model Update and 1 month afterwards for implementing and publishing applicable TCR related change via the applicable scheduled TCR Model Update. These changes will be included in the applicable Monthly and Annual Auctions,
In Market Footprint
1 Week / 6 Months
1 Week for basic ICCP/Scada Ref. additions. 6 Months for Generation and load related changes.
1 Month (If applicable)
In Reliability Area
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
PNODE
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
EMS Equipment or Station Name
1 Week / 6 Months
1 Month (If applicable)
(Same as note above.)
(Same as note above.)
IDC Bus or Machine ID
1 Week / 6 Months
(Same as note above.)
1 Month (If applicable)
(Same as note above.)
Delete ICCP Outbound points
(Typical for any type ICCP Deletion)
1 Week / 5 Weeks
The max time for deletions is five weeks unless there is no impact to any other system (local or remote). If there is no impact, the request can be completed in the next ICCP model update.
30 - 45 Days / 75 – 105 days (If applicable)
Monthly Auction - 30 to 45 days; Annual Auction - 75 – 105 days prior to June 1st. The indicated durations include the time for implementing changes in the Market and/or Reliability Models as well as implementing and publishing these changes in the TCR Models during the applicable scheduled Model updates.
Add PLC Points
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In Market Footprint Plant
4 Months
Unit
4 Months
Other
4 Months
Implement in applicable periodic update. Implement in applicable periodic update. Implement in applicable periodic update.
N/A
N/A
N/A
N/A
N/A
N/A
Implement in applicable periodic update. Implement in applicable periodic update. Implement in applicable periodic update.
N/A
N/A
N/A
N/A
N/A
N/A
Implement in applicable periodic update. Implement in applicable periodic update. Implement in applicable periodic update.
N/A
N/A
N/A
N/A
N/A
N/A
Implement in applicable periodic update. Implement in applicable periodic update. Implement in applicable periodic update.
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
In Reliability Area Plant
4 Months
Unit
4 Months
Other
4 Months
Change PLC Points In Market Footprint Plant
4 Months
Unit
4 Months
Other
4 Months
In Reliability Area Plant
4 Months
Unit
4 Months
Other
4 Months
IDC Model Change
IDC Bus Name or Machine ID Change
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Changes are incorporated during periodic Model Updates. IDC data updated on monthly and Semi-annual bases -- Monthly changes accumulate for the month and are implemented one day per month (includes time to remap units to Market Systems). Semi-annual changes accumulate over six months and are implemented over four days twice a year. (June 1st and October 1st are the update times)
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RSS
Add New Resources Change Resource Information Delete Resource Information
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Change to RSS Model only. (This type change may need to be implemented prior to the next scheduled periodic Model Update.)
1 Week
(Same as note above.)
1 Week
(Same as note above.)
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N/A
N/A
N/A
N/A
N/A
N/A
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Appendix F - Settlement Examples SPP Staff will be revising Settlement examples to match revised calculations. Examples will be included in Appendix F again once they are updated.
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1.
Introduction
1.1
Purpose
The purpose of this document is to add context to the settlement formulae from the FM protocols by providing transactional examples of the settlement charge types and intermediate calculations. Where practical the examples are presented with illustrations which show how different types of market instruments interact in achieving settlement results. In the interest of brevity and clarity the example calculations evaluate results in a single interval, be it 5-minute, hourly, daily or even monthly/yearly.
1.2
Definition of Terms
Acronym
Term
Definition
AO
Asset Owner
The middle tier of financial entities in the CM, used for settlement statements.
BA
Balancing Authority
A boundary defined by internal generation control to an instantaneous NAI signal
BDR
Block Demand Response
Behind the meter load reduction which requires calculated response
CBA
Consolidated Balancing Authority
Approach assumes the footprint will retain existing SAs for determining residual load while supplying NSI & NAI for the entire footprint to calculate the impact of NI
CC
Combined Cycle (Resource)
Resource comprised of many operational configurations such as 1 gas turbine & 1 steam turbine or 2 gas turbines and 1 steam turbine etc.
CM
Commercial Model
The financial entities, network elements and relationships between them constructing the backbone of the market
CP
Commitment Period
The date/time range of a DA market or RTBM resource Market or Self commitment
COS
Commercial Operations Systems
A suite of market applications including settlements, customer service and the portal
DA
Day Ahead (Market)
The future forward market for energy and operating reserves
DDR
Dispatchable Demand Response
Load reduction which can be metered
DRL
Demand Response Load
A meter location discretely representing the load behind which a demand response resource is located. A DRL is not necessarily associated with a SL which will be settled, its primary function is for acceptance of metering which supports the calculated method for BDRs & BDRs
DRR
Demand Response Resource
BDR or DDR
EIS
Energy Imbalance Service
The current SPP market
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Acronym
Term
Definition
FM
Future Market
SPP’s DA Market, RTBM and TCR Market for energy and Operating Reserves planned for implementation Q4 2012
EMS
Energy Management System
SPP repository and dashboard for MP SCADA data
JOU
Joint Owned Unit
Ownership of a physical resource shared among multiple financial entities
LRS
Load Ratio Share
The % of load at a single SL relative to the SPP total
MA
Meter Agent
Entity responsible for submittal of revenue quality interchange, resource and load meter data to settlements via the market portal
Meter Data Submittal Location
A child of SL – the level at which meter data is submitted. It is usually 1:1 with SL, but in certain cases multiple MDSLs may relate to a single SL. MDSLs are confined to a single SA (necessary for the purpose of residual & calibration calculation) while a SL may span multiple SAs.
MP
Market Participant
The highest tier of financial entities in the CM, used for invoicing and credit.
MS
MDSL
Market Settlements
The system built to implement new market protocols
MTR
Meter
Revenue Quality
MWP
Make Whole Payment
Cost guarantees during periods of SPP economic resource commitment
Make-Whole Eligibility Period
The settlement subset of a CP considered in MWP calculations
Net Actual Interchange
The actual net flow into or out of CBA or SA
NI
Net Inadvertent
The difference between the actual and scheduled net flow into or out of SPP
NSI
Net Scheduled Interchange
The scheduled net flow into or out of CBA or SA
OCL
Over Collected Losses
Settlement surplus related to marginal loss pricing, which is rebated based on payment of marginal losses.
OD
Operating Day
The day boundary for a single settlement period
OR
Operating Reserves
Capacity held for regulation, spinning and supplemental reserve
POP
Post Operations Processor
A rudimentary system which consists primarily of a market system database dump, and bridges the gap between RT Operations and MS
RUC
Reliability Unit Commitment
Operations process and algorithm for determining which units should be started
RTBM
Real Time Balancing Market
Future market for dispatch of energy and operating reserves to meet current demand
RTOSS
Regional Transmission Organization Scheduling System
Manages interchange schedule data and NSI / NAI for the footprint
RNU
Revenue Neutrality Uplift
Market charge type for balancing daily settlement
RUC
Reliability Unit Commitment
Market process for committing resources needed to meet the load forecast
MWEP NAI
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Acronym
Term
Definition
Settlement Area
A boundary within the market footprint which defines the load balance equation to determine the residual quantity
Supervisory Control And Data Acquisition
4 second resource and load bus signals from MP equipment sent to SPP
SE
State Estimator
An operations system which smooths, replaces and repairs SCADA data to create complete snapshots of the transmission system every 5 minutes
SL
Settlement Location
Pricing points in the footprint: Resource, Load, Interface, Trading Hub & Resource Hub types
TCR
Transmission Congestion Rights
The market (or instrument) for transmission planning and forward hedging of congestion rents
UOM
Unit of Measure
MW or MWh data submitted in 5-minute intervals
URD
Uninstructed Resource Deviation
Performance outside of a tolerance band from the dispatch setpoint
SA SCADA
1.3
Outstanding Issues/Assumptions Issue
Description
Combined Cycle Resources
CCs are settled in aggregate or as separate virtual shares; all data necessary to support these calculations are available as input.
Joint Owned Units
JOUs are settled as separate assets; the same calculation and data expectations as any other resource apply.
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2.
Market Model
2.1
Commercial Model
The settlement examples are based on a miniature model of the SPP footprint, but one which provides substantial diversity in the different organizational structures or transactional scenarios found in actual market operations.
2.1.1
Financial Entities and Relationships
Three tiers of financial entities comprise the backbone of settlements.
MP: the top level for invoicing and credit exposure calculations.
AO: an organizational or accounting sub-group used to compartmentalize market activity, settlement statements are presented at this level.
Asset: a resource or load owned by and AO, exclusive use of a SL for certain charge types.
Each of the settlement examples will provide a dialogue that associates the transactional activity to a single AO. The calculations themselves occur at various levels, primarily per SL, but in cases where SL granularity is not practical the results are at a zonal level or are summed to the AO.
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Figure 1
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2.1.2
Network Entities and Relationships
The relationships among MLs, SLs, SAs, LPs, RZNs, Common Bus described in the Market Protocols are not always important to settlement calculations; however, there are exceptions where an understanding of the underlying framework is essential. Settlement formulae use the billable metering determinant as the point of entry for calculations which require revenue quality injection and withdrawal data, but it is in fact an intermediate determinant derived from a chain of other raw data elements.
Actual submittals must be at a location, the MDSL, confined to a single SA for the purpose of calculating residual load. Where an SL consists of multiple MDSLs in different SAs the billable meter determinant is an aggregation of the submitted values.
Calibration of SA residual is included with MDSL values in the roll-up to the SL level.
Where metered load represents consumption net of demand response behind the meter the value is grossed up for the response.
Where a top down calculation results in submittals inclusive of transmission losses, the SE value of the SA losses are backed out of the submittal.
Demand response relying on the calculated method must be tied to a MDSL for which baseline data is available to support the calculation.
Absent any submittal the settlement system substitutes SE values.
Hourly meter submittals are profiled into 5 minute intervals.
The association of SLs to RZN is necessary for both the settlement of OR procured from resources and the cost allocation to zonal obligation. LPs are a modeling construct used to group SL members of a single financial entity together for the purpose of determining the loss factors, which in turn determine the rebate of OCL. Lastly, the Common Bus object is used as a tool to prevent charges for URD and contingency reserve deployment penalties where a group of resources measured in aggregate pass the performance threshold.
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2.2
Transactional Legend
Day-Ahead Cleared Energy Withdrawal
Any Settlement Location
Billable Meter MW
Injection Withdrawal
Injection
Bid
Offer
Cleared Virtual Bid or Offer Resource or Load Settlement Location
Interface Settlement Location Import
Import Day-Ahead Financial Schedule Buy
Real-Time Financial Schedule Buy
Sell
Sell
Export
Day-Ahead Import / Export
Day-Ahead Regulation, Spinning & Supplemental Reserves
Real-Time Regulation, Spinning & Supplemental Reserves
RegU p
RegU p
Spin Supp
Real Time Import / Export
Any Settlement Locations
Any Settlement Location
RegD n
Export
Transmission Congestion Right (source to sink)
RegD Spin Supp n
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Appendix G - Mitigated Offer Development Guidelines
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1.
Introduction
1.1
About These Guidelines
The Mitigated Offer Development Guidelines manual comprises Attachment G of SPP’s Market Protocols for Integrated Marketplace. This manual is maintained by the Mitigated Offer Taskforce under the direction of the Market Working Group and with the advice of the Market Monitoring Unit. To use this manual, read sections one and two then go to the section for a particular resource type for possible additional information. All capitalized terms shall have the same meaning as they are defined in the Market Protocols and/or the SPP Tariff. In the event of a conflict between the Market Tariff and this Attachment G, the most recent approved version of the Tariff will govern.
1.2
1.3
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Intended Audience
Market Participants
SPP Staff
Market Monitoring Unit
Regulators
Market Participants
What is in this Manual?
A table of contents that lists two levels of subheadings within each of the sections
An approval page that lists the required approvals and a brief outline of the current revision
Sections containing the specific guidelines, requirements, or procedures including SPP actions and SPP Member actions
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1.4
Mitigated Offer Task Force
The SPP Market Working Group (“MWG”) is responsible for the development of the Mitigated Offer Development Guidelines. It has tasked the Mitigated Offer Task Force (“MOTF”) with the initial development of the guidelines. The MOTF is comprised of members nominated by the members of the MWG. A representative of the SPP Market Monitoring Unit (“MMU”) may participate and provide comments to the MOTF or act as secretary of the MOTF.
1.5
Purpose
As described in Section 8.2 of the Integrated Marketplace Protocols, each Market Participant shall submit mitigated offer parameters along with each market offer. The mitigated offers reflect the cost of providing the offered product or service. SPP will use the mitigated offers to screen for market offers that adversely impact the market and as replacement offers in the case that those offers are mitigated. The purpose of this Manual is to define the mitigated offers to ensure that each Market Participant's mitigated offer is developed to represent the short-run marginal cost of production, ensuring that the Market Participants who own or control Resources with market power cannot exercise it.
1.6
Mitigated Offer Methodology Approval Process
Market Participants shall submit their initial cost data and supporting documentation at least three months prior to launch of SPP’s Integrated Marketplace, unless otherwise directed by the SPP MMU. The SPP MMU shall provide initial feedback no longer than two months after submittal, or 15 calendar days prior to the start of the Integrated Marketplace, or by another mutually agreed date. For all subsequent new resources, Market Participants shall submit the initial cost data and supporting documentation thirty days prior to submitting their first offer to the market, and the SPP MMU shall respond within fifteen calendar days. The SPP MMU shall maintain on its website a mechanism that allows Market Participants to conveniently and confidentially submit and update such data as required or as needed. The website shall also contain instructions and examples of required documentation. A Market Participant who seeks to obtain an exemption, exception or change to any time frame, process, methodology, calculation or policy set forth in these guidelines, or the approval of any mitigated offer that is not specifically permitted by these guidelines, shall submit a request to the SPP MMU for consideration and determination, except as otherwise specified herein.
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The SPP MMU shall approve or disapprove such a request based on the following criteria: the cost components included in all mitigated offers should reflect the short-run marginal cost of generation; the formulas used to calculate mitigated offers and the components of cost included in mitigated offers do not deviate from those specified in the SPP Tariff; and the documentation and data validation provided by the Market Participant are sufficient for the SPP MMU to verify mitigated offers on an ongoing basis. After receipt of such a request, the SPP MMU shall notify the Market Participant of its decision regarding the request no later than fifteen (15) calendar days after the submission of the request. If the Market Participant agrees with the SPP MMU’s decision, the request shall be deemed to be approved. In the event that the Market Participant disagrees with the SPP MMU’s decision and submits a dispute following the procedures described in section 12 of the SPP Tariff, the previously approved time frame, process, methodology, calculation or policy shall remain in place until the resolution of the dispute.
2.
Policies for All Resource Types
This section contains information that is relevant for the development of a mitigated offer for all types of resources.
2.1
Heat Rates
Heat Rate equals the mmBtu content of the heat input divided by the MWh of power output. The smaller the heat rate value the greater the efficiency. The heat rate can also be referred to as the input-output function. The term “mmBtu” is defined as millions of British Thermal Units. The following equation defines average heat rate over an amount of energy production or at a given net power output:
𝑇𝑜𝑡𝑎𝑙 𝐻𝑒𝑎𝑡 𝑅𝑎𝑡𝑒 =
𝑚𝑚𝐵𝑡𝑢 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡 = 𝑀𝑊ℎ 𝑁𝑒𝑡 𝑀𝑊
Incremental heat rate is the relationship between an additional MW of output and the additional heat input necessary to produce it. Graphically, the incremental heat rate can be determined from the ratio of the change in fuel input to the change in resource MW output; which is the slope of the input/output curve. An input/output curve shows the net MW output on
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the “x” axis and the heat input on the “y” axis. Mathematically, the incremental heat rate curve can be expressed as the first derivative of the input/output curve (input heat versus MW output).
𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐻𝑒𝑎𝑡 𝑅𝑎𝑡𝑒 = =
2.1.1
∆𝑚𝑚𝐵𝑡𝑢 𝐶ℎ𝑎𝑛𝑔𝑒 𝑖𝑛 𝐻𝑒𝑎𝑡 𝐺𝑜𝑖𝑛𝑔 𝐼𝑛 = ∆𝑀𝑊ℎ 𝐶ℎ𝑎𝑛𝑔𝑒 𝑖𝑛 𝐸𝑛𝑒𝑟𝑔𝑦 𝐶𝑜𝑚𝑖𝑛𝑔 𝑂𝑢𝑡
𝜕𝑦 𝑇𝑜𝑡𝑎𝑙 𝐻𝑒𝑎𝑡 𝑅𝑎𝑡𝑒 𝜕𝑥
Heat Content of Fuel
Heat Content of Fuel is the energy content of a given fuel, expressed in mmBtu per unit of fuel. Heat content of fuel may be based on of the following:
As burned test
In stock test
As received test
As shipped test
Contract value
Seller's invoice
Seller's quote
Nominal value based on Industry Standard
2.1.2
Heat Rate Curves
All Market Participants shall develop heat rate curves, which they must submit to the SPP MMU pursuant to the Mitigated Offer Methodology Approval Process (Section 1.6). These curves show input heat from burning fuel for each level of MW output for each of their Resources. The curves serve as the basis for the theoretical incremental heat rate curves for fuel consumption and performance factor development.
Heat rate curves submitted to SPP should be calculated on a net MW basis.
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Heat rate curves (one curve per fuel type of operating mode) will be based on design and/or comparable resource data modified by actual resource test data (when available), and/or actual resource operations data.
Data for the heat rate curve development should include normal minimum and normal maximum MW points. The heat rate curve for emergency ranges may be extrapolated from available data by the Market Participant.
This heat rate curve (or curves) will be used as the basis for incremental heat rate curves, incremental costs, and performance factor calculations.
Heat rate and heat input data used in offer curve and no-load cost development should be submitted to the Market Monitor pursuant to the Mitigated Offer Methodology Approval Process as a component of cost policy.
2.2
Performance Factors
Performance Factor is the calculated ratio of actual fuel burn to either theoretical fuel use (design heat input) or the most recent heat rate performance test. Actual burn may vary from theoretical or test fuel use due to factors such as resource age or modification, changes in fuel properties, seasonal ambient conditions, etc.
𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 =
𝑇𝑜𝑡𝑎𝑙 𝐴𝑐𝑡𝑢𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) 𝑇𝑜𝑡𝑎𝑙 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢)
The performance factor shall be calculated on either the total fuel consumed over a specific calibration period or a monthly spot check test basis. Market Participants are required to update their Resources’ Performance Factors(s) annually; however, Market Participants may update these performance factors more frequently to reflect seasonal variations and/or other operational changes. Those Market Participants lacking the “Total Theoretical Fuel Consumed” value may designate a performance factor of 1; these Market Participants must notify the SPP MMU prior to March 1, 2014. These Market Participants shall use fuel consumed during the first time that Resource(s) is committed for operation as the “Total Theoretical Fuel Consumed” value and report such value to SPP MMU. These Market Participants will also submit the fuel consumption data from a subsequent window of operation to update its Performance Factor.
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Requests for exemptions from these periods should first be submitted to the SPP MMU for evaluation pursuant to the Mitigated Offer Methodology Approval Process. The overall performance factor can be modified by a seasonal performance factor to reflect ambient conditions or equipment conditions.
2.2.1
Engineering Judgment in Performance Factors
The calculated performance factor may be superseded by estimates based on sound engineering judgment. If the period during which estimated performance factors are used exceeds three months, documentation concerning reasons for the override must be maintained and available for review upon request.
2.2.2
Calculation Methods of Performance Factors
There are three options available for use in determining a resource’s performance factor: 1. Total Fuel approach 2. Separate performance factors 3. Fixed start approach Performance factors are used in calculating start fuel as well as operating fuel. When the total fuel approach is used, the performance factor represents the ratio:
𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 =
𝑇𝑜𝑡𝑎𝑙 𝐴𝑐𝑡𝑢𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) 𝑇𝑜𝑡𝑎𝑙 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢)
With the total fuel approach, fuel quantities measured during start tests should be modified by the performance factor in effect at the time of the test so that theoretical or standard start fuel quantities will be on the same basis as the standard operating fuel quantity. Conditions encountered during the start of certain resources may make it preferable to assign separate performance factors for start and operating fuel (no-load fuel and fuel used for any energy production). If separate performance factors are calculated for start fuel prior to calculating the “operating fuel” performance factor, the operating fuel performance factor represents the ratio:
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𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐹𝑢𝑒𝑙 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟
=
𝑇𝑜𝑡𝑎𝑙 𝐴𝑐𝑡𝑢𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) − 𝐴𝑐𝑡𝑢𝑎𝑙 𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) 𝑇𝑜𝑡𝑎𝑙 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) − 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢)
Due to the variability and difficulty in measuring actual start fuel, an Market Participant may choose to set a fixed start performance factor of one, implicitly assigning all performance variations to no-load and incremental loading costs. In order to account for all fuel actually consumed, the operating fuel performance factor represents the ratio: 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐹𝑢𝑒𝑙 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟
=
𝑇𝑜𝑡𝑎𝑙 𝐴𝑐𝑢𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) − 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) 𝑇𝑜𝑡𝑎𝑙 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢) − 𝑇ℎ𝑒𝑜𝑟𝑒𝑡𝑖𝑐𝑎𝑙 𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢)
where Total Theoretical Start Fuel Consumed is the fuel quantity used in the start cost calculation.
“Like” Resources for Performance Factors
2.2.3
An average performance factor may be calculated and applied for groups of like resources burning the same type of fuel. Please see the Resource Type sections for further detail of “like” resources.
2.3
Fuel Cost Policies
Market Participants must submit a fuel cost policy for each Resource describing its method of calculation of fuel costs to the SPP MMU pursuant to the Mitigated Offer Methodology Approval Process. Such fuel cost policies shall include the following information: 1.
For the component of cost indicating daily delivered fuel cost, please include, for each fuel type:
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Source of fuel cost, for each Resource. For example; specified NYMEX index, forward contract.
Source of fuel basis cost (i.e. Henry Hub)
Methodology for converting fuel basis cost to $/mmBtu.
Average BTU content of fuel (as fuel prices must be converted to $/mmBtu), if source does not describe a fixed BTU content.
Any additional information regarding pricing fuel cost including;
When prices are revised
All additional charges
2.
Please include, for each fuel, any additional costs related to fuel or fuel handling.
3.
