Market Protocols
Revision 14.0a
Forward Looking Documentation
MAINTAINED BY
Market Design
PUBLISHED: 05/28/2004
LATEST REVISION: 02/24/2010
Copyright © 