For SO2 / NOx / CO2 Emission Allowance Costs, please include:
2.3.1
Units with emission allowance costs
How emission data is collected
How emission allowance is calculated in $/mmBtu
Source of emission costs
When costs are updated
Modifications to Fuel Cost Policies
A request to change the method of calculation of fuel cost shall be submitted to the SPP MMU for evaluation pursuant to the Mitigated Offer Methodology Approval Process in advance of the proposed change (this is referred to below as “the proposal”). The Market Participant and the SPP MMU shall discuss the proposal and the Market Participant will provide documentation supporting its request to the SPP MMU. The SPP MMU shall provide an initial response to the Market Participant in writing within 15 days of the Market Participant’s submission of the request to the SPP MMU, indicating its agreement with the request or areas of concern pursuant to the Mitigated Offer Methodology Approval Process. The changed method of calculation may be implemented immediately upon final approval pursuant to the Mitigated Offer Methodology Approval Process.
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2.3.2
Fuel Cost Calculation
The method of calculation of fuel cost may include the use of actual fuel prices paid, e.g. the contract price paid for fuel, or the spot price for fuel. The contract price for fuel must include the locational cost of fuel for the generating resource. The source used for spot price for fuel must be publicly available and reflect the locational cost of fuel for the generating resource. The locational cost of fuel shall include specification of any additional incremental costs of delivery for the generating resource. Each Market Participant will be responsible for establishing its own method of calculating delivered fossil fuel cost, limited to inventoried cost, replacement cost or a combination thereof, that reflects the way fuel is purchased or scheduled for purchase. The Market Participant shall submit any changes to the method of calculation to the SPP MMU with supporting documentation. The SPP MMU shall review the changes. If SPP MMU has concern over any such proposed changes, it will hold discussions with the Market Participant to mitigate concerns. The method of calculation may only be changed by receipt of final approval pursuant to the Mitigated Offer Methodology Approval Process in advance of the proposed change. Fossil fuel cost adjustments compensating for previous estimate inaccuracies should not be considered when determining the basic fuel cost component of Total Fuel Related Cost described under Section 2.3.3. Each Market Participant must review and document their historical fuel costs at least once per month (12 times per year). Additionally, each review must occur within forty (40) days of the preceding review. The results of this review will be used to determine whether a fuel cost update is necessary. The documentation of fuel costs must be filed via the Market Monitoring Unit website.
2.3.3
Total Fuel Related Costs
Total Fuel Related Cost (“TFRC”) is the sum of basic fuel cost, other fuel related cost, emission allowance cost, and variable operation and maintenance (VOM) cost. 𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 𝑅𝑒𝑙𝑎𝑡𝑒𝑑 𝐶𝑜𝑠𝑡𝑠 ($/𝑚𝑚𝐵𝑡𝑢) =
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= 𝑏𝑎𝑠𝑖𝑐 𝑓𝑢𝑒𝑙 𝑐𝑜𝑠𝑡𝑠($/𝑚𝑚𝐵𝑡𝑢) + 𝑜𝑡ℎ𝑒𝑟 𝑓𝑢𝑒𝑙 𝑟𝑒𝑙𝑎𝑡𝑒𝑑 𝑐𝑜𝑠𝑡𝑠($/𝑚𝑚𝐵𝑡𝑢) + 𝑆𝑂2 𝐴𝑙𝑙𝑜𝑤𝑎𝑛𝑐𝑒 𝑐𝑜𝑠𝑡($/𝑚𝑚𝐵𝑡𝑢) + 𝐶𝑂2 𝐴𝑙𝑙𝑜𝑤𝑎𝑛𝑐𝑒 𝑐𝑜𝑠𝑡($/𝑚𝑚𝐵𝑡𝑢) + 𝑁𝑂𝑋 𝐴𝑙𝑙𝑜𝑤𝑎𝑛𝑐𝑒 𝑐𝑜𝑠𝑡($/𝑚𝑚𝐵𝑡𝑢) + 𝑇𝐹𝑅𝐶 𝑉𝑂𝑀 ($/𝑚𝑚𝐵𝑡𝑢)
The other fuel-related cost components of TFRC may be calculated based on an average of shortrun variable costs for each such component for a period of one year or less, reviewed and updated annually, or based on a rolling twelve month average, reviewed and updated monthly. Both the term and the frequency of the other fuel-related costs calculation shall be included in the Market Participant’s fuel cost policy. The TFRC VOM is calculated using an allocated portion of the total VOM calculated under Section 2.4. Note that the sum of total allocated $ used to calculate TFRC VOM included here, the allocated VOM $ used to calculate Energy Offer Curve VOM under Section 2.5, the allocated VOM $ used to calculate No-Load VOM under 2.7, the allocated VOM $ used to calculate Start-Up VOM under 2.6 and the allocated VOM $ used to calculate Regulation VOM under 2.10 must not exceed the total VOM $ calculated under Section 2.4. Total Fuel Related Costs may vary between different Offer parameters to the extent that the differences can be quantified and demonstrated.
2.3.4
Types of Fuel Costs
Basic fuel cost is the commodity cost of fuel calculated as stated in the company’s fuel cost policy. NOTE: Basic Fuel Cost for each resource type will be addressed in subsequent sections. Other fuel related cost includes the additional incremental components of fuel cost required to operate a generating resource, such as transportation fees, taxes on fuel and water injection.
2.3.5
Emission Allowances
Market Participants with resources that require SO2, CO2, NOX, or other types of emission allowances (EAs) , as dictated by regulatory bodies, to operate may include in the resource’s TFRC the cost ($/mmBtu) of the EAs as determined in the Market Participant’s allowance cost policy.
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If a Market Participant includes Emission Allowances as components of TFRC, the Market Participant must submit with their cost policy its method of determining the cost of SO2, CO2, NOX, or other type of EA for evaluation pursuant to the Mitigated Offer Methodology Approval Process. An example of the calculation method must be included in the policy. Any changes to the method of calculation may be changed only after approval pursuant to the Mitigated Offer Methodology Approval Process. The period used for determining the projected SO2, CO2, NOX, or other type of emission discharge and the MMBTUs burned must be included in the Market Participant’s allowance cost policy and may be based on historical or projected data. For resources that have dual fuel firing capability, an Market Participant should use different EA factors based on the SO2, CO2, NOX, or other type of emission emitted for each particular fuel or fuel mix.
Emissions costs will be included in TFRC only during the emission compliance period and only by resources subject to compliance requirements. Details of the cost calculation methodology and example calculations will be contained in each Market Participant’s allowance cost policy. Compliance requirements and dates may vary by geographic region. Those Market Participants not incorporating emissions costs in their TFRC will be exempt from the requirements of this section 2.3.5.
2.3.6
Variable Fuel Transportation Equipment
When calculating the Total Fuel Related Costs, fixed charges for transportation equipment (e.g. pipelines, train cars, and barges) should be excluded. Dollars that represent lease charges are considered fixed charges if the total amount to be paid over a period is fixed regardless of the amount of fuel transported. Should the terms of the lease or transportation agreement be such that there is a fixed charge plus a charge for the amount of fuel delivered, the “charge per unit of fuel delivered” should be included in the Fuel on Board (FOB) delivered cost or in the calculation of the “other fuel related costs” as per the documented fuel pricing policy. The above guideline applies when a resource, plant, or system is served totally by leased fuel transportation equipment or fuel transportation contracts. When fuel is supplied by both leased and common carrier fuel transportation systems, the common carrier rate should be included in the FOB delivered cost or included in the calculation of the “other fuel related costs” as per the documented fuel pricing policy of each Market Participant.
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2.4
Total Variable Operation and Maintenance Cost
Total Variable Operation and Maintenance (VOM) costs are the parts and labor expenses of maintaining equipment and facilities in satisfactory operating condition. A resource should reflect its short-run incremental VOM costs by using the most current data available. This could include the previous maintenance cycle period cost or actual short-run incremental cost where available. 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 ($) = 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟 ) 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑦𝑒𝑎𝑟 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟 + (𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟 ∗ ) 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟 + (𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟−1 ∗ )+⋯ 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟−1
[(𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑦𝑒𝑎𝑟 ∗
+ (𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑦𝑒𝑎𝑟−𝑚𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑝𝑒𝑟𝑖𝑜𝑑+1 ∗
𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟 )] 𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟−𝑚𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑝𝑒𝑟𝑖𝑜𝑑 𝑦𝑒𝑎𝑟𝑠+1
The SPP MMU will review the development of the total maintenance costs for all resources pursuant to the Mitigated Offer Methodology Approval Process. The total VOM cost as calculated above is based on available maintenance expense history for the defined Maintenance Period (See Section 2.4.2) regardless of Market Participantship. Only expenses incurred as a result of short-run incremental electric production (short-run marginal costs) qualify for inclusion.
2.4.1
Escalation Index
Escalation Index is the annual escalation index as derived from the July 1 Handy - Whitman Index for the SPP region, “construction cost electrical plant”. Otherwise, the Bureau of Labor Statistics Producer Price Index Series ID PCU3331203331208, Construction Machinery Manufacturing, Other Construction Machinery and Equipment shall be used for the Escalation Index as shown below.
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Bureau of Labor Statistics Producer Price Index 2004: Index 104.7 – Escalation Factor 1.314 2005: Index 108.9 – Escalation Factor 1.264 2006: Index 114.4 – Escalation Factor 1.203 2007: Index 120.1 – Escalation Factor 1.146 2008: Index 125.6 - Escalation Factor 1. 096 2009: Index 129.0 - Escalation Factor 1. 067 2010: Index 131.1 - Escalation Factor 1. 050 2011: Index 134.8 - Escalation Factor 1. 021 2012: Index 137.6(est) - Escalation Factor 1.000
2.4.2
Maintenance Period
The period of years between major overhauls or such other period as used in the calculation of total VOM under Section 2.4, not to exceed 10 years. If a resource experiences a significant configuration change, the resource may submit to the SPP MMU its changed VOM cost methodology. Examples of a significant resource configuration change may include but are not limited to:
Flue Gas Desulfurization (FGD or scrubber)
Activated Carbon Injection (ACI)
Selective Catalytic NOX Reduction (SCR)
Selective Non-Catalytic NOX Reduction (SNCR)
Low-NOX burners
Bag House addition
Long-term Fuel change (greater than 10 years)
Water injection for NOX control
Gas Turbine Inlet Air Cooling
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Dry Sorbent Injection (DSI)
2.4.3
Average VOM Cost
Average VOM Cost is the average VOM cost $/mmBtu, $/MWh or $/hour. This is defined as allocated VOM dollars in the historical Maintenance Period divided by total MWhs, total fuel or total on-line hours associated with the historical Maintenance Period, depending on VOM type.
𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝐶𝑢𝑟𝑣𝑒 (𝐸𝑂𝐶) 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($⁄𝑀𝑊ℎ)41 𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝐸𝑂𝐶 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4 𝑇𝑜𝑡𝑎𝑙 𝑀𝑤ℎ𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑
=
𝑇𝐹𝑅𝐶 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($⁄𝑚𝑚𝐵𝑡𝑢)42
=
𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑇𝐹𝑅𝐶 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4 𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 (𝑚𝑚𝐵𝑡𝑢 )𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑
𝑁𝑜𝑙𝑜𝑎𝑑 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($⁄𝑚𝑚𝐵𝑡𝑢 )43
=
𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑁𝑜𝑙𝑜𝑎𝑑 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4 𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 (𝑚𝑚𝐵𝑡𝑢)𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑
𝑁𝑜𝑙𝑜𝑎𝑑 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡 ($⁄𝐻𝑜𝑢𝑟)44
=
𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑁𝑜𝑙𝑜𝑎𝑑 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4 𝑇𝑜𝑡𝑎𝑙 𝑜𝑛 − 𝑙𝑖𝑛𝑒 ℎ𝑜𝑢𝑟𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑
𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($⁄𝑆𝑡𝑎𝑟𝑡) 45 41
See Section 2.5 and Section 2.10.1.
42
See Section 2.3
43
See Section 2.7
44
See Section 2.7
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=
𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4 𝑇𝑜𝑡𝑎𝑙 𝑆𝑡𝑎𝑟𝑡𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑
𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡 ($⁄𝑆𝑡𝑎𝑟𝑡) 46 𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4 𝑇𝑜𝑡𝑎𝑙 𝑆𝑡𝑎𝑟𝑡𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑 The VOM adders should be reviewed and updated at least once every twelve months or once in the maintenance cycle, whichever is shorter. =
If a Market Participant feels that a resource modification or required change in operating procedures will affect the resource's VOM adders, the revised VOM adders must be submitted to the SPP MMU for review and approval pursuant to the Mitigated Offer Methodology Approval Process.
2.5
Mitigated Energy Offer Curve
The Mitigated Energy Offer Curve is a set of up to ten price/quantity pairs (measured in $/MWh and MW) describing the short-run marginal cost of providing energy based on the heat rate curve, fuel cost, and variable operations and maintenance costs. 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 ($⁄𝑀𝑊ℎ) = 𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒(𝑚𝑚𝐵𝑡𝑢 ⁄𝑀𝑊ℎ) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 𝑅𝑒𝑙𝑎𝑡𝑒𝑑 𝐶𝑜𝑠𝑡𝑠($⁄𝑚𝑚𝐵𝑡𝑢) + 𝐸𝑂𝐶 𝑉𝑂𝑀($⁄𝑀𝑊ℎ) where EOC VOM is defined in Section 2.4.3, the heat rate is as defined in Section 2.1, the performance factor is as defined in Section 2.2, and the Total Fuel Related Cost is as defined in Section 2.3. The EOC VOM is calculated using an allocated portion of the total VOM calculated under Section 2.4.
45
See Section 2.6
46
See Section 2.10
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Note that the sum of total allocated $ used to calculate EOC VOM included here, the allocated VOM $ used to calculate TFRC VOM under Section 2.3, the allocated VOM $ used to calculate No-Load VOM under 2.7, the allocated VOM $ used to calculate Start-Up VOM under 2.6 and the allocated VOM $ used to calculate Regulation VOM under 2.10 must not exceed the total VOM $ calculated under Section 2.4.
2.6
Mitigated Start- Up Offer
2.6.1
Start- Up Offer Definitions
The Mitigated Start-Up Offer is the dollars per start as determined from start fuel, total fuelrelated cost, performance factor, electrical costs, start VOM adder, and additional labor cost, if required above normal station manning levels. 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑆𝑡𝑎𝑟𝑡-𝑈𝑝 𝑂𝑓𝑓𝑒𝑟($⁄𝑆𝑡𝑎𝑟𝑡) = [𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙(𝑚𝑚𝐵𝑡𝑢 ⁄𝑆𝑡𝑎𝑟𝑡) ∗ 𝑇𝐹𝑅𝐶($⁄𝑚𝑚𝐵𝑡𝑢) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟] + [𝑆𝑡𝑎𝑡𝑖𝑜𝑛 𝑆𝑒𝑟𝑣𝑖𝑐𝑒(𝑀𝑊ℎ/𝑆𝑡𝑎𝑟𝑡) ∗ 𝑆𝑡𝑎𝑡𝑖𝑜𝑛𝑆𝑒𝑟𝑣𝑖𝑐𝑒 𝑅𝑎𝑡𝑒($⁄𝑀𝑊ℎ)] + 𝑆𝑡𝑎𝑟𝑡 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟($⁄𝑆𝑡𝑎𝑟𝑡) + 𝑆𝑡𝑎𝑟𝑡 𝐴𝑑𝑑𝑖𝑡𝑖𝑜𝑛𝑎𝑙 𝐿𝑎𝑏𝑜𝑟 𝐶𝑜𝑠𝑡($⁄𝑆𝑡𝑎𝑟𝑡)
Station Service Rate is either a $/MWh value equal to the 12-month rolling average LMP at the station, updated at least quarterly, or the retail tariff rate applicable to the resource not included in the VOM calculated under Section 2.4. Start Fuel is the fuel consumed from first fire of start process (initial reactor criticality for nuclear resources) to breaker closing (including auxiliary boiler fuel) plus fuel expended from breaker opening of the previous shutdown to initialization of the resource start-up, excluding normal plant heating/auxiliary equipment fuel requirements. Start VOM – The Start VOM is calculated using an allocated portion of the total VOM calculated under Section 2.4.3. Note that the sum of total allocated $ used to calculate Start VOM included here, the allocated VOM $ used to calculate TFRC VOM under Section 2.3, the allocated VOM $ used to calculate No-Load VOM under 2.7, the allocated VOM $ used to calculate EOC VOM under 2.5 and the allocated VOM $ used to calculate Regulation VOM under 2.10 must not exceed the total VOM $ calculated under Section 2.4.
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Start Additional Labor Cost – Additional labor costs for start-up required above normal station manning levels not included in the VOM calculated under Section 2.4. A different value may be submitted for on-peak versus off-peak periods.
2.7
Mitigated No Load Offer
2.7.1
No-Load Definitions
Mitigated No-load Offer is the hourly fixed cost, expressed in $/hr, required to operate the resource at zero electricity output to the grid. This is used in creating a monotonically nondecreasing incremental cost curve.
2.7.2
No-Load Fuel
The no-load heat input may be determined by collecting heat input values as a function of output and performing a regression analysis. The heat input values as a function of output may be either created from heat rate test data or the initial design heat input curve of a resource. The minimum number of points to develop a heat input curve shall be 2 points for a dispatchable resource with a variable output and 1 point for a resource with a fixed output. The documentation must be adequate to permit the MMU to verify no-load development calculation methods used subject to the Mitigated Offer Methodology Approval Process. Mitigated No-Load Offer Calculation The initial resource Mitigated No-Load Offer ($/Hr) is the No-Load fuel input rate multiplied by the performance factor, multiplied by the (Total Fuel-Related Cost (TFRC)): 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑁𝑜 𝐿𝑜𝑎𝑑 𝑂𝑓𝑓𝑒𝑟 ($⁄ℎ𝑜𝑢𝑟) = 𝑁𝑜 𝐿𝑜𝑎𝑑 𝐹𝑢𝑒𝑙(𝑚𝑚𝐵𝑡𝑢 ⁄ℎ𝑜𝑢𝑟) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ ( 𝑁𝑜 𝐿𝑜𝑎𝑑 𝑉𝑂𝑀($⁄𝑚𝑚𝐵𝑡𝑢) + 𝑇𝐹𝑅𝐶 ($/𝑚𝑚𝐵𝑡𝑢) ) The Mitigated No-Load Offer may also be calculated by subtracting the incremental cost (resource’s economic minimum mitigated energy offer value multiplied by MW value) at the resource’s economic minimum point from the total cost (from the heat input at economic minimum value) at the resource’s economic minimum point.
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𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑁𝑜-𝐿𝑜𝑎𝑑 𝑂𝑓𝑓𝑒𝑟 ($⁄ℎ𝑜𝑢𝑟) = 𝑀𝑖𝑛. 𝐸𝑐𝑜𝑛. 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐿𝑖𝑚𝑖𝑡 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡(𝑚𝑚𝐵𝑡𝑢) ( ) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ (𝑇𝐹𝑅𝐶($/𝑚𝑚𝐵𝑡𝑢) + 𝑁𝑜 𝐿𝑜𝑎𝑑 𝑉𝑂𝑀($/𝑚𝑚𝐵𝑡𝑢)) − (𝑀𝑖𝑛. 𝐸𝑐𝑜𝑛. 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐿𝑖𝑚𝑖𝑡 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡($⁄𝑀𝑊ℎ) ∗ 𝑀𝑖𝑛. 𝐸𝑐𝑜𝑛. 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐿𝑖𝑚𝑖𝑡 (𝑀𝑊)) Note that if the source of VOM is in terms of dollars per on-line hours, the equation changes to: 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑁𝑜-𝐿𝑜𝑎𝑑 𝑂𝑓𝑓𝑒𝑟($⁄ℎ𝑜𝑢𝑟) = (𝑀𝑖𝑛. 𝐸𝑐𝑜𝑛. 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐿𝑖𝑚𝑖𝑡 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡(𝑚𝑚𝐵𝑡𝑢) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑇𝐹𝑅𝐶($/𝑚𝑚𝐵𝑡𝑢)) + 𝑁𝑜 𝐿𝑜𝑎𝑑 𝑉𝑂𝑀($/ℎ𝑜𝑢𝑟) − (𝑀𝑖𝑛. 𝐸𝑐𝑜𝑛. 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐿𝑖𝑚𝑖𝑡 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡($⁄𝑀𝑊ℎ) ∗ 𝑀𝑖𝑛. 𝐸𝑐𝑜𝑛. (𝑀𝑊)) The No Load VOM is calculated using an allocated portion of the total VOM calculated under Section 2.4.3. Note that the sum of total allocated $ used to calculate No Load VOM included here, the allocated VOM $ used to calculate TFRC VOM under Section 2.3, the allocated VOM $ used to calculate Start VOM under 2.6, the allocated VOM $ used to calculate EOC VOM under 2.5 and the allocated VOM $ used to calculate Regulation VOM under 2.10 must not exceed the total VOM $ calculated under Section 2.4.
2.8
Mitigated Spinning Reserve Offer
The mitigated Spinning Reserve Offer shall be equal to zero for Resources other than CTs and Hydro Resource with synchronous condenser capability. See Sections 6.8 and 7.7 for Mitigated Spinning Reserve Offers for CT and Hydro Resources. No known incremental costs are incurred for providing Spinning Reserves from other resource types.
2.9
Mitigated Supplemental Reserve Offer
The Mitigated Supplemental Reserve Offer shall include any labor costs necessary for the resource to be prepared for deployment up to but not exceeding: 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑆𝑢𝑝𝑝𝑙𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝑅𝑒𝑠𝑒𝑟𝑣𝑒 𝑂𝑓𝑓𝑒𝑟($⁄𝑀𝑊 ) ≤ 𝐴𝑑𝑑𝑖𝑡𝑖𝑜𝑛𝑎𝑙 𝐿𝑎𝑏𝑜𝑟 𝐶𝑜𝑠𝑡($)/𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑆𝑢𝑝𝑝𝑙𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝑅𝑒𝑠𝑒𝑟𝑣𝑒 𝑀𝑊 For Resources providing off-line Supplemental Reserves, the Average Supplemental Reserve MW to be applied to the additional labor cost is the average of historical Supplemental Reserve
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awards for the past twelve months. In the case that a Resource does not have a sufficient history of Supplemental Reserve awards, the Average Supplemental Reserve MW may be the capacity offered as represented by the Resource’s Maximum Quick-Start Response Limit offer parameter.
2.10
Comment [MPRR141.1484]: MPRR141 Awaiting FERC filing
Mitigated Regulation-Up and Regulation-Down Service Offers
The Mitigated Regulation-Up and the Mitigated Regulation-Down Offer shall include the following components up to but not exceeding: 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑅𝑒𝑔𝑢𝑙𝑎𝑡𝑖𝑜𝑛 𝑂𝑓𝑓𝑒𝑟($⁄𝑀𝑊 ) ≤ 𝐶𝑜𝑠𝑡 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑑𝑢𝑒 𝑡𝑜 𝐻𝑒𝑎𝑡 𝑅𝑎𝑡𝑒 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑑𝑢𝑟𝑖𝑛𝑔 𝑛𝑜𝑛-𝑠𝑡𝑒𝑎𝑑𝑦 𝑠𝑡𝑎𝑡𝑒 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛 ($/𝑀𝑊) + 𝐶𝑜𝑠𝑡 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑖𝑛 𝑉𝑂𝑀($/𝑀𝑊) + 𝑈𝑛𝑐𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑒𝑑 𝐶𝑜𝑠𝑡($/𝑀𝑊) The Mitigated Regulation-Up Mileage Offer shall include the following components up to but not exceeding: 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑅𝑒𝑔𝑢𝑙𝑎𝑡𝑖𝑜𝑛 − 𝑈𝑝 𝑀𝑖𝑙𝑒𝑎𝑔𝑒 𝑂𝑓𝑓𝑒𝑟($⁄𝑀𝑊 ) ≤
Comment [MPRR141.1485]: MPRR141 Awaiting FERC filing
[ 𝐶𝑜𝑠𝑡 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑑𝑢𝑒 𝑡𝑜 𝐻𝑒𝑎𝑡 𝑅𝑎𝑡𝑒 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑑𝑢𝑟𝑖𝑛𝑔 𝑛𝑜𝑛-𝑠𝑡𝑒𝑎𝑑𝑦 𝑠𝑡𝑎𝑡𝑒 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛 ($/𝑀𝑊) + 𝐶𝑜𝑠𝑡 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑖𝑛 𝑉𝑂𝑀 (
$ )] ∗ 𝑅𝑒𝑔𝑢𝑙𝑎𝑡𝑖𝑜𝑛 − 𝑈𝑝 𝑀𝑖𝑙𝑒𝑎𝑔𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 𝑀𝑊
The Mitigated Regulation-Down Mileage Offer shall include the following components up to but not exceeding:
Comment [MPRR141.1486]: MPRR141 Awaiting FERC filing
𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑅𝑒𝑔𝑢𝑙𝑎𝑡𝑖𝑜𝑛 − 𝐷𝑜𝑤𝑛 𝑀𝑖𝑙𝑒𝑎𝑔𝑒 𝑂𝑓𝑓𝑒𝑟($⁄𝑀𝑊 ) ≤ [ 𝐶𝑜𝑠𝑡 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑑𝑢𝑒 𝑡𝑜 𝐻𝑒𝑎𝑡 𝑅𝑎𝑡𝑒 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑑𝑢𝑟𝑖𝑛𝑔 𝑛𝑜𝑛-𝑠𝑡𝑒𝑎𝑑𝑦 𝑠𝑡𝑎𝑡𝑒 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛 ($/𝑀𝑊) $ + 𝐶𝑜𝑠𝑡 𝐼𝑛𝑐𝑟𝑒𝑎𝑠𝑒 𝑖𝑛 𝑉𝑂𝑀 ( )] ∗ 𝑅𝑒𝑔𝑢𝑙𝑎𝑡𝑖𝑜𝑛 − 𝐷𝑜𝑤𝑛 𝑀𝑖𝑙𝑒𝑎𝑔𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 𝑀𝑊
2.10.1
Uncompensated Costs:
For Regulation-Up: Uncompensated cost should reflect the opportunity cost of the lost energy dispatch between the Maximum Economic Capacity Operating Limit and the Maximum Regulation Capacity Operating Limit or the additional cost of producing energy between the Minimum Economic Capacity Operating Limit and the Minimum Regulation Capacity Operating Limit. It shall only be included for Real-Time Balancing Market offers, and it shall not exceed the lesser of the uncompensated regulation lost opportunity cost cap, as determined by the SPP MMU, and the uncompensated cost as calculated below:
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𝑈𝑛𝑐𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑒𝑑 𝑐𝑜𝑠𝑡 ($/𝑀𝑊) ≤ 𝑀𝑎𝑥 [ 0, (𝐷𝐴 𝐿𝑀𝑃 ($/𝑀𝑊) − 𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝑓𝑜𝑟 𝑀𝑊 𝑎𝑏𝑜𝑣𝑒 𝑅𝑒𝑔𝑀𝑎𝑥 ($/𝑀𝑊))] ∗ ((𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊)– 𝑅𝑒𝑔𝑀𝑎𝑥(𝑀𝑊))) / (𝐷𝐴 𝑅𝑒𝑔𝑈𝑝 𝐴𝑤𝑎𝑟𝑑 (𝑀𝑊)) + 𝑀𝑎𝑥 [ 0, (𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝑓𝑜𝑟 𝑀𝑊 𝐵𝑒𝑙𝑜𝑤 𝑅𝑒𝑔𝑀𝑖𝑛 ($ /𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃 ($/𝑀𝑊))] ∗ (𝑅𝑒𝑔𝑀𝑖𝑛 (𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊))/(𝐷𝐴 𝑅𝑒𝑔𝑈𝑝 𝐴𝑤𝑎𝑟𝑑 (𝑀𝑊)).
The Weighted average Mitigated Energy Offer for MW above RegMax is the area under the Mitigated Energy Offer Curve between the Maximum Regulating Capacity Operating Limit and the MW at which the DA LMP crosses the Mitigated Energy Offer Curve divided by the capacity range between the two MW points. If the DA RegUp Award (MW) is zero, it may be replaced by five times the resource regulation ramp rate. For Regulation-Down: Uncompensated cost should reflect the opportunity cost of the lost energy dispatch between the Maximum Economic Capacity Operating Limit and the Maximum Regulation Capacity Operating Limit or the additional cost of producing energy between the Minimum Economic Capacity Operating Limit and the Minimum Regulation Capacity Operating Limit. It shall only be included for Real-Time Balancing Market offers, and it shall not exceed the lesser of the uncompensated regulation minimum limit cost cap, as determined by the SPP MMU, and the uncompensated cost as calculated below: 𝑈𝑛𝑐𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑒𝑑 𝑐𝑜𝑠𝑡 ($/𝑀𝑊) ≤ 𝑀𝑎𝑥 [ 0, (𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝑓𝑜𝑟 𝑀𝑊 𝑏𝑒𝑙𝑜𝑤 𝑅𝑒𝑔𝑀𝑖𝑛($ /𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃($/𝑀𝑊))] ∗ (( 𝑅𝑒𝑔𝑀𝑖𝑛(𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊)))/ (𝐷𝐴 𝑅𝑒𝑔𝐷𝑜𝑤𝑛 𝐴𝑤𝑎𝑟𝑑(𝑀𝑊)) + 𝑀𝑎𝑥 [ 0, 𝐷𝐴 𝐿𝑀𝑃 ($/𝑀𝑊) − 𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟𝑓𝑜𝑟 𝑀𝑊 𝐴𝑏𝑜𝑣𝑒 𝑅𝑒𝑔𝑀𝑎𝑥 ($/𝑀𝑊))] ∗ (𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊) − 𝑅𝑒𝑔𝑀𝑎𝑥 (𝑀𝑊))/(𝐷𝐴 𝑅𝑒𝑔𝐷𝑜𝑤𝑛 𝐴𝑤𝑎𝑟𝑑 (𝑀𝑊)). The Weighted average Mitigated Energy Offer for MW below RegMin is the area above the DA LMP and below the Mitigated Energy Offer Curve between the greater of the MW at which the
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DA LMP crosses the Mitigated Energy Offer Curve and the Minimum Regulation Capacity Operating Limit divided by the capacity range between the two MW points. If the DA RegDown Award (MW) is zero, it may be replaced by five times the resource regulation ramp rate.
2.10.2
Cost Increase due to Heat Rate increase during non-steady state:
The cost (in $/MW of Regulation Mileage) increase due to the heat rate increase resulting from operating the resource at a non-steady-state condition. This heat rate loss factor rate shall not exceed 0.35% of the top Regulation load MW heat rate value.
2.10.3
Comment [MPRR141.1488]: MPRR141 Awaiting FERC filing
Cost increase in Variable Operations and Maintenance:
The cost increase (in $/MWh of Regulation Mileage) of variable operations and maintenance (VOM) cost resulting from operating the resource at lower MW output incurred from the provision of Regulation. Increased VOM costs shall be calculated by the following methods and shall not exceed those levels below: The variable operation and maintenance (VOM) costs can be applied by resource type up to the following: Exhibit 1: VOM for all Hydro Resources or Non-Hydro Resources providing service
Super-critical Steam: $10.00 per MWh of Regulation
Sub-critical Steam: $3.50 per MWh of Regulation
Combined Cycle: $2.50 per MWh of Regulation
Combustion Turbine: $2.00 per MWh of Regulation
Hydro: $1.00 per MWh of Regulation
Reciprocating Engines: $2.00 per MWh of Regulation
For example, a 100 MW sub-critical coal fired steam resource that has been providing Regulation service for a 3 year Maintenance Period. The resource was deployed for 2,000 MWh of Regulation service over the past three years and the historical total VOM = $500,000. Exhibit 2: Example of VOM for Non-Hydro Resources providing Regulation
𝑉𝑂𝑀 𝑐𝑜𝑠𝑡𝑠 𝑡𝑜 𝑠𝑢𝑏𝑡𝑟𝑎𝑐𝑡 = ($3. 50 𝑝𝑒𝑟 𝑅𝑒𝑔𝑢𝑙𝑎𝑡𝑖𝑜𝑛 𝑀𝑊ℎ ∗ 2,000 𝑀𝑊ℎ)
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= $7,000 𝐵𝑎𝑙𝑎𝑛𝑐𝑒 𝑜𝑓 ℎ𝑖𝑠𝑡𝑜𝑟𝑖𝑐𝑎𝑙 𝑡𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝑎𝑐𝑐𝑜𝑢𝑛𝑡𝑠 = $500,000 − $7,000 = $493,000 The variable O&M (VOM) is calculated using the total VOM calculated under Section 2.4. Note that the sum of total $ used to calculate VOM included here, the total VOM $ used to calculate VOM under Sections 2.3, the total VOM $ used to calculate VOM under 2.5, the total VOM $ used to calculate VOM under 2.6 and the total VOM $ used to calculate VOM under 2.7 must not exceed the total VOM $ calculated under Section 2.4. Actual Regulation VOM incremental costs if they exceed the levels above must be submitted and evaluated pursuant to the Mitigated Offer Methodology Approval Process.
2.10.4
Uncompensated Costs:
For Regulation-Up: Uncompensated cost should reflect the opportunity cost of the lost energy dispatch between the Maximum Economic Capacity Operating Limit and the Maximum Regulation Capacity Operating Limit or the additional cost of producing energy between the Minimum Economic Capacity Operating Limit and the Minimum Regulation Capacity Operating Limit. It shall only be included for Real-Time Balancing Market offers, and it shall not exceed the lesser of the uncompensated regulation lost opportunity cost cap, as determined by the SPP MMU, and the uncompensated cost as calculated below: 𝑈𝑛𝑐𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑒𝑑 𝑐𝑜𝑠𝑡 ($/𝑀𝑊) ≤ 𝑀𝑎𝑥 [ 0, (𝐷𝐴 𝐿𝑀𝑃 ($/𝑀𝑊) − 𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝑓𝑜𝑟 𝑀𝑊 𝑎𝑏𝑜𝑣𝑒 𝑅𝑒𝑔𝑀𝑎𝑥 ($/𝑀𝑊))] ∗ ((𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊)– 𝑅𝑒𝑔𝑀𝑎𝑥(𝑀𝑊))) / (𝐷𝐴 𝑅𝑒𝑔𝑈𝑝 𝐴𝑤𝑎𝑟𝑑 (𝑀𝑊)) + 𝑀𝑎𝑥 [ 0, (𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝑓𝑜𝑟 𝑀𝑊 𝐵𝑒𝑙𝑜𝑤 𝑅𝑒𝑔𝑀𝑖𝑛 ($ /𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃 ($/𝑀𝑊))] ∗ (𝑅𝑒𝑔𝑀𝑖𝑛 (𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊))/(𝐷𝐴 𝑅𝑒𝑔𝑈𝑝 𝐴𝑤𝑎𝑟𝑑 (𝑀𝑊)).
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The Weighted average Mitigated Energy Offer for MW above RegMax is the area under the Mitigated Energy Offer Curve between the Maximum Regulating Capacity Operating Limit and the MW at which the DA LMP crosses the Mitigated Energy Offer Curve divided by the capacity range between the two MW points. If the DA RegUp Award (MW) is zero, it may be replaced by five times the resource regulation ramp rate. For Regulation-Down: Uncompensated cost should reflect the opportunity cost of the lost energy dispatch between the Maximum Economic Capacity Operating Limit and the Maximum Regulation Capacity Operating Limit or the additional cost of producing energy between the Minimum Economic Capacity Operating Limit and the Minimum Regulation Capacity Operating Limit. It shall only be included for Real-Time Balancing Market offers, and it shall not exceed the lesser of the uncompensated regulation minimum limit cost cap, as determined by the SPP MMU, and the uncompensated cost as calculated below: 𝑈𝑛𝑐𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑒𝑑 𝑐𝑜𝑠𝑡 ($/𝑀𝑊) ≤ 𝑀𝑎𝑥 [ 0, (𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝑓𝑜𝑟 𝑀𝑊 𝑏𝑒𝑙𝑜𝑤 𝑅𝑒𝑔𝑀𝑖𝑛($ /𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃($/𝑀𝑊))] ∗ (( 𝑅𝑒𝑔𝑀𝑖𝑛(𝑀𝑊) − 𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊)))/ (𝐷𝐴 𝑅𝑒𝑔𝐷𝑜𝑤𝑛 𝐴𝑤𝑎𝑟𝑑(𝑀𝑊)) + 𝑀𝑎𝑥 [ 0, 𝐷𝐴 𝐿𝑀𝑃 ($/𝑀𝑊) − 𝑊𝑒𝑖𝑔ℎ𝑡𝑒𝑑 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟𝑓𝑜𝑟 𝑀𝑊 𝐴𝑏𝑜𝑣𝑒 𝑅𝑒𝑔𝑀𝑎𝑥 ($/𝑀𝑊))] ∗ (𝐷𝐴 𝐿𝑀𝑃 𝐵𝑎𝑠𝑒𝑑 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ (𝑀𝑊) − 𝑅𝑒𝑔𝑀𝑎𝑥 (𝑀𝑊))/(𝐷𝐴 𝑅𝑒𝑔𝐷𝑜𝑤𝑛 𝐴𝑤𝑎𝑟𝑑 (𝑀𝑊)). The Weighted average Mitigated Energy Offer for MW below RegMin is the area above the DA LMP and below the Mitigated Energy Offer Curve between the greater of the MW at which the DA LMP crosses the Mitigated Energy Offer Curve and the Minimum Regulation Capacity Operating Limit divided by the capacity range between the two MW points. If the DA RegDown Award (MW) is zero, it may be replaced by five times the resource regulation ramp rate. Exhibit 3: Regulation-Up Maximum Allowable Mitigated Offer Example
Example: Sub-critical Coal-Fired Steam Resource, Regulation-Up Service Resource Operating Mode
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Maximum Regulation Operating Limit
Capacity 100 MW
9,000 Btu/kWh
Maximum Economic Capacity Operating 110 MW Limit Steam Resource Regulation Band
20 MW
Lowest Regulating Operating Load
40 MW
12,500 Btu/kWh
Base Prices Fuel Cost (TFRC):
$2.25/mBtu
Uncompensated Cost due to lower Maximum Operating Limit DA LMP
$30.00/MWh
DA Regulation-Up Award
20 MW/hour
Weighted Average Energy Cost for MW $15.00/MWh Above Reg. Max Limit =[($30/MWh - $15/MWh) * (110 MW – 100 MW)] / 20MW/hour = $7.50 $/MW
Uncompensated Cost
Total Regulation Cost (hourly) (a) Heat Rate Adjustment Steady-State Operation)
(Non = 3.15 mBtu/hour * $2.25/mBtu / 20 MW
(b) Regulation VOM Adder Uncompensated Cost (c) Mitigated Regulation-Up Mileage Offer = (a) +(b) + (c)
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(d) Mitigated Regulation-Up Offer
$7.50/MW Comment [MPRR141.1490]: MPRR141 Awaiting FERC filing
(e) Mitigated Regulation-Up Service $11.35/MW Offer = (c) + (d)
3.
Nuclear Unit Guidelines
This section presents information relevant for mitigated offer development for nuclear units. Nuclear Plant – A facility that is licensed to produce commercial power from controlled nuclear reactions to heat water to produce steam that drives steam turbines resources.
3.1
Nuclear Heat Rate Note: The information in Section 2.1 contains basic Heat Rate information relevant for all unit types including nuclear units.
3.2
Performance Factor Note: The information in Section 2.2 contains basic Performance Factor information relevant for all unit types including nuclear units.
3.3
Fuel Cost Note: The information in Section 2.3 contains basic Fuel Cost information relevant for all unit types. The following information only pertains to nuclear units.
3.3.1
Basic Nuclear Fuel Cost
Basic Nuclear Fuel Cost - Basic nuclear fuel cost shall be based on the dollars in FERC Account 518, less in-service interest charges (whether related to fuel that is leased or capitalized). This quantity shall be calculated in units of dollars per mmBtu, as forecast for the applicable fuel cycle. 𝐵𝑎𝑠𝑖𝑐 𝑁𝑢𝑐𝑙𝑒𝑎𝑟 𝐹𝑢𝑒𝑙 𝐶𝑜𝑠𝑡($⁄𝑚𝑚𝐵𝑡𝑢 ) = 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑖𝑛 𝐹𝐸𝑅𝐶 𝐴𝑐𝑐𝑜𝑢𝑛𝑡 518($/𝑚𝑚𝐵𝑡𝑢) − 𝐼𝑛𝑡𝑒𝑟𝑒𝑠𝑡 𝐶𝑜𝑠𝑡($/𝑚𝑚𝐵𝑡𝑢)
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3.3.2
Total Fuel-Related Costs for Nuclear Units
𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 𝑅𝑒𝑙𝑎𝑡𝑒𝑑 𝐶𝑜𝑠𝑡𝑠 𝑓𝑜𝑟 𝑁𝑢𝑐𝑙𝑒𝑎𝑟 𝑈𝑛𝑖𝑡𝑠($/𝑚𝑚𝐵𝑡𝑢) = 𝐵𝑎𝑠𝑖𝑐 𝑁𝑢𝑐𝑙𝑒𝑎𝑟 𝐹𝑢𝑒𝑙 𝐶𝑜𝑠𝑡($/𝑚𝑚𝐵𝑡𝑢) + 𝑇𝐹𝑅𝐶 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟($/𝑚𝑚𝐵𝑡𝑢)
3.4
Mitigated Start-Up Offer Note: The information in Section 2.6 contains basic Mitigated Start-Up Offer information relevant for all unit types. The following information only pertains to nuclear units.
Start Cost – The dollars per start as determined from start fuel, total fuel-related cost, performance factor, electrical costs, start VOM adder, and additional labor cost, if required above normal station manning levels. Start Fuel – Fuel consumed from first fire of start process (initial reactor criticality for nuclear units) to breaker closing and fuel expended from breaker opening of the previous shutdown to initialization of the unit start-up, excluding normal plant heating/auxiliary equipment fuel requirements.
3.4.1
Hot Start Cost
Hot start cost is the expected cost to start a steam unit, which is in the "hot" condition. Hot conditions vary unit by unit, but in general, a unit is hot after an overnight shutdown. Components of hot start cost include:
Total fuel-related cost from first fire of start process (initial reactor criticality for nuclear units) to breaker closing priced at the cost of fuel currently in effect
And shutdown fuel cost defined as the cost of fuel expended from breaker opening of the previous shutdown to initialization of the (hot) unit start-up, excluding normal plant heating/auxiliary equipment fuel requirements.
3.4.2
Intermediate Start Cost
Intermediate start cost is the expected cost to start a steam unit during a period where neither hot or cold conditions apply. Use of intermediate start cost is optional based on Market Participant’s policy and physical machine characteristics. The only restriction is that once an intermediate start cost is defined for a unit, the cost must be used consistently in scheduling and accounting. Components of intermediate start cost include:
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Total fuel-related cost from first fire (initial reactor criticality for nuclear units) to breaker closing priced at the cost of fuel currently in effect
And shutdown fuel cost defined as the cost of fuel expended from breaker opening of the previous shutdown to initialization of the (intermediate) unit start-up, excluding normal plant heating/auxiliary equipment fuel requirements.
3.4.3
Cold Start Cost
Cold start cost is the expected cost to start a steam unit that is in the “cold” condition. Cold conditions vary unit by unit, but in general, a unit is cold after a two or three-day shutdown. Components of cold start cost include:
Total fuel-related cost from first fire (initial reactor criticality for nuclear units) to breaker closing priced at the cost of fuel currently in effect
And shutdown fuel cost defined as the cost of fuel expended from breaker opening of the previous shutdown to shutdown of equipment needed for normal cool down of plant components, excluding normal plant heating/auxiliary equipment fuel requirements.
3.4.4
Additional Components Applied to Hot, Intermediate and Cold Start-Up Costs
These additional components for station service, labor and Start VOM apply to all types of starts and should be added to the cost.
Station service from initiation of start sequence to breaker closing (total station use minus normal base station use) priced at the Station Service rate.
Station service after breaker opening during shutdown (station service during shutdown should be that associated with the normal unit auxiliary equipment operated during shutdown in excess of base unit use, this station service is not to include VOM or nonnormal use) priced at the Station Service rate.
Additional labor costs in excess of normal station manning requirements that are incurred when starting the unit that is not accounted for in VOM Adder.
Start VOM Adder.
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3.5
Mitigated No Load Offer Note: The information in Section 2.7 contains basic Mitigated No Load Offer information relevant for all unit types including nuclear units.
3.6
VOM Cost Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types including nuclear units.
Nuclear VOM Cost - The historical dollars per unit of fuel (or heat) as derived from FERC Accounts 530 and 531 for nuclear steam units.
3.6.1
Configuration Addition VOM Adder
For units undergoing a significant system or unit Configuration Addition the use of an additional “Configuration Addition VOM Adder” may be included in the determination of the total maintenance adder. It is not intended to be used for upgrades to existing equipment. Examples of significant system or unit Configuration Additions may include but are not limited to:
Conversion from open loop to closed loop circulation water systems
The specific system or unit configuration system change must be reviewed by the MMU for evaluation pursuant to the Mitigated Offer Methodology Approval Process prior to approving the use of a Configuration Addition Maintenance adder.
3.6.2
Calculation of the Configuration Addition VOM Adder:
The Configuration Addition Maintenance adder (“CAMA”) is to be calculated in the same manner as the VOM cost adder described in this section with the exception that the Configuration Addition VOM total maintenance dollars are only the incremental additional costs incurred because of the system or unit configuration change. As with the current maintenance adder calculation, the adder for year (Y) uses the actual costs beginning with year (Y-1). Therefore, the first year of actual incremental additional expenses will be captured by the CAMA in the second year.
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Following the initial year of use of the CAMA, each additional year’s Configuration Addition VOM cost will be incorporated into the Configuration Addition Maintenance adder until the end of the historical maintenance cost period selected for the unit. To calculate the Configuration Addition VOM Adder, calculate the solely incremental VOM Cost for the Configuration Change. Please note these expenses are purely incremental.
3.6.3
Reductions in Total VOM Costs:
While it is expected that the Configuration Addition VOM adder will most often be used to cover step increases in VOM costs, it is also to be used to capture step decreases in VOM costs resulting from a significant system or unit configuration change that results in a significant reduction in VOM costs. Any equipment that falls into disuse or is retired because of the configuration change must have its VOM expenses removed from the historical record used to develop the VOM adder. An example of a significant system or unit configuration change that may result in a step decrease in qualified VOM costs includes, but is not limited to, conversion from open loop to closed loop circulation water systems.
3.7
Mitigated Spinning Reserve Offer Note: The information in Section 2.8 contains basic Spinning Reserve information relevant for all unit types including nuclear units where applicable.
3.8
Mitigated Supplemental Reserve Offer Note: The information in Section 2.9 contains basic Supplemental Reserve information relevant for all unit types including nuclear units where applicable.
3.9
Mitigated Regulation Offers Note: The information in Section 2.10 contains basic Regulation information relevant for all unit types including nuclear units where applicable.
4.
Fossil Steam Unit Guidelines
This section contains information pertaining to Fossil Steam Unit mitigated offer development.
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Fossil Steam Turbine plants use combusted fossil fuels to heat water and create steam that generates the dynamic pressure to turn the blades of a steam turbine resource.
4.1
Heat Rate Note: The information in Section 2.1 contains basic Heat Rate information relevant for all unit types including fossil steam units.
4.2
Performance Factor Note: The information in Section 2.2 contains basic Performance Factor information relevant for all unit types. The following information only pertains to fossil steam units.
Like units that can be used for calculation of performance factors are units having similar ratings, steam conditions, make or model and same site location.
4.3
Fuel Cost Note: The information in Section 2.3 contains basic Fuel information relevant for all unit types. The following information only pertains to fossil steam units.
Fossil fuel cost adjustments compensating for previous estimate inaccuracies should not be considered when determining the basic fossil cost component of Total Fuel Related Cost . Fossil Other Fuel-Related Costs - the dollars in FERC Account 501 Fuel plus incremental expenses for fuel treatment and pollution control (excluding SO2 and NOX emission allowance costs) that were not included in Account 501; minus the fuel expenses from FERC Account 151 that were charged into Account 501, all divided by the fuel (heat content or quantity) shifted from Account 151 into Account 501.
4.4
Hot Start Cost, Intermediate Start Cost, and Cold Start cost Note: The information in Section 2.4 contains basic Start Cost information relevant for all unit types. The following information only pertains to fossil steam units.
𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑆𝑡𝑎𝑟𝑡-𝑈𝑝 𝑂𝑓𝑓𝑒𝑟($⁄𝑆𝑡𝑎𝑟𝑡) =
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[𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑 (𝑚𝑚𝐵𝑡𝑢 ⁄𝑆𝑡𝑎𝑟𝑡) ∗ 𝑇𝐹𝑅𝐶 ($⁄𝑚𝑚𝐵𝑡𝑢) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟] + [𝑆𝑡𝑎𝑡𝑖𝑜𝑛 𝑆𝑒𝑟𝑣𝑖𝑐𝑒(𝑀𝑊ℎ/𝑆𝑡𝑎𝑟𝑡) ∗ 𝑆𝑡𝑎𝑡𝑖𝑜𝑛 𝑆𝑒𝑟𝑣𝑖𝑐𝑒 𝑅𝑎𝑡𝑒($⁄𝑀𝑊ℎ)] + 𝑆𝑡𝑎𝑟𝑡 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟($⁄𝑆𝑡𝑎𝑟𝑡) + 𝑆𝑡𝑎𝑟𝑡 𝐴𝑑𝑑𝑖𝑡𝑖𝑜𝑛𝑎𝑙 𝐿𝑎𝑏𝑜𝑟 𝐶𝑜𝑠𝑡($⁄𝑆𝑡𝑎𝑟𝑡) + [𝑆ℎ𝑢𝑡-𝐷𝑜𝑤𝑛 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢 ⁄𝑆𝑡𝑎𝑟𝑡) ∗ 𝑇𝐹𝑅𝐶($⁄𝑚𝑚𝐵𝑡𝑢 ) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟]
4.4.1
Hot Start Cost
Hot start cost is the expected cost to start a steam unit, which is in the “hot” condition. Hot conditions vary unit by unit, but in general, a unit is hot after an overnight shutdown. Components of hot start cost include: Start Fuel Consumed is the amount of fuel consumed from first fire of start process to breaker closing (including auxiliary boiler fuel). Shutdown Fuel Consumed is the amount of fuel consumed from breaker opening of the previous shutdown to initialization of the (hot) unit start-up, excluding normal plant heating/auxiliary equipment fuel requirements. Station Service from initiation of start sequence to breaker closing (total station use minus normal base station use) priced at the Station Service rate and station service after breaker opening during shutdown (station service during shutdown should be that associated with the normal unit auxiliary equipment operated during shutdown in excess of base unit use, this station service is not to include VOM or non-normal use) priced at the Station Service rate. Additional labor costs in excess of normal station manning requirements that are incurred when starting the unit. Start VOM Adder - Section 3.6 contains information regarding calculation of VOM Adder.
4.4.2
Intermediate Start Cost
Intermediate start cost is the expected cost to start a steam unit during a period where neither hot nor cold conditions apply. Use of intermediate start cost is optional based on company policy and physical machine characteristics. The only restriction is that once an intermediate start cost is defined for a unit, the cost must be used consistently in scheduling and accounting. Components of intermediate start cost include: Start Fuel Consumed is the amount of fuel consumed from first fire of start process to breaker closing (including auxiliary boiler fuel).
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Shutdown Fuel Consumed is the amount of fuel consumed from breaker opening of the previous shutdown to initialization of the (intermediate) unit start-up, excluding normal plant heating/auxiliary equipment fuel requirements. Station Service from initiation of start sequence to breaker closing (total station use minus normal base station use) priced at the Station Service rate and station service after breaker opening during shutdown (station service during shutdown should be that associated with the normal unit auxiliary equipment operated during shutdown in excess of base unit use, this station service is not to include VOM or non-normal use) priced at the Station Service rate. Additional labor costs in excess of normal station manning requirements that are incurred when starting the unit. Start VOM Adder - Section 2.6 contains information for calculation of the Start VOM Adder.
4.4.3
Cold Start Cost
Cold start cost is the expected cost to start a steam unit that is in the “cold” condition. Cold conditions vary unit by unit, but in general, a unit is cold after a two or three-day shutdown. Components of cold start cost include: Start Fuel Consumed is the amount of fuel consumed from first fire of start process to breaker closing (including auxiliary boiler fuel). Shutdown Fuel Consumed is the amount of fuel consumed from breaker opening of the previous shutdown to initialization of the (cold) unit start-up, excluding normal plant heating/auxiliary equipment fuel requirements. Station Service from initiation of start sequence to breaker closing (total station use minus normal base station use) priced at the Station Service rate and station service after breaker opening during shutdown (station service during shutdown should be that associated with the normal unit auxiliary equipment operated during shutdown in excess of base unit use, this station service is not to include VOM or non-normal uses) priced at the Station Service rate. Additional labor costs in excess of normal station manning requirements that are incurred when starting the unit. Start VOM Adder - Section 2.6 contains information for calculation of the Start VOM Adder.
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4.5
Mitigated No Load Offer Note: The information in Section 2.7 contains basic Mitigated No Load Offer information relevant for all unit types including fossil steam units.
4.6
VOM Cost Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following information only pertains to fossil steam units.
Fossil Steam - VOM Cost - is the historical VOM dollars as derived from FERC Accounts 512 and 513 for fossil steam units. Units with less than 1 year of history are considered immature. Such units can be assigned their calculated Maintenance Adder and/or Start Cost Maintenance Adder, or a forecast value, subject to evaluation pursuant to the Mitigated Offer Methodology Approval Process.
4.6.1
Configuration Addition VOM Adder
For units undergoing a significant system or unit Configuration Addition the use of an additional “Configuration Addition VOM Adder” may be included in the determination of the total VOM adder. It is not intended to be used for upgrades to existing equipment (i. e. : replacement of a standard burner with a low NOX burner). Examples of significant system or unit Configuration Additions may include but are not limited to:
Installation of Flue Gas Desulfurization (FGD or scrubber) systems
Activated Carbon Injection (ACI) or other sorbent injection systems
Installation of SCR or SNCR NOX removal systems
Conversion from open loop to closed loop circulation water systems
Bag House addition
Water injection for NOX control
Gas Turbine Inlet Air Cooling
Dry Sorbent Injection (DSI)
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The specific system or unit configuration system change needs to be reviewed by the MMU pursuant to the Mitigated Offer Methodology Approval Process and receive final approval thereof prior to the use of a Configuration Addition VOM Adder.
4.6.2
Calculation of the Configuration Addition VOM Adder
The Configuration Addition VOM Cost (CAVC) is to be calculated in the same manner as the VOM Adder described in this section with the exception that the Configuration Addition VOM Cost dollars are only the incremental additional costs incurred because of the system or unit configuration change. As with the current VOM dollar calculation under Section 2.4, the adder for year (Y) uses the actual costs beginning with year (Y-1). Therefore, the first year of actual incremental additional expenses will be captured by the CAVC in the second year. Following the initial year of use of the CAVA, each additional year‘s CAVA will be incorporated into the total until the end of the historical Maintenance Period selected for the unit.
4.6.3
Reductions in Total VOM Costs
While it is expected that the Configuration Addition VOM adder will most often be used to cover step increases in VOM costs, it is also to be used to capture step decreases in VOM costs resulting from a significant system or unit configuration change that results in a significant reduction in VOM costs. Any equipment that falls into disuse or is retired because of the configuration change must have its VOM expenses removed from the historical record used to develop the VOM adder. An example of a significant system or unit configuration change that may result in a step decrease in qualified VOM costs includes, but is not limited to, a fuel change from coal to gas fuel.
4.7
Mitigated Spinning Reserve Offer Note: The information in Section 2.8 contains basic Spinning Reserve information relevant for all unit types.
4.8
Mitigated Supplemental Reserve Offer Note: The information in Section 2.9 contains basic Supplemental Reserves information relevant for all unit types including fossil steam units.
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4.9
Regulation Note: The information in Section 2.10 contains basic Regulation Cost information relevant for all unit types including fossil steam units.
5.
Combined Cycle (CC) Guidelines
This section contains information pertaining to Combined Cycle Cost development. Combined Cycle - An electric generating technology in which electricity is generated by both a combustion turbine resource (the Brayton Cycle) and a steam turbine resource (the Rankine Cycle) hence the name combined cycle. The CT exhaust heat flows to a conventional boiler or to a heat recovery steam resource (HRSG) to produce steam for use by a steam turbine resource in the production of electricity. Heat recovery steam resource (HRSG) – A CT exhaust feeds hot gas into a heat to steam exchanger installed on combined-cycle power plants designed to utilize the heat in the combustion turbine exhaust to produce steam to drive a conventional steam turbine resource. The HRSG may or may not also include a supplemental source of heat, e.g. duct firing.
5.1
Heat Rate Note: The information in Section 2.1 contains basic Heat Rate information relevant for all unit types including combined cycle units.
5.2
Performance Factors Note: The information in Section 2.2 contains basic Performance Factor information relevant for all unit types including combined cycle units.
5.3
Fuel Cost Note: The information in Section 2.3contains basic Fuel Cost information relevant for all unit types including combined cycle units.
5.4
Mitigated Start-Up Offer Note: The information in Section 2.4 contains basic Mitigated Start-Up Offer information relevant for all unit types. The following additional information only pertains to combined cycle units.
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Start costs for Combined Cycle (CC) plants shall include only the following components and shall never be less than zero: 𝑆𝑡𝑎𝑟𝑡 𝐶𝑜𝑠𝑡 ($⁄𝑆𝑡𝑎𝑟𝑡) = (𝑆𝑡𝑎𝑟𝑡 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢 ⁄𝑆𝑡𝑎𝑟𝑡) ∗ 𝑇𝐹𝑅𝐶($⁄𝑚𝑚𝐵𝑡𝑢 ) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟) + (𝑆𝑡𝑎𝑡𝑖𝑜𝑛 𝑆𝑒𝑟𝑣𝑖𝑐𝑒 (𝑀𝑊ℎ) ∗ 𝑆𝑡𝑎𝑡𝑖𝑜𝑛 𝑆𝑒𝑟𝑣𝑖𝑐𝑒 𝑅𝑎𝑡𝑒($⁄𝑀𝑊ℎ)) + 𝑆𝑡𝑎𝑟𝑡 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟($⁄𝑆𝑡𝑎𝑟𝑡) + 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐿𝑎𝑏𝑜𝑟 𝐶𝑜𝑠𝑡($⁄𝑆𝑡𝑎𝑟𝑡) Start cost can be calculated and offered for Hot, Intermediate and Cold Start conditions. Start Fuel Consumed is the amount of fuel consumed from first CT fire to breaker closing for the steam turbine resource, as measured during a normal start sequence, and the amount of fuel consumed from breaker opening for the steam turbine resource to fuel valve closure. Additionally, for Combined Cycle Resources not registered under configuration based option, this includes the amount of fuel consumed from CT first fire to the point where heat recovery steam resource (HRSG) steam pressure matches steam turbine inlet pressure, for any CT unit/HRSG combinations started after synchronization of the steam turbine resource. Station service is included from initiation of start sequence of initial combustion turbine to breaker closing of the steam turbine resource (total station use minus normal base station use) priced at the Station Service Rate. Add to this (+) station service after breaker opening of the last component when finished operating as a combined cycle unit, priced at the Station Service rate. (Station service during shutdown should be that associated with the normal unit auxiliary equipment operated during shutdown in excess of base unit use. This station service is not to include VOM or non-normal uses. ) Minus (-) the integration of net generation from CT synchronization to steam turbine resource synchronization or to HRSG steam output at line pressure, priced at the actual cost of the unit. Minus (-) the integration of net generation during the shutdown period, priced at the actual cost of the unit. Incremental labor costs in excess of normal station manning requirements (only when necessary to start the CC unit). Start VOM Adder - this quantity includes Start VOM $ for CT Starting from CT breaker closing to steam turbine resource breaker closing and from steam turbine resource breaker opening at the start of unit shutdown to CT breaker opening.
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5.5
Mitigated Transition State Offer
𝑀𝑖𝑡𝑖𝑔𝑎𝑡𝑒𝑑 𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛 𝑆𝑡𝑎𝑡𝑒 𝑂𝑓𝑓𝑒𝑟($⁄𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛) = (𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑(𝑚𝑚𝐵𝑡𝑢 ⁄𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛) ∗ 𝑇𝐹𝑅𝐶($⁄𝑚𝑚𝐵𝑡𝑢 ) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟) + 𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($⁄𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛) + 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐿𝑎𝑏𝑜𝑟 𝐶𝑜𝑠𝑡($⁄𝑇𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛) Transition Fuel Consumed is the amount of additional fuel consumed moving from the current configuration to another configuration (i.e. moving from a 1 X 1 to a 2 X 1) Incremental transition labor costs in excess of normal station manning requirements (only when necessary to transition the CC to a different configuration) Transition VOM Cost - this quantity includes Transition VOM $ incurred moving from the current configuration to another configuration (i.e. moving from a 1 X 1 to a 2 X 1)
5.55.6
Mitigated No Load Offer Note: The information in Section 2.7 contains basic No Load information relevant for all unit types including combined cycle units.
5.65.7
VOM Cost Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to combined cycle units.
Combined Cycle VOM Cost – the historical VOM dollars as derived from FERC Accounts 512, 513, and 553. If submitting as a simple cycle combustion turbine, use total dollars from FERC Account 553.
5.75.8
Mitigated Spinning Reserve Offer Note: The information in Section 2.8 contains basic Spinning Reserve information relevant for all unit types.
5.85.9
Mitigated Supplemental Reserve Offer Note: The information in Section 2.9 contains basic Supplemental Reserve information relevant for all unit types including combined cycle units.
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5.95.10 Mitigated Regulation Offers Note: The information in Section2.10 contains basic Regulation information relevant for all unit types including combined cycle units.
Combustion Turbine (CT) and Reciprocating Engine Guidelines
6.
This section details specific information for the mitigated offer development for units that are Combustion turbine or reciprocating engine resources. Combustion Turbine Resource – A generating unit in which a natural gas or oil fired combustion turbine engine is the prime mover for an electrical resource. Reciprocating Engine Resource – A generating unit in which a reciprocating engine is the prime mover for an electrical resource.
6.1
Combustion Turbine and Reciprocating Engine Heat Rate Note: The information in Section 2.1 contains basic Heat Rate information relevant for all unit types, including CTs and Reciprocating Engines.
6.2
Performance Factor Note: The information in Section 2.2 contains basic Performance Factor information relevant for all unit types. The following additional information only pertains to CT, diesel and reciprocating engine units.
“Like” Combustion Turbine Units - An average performance factor may be calculated and applied for groups of like units burning the same type of fuel. “Like” includes same primary manufacturer not necessarily engine or resource manufacturer, but one with overall system responsibility. The following are two examples:
Worthington sells CT's with P&W engines and a GE resource. Worthington would be considered the primary manufacturer.
Same general frame size - a manufacturer may modify a basic design to produce units with varying capabilities. Units built with such variations may be placed in a single group.
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6.3
Fuel Cost Note: The information in Section 2.3 contains basic Fuel Cost information relevant for all unit types including CTs, and reciprocating diesel engine units.
6.3.1
Combustion Turbine other Fuel-Related Costs
The dollars in FERC Account 547, plus incremental expenses for fuel treatment and pollution control excluding SO2 and NOX emission allowance costs that were not included in Account 547; minus the fuel expenses from FERC Account 151 that were charged into Account 547, all divided by the fuel (heat content or quantity) shifted from Account 151 into Account 547.
6.4
Energy Offer Curve for Quick Start Note: The information in Section 2.5 contains basic Mitigated Energy Offer Curve information relevant for all unit types. The following additional information only pertains to SCED Quick Start units.
A Quick Start Resource is a Resource that dispatched directly by SCED in the RTBM. A Quick Start Resource that is dispatched by the Real-Time Balancing Market (SCED, as opposed to SCUC or RUC), may include start-up costs as part of the Mitigated Energy Offer Curve. If Start-Up Adder and No-Load Adder are used here, the Mitigated Start-up Offer under Section 2.6 and the Mitigated No-Load Offer under Section 2.7 must be equal to zero. Mitigated Energy Offer ($/MWh) = (Heat Rate (mmBtu/MWh) * Performance Factor * Total Fuel Related Costs ($/mmBtu)) + Start VOM ($/MWh) + Start-Up Adder ($/MWh) + No Load Adder ($/MWh) The Start-Up Adder is computed as the cost to start the Resource divided by the average energy during the minimum run time: Start-Up Adder ($/MWh) = Start-Up Costs ($/Start) / Average Energy During Minimum Run Time (MWh/start) The average energy during minimum run time is the average energy output during the minimum run time for SCED quick start deployments during the past year. 𝐴𝑣. 𝐸𝑛𝑒𝑟𝑔𝑦 𝑑𝑢𝑟𝑖𝑛𝑔 𝑀𝑖𝑛. 𝑅𝑢𝑛 𝑇𝑖𝑚𝑒 (𝑀𝑊ℎ⁄𝑠𝑡𝑎𝑟𝑡) =
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𝐴𝑣𝑒𝑟𝑎𝑔𝑒 % 𝑜𝑓 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐸𝑐𝑜𝑛𝑜𝑚𝑖𝑐 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐿𝑖𝑚𝑖𝑡 ∗ 𝑀𝑎𝑥. 𝐸𝑐𝑜𝑛. 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝑂𝑝. 𝐿𝑖𝑚𝑖𝑡(𝑀𝑊) ∗ 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑅𝑢𝑛 𝑇𝑖𝑚𝑒(ℎ𝑜𝑢𝑟𝑠) No Load Adder ($/MWh) = No Load Costs ($/hour) / Average Hourly MWh output The average hourly output during an hour is the sum of the energy output during SCED quick start deployments during the past year divided by the number of hours of SCED deployments in the past year.
6.5
Mitigated Start-Up Offer Note: The information in Section 2.6 contains basic Mitigated Start-Up Offer information relevant for all unit types, including combustion turbine and reciprocating engine resource units that are not operating as SCED dispatchable Resources as described under Section 6.4.
6.6
Mitigated No Load Offer for CTs Note: The information in Section 2.7 contains basic No Load information relevant for all unit types, including CTs, diesel engines and reciprocating engines that are not operating as SCED dispatchable Resources as described under Section 6.4. .
6.7
VOM Cost Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to CT and diesel engine units.
Combustion Turbine - VOM Cost – The historical total dollars from FERC Account 553 should be used to calculate the VOM $ specified under Section 2.4.
6.8
Mitigated Spinning Reserve Offer Note: The information in Section 2.8 contains basic Spinning Reserve information relevant for all unit types. The following additional information only pertains to CT, diesel and reciprocating engine units with synchronous condenser capability.
Total spinning costs for combustion turbine and reciprocating engine resources with synchronous condenser capability shall include the following components:
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Start costs if applicable, shall be applied when a unit moves from on off-line status to synchronization with the grid but shall not be applied when a unit moves from energy generation to an off-line status..
VOM cost in $/Hr divided by the Spinning MW provided.
Actual cost of power consumed during condensing operations at real time bus LMP as determined by Market Settlements. MW consumed must be included in the offer.
6.9
Mitigated Supplemental Reserve Offer
Note: The information in Section 2.9 contains basic Supplemental Reserve information relevant for all unit types, including CT, diesel and reciprocating engine units.
6.10
Mitigated Regulation Offers Note: The information in Section 2.10 contains basic Regulation information relevant for all unit types, including CT, diesel and reciprocating engine units.
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7.
Hydro Guidelines
This section contains information for the development of Hydro or Hydro Pumped Storage cost offers. Hydro Unit – Generating unit in which the energy of flowing water drives the turbine resource to produce electricity. This classification includes pumped and run-of-river hydro. Pumped Hydro Unit – Hydroelectric power generation that stores energy in the form of water by pumping from a lower elevation source to a higher elevation reservoir, then allowing the upper reservoir to drain turning the turbines to produce power.
7.1
Pumping Efficiency (Pumped Hydro Only)
Pumping Efficiency is the Pumped Hydro Unit’s version of a heat rate. It measures the ratio of generation produced to the amount of generation used as fuel. Pumping Efficiency (PE) is calculated by dividing the MWh of generation produced while operating in generation mode by the MWh required to pump the water needed to produce the generation MWh. 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 =
𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑜𝑑𝑢𝑐𝑒𝑑 𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑢𝑚𝑝𝑒𝑑 𝑎𝑠 𝐹𝑢𝑒𝑙
For example, it requires 1,000 ft3 to produce one MWh of generation as water flows from the pond to the sink and it requires two MWh of pumping load to pump 1,000 ft3 of water from the sink to the pond. The resultant efficiency is: 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 =
𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑜𝑑𝑢𝑐𝑒𝑑 3. 5 𝑀𝑊ℎ (𝑔𝑒𝑛𝑒𝑟𝑎𝑡𝑒𝑑) = 𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑢𝑚𝑝𝑒𝑑 𝑎𝑠 𝐹𝑢𝑒𝑙 5 𝑀𝑊ℎ (𝑝𝑢𝑚𝑝𝑒𝑑)
= 0. 70 In order to account for environmental and physical factors associated with the characteristics of the pond and pumping operations that limit the accuracy of calculating short term pumping efficiency, a seven day rolling total of pumping and generation MWh are utilized for pumping efficiency calculations. PE can be calculated by one of three methods. An owner must make the choice of method by December 31 prior to the year of operation and cannot change to another method for a period of one calendar year.
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Option 1: Twelve month calendar actual Pumping Efficiency. o The previous 12-month calendar year average Pumping Efficiency based on actual pumping operations.
Option 2: Three month rolling Pumping Efficiency. o The previous three months rolling actual efficiency where the average monthly availability is 50% or greater. The calculation must be updated after each month.
Option 3: The previous month actual Pumping Efficiency. o The previous month actual efficiency where the availability is 50% or greater. The calculation must be updated monthly.
7.2
Performance Factors Note: The information in Section 2.2 contains basic Performance Factor information relevant for all unit types. The following additional information only pertains to hydro units.
7.3
Fuel Cost
To be consistent with other SPP units within this manual the term fuel cost is used to account for the energy necessary to pump from the lower reservoir to the upper reservoir. Note: The information in Section 2.3 contains basic Fuel Cost information relevant for all unit types. The following additional information only pertains to pumped hydro units. If, a Market Participant wishes to change its method of calculation of pumped storage TFRC, the Market Participant shall notify the SPP MMU in writing by December 31 prior to the year of operation, to be evaluated pursuant to the Mitigated Offer Methodology Approval Process before the beginning of the cycle in which the new method is to become effective. The new cycle starts on February 1st and continues for a period of one year. Pumped Storage Fuel Cost – Pumped storage fuel cost shall be calculated on a seven (7) day rolling basis by multiplying the real time bus LMP at the plant node by the actual power consumed when pumping. The following equations govern pumping storage fuel cost: 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝑃𝑜𝑤𝑒𝑟 𝐶𝑜𝑠𝑡($⁄𝑀𝑊ℎ) =
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∑ 𝑅𝑒𝑎𝑙 𝑇𝑖𝑚𝑒 𝐿𝑀𝑃 ($/𝑀𝑊ℎ) ∗ 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝑃𝑜𝑤𝑒𝑟 (𝑀𝑊ℎ) 𝑇𝑜𝑡𝑎𝑙 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝑃𝑜𝑤𝑒𝑟 (𝑀𝑊ℎ) ∗ 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝐸𝑓𝑓𝑖𝑐𝑒𝑛𝑐𝑦
7.3.1
Total Energy Input Related Costs for Pumped Storage Hydro Plant Generation
Total energy input-related costs for all pumped storage hydro units shall be defined as follows: 𝑃𝑢𝑚𝑝𝑒𝑑 𝑆𝑡𝑜𝑟𝑎𝑔𝑒 𝐻𝑦𝑑𝑟𝑜 𝑇𝑜𝑡𝑎𝑙 𝐸𝑛𝑒𝑟𝑔𝑦 𝐼𝑛𝑝𝑢𝑡 𝑅𝑒𝑙𝑎𝑡𝑒𝑑 𝐶𝑜𝑠𝑡($/𝑀𝑊ℎ) = 𝑃𝑢𝑚𝑝𝑖𝑛𝑔 𝑃𝑜𝑤𝑒𝑟 𝐶𝑜𝑠𝑡($/𝑀𝑊ℎ) + 𝐸𝑂𝐶 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($/𝑀𝑊ℎ)
7.4
Mitigated Start-Up Offer
Hydro Units do not have Start-up costs.
7.5
Mitigated No Load Offer
Hydro Units do not have No Load costs.
7.6
VOM Cost Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to hydro units.
The historical total dollars from the FERC accounts listed here should be used to calculate the VOM $ specified under Section 2.4. The cost of labor, materials used and expenses incurred in the maintenance of plant, includible in Account 332, Reservoirs, Dams, and Waterways. (See operating expense instruction 2). The cost of labor materials used and expenses incurred in the maintenance of fish and wildlife, and recreation facilities, the book cost of which is includible in Account 332, Reservoirs, Dams, and Waterways, includable in Account 545, Maintenance of Miscellaneous Hydraulic Plant.
7.7
Spinning Reserve: Hydro Unit Costs Note: The information in Section 2.8 contains basic Spinning Reserve information relevant for all unit types. The following additional information only pertains to hydro units if applicable.
Total spinning costs for Hydro units shall include the following components:
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𝐻𝑦𝑑𝑟𝑜 𝐶𝑜𝑠𝑡𝑠 𝑡𝑜 𝐶𝑜𝑛𝑑𝑒𝑛𝑠𝑒 ($⁄𝑀𝑊 ) $ 𝑆𝑡𝑎𝑟𝑡 𝐶𝑜𝑠𝑡𝑠 ($) + (𝑃𝑜𝑤𝑒𝑟 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑 (𝑀𝑊ℎ) ∗ 𝐿𝑀𝑃 ( )) + 𝑉𝑂𝑀($/ℎ𝑜𝑢𝑟) 𝑀𝑊ℎ =( ) 𝑆𝑝𝑖𝑛𝑛𝑖𝑛𝑔 𝑅𝑒𝑠𝑒𝑟𝑣𝑒 𝑀𝑊 Start costs – if applicable, start costs shall be applied when a unit moves from cold to condensing operations and when a unit moves from condensing operations to energy generation, but shall not be applied when a unit moves from energy generation to condensing operations. In addition (+) identified variable Operating and Maintenance cost in $/hour divided by the Spinning MW provided. These costs shall be totaled over the Maintenance Period and divided by total MWh generated over the maintenance period. These variable Operating and Maintenance costs shall include:
Maintenance of Electric Plant as derived from FERC Account 544
Maintenance of Reservoirs as derived from FERC Account 543
Total hydro condensing offers must be expressed in dollars per hour per MW of Spinning Reserve ($/MW) and must specify the total MW of Spinning Reserve offered.
7.8
Mitigated Supplemental Reserve Offer Note: The information in Section 2.9 contains basic Supplemental Reserve information relevant for all unit types including Hydro units.
7.9
Mitigated Regulation Offers Note: The information in Section 2.10 contains basic Regulation information relevant for all unit types.
8.
Demand Response Guidelines
A Demand Response Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind-the-meter resource that is dispatchable either on a 5-minute basis or an hourly basis;
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8.1
Demand Response Resource (DRR) Cost for Behind the Meter Generation
Market Participants using behind the meter resource as a DDR Resource should refer to the appropriate unit type defined in this manual to develop incremental cost,
8.2
DRR Cost for Demand Reduction
Demand Reduction is the actual reduction of load at the direction of SPP through the commitment and dispatch of as associated DRR. This could include the cycling of air conditioners or the shutdown of an industrial production process in order to reduce the load at a site. Incremental costs can include quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage. Typically, demand reduction would be registered as a Block Demand Response Resource but an industrial site that can control its load consumption on a real-time basis could register as a Dispatchable Demand Response Resource.
8.3
DRR Start-Up Cost
DRR Start-Up cost is the cost to shut down or curtail a load for a given period, which does not vary with output, or the start cost of a behind the meter resource. Start costs for DRRs represented by behind-the-meter resources are defined by unit type in this manual. Start-Up costs for DRRs representing load curtailment are not specifically defined but will be evaluated on a case by case basis when submitted as part of a Market Participants fuel cost policy for reasonableness.
8.4
DRR Cost to Provide Spinning and/or Supplemental Reserves
Spinning Reserves from Demand Response Resources must be provided by equipment electrically synchronized to the system, and able to be fully deployed for the cleared amount within ten minutes upon request by SPP. The costs of spinning reserves from a DRR are the quantifiable incremental costs to reduce load by the offered amount within ten minutes. Incremental costs include shut down costs and opportunity costs.
8.5
DRR Cost to Provide Regulation
Regulation-Up and/or Regulation-Down from Dispatchable Demand Response Resources must be provided by equipment electrically synchronized to the system and able qualify for provision of regulation services. The costs of regulation from DDR Resources are the quantifiable
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incremental costs to reduce load by the offered amount within five minutes. Incremental costs include shut down costs and opportunity costs.
9.
Wind Guidelines
Wind Units- Generating unit in which wind spins the turbine resource to produce electricity.
9.1
Fuel Cost
Wind Units may include applicable costs that vary by MWh output.
9.2
Mitigated Start-Up Offer
Wind Units do not have start costs.
9.3
Mitigated No Load Offer
Wind Units do not have No Load costs.
9.4
VOM
Wind units should reflect their short-run incremental VOM costs by using the most current data available. This could include the previous actual short-run incremental cost where available. For wind units, VOM dollars from the previous years should be divided by MWh generated in the same period. 𝐸𝑂𝐶 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟 ($/𝑀𝑊ℎ) =
10.
𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 ($) 𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑜𝑑𝑢𝑐𝑒𝑑
Solar Guidelines
Solar photovoltaic - Generating unit in which light from the sun is converted into electricity through solar cells. Solar thermal – Generating unit in which heat from the sun is used to create steam that spins a turbine to generate electricity.
10.1
Fuel Cost
Solar Units may include applicable costs that vary by MWh output.
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10.2
Mitigated Start-Up Offer
Solar Units do not have start costs.
10.3
Mitigated No Load Offer
Solar Units do not have No Load costs.
10.4
VOM
Solar units should reflect their short-run incremental VOM costs by using the most current data available. This could include the previous actual short-run incremental cost where available. For solar units, VOM dollars from the previous years should be divided by MWh generated in the same period. 𝐸𝑂𝐶 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟 ($/𝑀𝑊ℎ) =
𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 ($) 𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑜𝑑𝑢𝑐𝑒𝑑
11.
Energy Market Opportunity Cost Guidelines
11.1
Basis for Opportunity Cost to be Included in Mitigated Offers
Opportunity Cost may be a component of mitigated offers under certain circumstances. There are two reasons for application of Opportunity Costs as contained in this section.
11.1.1
Environmental Run-hour Restriction
Opportunity costs associated with an externally imposed environmental run-hour restriction on a generation unit. Examples would include a limit on emissions for the unit imposed by a regulatory agency or legislation, a direct run hour restriction in the operating permit, or a heat input limitation defined by a regulatory decision or operating permit. Environmental run-hour restrictions must have suitable supporting documentation.
11.1.2
Physical Equipment Limitations
Physical equipment limitations that cause the unit to experience a restriction in the number of starts or run hours would be eligible for opportunity cost. Physical equipment limitations must
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have supporting evidence submitted by the Asset Owner. Documentation such as an OEM recommendation or bulletin and/or insurance carrier restrictions would meet this criterion.
11.1.3
Non-Regulatory Opportunity Cost: Fuel Limitations
Fuel Limitations are eligible for Non-Regulatory Opportunity Costs for a fuel supply limitation, for up to one year, resulting from an event of force majeure. Force Majeure is defined as: Any cause beyond the control of the affected Interconnection Party or Construction Party, including but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of due diligence such party could not reasonably have been expected to avoid, and which, by the exercise of due diligence, it has been unable to overcome. Force Majeure does not include (i) a failure of performance that is due to an affected party’s own negligence or intentional wrongdoing; (ii) any removable or remediable causes (other than settlement of a strike or labor dispute) which an affected party fails to remove or remedy within a reasonable time; or (iii) economic hardship of an affected party.
11.2
Calculation Method
Market Participants may opt to follow the method proposed here, or they may develop alternative methods specific to their Resources and submit those methods to the SPP MMU for approval. Requests for inclusion of opportunity costs in offers using other methods not defined in the Mitigated Offer Development Guidelines should be initially submitted to the SPP MMU for evaluation under the Mitigated Offer Methodology Approval Process. Opportunity costs are a distinct component of the mitigated offer. As is the case with any computation of the mitigated offer, market participants may elect to enter their mitigated offer at a value less than the computed mitigated offer. However, they may not exceed the computed value.
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11.2.1
Overview of the Opportunity Cost Calculation
When added to the marginal cost of production in the Energy Offer Curve, the opportunity cost raises the offer to a level where the market dispatches the Resource up to, but not in excess of the run-time restriction. This is accomplished by 1. Forecasting LMPs and production costs for the resource, 2. Determining the market value of each potential run hour, revenue minus costs, 3. Ranking potential run hours (or blocks of run hours) during the restricted time frame by market value, 4. Identifying the opportunity cost adder as the market value of the lowest ranked hour (or block of hours), 5. Adding the opportunity cost adder to the Mitigated Energy Offer Curve. Opportunity cost calculations are based on daily, monthly, or annual run-time restrictions as applicable to the Resource. The run-time restriction parameters and supporting documentation must be submitted to the SPP MMU pursuant to the Mitigated Offer Methodology Approval Process (Section 1.6).
11.2.2
Daily Opportunity Cost Calculation
The daily opportunity cost calculation is used for Resources with a daily run-time restriction and a minimum run time that does not exceed one hour. This would include pumped storage hydro resources with externally imposed environmental restrictions on daily water levels. The daily calculation would typically be performed on operating day minus two (OD – 2) for the Day Ahead Market to run on OD – 1 for the operating day. 11.2.2.1
Step 1: Forecast Hourly Resource LMPs Inputs required for STEP 1:
Previous four weeks of hourly average RTBM LMPs at the Resource Settlement Location
To create a forecast for the Resource LMP, take the average LMP for the same hour of the day and day of the week for the last four weeks. (NERC holidays may be excluded from the four
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week history, and weekend days may be substituted for the same day of the week if the operating day is a NERC holiday.) 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑓𝑑,ℎ = (𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑓𝑑−7,ℎ + 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑓𝑑−14,ℎ + 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑓𝑑−21,ℎ + 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑓𝑑−28,ℎ )/4 For example, 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑁𝑜𝑣𝑒𝑚𝑏𝑒𝑟 5,2013 𝐻𝐸 9:00 = (𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑂𝑐𝑡𝑜𝑏𝑒𝑟 29,2013 𝐻𝐸 9:00 + 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑂𝑐𝑡𝑜𝑏𝑒𝑟 22,2013 𝐻𝐸 9:00 + 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑂𝑐𝑡𝑜𝑏𝑒𝑟 15,2013 𝐻𝐸 9:00 + 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑂𝑐𝑡𝑜𝑏𝑒𝑟 8,2013 𝐻𝐸 9:00 )/4 Output for STEP 1: 11.2.2.2
Hourly forecast Resource LMPs for the operating day
Step 2: Calculate the price-cost margin for each hour of the day Inputs required for STEP 2:
Output from Step 1
Expected future full load seasonal (May-September/October-April) heat rate for the compliance period
Total Fuel related costs as defined in Section 2
VOM as defined in Section 2
The hourly margin is the hourly price minus hourly production cost.
𝑀𝑎𝑟𝑔𝑖𝑛𝑓𝑑,ℎ = 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑓𝑑,ℎ − 𝐻𝑜𝑢𝑟𝑙𝑦𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛𝐶𝑜𝑠𝑡𝑓𝑑,ℎ , where 𝐻𝑜𝑢𝑟𝑙𝑦𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛𝐶𝑜𝑠𝑡𝑓𝑑,ℎ = 𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (𝑀𝐵𝑡𝑢/𝑀𝑊ℎ) 𝑋 𝑇𝑜𝑡𝑎𝑙𝐹𝑢𝑒𝑙𝑅𝑒𝑙𝑎𝑡𝑒𝑑𝐶𝑜𝑠𝑡𝑓𝑑,ℎ ($/ 𝑀𝐵𝑡𝑢) + 𝑉𝑂𝑀.
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Output for STEP 2: 11.2.2.3
24 hourly forecast profit margins for the operating day
Step 3: Determine the Opportunity Cost Component
The opportunity cost component for the Mitigated Energy Offer Curve is determined by ranking each potential run hour by its hourly margin, with the highest value hour ranked 1. The opportunity cost component is the hourly margin for the hour with rank equal to the run hour limit.
11.2.3
Long Term Opportunity Cost Calculation
The long term calculation applies to run-time restrictions that exceed 30 days. This method uses monthly forward prices as the basis for forecasts of fuel and electricity costs in the future. Opportunity costs calculated with this method will change frequently. Given that fuel futures can change daily, the opportunity costs computed can likewise change daily. Market Participants who include opportunity costs in their mitigated offers must recalculate their long term opportunity cost no less frequently than once per every 7 days. 11.2.3.1
Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPs Inputs required for STEP 1:
Natural Gas futures prices for Henry Hub and
A random number generator
The forecast of the average SPP LMP is obtained by simulating from the model below or an update to the model provided by the SPP Market Monitoring Unit. The first equation describes the relationship between the monthly average SPP LMP and the price of natural gas. The second equation describes random daily deviations in price that are persistent over time. 𝑜𝑛−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
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= 8.2429 + 6.1039 ∗ 𝐹𝑢𝑡𝑢𝑟𝑒𝐻𝑒𝑛𝑟𝑦𝐻𝑢𝑏𝑓𝑦,𝑚 + 𝑣𝑓𝑦,𝑚,𝑑
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𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑛−𝑝𝑒𝑎𝑘
𝑜𝑛−𝑝𝑒𝑎𝑘
= 0.5097 ∗ 𝑣𝑓𝑦,𝑚,𝑑−1 + 𝑒𝑓𝑦,𝑚,𝑑
𝑜𝑛−𝑝𝑒𝑎𝑘 𝑒𝑓𝑦,𝑚,𝑑 ~𝑁𝑜𝑟𝑚𝑎𝑙(0,29.5) 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
= 9.3146 + 3.4827 ∗ 𝐹𝑢𝑡𝑢𝑟𝑒𝐻𝑒𝑛𝑟𝑦𝐻𝑢𝑏𝑓𝑦,𝑚 + 𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
= 0.4942 ∗ 𝑣𝑓𝑦,𝑚,𝑑−1 + 𝑒𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑒𝑓𝑦,𝑚,𝑑
~𝑁𝑜𝑟𝑚𝑎𝑙(0,19.12)
𝑜𝑛−𝑝𝑒𝑎𝑘 To simulate the model, use a random number generator to obtain values for 𝑒𝑓𝑦,𝑚,0 and 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑒𝑓𝑦,𝑚,0
, the day prior to the first day in the forecast period. For example, 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑒2012,𝐴𝑢𝑔𝑢𝑠𝑡 13= 4.1278 is a single draw from the Normal distribution with a mean of zero and a variance of 19.12. Only 𝑜𝑛−𝑝𝑒𝑎𝑘
one random number each is needed to simulate 𝑣0 𝑜𝑛−𝑝𝑒𝑎𝑘 𝑣𝑓𝑦,𝑚,𝑑
and
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
and 𝑣0
. All other values for 𝑜𝑛−𝑝𝑒𝑎𝑘
are calculated from the previous realizations of 𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑣𝑓𝑦,𝑚,𝑑 ,
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑜𝑛−𝑝𝑒𝑎𝑘 and 𝑒𝑓𝑦,𝑚,𝑑 and 𝑒𝑓𝑦,𝑚,𝑑 are 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑜𝑛−𝑝𝑒𝑎𝑘 𝑣0 and 𝑣0 are known from the
zero on average.
and
If the actual realizations of
forecast model estimation, they may be used in
place of the random draw.
For example, 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 𝑒2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 4.1278 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 0.4942 ∗ 4.1278 = 2.039 Henry Hub natural gas monthly futures prices may be obtained daily from the CME Group 𝑜𝑛−𝑝𝑒𝑎𝑘
website.47 Using these natural gas futures prices and the computed realizations of 𝑣𝑓𝑦,𝑚,𝑑 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣𝑓𝑦,𝑚,𝑑
and
𝑜𝑛−𝑝𝑒𝑎𝑘 , the first equation above is applied to obtain 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑 and 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
. For example,
47
As of November 5, 2013, these could be found at http://www.cmegroup.com/trading/energy/natural-gas/naturalgas.html.
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𝐹𝑢𝑡𝑢𝑟𝑒𝐻𝑒𝑛𝑟𝑦𝐻𝑢𝑏𝐴𝑢𝑔𝑢𝑠𝑡 2012 = 3.534 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 9.3146 + (3.4827 ∗ 3.534) + 2.039 = $23.66. To obtain a monthly forecast of the average SPP LMP for on-peak and off-peak, average the 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑜𝑛−𝑝𝑒𝑎𝑘 computed values of 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑 and 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
for each
future month in the period for which the run-time restriction applies. 𝑜𝑛−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚
=
=
1 𝑁𝑑 1 𝑁𝑑
∑
𝑜𝑛−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
𝑑 𝑖𝑛 𝑓𝑦,𝑚
∑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
𝑑 𝑖𝑛 𝑓𝑦,𝑚
where Nd is the number of days in the month. Outputs for STEP 1:
11.2.3.2
Forecasted On-Peak and Off-Peak SPP Monthly Average LMP
Step 2: Derive Historical Monthly LMP Basis Differential between the Resource Settlement Location and the SPP Real-Time Marginal Energy Component of LMP Inputs required for STEP 2:
Output from Step 1,
Three years of historical hourly real-time LMPs at the Resource Settlement Location, and
Three years of historical hourly average SPP RTBM LMPs
The difference between the SPP average LMP and the LMP at the relevant Resource Settlement Location can be accounted for in the historic, monthly average basis differential for both peak and off-peak hours. This basis differential can be expressed as the average, over all peak or off-
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peak hours in a month, of the ratio of the hourly Resource Settlement Location LMP to the hourly average SPP LMP. If this ratio is greater than one, it means the Resource LMP is greater than the SPP LMP on average. If this ratio is less than one, it means the Resource LMP is less than the SPP LMP on average. The forecast average SPP LMP multiplied by a historical basis adjustment ratio to the Resource Settlement Location creates monthly Resource LMPs. The three prior calendar year’s historical data is used to make this calculation. For example, when calculating opportunity costs for July 2, 2012 for a unit with a calendar year compliance period, use historical LMP data from July 2nd (2009, 2010, 2011) to December 31st (2009, 2010, 2011). For units with a 12 month rolling compliance period, use LMP data from the previous three years, beginning on the date calculated and ending two days previous. For example, when a unit is calculating opportunity cost for July 2nd, 2012 with a rolling 12 month compliance period, use historical LMP data from July 2nd (2009, 2010, 2011) to June 30th (2009, 2010, 2011). Begin by taking the hourly LMPs for the three prior calendar years at the Resource Settlement Location, and for every hour, divide that hour’s LMP by the corresponding forecast average SPP LMP. The historic hourly basis differential in hour h, day d, month m, and year y is 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑦,𝑚,𝑑,ℎ =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ 𝐴𝑣. 𝑆𝑃𝑃 𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ
Note: When the average SPP LMP is zero and the Resource LMP is zero, then the ratio value is one. If the average SPP LMP is zero and the Resource LMP is not zero, then the value is null, and it is not included in the average. For example, 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻 16 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻 16 𝐴𝑣. 𝑆𝑃𝑃 𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻 16
𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻 16 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻 16 𝐴𝑣. 𝑆𝑃𝑃 𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻 16
𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻 16 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻 16 𝐴𝑣. 𝑆𝑃𝑃 𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻 16
Exhibit 4: Three hourly basis differential ratio values for the same hour in each of three historical years
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Once the hourly basis ratios are calculated for every hour during the three-year history, for each historic month take the sum of the on-peak hourly basis differentials in the month, and divide by the number of peak hours in the month (observations). Similarly, for every month, sum the offpeak hourly basis ratios, and then divide by the number of off-peak hours within that month. When calculating the monthly peak basis ratio, all days in the month will be used for the average. These monthly basis differentials adjust the average SPP LMP monthly peak and offpeak forecasts to expected peak and off-peak monthly forward Resource LMPs. 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑦,𝑚 =
𝑝𝑒𝑎𝑘 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠𝑦,𝑚,𝑑,ℎ
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑦,𝑚 =
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 ∑𝑜𝑓𝑓-𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠𝑦,𝑚,𝑑,ℎ
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
For example, 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐽𝑢𝑛𝑒 2009 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦 𝐵𝑎𝑠𝑖𝑠 𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠 𝐽𝑢𝑛𝑒 2009) = 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝐽𝑢𝑛𝑒 2009 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐽𝑢𝑛𝑒 2010 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦 𝐵𝑎𝑠𝑖𝑠 𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠 𝐽𝑢𝑛𝑒 2010) = 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝐽𝑢𝑛𝑒 2010 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐽𝑢𝑛𝑒 2011 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦 𝐵𝑎𝑠𝑖𝑠 𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠 𝐽𝑢𝑛𝑒 2011) = 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝐽𝑢𝑛𝑒 2011 Exhibit 5: Monthly Peak Basis Differentials for the three historical periods Multiply monthly peak and off-peak basis differential ratios by the respective monthly peak and off-peak SPP average LMPs to derive forecasted monthly peak and off-peak Resource LMPs from the historical year. When calculating the monthly peak basis differential ratio, all days in the month will be used for the average.
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𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝑓𝑦,𝑚
𝑝𝑒𝑎𝑘
𝑝𝑒𝑎𝑘
= 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚 ∗ 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝑅𝑎𝑡𝑖𝑜𝑦,𝑚 For example, 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝐽𝑢𝑛𝑒 2012 𝑏𝑎𝑠𝑒 2009 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃 𝑓𝑜𝑟 𝑑𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐽𝑢𝑛𝑒 2012 ) 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ (𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜 𝐽𝑢𝑛𝑒 2009 ) 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝐽𝑢𝑛𝑒 2012,𝑏𝑎𝑠𝑒 2010 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃 𝑓𝑜𝑟 𝑑𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐽𝑢𝑛𝑒 2012 ) 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ (𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐽𝑢𝑛𝑒 2010 ) 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝐽𝑢𝑛𝑒 2012,𝑏𝑎𝑠𝑒 2011 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃 𝑓𝑜𝑟 𝑑𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐽𝑢𝑛𝑒 2012 ) ∗ (𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜 𝐽𝑢𝑛𝑒 2011 )
Exhibit 6: Forecasted monthly Resource Settlement Location prices for three historical periods Outputs from STEP 2: Three peak and off-peak monthly Resource LMP forecasts for each month remaining in the compliance period
11.2.3.3
Step 3: Derive hourly volatility scalars to incorporate hourly volatility into the LMP forecast Inputs for STEP 3: Three years historical hourly real-time LMPs at the Resource Settlement Location
The monthly LMP forecasts only consider the average peak and off-peak prices for the month and do not consider hourly LMP volatility. Step 3 derives an hourly volatility scalar. This scalar will later be multiplied against the forecast in Step 2 to derive an hourly Resource LMP forecast
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that incorporates historic hourly peak and off-peak LMP volatility as well as monthly peak and off-peak basis differentials from the historical year. First, for each historic month, compute the average peak and off-peak price at the Resource Settlement Location for each remaining month in the compliance period. When calculating the monthly average Resource LMP all days in the month will be used for the average. 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑝𝑒𝑎𝑘 𝑦,𝑚 = 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑦,𝑚
=
∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠 𝐻𝑜𝑢𝑟𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑝𝑒𝑎𝑘 𝑦,𝑚,𝑑,ℎ 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠 𝐻𝑜𝑢𝑟𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
Next, for every hour, take the hourly Resource LMP divided by the relevant monthly average peak or off-peak Resource LMP computed above. If the hour is an on-peak hour, divide by the average peak LMP for the month. 𝑝𝑒𝑎𝑘
𝑝𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑,ℎ
=
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝑦,𝑚,𝑑,ℎ 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑝𝑒𝑎𝑘 𝑦,𝑚
If the hour is off-peak, divide that hour by the monthly off-peak average price for the corresponding month. 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑,ℎ
=
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝑦,𝑚,𝑑,ℎ
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑦,𝑚
For example,
𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐻23 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐻23 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐴𝑢𝑔𝑢𝑠𝑡 2009 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃
𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻23 =
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𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻23 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻23 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐴𝑢𝑔𝑢𝑠𝑡 2011 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃
Exhibit 7: Volatility scalar for the each of the three historical years
Output from STEP 3: Three ratio values per hour for each of the historical years used for volatility 11.2.3.4
Step 4: Create three sets of hourly forecasted Resource Settlement Location values Inputs to STEP 4:
Output from STEP 2: On-peak/off-peak monthly Resource Settlement Location LMP Forecast
Output from STEP 3: Hourly volatility scalars
Step 4 creates three hourly forecasts from the volatility scalars developed in Step 3 and the monthly Resource LMP forecasts developed in Step 2. Multiply the hourly volatility scalars developed in Step 3 by the corresponding peak or off-peak from the historical year forecasted monthly Resource LMP calculated in Step 2. The expected or forecasted LMP for hour h, day d, month m, based on year y that is a peak hour is 𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑦,𝑚,𝑑,ℎ 𝑝𝑒𝑎𝑘 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟 𝑝𝑒𝑎𝑘 𝑦,𝑚,𝑑,ℎ ∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑓𝑦,𝑚
The expected or forecasted LMP for hour h, day d, month m, based on year y that is an off-peak hour is
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Exhibit 8: Forecasted Resource Settlement Location LMPs for one hour for each of the three historical base years 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑦,𝑚,𝑑,ℎ
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟 𝑦,𝑚,𝑑,ℎ
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝑃𝑟𝑖𝑐𝑒 𝑓𝑦,𝑚
For example, assume that it is July 15, 2012. To create the set of three forecasted prices for each hour of August 13, 2012: 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻23,𝑏𝑎𝑠𝑒 2009 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐻23 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 2012 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻23,𝑏𝑎𝑠𝑒 2010 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻23 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 2012 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻23,𝑏𝑎𝑠𝑒 2011 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻23 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 2012 Outputs from STEP 4: Three hourly Resource LMP forecasts for each hour remaining in the compliance period 11.2.3.5
Step 5: Create a daily fuel volatility scalar Inputs to STEP 5:
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Fuel Weights if dual fuel
Step 4 creates a daily fuel volatility scalar using historic daily delivered fuel prices (as used to develop a unit’s Total Fuel Related Cost (“TFRC”)) from the previous three calendar years. Take each daily resource-delivered fuel price and divide it by the monthly average resourcedelivered fuel price to create a ratio for every day in the three-year history. In calculating monthly average resource prices, all days in the month will be used for the average. For units that have dual fuels, the daily delivered fuel prices need to be multiplied by their respective weights and then added together. Nm is the number of days in month m. Units with a single fuel type: 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑 = (
𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝑦,𝑚,𝑑 𝑁𝑚 ∑𝑛=1 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝑦,𝑚 𝑁𝑚
)
Units with dual fuel: 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑 (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝐴𝑦,𝑚,𝑑 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴) + (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝑇𝑦𝑝𝑒𝐵𝑦,𝑚,𝑑 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵)
= (
𝑁𝑚 ∑𝑛=1 ((𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝐴𝑦,𝑚 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴) + (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝑇𝑦𝑝𝑒𝐵𝑦,𝑚 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵)) ) 𝑁𝑚
For example, 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 =
𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝐴𝑢𝑔𝑢𝑠𝑡 2009 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑 𝐹𝑢𝑒𝑙 𝑃𝑟𝑖𝑐𝑒
𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 =
𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝐴𝑢𝑔𝑢𝑠𝑡 2010 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑 𝐹𝑢𝑒𝑙 𝑃𝑟𝑖𝑐𝑒
𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 =
𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑃𝑟𝑖𝑐𝑒𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝐴𝑢𝑔𝑢𝑠𝑡 2011 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑 𝐹𝑢𝑒𝑙 𝑃𝑟𝑖𝑐𝑒
Exhibit 9: Three daily fuel volatility scalars values developed for August 13 in each of three historic years for a unit with a single fuel
If there is no fuel cost record for a given date, use the previous available value.
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Output from STEP 5: Three years of historic daily scalars for fuel volatility 11.2.3.6
Step 6: Create three daily delivered fuel forecasts Inputs for STEP 6:
CME Forward curve for Fuels from the most recent trading day, for delivery in the compliance period ($/MMBTU) with a daily delivery charge adjustment
Fuel Weights if dual fuel
Fuel contract monthly prices if applicable
Output from STEP 5: Three years historic daily scalars for fuel volatility
Step 6 takes fuel futures and/or contract prices and the daily delivered fuel scalars from Step 5 and multiplies them together to create a fuel forecast that corresponds on an average monthly basis to the fuel futures, yet maintains historical volatility. For Resources that have dual fuels: the fuel forwards for the two fuels will be multiplied by their respective weights (derived from expected use of each fuel), added together, and then multiplied by the daily fuel volatility scalar. For Resources with some or all of their fuel procured by contract, the contract and fuel forwards are multiplied by their respective weights (derived from expected use of each fuel) and added together and then multiplied by the daily fuel volatility scalar. The current daily delivery charge adjustment will be applied through the compliance period. Resources with a single fuel: 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑓𝑦,𝑚,𝑑 = 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑 ∗ [(𝑊𝑒𝑖𝑔ℎ𝑡𝑆𝑝𝑜𝑡𝑚 ∗ 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝑓𝑦,𝑚 ) + (𝑊𝑒𝑖𝑔ℎ𝑡𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑚 ∗ 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑃𝑟𝑖𝑐𝑒𝑓𝑦,𝑚 )],
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where WeightSpotm + WeightContractm = 1. Resource with dual fuel: (Permits the use of dual fuels for Resources that may burn multiple fuels or source fuels from different areas at different prices. For Resources with restrictions on consumption of specific fuels, this method allows accounting for both fuels in the same calculation.)
𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑓𝑦,𝑚,𝑑 = 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑 ∗ [𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴𝑚 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑇𝑦𝑝𝑒𝐴𝑚 ∗ 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑃𝑟𝑖𝑐𝑒𝑇𝑦𝑝𝑒𝐴𝑓𝑦,𝑚 ( )+ + 𝑊𝑒𝑖𝑔ℎ𝑡𝑆𝑝𝑜𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴𝑚 ∗ (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑦𝐴𝑑𝑗𝑢𝑠𝑡𝑚𝑒𝑛𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴 + 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝑇𝑦𝑝𝑒𝐴𝑓𝑦,𝑚 ) 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵𝑚 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑇𝑦𝑝𝑒𝐵𝑚 ∗ 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑃𝑟𝑖𝑐𝑒𝑇𝑦𝑝𝑒𝐵𝑓𝑦,𝑚
( )] +𝑊𝑒𝑖𝑔ℎ𝑡𝑆𝑝𝑜𝑡𝐹𝑢𝑒𝑇𝑦𝑝𝑒𝑙𝐵𝑚 ∗ (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑦𝐴𝑑𝑗𝑢𝑠𝑡𝑚𝑒𝑛𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵 + 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝑇𝑦𝑝𝑒𝐵𝑓𝑦,𝑚 ) ,
where WeightContractFuelTypeAm + WeightSpotFuelTypeAm = 1 and WeightContractFuelTypeBm + WeightSpotFuelTypeBm = 1. For example, for a unit with a single fuel, 𝑏𝑎𝑠𝑒 2009 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012
= 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 ∗ 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝐴𝑢𝑔𝑢𝑠𝑡 2012
𝑏𝑎𝑠𝑒 2010 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012
= 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 ∗ 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝐴𝑢𝑔𝑢𝑠𝑡 2012
𝑏𝑎𝑠𝑒 2011 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012
= 𝐷𝑎𝑖𝑙𝑦𝐹𝑢𝑒𝑙𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 ∗ 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝐴𝑢𝑔𝑢𝑠𝑡 2012 Exhibit 10: Create three daily delivered fuel forecasts from the volatilities of three historic years
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Outputs from STEP 6: 11.2.3.7
Daily Resource delivered fuel forecast
Step 7: Create Resource(s) cost for each of the three forecasts Inputs for STEP 7:
Expected future full load seasonal (May-September/ October – April) heat rate for the compliance period
Fuel Prices output from Step 6
Unit SO2, CO2, and NOX Emission Rates (lbs/MMBTU)
(Note that the CO2 adder is in effect only for incurring carbon emission charges)Futures prices for SO2, CO2 and NOX from Evolution Markets ($/ton) modified to $/lb
Energy Offer Curve VOM as defined in Section 2
In Step 7, take the Resource characteristics, future emission allowance prices, the three daily fuel forecasts and create a daily Resource cost for the three forecasts using the appropriate heat rate for the forecast day. Resource costs do not include start costs. They will be added later in the calculation of Resource Dispatch Cost. For each day in the three fuel forecasts, a Resource dispatch cost is calculated as follows:
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𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐶𝑜𝑠𝑡𝑓𝑦,𝑚,𝑑
𝑀𝐵𝑡𝑢 $ 𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟 = [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 ( ) ∗ 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑓𝑦,𝑚,𝑑 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 + [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (
𝑀𝐵𝑡𝑢 𝑙𝑏𝑠 $ ) ∗ 𝑁𝑂𝑋 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑅𝑎𝑡𝑒 ( ) ∗ 𝐶𝑜𝑠𝑡 𝑜𝑓 𝑁𝑂𝑋 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏
+ [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (
𝑀𝐵𝑡𝑢 𝑙𝑏𝑠 $ ) ∗ 𝑆𝑂2 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑅𝑎𝑡𝑒 ( ) ∗ 𝐶𝑜𝑠𝑡 𝑜𝑓 𝑆𝑂2 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏
+ [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (
𝑀𝐵𝑡𝑢 𝑙𝑏𝑠 $ ) ∗ 𝐶𝑂2 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑅𝑎𝑡𝑒 ( ) ∗ 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑂2 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏
+ 𝐸𝑂𝐶 𝑉𝑂𝑀 For example, Heat rate=10.35 MMBTU/MWh NOX emission rate =0.328 lbs/MMBTU SO2 emission rate=1.2 lbs/MMBTU CO2 emission rate=117 lbs/MMBTU DailyDeliveredFuelForecast=$5.56/MMBTU Combined NOX Allowance cost=$1375/ton SO2 Allowance cost=$200/ton CO2 emission cost = $8/ton EOC VOM = $2.22/MWh 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐶𝑜𝑠𝑡 10.35 𝑀𝐵𝑡𝑢 $5.56 = [( )∗( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢
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10.35𝑀𝐵𝑡𝑢 0.328 𝑙𝑏𝑠 $1,375 𝑡𝑜𝑛 )∗( )∗( )∗( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑡𝑜𝑛 2,000 𝑙𝑏𝑠
+ [(
10.35𝑀𝐵𝑡𝑢 1.2 𝑙𝑏𝑠 $200 𝑡𝑜𝑛 )∗( )∗( )∗( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑡𝑜𝑛 2,000 𝑙𝑏𝑠
+ [(
10.35𝑀𝐵𝑡𝑢 117 𝑙𝑏𝑠 $8 𝑡𝑜𝑛 $2.22 )∗( )∗( )∗( )] + ( ) 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑡𝑜𝑛 2,000 𝑙𝑏𝑠 𝑀𝑊ℎ
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$57.58 $2.33 $1.24 $4.84 $2.22 =( )+( )+( )+( )+( ) = $68.18/𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ
Exhibit 11: Daily Resource Cost
Outputs for Step 7: Three forecasts based on historic year factors for daily resource cost
11.2.3.8
Step 8: Calculate the margin for every hour in the three hourly forecasts Inputs for Step 8:
Daily Resource Cost from Step 7
Hourly Resource Settlement Location LMP forecast from Step 4
All future maintenance outage information
Resource-specific minimum runtime parameter restriction
Resource-specific start up costs (cold startup costs for combined cycle and combustion turbine units and hot startup costs for steam units)
Resource Economic Maximum Operating Limit
Step 8 calculates the hourly margin the generator would receive by comparing the cost offer developed in Step 7 against the hourly forecasted Resource LMPs developed in Step 4. To remove planned outages, for any future date that the unit will be offline, set the outage hours to unavailable for all three forecasts. For Resources with minimum run time restrictions, this step calculates the total margins in blocks of adjacent hours, based on the sum of the margins of each block and the minimum
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runtime parameter restriction of the Resource. Blocks may include additional incremental hours, if these hours are found to be more valuable than the additional block, up to double the Resource’s minimum runtime. Adjacent hour blocks with equal or greater number of hours than double a Resource’s minimum run time will be split into multiple blocks (however, adjacent blocks do not use an additional startup cost). For Resources with start-up costs, the value of the Resource’s start-up cost divided by Economic Maximum Operating Limit will be subtracted from the total margin of each block that contains a new start, but not from each subsequent incremental hour added to the block, in order to correctly value hours that do not incur start costs. Calculate the total margins for all blocks of hours in the three forecasts.
𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟
𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘
=
𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟 𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟 ∑𝑇𝑡=𝑏𝑙𝑜𝑐𝑘 (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦(𝑡),𝑚(𝑡),𝑑(𝑡),ℎ(𝑡) − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝑓𝑢𝑡𝑢𝑟𝑒 𝑦,𝑚,𝑑 ),
where T = block + MRT – 1 and MRT = minimum run time. When applicable, ResourceDispatchCost includes start-up costs. The block ranges from 1 to Total Number of Hours – MRT + 1 and y(t), m(t), d(t), h(t) are the year, month, day and hour corresponding to the tth overall hour of the time period spanning from the date calculated to the end of the compliance period forecasted. The Total Number of Hours variable represents the number of hours left in the compliance period to be forecasted, and is based on the date calculated and whether or not the Resource has a rolling 12 month run-hour restriction. For example,
2009 𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘 3788 𝑇=3788+1−1
=
∑
2009 2009 (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ(𝑡) − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝑦,𝑚,𝑑,ℎ(𝑡) )
𝑡=3788 2009 2009 = (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻16 − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 )
= $78.27 − $68.18 = $10.09
2010 𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘 3788
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∑
=
2010 2010 (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ(𝑡) − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝑦,𝑚,𝑑,ℎ(𝑡) )
𝑡=3788 2010 2010 = (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻16 − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 )
= $58.00 − $52.41 = $5.59
2011 𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘 3788 𝑇=3788+1−1
=
∑
2011 2011 (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ(𝑡) − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝑦,𝑚,𝑑,ℎ(𝑡) )
𝑡=3788 2011 2011 = (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻16 − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 )
= $63.78 − $76.72 = -$12.94 At this point, the blocks of hours would be ranked according to the value of their total margins. Exhibit 12: Calculating total margins with a minimum runtime of one hour (i.e. no minimum runtime restriction), using historical data from the past three calendar years
Output from Step 8: Three sets of ranked blocks of total margin forecasts including each hour in the compliance period, adjusted to include start-up costs for each block that contains a new start, with all future outage hours removed 11.2.3.9
Step 9: Determine the opportunity cost component Input to Step 9: Three sets of ranked blocks of total margin forecasts
For each of the three years, the opportunity cost component for that year will be the total margin per hour of the lowest value block added before the run hour limit was reached. The three opportunity costs will then be averaged to get the opportunity cost component available to the
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Resource. If the final opportunity cost component is less than zero then the opportunity cost component will be set to zero. For example, The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎𝟎9 = $𝟕.𝟗𝟗/𝐌𝐖𝐡. The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎10 = -$𝟐.𝟓𝟒/𝐌𝐖𝐡. The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎11 = $𝟏𝟎.𝟓𝟗/𝐌𝐖𝐡.
700𝑡ℎ ℎ𝑜𝑢𝑟 𝑜𝑝𝑝𝑜𝑟𝑡𝑢𝑛𝑖𝑡𝑦 𝑐𝑜𝑠𝑡 𝑐𝑜𝑚𝑝𝑜𝑛𝑒𝑛𝑡 =
$7.99 + (−$2.54) + $10.59 = $5.33/𝑀𝑊ℎ 3
Exhibit 13: A unit with 700 run hours
Output from step 9: Maximum Opportunity Cost Component that can be included in a run-limited Resource’s Mitigated Energy Offer Curve.
11.2.4
Short Term Opportunity Cost Calculation
Short Term Opportunity Costs are of limited duration where the event lasts 30 days or less. The Short Term Method modifies the method in Section 11.2.3 to capture intra-month price movements in fuel markets on a daily basis. The method requires Resources to recalculate opportunity costs every day during the short-term episode, using daily forward prices for fuel instead of monthly forwards. 11.2.4.1
Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPs Inputs required for STEP 1:
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The forecast of the average SPP LMP is obtained by simulating from the model below or an update to the model provided by the SPP Market Monitoring Unit. The first equation describes the relationship between the monthly average SPP LMP and the price of natural gas. The second equation describes random daily deviations in price that are persistent over time. 𝑜𝑛−𝑝𝑒𝑎𝑘 𝑜𝑛−𝑝𝑒𝑎𝑘 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑 = 8.2429 + 6.1039 ∗ 𝐹𝑢𝑡𝑢𝑟𝑒𝐻𝑒𝑛𝑟𝑦𝐻𝑢𝑏𝑓𝑦,𝑚 + 𝑣𝑓𝑦,𝑚,𝑑 𝑜𝑛−𝑝𝑒𝑎𝑘
𝑜𝑛−𝑝𝑒𝑎𝑘
𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑛−𝑝𝑒𝑎𝑘
𝑒𝑓𝑦,𝑚,𝑑 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
~𝑁𝑜𝑟𝑚𝑎𝑙(0,29.5) 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
= 9.3146 + 3.4827 ∗ 𝐹𝑢𝑡𝑢𝑟𝑒𝐻𝑒𝑛𝑟𝑦𝐻𝑢𝑏𝑓𝑦,𝑚 + 𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣𝑓𝑦,𝑚,𝑑
𝑜𝑛−𝑝𝑒𝑎𝑘
= 0.5097 ∗ 𝑣𝑓𝑦,𝑚,𝑑−1 + 𝑒𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
= 0.4942 ∗ 𝑣𝑓𝑦,𝑚,𝑑−1 + 𝑒𝑓𝑦,𝑚,𝑑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑒𝑓𝑦,𝑚,𝑑
~𝑁𝑜𝑟𝑚𝑎𝑙(0,19.12) 𝑜𝑛−𝑝𝑒𝑎𝑘
To simulate the model, use a random number generator to obtain values for 𝑒𝑓𝑦,𝑚,0 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑒𝑓𝑦,𝑚,0
and
, day prior to the first day in the forecast period.
For example, 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑒2012,𝐴𝑢𝑔𝑢𝑠𝑡 13= 4.1278 is a single draw from the Normal distribution with a mean of zero and a variance of 19.12. Only 𝑜𝑛−𝑝𝑒𝑎𝑘
one random number each is needed to simulate 𝑣0 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑜𝑛−𝑝𝑒𝑎𝑘 𝑣𝑓𝑦,𝑚,𝑑 and 𝑣𝑓𝑦,𝑚,𝑑 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑜𝑛−𝑝𝑒𝑎𝑘 𝑣𝑓𝑦,𝑚,𝑑 , and 𝑒𝑓𝑦,𝑚,0 𝑜𝑛−𝑝𝑒𝑎𝑘
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
and 𝑣0
. All other values for 𝑜𝑛−𝑝𝑒𝑎𝑘
are calculated from the previous realizations of 𝑣𝑓𝑦,𝑚,𝑑 and
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 𝑒𝑓𝑦,𝑚,0
and
are zero on average. If the actual realizations of
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣0 and 𝑣0 are known from the forecast model estimation, they may be used in place of the random draw. For example, 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 𝑒2012,𝐴𝑢𝑔𝑢𝑠𝑡 13= 4.1278 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 0.4942 ∗ 4.1278 = 2.039.
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Henry Hub natural gas monthly futures prices may be obtained daily from the CME Group 𝑜𝑛−𝑝𝑒𝑎𝑘
website.48 Using these natural gas futures prices and the computed realizations of 𝑣𝑓𝑦,𝑚,𝑑 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑣𝑓𝑦,𝑚,𝑑
and
𝑜𝑛−𝑝𝑒𝑎𝑘 , the first equation above is applied to obtain 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑 and 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
. For example,
𝐹𝑢𝑡𝑢𝑟𝑒𝐻𝑒𝑛𝑟𝑦𝐻𝑢𝑏𝐴𝑢𝑔𝑢𝑠𝑡 2012 = 3.534 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃2012,𝐴𝑢𝑔𝑢𝑠𝑡 13 = 9.3146 + 3.4827 ∗ 3.534 + 2.039= $23.66. To obtain a monthly forecast of the average SPP LMP for on-peak and off-peak, average the 𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝑜𝑛−𝑝𝑒𝑎𝑘 computed values of 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑 and 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
for each
future month in the period for which the run-time restriction applies. 𝑜𝑛−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚
=
=
1 𝑁𝑑 1 𝑁𝑑
∑
𝑜𝑛−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
𝑑 𝑖𝑛 𝑓𝑦,𝑚
∑
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑆𝑃𝑃 𝐿𝑀𝑃𝑓𝑦,𝑚,𝑑
𝑑 𝑖𝑛 𝑓𝑦,𝑚
where Nd is the number of days in the month. Outputs for STEP 1:
11.2.4.2
Forecasted On-Peak and Off-Peak SPP Monthly Average LMP
Step 2: Derive Historical Monthly LMP Basis Differential between the Resource Settlement Location and the SPP Real Time Marginal Energy Component of LMP Inputs required for STEP 2:
Output from STEP 1,
48
As of November 5, 2013, these could be found at http://www.cmegroup.com/trading/energy/natural-gas/naturalgas.html.
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Three years of historical hourly average real-time LMPs at the Resource Settlement Location, and
Three years of historical hourly average SPP RTBM LMP
The mismatch between the average SPP LMP and the LMP at the relevant Resource Settlement Location can be accounted for in the historic, monthly average basis differential for both peak and off-peak hours. The basis differential is an average for the peak or off-peak hours intramonth of the difference between the average hourly Resource LMP and the hourly average SPP LMP. The result is a ratio of the Resource Settlement Location to the average SPP LMP by time. If this ratio is greater than one, it means the Resource LMP is greater than the average SPP LMP. If this ratio is less than one, it means the Resource LMP is less than the average SPP LMP on average. The resulting ratio can be applied to the average SPP LMP to adjust it into to the specific Resource Settlement Location. The forecast average SPP LMPs are multiplied by the historical basis adjustment ratio or shaping factor at the Resource Settlement Location to approximate the intra-month delivered Resource LMPs. Begin by taking the average hourly intra-month Resource LMPs for the three prior calendar years, and for every hour, divide that hour’s price by the corresponding average SPP LMP. The historic hourly basis differential in hour h, day d, month m, and year y is 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑦,𝑚,𝑑,ℎ =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ 𝑆𝑃𝑃 𝑀𝐸𝐶𝑦,𝑚,𝑑,ℎ
Note: When the average SPP LMP is zero and the ResourceLMP is zero, then the ratio value is one. If the average SPP LMP is zero and the ResourceLMP is not zero, then the value is null, and it is not included in the average. For example, 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻 16 =
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𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻 16 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻 16 𝑆𝑃𝑃 𝑀𝐸𝐶𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻 16
𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻 16 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻 16 𝑆𝑃𝑃 𝑀𝐸𝐶𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻 16
Exhibit 14: Three hourly basis differential ratio values for the same hour in each of three historical years
Once the hourly basis ratios are calculated for every hour in the historic period, take the sum of the on-peak hourly basis differentials, and divide by the number of peak hours. Similarly sum the off-peak hourly basis ratios, for the month then divide by the number of off-peak hours. When calculating the intra-month peak basis differential ratio, all days in the month will be used for the average. The intra-month basis differentials adjust the average SPP LMP daily forecast peak and off-peak DA prices to expected peak and off-peak daily forward prices delivered to the Resource Settlement Location. 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑦,𝑚 =
𝑝𝑒𝑎𝑘 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠𝑦,𝑚,𝑑,ℎ
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑦,𝑚 =
𝑜𝑓𝑓−𝑝𝑒𝑎𝑘 ∑𝑜𝑓𝑓-𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠 𝐻𝑜𝑢𝑟𝑙𝑦𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠𝑦,𝑚,𝑑,ℎ
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
For example, 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡 2009 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦 𝐵𝑎𝑠𝑖𝑠 𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠 𝐴𝑢𝑔𝑢𝑠𝑡2009) = 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝐴𝑢𝑔𝑢𝑠𝑡2009
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡2010 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦 𝐵𝑎𝑠𝑖𝑠 𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠 𝐴𝑢𝑔𝑢𝑠𝑡2010) = 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝐴𝑢𝑔𝑢𝑠𝑡2010
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𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡2011 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦 𝐵𝑎𝑠𝑖𝑠 𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝑠 𝐴𝑢𝑔𝑢𝑠𝑡2011) = 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝐴𝑢𝑔𝑢𝑠𝑡2011 Exhibit 15: Monthly Peak Basis Differentials for the three historical periods
Multiply monthly peak and off-peak basis differential ratios by the respective monthly peak and off-peak hub forwards to derive forecasted monthly peak and off-peak Resource Settlement Location prices from the historical year. When calculating the intra-monthly peak basis differential ratio, all days in the month will be used for the average. 𝑝𝑒𝑎𝑘 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃𝑓𝑦,𝑚 𝑝𝑒𝑎𝑘
𝑝𝑒𝑎𝑘
= 𝑆𝑃𝑃 𝑀𝐸𝐶 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝑓𝑦,𝑚 ∗ 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝑅𝑎𝑡𝑖𝑜𝑦,𝑚 For example, 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡2012 𝑏𝑎𝑠𝑒 2009 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= (𝑆𝑃𝑃 𝑀𝐸𝐶 𝑓𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝑓𝑜𝑟 𝑑𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐴𝑢𝑔𝑢𝑠𝑡2012 ) 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ (𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡2009 )
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒 𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡2012,𝑏𝑎𝑠𝑒 2010 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= (𝑆𝑃𝑃 𝑀𝐸𝐶 𝑓𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝑓𝑜𝑟 𝑑𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐴𝑢𝑔𝑢𝑠𝑡2012 ) 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ (𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡2010 )
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝐵𝑢𝑠 𝑃𝑟𝑖𝑐𝑒𝐴𝑢𝑔𝑢𝑠𝑡2012,𝑏𝑎𝑠𝑒 2011 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
= (𝑆𝑃𝑃 𝑀𝐸𝐶 𝑓𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝑓𝑜𝑟 𝑑𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐴𝑢𝑔𝑢𝑠𝑡2012 ) ∗ (𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑂𝑓𝑓𝑃𝑒𝑎𝑘𝐵𝑎𝑠𝑖𝑠𝐷𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙𝑅𝑎𝑡𝑖𝑜𝐴𝑢𝑔𝑢𝑠𝑡2011 ) Exhibit 16: Forecasted monthly Resource Settlement Location prices for three historical periods
Outputs from STEP 2: Three peak and off-peak monthly Resource LMP forecasts for the remaining days in a month
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11.2.4.3
Step 3: Derive hourly volatility scalars to incorporate hourly volatility into the LMP forecast Inputs for Step 3: Three years historical average hourly real-time LMPs at the Resource Settlement Location
Daily average SPP LMP forecasts are average peak and off-peak prices for the next day and do not include hourly LMP volatility. Step 3 derives an hourly volatility scalar. This scalar will later be multiplied against the forecasted prices in Step 2 to develop an hourly Resource LMP forecast that incorporates historic hourly peak and off-peak LMP volatility. First, for each historic month compute the average peak and off-peak price at the Resource Settlement Location for the intra-month. When calculating the monthly average Resource LMP all days in the month will be used for the average. 𝑝𝑒𝑎𝑘
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚 =
𝑝𝑒𝑎𝑘 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ )
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚
=
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘 ∑𝑝𝑒𝑎𝑘 ℎ𝑜𝑢𝑟𝑠(𝐻𝑜𝑢𝑟𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ )
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑠 𝑖𝑛 𝑚𝑜𝑛𝑡ℎ 𝑚
Next, for every hour, take the hourly Resource Settlement Location LMP divided by the relevant monthly average peak or off-peak Resource Settlement Location LMP computed above. If the hour is an on-peak hour, divide by the average peak LMP for the month. 𝑝𝑒𝑎𝑘
𝑝𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑,ℎ =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ 𝑝𝑒𝑎𝑘 𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚
If the hour is off-peak, divide that hour by the monthly off-peak average price for the corresponding month. 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑,ℎ
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𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ
𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝐴𝑣𝑒𝑟𝑎𝑔𝑒𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚
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For example, Exhibit 18: Volatility scalar for the each of the three historical years
𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐻23 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐻23 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐴𝑢𝑔𝑢𝑠𝑡 2009 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃
𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻23 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻23 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐴𝑢𝑔𝑢𝑠𝑡 2010 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃
𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻23 =
𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻23 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑂𝑓𝑓-𝑃𝑒𝑎𝑘 𝐴𝑢𝑔𝑢𝑠𝑡 2011 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃
Exhibit 17: Volatility scalar for the each of the three historical years
Output from STEP 3: Three ratio values per hour for each of the historical years used for volatility 11.2.4.4
Step 4: Create three sets of hourly forecasted Resource LMPs Inputs to STEP 4:
Output from STEP 2: On-peak/off-peak monthly Resource LMP Forecasts
Output from STEP 3: Hourly volatility scalars
Step 4 creates three hourly forecasts from the volatility scalars developed in Step 3 and the monthly Resource LMP forecasts developed in Step 2. Multiply the hourly volatility scalars
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developed in Step 3 by the corresponding peak or off-peak from the historical year forecasted monthly Resource LMP calculated in Step 2. The expected or forecasted LMP for hour h, day d, month m, based on year y that is a peak hour is 𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑦,𝑚,𝑑,ℎ = 𝑝𝑒𝑎𝑘 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑,ℎ ∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑝𝑒𝑎𝑘 𝑓𝑦,𝑚 .
The expected or forecasted LMP for hour h, day d, month m, based on year y that is an off-peak hour is 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦,𝑚,𝑑,ℎ 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝑦,𝑚,𝑑,ℎ
= 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝑓𝑦,𝑚
.
For example, assume that it is July 15, 2012. To create the set of three forecasted prices for each hour of 𝐴𝑢𝑔𝑢𝑠𝑡 13, 2012: 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻23,𝑏𝑎𝑠𝑒 2009 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2009 𝐻23 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝑃𝑟𝑖𝑐𝑒 𝐴𝑢𝑔𝑢𝑠𝑡 2012 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻23,𝑏𝑎𝑠𝑒 2010 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2010 𝐻23 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 2012 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻23,𝑏𝑎𝑠𝑒 2011 = 𝐻𝑜𝑢𝑟𝑙𝑦𝑉𝑜𝑙𝑎𝑡𝑖𝑙𝑖𝑡𝑦𝑆𝑐𝑎𝑙𝑎𝑟𝐴𝑢𝑔𝑢𝑠𝑡 13,2011 𝐻23 𝑜𝑓𝑓-𝑝𝑒𝑎𝑘
∗ 𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑀𝑜𝑛𝑡ℎ𝑙𝑦𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃 𝐴𝑢𝑔𝑢𝑠𝑡 2012 Exhibit 19: Forecasted Resource LMPs for one hour for each of the three historical base years
Outputs from STEP 4: Three hourly Resource LMP forecasts for each hour remaining in the compliance period
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11.2.4.5
Step 5: Fuel Price Inputs for STEP 5:
Fuel Weights if dual fuel
Contract Fuel Prices if Applicable
In the short term method, no volatility is applied to the fuel prices. Take the Day Ahead Price for the appropriate fuel; add the delivery adder and this is the appropriate fuel price to use. For Resources that have dual fuels; the daily delivered fuel prices need to be multiplied by their respective weights and then added together. If there is no fuel cost record for a given date, use the most recently available value. For Resources with some or all of their fuel procured by contract, the contract and Day Ahead fuel prices are multiplied by their respective weights (derived from expected use of each fuel) and added together and then multiplied by the daily fuel volatility scalar. The current daily delivery charge adjustment will be applied through the compliance period. Resource with a single fuel: 𝐷𝑎𝑖𝑙𝑦 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑 𝐹𝑢𝑒𝑙𝑦,𝑚,𝑑 = 𝑊𝑒𝑖𝑔ℎ𝑡𝑆𝑝𝑜𝑡𝑚 ∗ (𝐷𝑎𝑦 𝐴ℎ𝑒𝑎𝑑 𝐹𝑢𝑒𝑙 𝑃𝑟𝑖𝑐𝑒 + 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝐴𝑑𝑗𝑢𝑠𝑡𝑚𝑒𝑛𝑡) + (𝑊𝑒𝑖𝑔ℎ𝑡 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑚 ∗ 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡 𝑃𝑟𝑖𝑐𝑒𝑚 ), where 𝑊𝑒𝑖𝑔ℎ𝑡 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑚 + 𝑊𝑒𝑖𝑔ℎ𝑡 𝑆𝑝𝑜𝑡𝑚 = 1. Resource with dual fuel: The following equation permits use of dual fuels for Resources that may burn multiple fuels or source fuels from different areas at different prices. For Resources with restrictions on consumption of specific fuels, this method allows accounting for both fuels in the same calculation. 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝑓𝑦,𝑚,𝑑 = 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴𝑚 ∗ 𝑊𝑒𝑖𝑔ℎ𝑡𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑇𝑦𝑝𝑒𝐴𝑚 ∗ 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑃𝑟𝑖𝑐𝑒𝑇𝑦𝑝𝑒𝐴𝑓𝑦,𝑚
( )+ + 𝑊𝑒𝑖𝑔ℎ𝑡𝑆𝑝𝑜𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴𝑚 ∗ (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑦𝐴𝑑𝑗𝑢𝑠𝑡𝑚𝑒𝑛𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐴 + 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝑇𝑦𝑝𝑒𝐴𝑓𝑦,𝑚 ) 𝑊𝑒𝑖𝑔ℎ𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵𝑚 ∗
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𝑊𝑒𝑖𝑔ℎ𝑡𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑇𝑦𝑝𝑒𝐵𝑚 ∗ 𝐶𝑜𝑛𝑡𝑟𝑎𝑐𝑡𝑃𝑟𝑖𝑐𝑒𝑇𝑦𝑝𝑒𝐵𝑓𝑦,𝑚 ( ) +𝑊𝑒𝑖𝑔ℎ𝑡𝑆𝑝𝑜𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵𝑚 ∗ (𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑦𝐴𝑑𝑗𝑢𝑠𝑡𝑚𝑒𝑛𝑡𝐹𝑢𝑒𝑙𝑇𝑦𝑝𝑒𝐵 + 𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑤𝑎𝑟𝑑𝑇𝑦𝑝𝑒𝐵𝑓𝑦,𝑚 ) , where WeightContractFuel𝑇𝑦𝑝𝑒Am + WeightSpotFuel𝑇𝑦𝑝𝑒Am WeightContractFuel𝑇𝑦𝑝𝑒Bm + WeightSpotFuel𝑇𝑦𝑝𝑒Bm = 1.
=
1
and
Outputs from Step 5: Daily Resource delivered fuel forecast 11.2.4.6
Step 6: Create generating unit’s cost for each of the three forecasts Inputs for Step 6:
Expected future full heat rate intra-month
Fuel Prices output from Step 5
Unit SO2, CO2, and NOX Emission Rates (lbs/MMBTU)
(Note that the CO2 adder is in effect only for incurring carbon emission charges)
Futures prices for SO2, CO2 and NOX from Evolution Markets ($/ton) modified to $/lb
Energy Offer Curve VOM as defined in Section 2
In step 6, take the Resource characteristics, future emission allowance prices, the three daily fuel forecasts and create a daily Resource cost for the three forecasts using the appropriate heat rate for the forecast day. Resource costs do not include start costs, start costs will be added later in the calculation of Resource dispatch cost. For each day in the three fuel forecasts, a Resource dispatch cost is calculated as follows:
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𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐶𝑜𝑠𝑡 𝑓𝑦,𝑚,𝑑
𝑀𝐵𝑡𝑢 $ 𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟 = [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 ( ) ∗ 𝐷𝑎𝑖𝑙𝑦𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑒𝑑𝐹𝑢𝑒𝑙𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑓𝑦,𝑚,𝑑 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 + [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (
𝑀𝐵𝑡𝑢 𝑙𝑏𝑠 $ ) ∗ 𝑈𝑛𝑖𝑡𝑁𝑂𝑋 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑅𝑎𝑡𝑒 ( ) ∗ 𝐶𝑜𝑠𝑡 𝑜𝑓 𝑁𝑂𝑋 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏
+ [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (
𝑀𝐵𝑡𝑢 𝑙𝑏𝑠 $ ) ∗ 𝑈𝑛𝑖𝑡𝑆𝑂2 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑅𝑎𝑡𝑒 ( ) ∗ 𝐶𝑜𝑠𝑡 𝑜𝑓 𝑆𝑂2 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏
+ [𝐻𝑒𝑎𝑡𝑅𝑎𝑡𝑒 (
𝑀𝐵𝑡𝑢 𝑙𝑏𝑠 $ ) ∗ 𝑈𝑛𝑖𝑡𝐶𝑂2 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑅𝑎𝑡𝑒 ( ) ∗ 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑂2 ( )] 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏
+ 𝐸𝑂𝐶 𝑉𝑂𝑀 For example, Unit heat rate = 10.35 MMBTU/MWh Unit NOx emission rate = 0.328 lbs/MMBTU Unit SO2 emission rate = 1.2 lbs/MMBTU Unit CO2 emission rate = 117 lbs/MMBTU DailyDeliveredFuelForecast = $3.01/MMBTU Combined NOX Allowance cost = $1375/ton SO2 Allowance cost = $200/ton CO2 emission cost = $8/ton EOC VOM = $2.22/MWh 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐶𝑜𝑠𝑡 = [(
10.35 𝑀𝐵𝑡𝑢 $3.01 )∗( )] + 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢
10.35𝑀𝐵𝑡𝑢 0.328 𝑙𝑏𝑠 $0.6875 [( )∗( )∗( )] + 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏 [( [(
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10.35𝑀𝐵𝑡𝑢 117 𝑙𝑏𝑠 $0.004 $2.22 )∗( )∗( )] + ( ) 𝑀𝑊ℎ 𝑀𝐵𝑡𝑢 𝑙𝑏 𝑀𝑊ℎ
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$31.14 $2.33 $1.24 $4.84 $2.22 =( )+( )+( )+( )+( ) = $41.77/𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ 𝑀𝑊ℎ
Exhibit 20: Daily Resource Cost
Outputs for step 6: Three forecasts based on historic year factors for daily Resource cost 11.2.4.7
Step 7: Calculate the margin for every hour in the three hourly forecasts Inputs for Step 7:
Daily Resource Cost
Hourly Resource LMP forecast from Step 4
Resource-specific minimum run-time parameter restriction
Resource-specific start up costs (cold start-up costs for combined cycle and combustion turbine units and hot startup costs for steam units)
Resource Economic Maximum Capacity Operating Limit
Step 7 calculates the hourly margin the Resource would receive by comparing the cost offer developed in Step 6 against the hourly forecasted Resource LMPs developed in Step 4. For Resources with minimum run time restrictions, this step calculates total margins in blocks of adjacent hours, based on the sum of the margins of each block and the minimum run time parameter restriction of the Resource. Blocks may include additional incremental hours, if these hours are found to be more valuable than an additional block, up to double a Resource’s minimum run time. Adjacent hour blocks with equal or greater number of hours than double a Resource’s minimum run time will be split into multiple blocks (however adjacent blocks do not use an additional start cost). For Resources with start-up costs, the value of the Resource’s start-
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up cost divided by Economic Capacity Maximum Operating Limit will be subtracted from the total margin of each block that contains a new start, but not from each subsequent incremental hour added to the block, in order to correctly value hours that do not incur start costs. Calculate the total margins for all blocks of hours in the three forecasts: 𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟
𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘
=
𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟 𝑏𝑎𝑠𝑒 𝑦𝑒𝑎𝑟 ∑𝑇𝑡=𝑏𝑙𝑜𝑐𝑘 (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦(𝑡),𝑚(𝑡),𝑑(𝑡),ℎ(𝑡) − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝑓𝑢𝑡𝑢𝑟𝑒 𝑦,𝑚,𝑑 ),
where T = block + MRT – 1 and MRT = minimum run time. When applicable, ResourceDispatchCost includes start-up costs. The block ranges from 1 to Total Number of Hours – MRT + 1 and y(t), m(t), d(t), h(t) are the year, month, day and hour corresponding to the tth overall hour of the time period spanning from the date calculated to the end of the intra-month period. The Total Number of Hours variable represents the number of hours left in the compliance period to be forecasted, and is based on the date calculated and whether or not the Resource has a rolling 12 month run-hour restriction. For example, 2009 𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘 3679 𝑇=3679+1−1
=
∑
2009 (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝑦(𝑡),𝑚(𝑡),𝑑(𝑡),ℎ(𝑡)
𝑡=3679 2009 − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝑓𝑢𝑡𝑢𝑟𝑒 𝑦,𝑚,𝑑 ) 2009 2009 = (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻16 − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 )
= $53.23 − $41.77 = $11.46
2010 𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘 3679 2010 2010 = (𝐹𝑜𝑟𝑒𝑐𝑎𝑠𝑡𝑒𝑑𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐿𝑀𝑃𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 𝐻16 − 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝐷𝑖𝑠𝑝𝑎𝑡𝑐ℎ𝐶𝑜𝑠𝑡𝐴𝑢𝑔𝑢𝑠𝑡 13,2012 )
= $55.44 − $57.88 = -$2.44
2011 𝑇𝑜𝑡𝑎𝑙𝑀𝑎𝑟𝑔𝑖𝑛𝐵𝑙𝑜𝑐𝑘𝑏𝑙𝑜𝑐𝑘 3679
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= $49.78 − $49.72 = $0.06 Exhibit 21: Calculating total margins with a minimum run time of one hour (i.e. no minimum run time restriction), using historical data from the past three calendar years
At this point, the blocks of hours would be ranked according to the value of their total margins. Output from step 7: Three sets of ranked blocks of total margin forecasts including each hour in the compliance period, adjusted to include start-up costs for each block that contains a new start, with all future outage hours removed 11.2.4.8
Step 8: Determine the opportunity cost adder Input for Step 8: Three sets of ranked blocks of total margin forecasts
For each of the three years, the opportunity cost for that year will be the total margin per hour of the lowest value block added before the run hour limit was reached. The three opportunity costs will then be averaged to get the opportunity cost adder available to the Resource. If the opportunity cost adder is less than 0, the opportunity cost adder will be set to 0. The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎𝟎9 = $𝟏𝟖.𝟑𝟑/𝐌𝐖𝐡 The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎10 = -$𝟐.𝟓𝟎/𝐌𝐖𝐡 The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎11 = $𝟏.𝟓𝟗/𝐌𝐖𝐡
700𝑡ℎ ℎ𝑜𝑢𝑟 𝑜𝑝𝑝𝑟𝑜𝑡𝑢𝑛𝑖𝑡𝑦 𝑐𝑜𝑠𝑡 𝑎𝑑𝑑𝑒𝑟 =
$18.33 + (−$2.50) + $1.59 = $5.81/𝑀𝑊ℎ 3
Exhibit 22: A unit with 700 run hours left
Output from Step 8:
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Maximum Opportunity Cost Component that can be added to an environmentally run limited Resource’s Mitigated Energy Offer Curve
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Appendix G – Attachment A. No Load Calculation Examples The information included in this Attachment A provides guidance for calculating No-Load costs for various types of generating units.
A.1 No-Load Fuel All SPP Market Participants shall use no-load fuel to develop no-load costs for their units. Since generating units cannot normally be run stable at zero net output, the no-load fuel may be determined by:
Collecting heat input values as a function of output and performing a regression analysis,
Using heat input values as provided by Original Equipment Manufacturer and performing a regression analysis,
Using the initial design heat input curve for an immature unit and performing a regression analysis
Determining the measured value of fuel consumed at zero net output from test data (moment of generator output breaker closure).
A.2 Typical Steam Unit Example An example of collecting heat input values as a function of output and performing a regression analysis on the data to obtain the no-load fuel for a typical fossil steam unit is shown below:
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Typical Oil Unit Input-Output Curve for 550 MW Steam Unit from Plant Instrumentation Data 7,000 Measured or Calculated Heat Input 6,000
Poly. (Measured or Calculated Heat Input)
5,000
mmBtu
No Load Fuel = 306.744 mmBtu/hr 4,000 3,000 2,000 Fitted Regression Line Equation y = 1.56391E-03x2 + 9.68940E+00x + 3.06744E+02
1,000 0 0
100
200
MW
300
400
500
600
Each diamond in the graph above indicates one hourly heat input data point calculated from plant instrumentation during operations. A regression analysis was performed on the data collected to obtain the unit’s Heat Input curve as a function of Output with oil as a fuel: 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡 (𝑚𝑚𝐵𝑇𝑈⁄ℎ𝑜𝑢𝑟) = 0.00156391 ∗ 𝑀𝑊 2 + 9.6894 ∗ 𝑀𝑊 + 306.744 Then the No-Load Fuel at zero output is 𝑁𝑜 − 𝐿𝑜𝑎𝑑 𝐹𝑢𝑒𝑙 = 306.744 𝑚𝑚𝐵𝑇𝑈⁄ℎ𝑜𝑢𝑟 The initial estimate of a unit’s No-Load Cost ($/Hr) is: Performance Factor = 1.02
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Total Fuel related Cost (TFRC) = $14.00 MBTU 𝑁𝑜 𝐿𝑜𝑎𝑑 𝐶𝑜𝑠𝑡 ($⁄𝐻𝑜𝑢𝑟) = (𝑁𝑜 𝐿𝑜𝑎𝑑 𝐹𝑢𝑒𝑙 ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑇𝐹𝑅𝐶) $14.00 = 306.744 𝑚𝑚𝐵𝑇𝑈⁄ℎ𝑜𝑢𝑟 ∗ 1.02 ∗ = $4,380/ℎ𝑜𝑢𝑟 𝑚𝑚𝐵𝑇𝑈 The unit’s Cost Curve must be developed to determine if adjustments are needed for the unit’s No-Load Cost. The Heat Input Curve Equation is used to determine the units heat input at various outputs. Total Operating Cost is calculated by: VOM = $0.15/MBTU 𝑇𝑜𝑡𝑎𝑙 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐶𝑜𝑠𝑡 ($⁄ℎ𝑜𝑢𝑟) = 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡 ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ (𝑇𝐹𝑅𝐶 + 𝑉𝑂𝑀)
Output (MW)
Heat Input (MBTU/hr)
Total Operating Cost ($/hr)
50
795.12
11,476
160
1897.08
27,381
310
3460.75
49,949
410
4542.29
65,559
525
5824.73
84,068
550
6109.00
88,171
The unit’s incremental cost ($/MWh) at various outputs can be determined arithmetically by the following equation:
𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡 ($⁄𝑀𝑊ℎ) =
𝑇𝑜𝑡𝑎𝑙 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐶𝑜𝑠𝑡 𝑀𝑊2 − 𝑇𝑜𝑡𝑎𝑙 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐶𝑜𝑠𝑡 𝑀𝑊1 𝑀𝑊2 − 𝑀𝑊1
Output (MW)
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($/MWh) 50
141.91
160
144.59
310
150.46
410
156.10
525
160.95
550
164.11
When calculating the first increment, MW1 is zero and the Total Operating Cost MW1 is the NoLoad Cost. Since the Incremental Costs are monotonically increasing, no adjustment to the NoLoad Cost is required. The unit’s Incremental Cost ($/MWh) at various outputs can also be determined by using the derivative of the Heat Input Curve: 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡 ($⁄𝑀𝑊ℎ) = (2 ∗ 0.00156391 ∗ 𝑀𝑊 + 9.6894) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ (𝑇𝐹𝑅𝐶 + 𝑉𝑂𝑀)
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Output (MW)
Incremental Cost ($/MWh)
50
142.10
160
147.07
310
153.84
410
158.36
525
163.55
550
164.68
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The no-load cost is calculated by subtracting the incremental cost (unit’s economic minimum cost-offer value multiplied by MW value) at the unit’s economic minimum point from the total cost (from the heat input at economic minimum value) at the unit’s economic minimum point. 𝑁𝑜 𝐿𝑜𝑎𝑑 𝐶𝑜𝑠𝑡($⁄ℎ𝑜𝑢𝑟) = (𝐸𝑐𝑜𝑛𝑜𝑚𝑖𝑐 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡 ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ (𝑇𝐹𝑅𝐶 + 𝑉𝑂𝑀)) − (𝐸𝑐𝑜𝑛𝑜𝑚𝑖𝑐 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡 ∗ 𝐸𝑐𝑜𝑛𝑜𝑚𝑖𝑐 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑀𝑊) 𝑚𝑚𝐵𝑇𝑈 $14.00 = (795.12 ∗ 1.02 ∗ ( + $0.15/𝑚𝑚𝐵𝑇𝑈)) ℎ𝑜𝑢𝑟 𝑚𝑚𝐵𝑇𝑈 $142.10 −( ∗ 50𝑀𝑊) = $4,370.97/ℎ𝑜𝑢𝑟 𝑀𝑊ℎ Differences in the calculated No Load between the two methods are due to the differences in using a block average cost offer method versus a sloped derivative cost offer. When using the derivative method, the Market Participant must use the slope option when entering the Mitigated Energy Offer Curve into the Market User Interface.
A.3 Typical Combustion Turbine Example An example of using the design heat input curve and performing a regression analysis to obtain the no-load fuel for a simple cycle combustion turbine with peak firing is shown below:
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Combustion Turbine with Peak Firing Step Heat Input Curve 1400 No Load Fuel = 578.23 mmBtu/hr 1200
mmBtu
Peak Load
Fitted Regression Line Equation y = 0.0498x2 + 0.8122x + 578.23
1000 800
Base Load Minimum Load
600 400 Measured or Calculated Heat Input
200
Poly. (Measured or Calculated Heat Input) 0 0
20
40
60
80
100
120
MW
Each diamond in the graph above is a design heat input data point obtained from the original equipment manufacturer or calculated by heat balance. A regression analysis was performed on the design data to obtain the unit’s Heat Input curve as a function of Output with natural gas as a fuel: 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡 (𝑚𝑚𝐵𝑇𝑈⁄ℎ𝑜𝑢𝑟) = 0.0498 ∗ 𝑀𝑊 2 + 0.8122 ∗ 𝑀𝑊 + 578.23 Then the No-Load Fuel at zero output is 𝑁𝑜 𝐿𝑜𝑎𝑑 𝐹𝑢𝑒𝑙 = 578.23 𝑚𝑚𝐵𝑇𝑈/ℎ𝑜𝑢𝑟 The initial estimate of a unit’s No-Load Cost ($/Hr) is: Performance Factor = 1.02
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Total Fuel related Cost (TFRC) = $4.00 MBTU 𝑁𝑜 𝐿𝑜𝑎𝑑 𝐶𝑜𝑠𝑡 ($⁄ℎ𝑜𝑢𝑟) = (𝑁𝑜 𝐿𝑜𝑎𝑑 𝐹𝑢𝑒𝑙 ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑇𝐹𝑅𝐶 ) = 578.23 𝑚𝑚𝐵𝑇𝑈⁄ℎ𝑜𝑢𝑟 ∗ 1.02 ∗ $4.00/𝑚𝑚𝐵𝑇𝑈 = $2,359/ℎ𝑜𝑢𝑟 The unit’s Cost Curve must be developed to determine if adjustments are needed for the unit’s No-Load Cost. The Heat Input Curve Equation is used to determine the units heat input at various outputs. Total Operating Cost is calculated by: Maintenance Factor = 1.0 for Minimum & Base (=4.0 for Peak) VOM = $75.00/ESH 𝑇𝑜𝑡𝑎𝑙 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐶𝑜𝑠𝑡($⁄ℎ𝑜𝑢𝑟) = 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡 ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑇𝐹𝑅𝐶 + 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑉𝑂𝑀
Output (MW)
Heat Input (MBTU/hr)
Total Operating Cost ($/hr)
70
879.02
3,662
90
1054.57
4,378
100
1157.28
5,022
The unit’s Incremental Cost ($/MWh) at various outputs can be determined arithmetically by the following equation:
𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡($⁄𝑀𝑊ℎ) =
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Output (MW)
Incremental Cost ($/MWh)
70
18.61
90
35.82
100
64.42
When calculating the first increment, MW1 is zero and the Total Operating Cost MW1 is the NoLoad Cost. Since the Incremental Costs are monotonically increasing, no adjustment to the NoLoad Cost is required. The unit’s Incremental Cost ($/MWh) at various outputs can also be determined by using the derivative of the Heat Input Curve: 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡𝑎𝑙 𝐶𝑜𝑠𝑡 ($⁄𝑀𝑊ℎ) = ((2 ∗ 0.0498 ∗ 𝑀𝑊 + 0.8122) ∗ 𝑃𝑒𝑟𝑓𝑜𝑟𝑚𝑎𝑛𝑐𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 ∗ 𝑇𝐹𝑅𝐶) +
∆𝑉𝑂𝑀 ∆𝑀𝑊
Since VOM is in the units of $/hr it can only be added to the first incremental and any incremental where the maintenance factor changes.
Output (MW)
Incremental Cost ($/MWh)
70
32.83
90
39.89
100
66.45
The no-load cost is calculated by subtracting the incremental cost (unit’s economic minimum cost-offer value multiplied by MW value) at the unit’s economic minimum point from the total cost (from the heat input at economic minimum value) at the unit’s economic minimum point.
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No − Load Cost ($/hr) = = (Economic Minimum Heat Input ∗ Performance Factor ∗ TFRC) + VOM − (Economic Minimum Incremental Cost ∗ Economic Minimum MW) = (872.58mmBtu/hr ∗ 1.02 ∗ $4.00/mmBtu) + ($75.00/ESH) − ($25.82/MWh ∗ 105 MW) = $924.03/hr
Since VOM is in the units of $/hr it can only be added to the first incremental and any incremental where the maintenance factor changes. Differences in the calculated No-Load between the two methods are due to the differences in using a block average cost offer method versus a sloped derivative cost offer. When using the derivative method, user must select “Use Sloped Offer” when entering cost information into the MUI.
B.1 No-Load Cost Adjustments The calculated no-load cost may need to be adjusted to allow for the first incremental point of the unit’s generator offer curve to comply with SPP’s monotonically increasing curve requirement. An example of adjusting the no-load cost for a typical natural gas fired Steam Unit after calculation follows. Heat input values as a function of output was collected for a typical fossil steam and a regression analysis was performed to obtain the no-load.
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Typical Natural Gas Heat Input Output Curve for 550 MW Steam Unit from Plant Instrumentation Data 6,000 Fitted Regression Line Equation y = 1.48321E-04x2 + 1.07195E+01x + 2.38232E+02
5,000
mmBtu
4,000
No Load Fuel = 238.232 mmBtu/hr
3,000 2,000
1,000
Measured or Calculated Heat Input Poly. (Measured or Calculated Heat Input)
0 0
100
200
300
400
500
MW
Each diamond in the graph above indicates one hourly heat input data point calculated from plant instrumentation during operations. A regression analysis was performed on the data collected to obtain the unit’s Heat Input curve as a function of Output with oil as a fuel: Heat Input (mmBTU/Hr) = 0.000148321 ∗ 𝑀𝑊 2 + 10.7195 ∗ 𝑀𝑊 + 238.232 Then the No-Load Fuel at zero output is No − Load Fuel = 238.232 mmBtu/hr The initial estimate of a unit’s No-Load Cost ($/Hr) is: Performance Factor = 1.02 Total Fuel related Cost (TFRC) = $4.00 MBTU No Load Cost($ ⁄ Hour) =
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( No Load Fuel ∗ Performance Factor ∗ TFRC) = 238.232 𝑚𝑚𝐵𝑡𝑢/ℎ𝑟 ∗ 1.02 ∗ $4.00/𝑚𝑚𝐵𝑡𝑢 = $972/ℎ𝑟 The unit’s Cost Curve must be developed to determine if adjustments are needed for the unit’s No-Load Cost. The Heat Input Curve Equation is used to determine the units heat input at various outputs. Total Operating Cost is calculated by: VOM = $0.15/MBTU Total Operating Cost ($/hr) = Heat Input ∗ Performance Factor ∗ (TFRC + VOM)
Output (MW)
Heat Input (MBTU/hr)
Total Operating Cost ($/hr)
50
774.58
3,279
160
1957.15
8,285
310
3575.53
15,135
410
4658.16
19,718
525
5906.85
25,004
550
6178.82
26,155
The unit’s Incremental Cost ($/MWh) at various outputs can be determined arithmetically by the following equation: Incremental Cost ($/MWh) = Total Operating Cost MW2 − Total Operating Cost MW1/(MW2 − MW1)
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Output (MW)
Incremental Cost ($/MWh)
50
46.14
160
45.51
310
45.67
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410
45.83
525
45.96
550
46.05
When calculating the first increment, MW1 is zero and the Total Operating Cost MW1 is the No-Load Cost. However due to the quality of the heat input data, the first increment of the cost offer was greater than the second increment. This is shown in the graph below:
Typical Natural Gas Unit Heat Rate & Cost Curvesfor 550 MW Steam Unit 16,000
$48 No Load Cost = No Load Fuel * Fuel Cost = $971.99 $/hr
15,000
$47 $46
Fuel Cost = $4/mmbtu VOM Cost = $0.15/mmBtu
13,000
$45
12,000
$44
11,000
$43
10,000
$42
Heat Rate Incremental Heat rate Cost Offer - $/MWH
9,000 8,000 0
100
200
300 MW
400
500
$/MWH
Btu/Kwh
14,000
$41 $40 600
The No-Load cost was then raised to $1007.76 until the first increment of the cost offer was less than $1/MWh below the second increment, producing a monotonically increasing curve in the graph below:
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Typical Natural Gas Unit Heat Rate & Cost Curves for 550 MW Steam Unit 16,000
$48 $47
No Load Cost = No Load Fuel * Fuel Cost = $1007.76 $/hr
14,000
$46
13,000
$45
12,000
$44
11,000
$43 Heat Rate
10,000
$42
Incremental Heat rate
Fuel Cost = $4/mmbtu VOM Cost = $0.15/mmBtu
9,000
$/MWH
Btu/Kwh
15,000
$41
Cost Offer - $/MWH
8,000
$40 0
100
200
MW
300
400
500
600
To avoid making adjustments to the No-Load, first calculate the unit’s Incremental Cost ($/MWh) at various outputs using the derivative of the Heat Input Curve: Incremental Cost ($/MWh) = (2 ∗ 0.000148321 ∗ MW + 10.7195) ∗ Performance Factor ∗ (TFRC + VOM)
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Output (MW)
Incremental Cost ($/MWh)
50
45.43
160
45.58
310
45.76
410
45.89
525
46.03
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550
46.06
The no-load cost is calculated by subtracting the incremental cost (unit’s economic minimum cost-offer value multiplied by MW value) at the unit’s economic minimum point from the total cost (from the heat input at economic minimum value) at the unit’s economic minimum point. No − Load Cost ($/hr) = = (Economic Minimum Heat Input ∗ Performance Factor ∗ (TRFC + VOM)) − (Economic Minimum Incremental Cost ∗ Economic Minimum MW) = (774.58mmBtu/hr ∗ 1.02 ∗ ($4.00/mmBtu + $0.15/mmBtu)) − ($45.43/MWh ∗ 50 MW) = $1007.3/hr
Differences in the calculated No-Load between the two methods are due to the differences in using a block average cost offer method versus a sloped derivative cost offer. When using the derivative method, user must select “Use Sloped Offer” when entering cost information into eMKT.
B.2 Combustion Turbine Zero No-Load Example A zero No-Load example for a simple cycle combustion turbine with a single offer block is shown below:
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Combustion Turbine with Peak Firing Step Heat Input Curve 1400 No Load Fuel = 578.23 mmBtu/hr 1200
mmBtu
Peak Load
Fitted Regression Line Equation y = 0.0498x2 + 0.8122x + 578.23
1000 800
Base Load Minimum Load
600 400 Measured or Calculated Heat Input
200
Poly. (Measured or Calculated Heat Input) 0 0
20
40
60
80
100
120
MW
Each diamond in the graph above is a design heat input data point obtained from the original equipment manufacturer or calculated by heat balance. A regression analysis can be performed on the design data to obtain the unit’s Heat Input curve as a function of Output with natural gas as a fuel: Heat Input (mmBTU/Hr) = 0.0498 ∗ 𝑀𝑊 2 + 0.8122 ∗ 𝑀𝑊 + 578.23 Or the fuel input to the unit during operation can be directly measured. The unit may be submitted with a single cost offer block and zero No-Load Cost ($/Hr. No Load Cost($ ⁄ Hour) = = $0/hr The unit’s Heat Input Curve Equation or actual measured fuel input data is used to determine the units heat input at its maximum output (100MW).
Heat Input (mmBTU/Hr) =
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0.0498 ∗ 1002 + 0.8122 ∗ 100 + 578.23 = 1157.45 mmBtu/hr Total Operating Cost at 100 MW is calculated by: Maintenance Factor = 1.0 for Minimum & Base (=4.0 for Peak) VOM = $75.00/ESH Total Operating Cost ($/hr) = Heat Input ∗ Performance Factor ∗ TFRC + Maintenance Factor ∗ VOM = 1157.28 mmBtu/hr ∗ 1.02 ∗ $4.00/mmBtu + 4.0 ∗ $75/hr = $5,022/hr The unit’s Incremental Cost ($/MWh) at maximum output with a zero No-Load Cost is calculated by: Incremental Cost ($/MWh) = Total Operating Cost Maximum Output/(Maximum Output) ($5,022)/(100MW)
= $𝟓𝟎. 𝟐𝟐 /𝑴𝑾𝒉
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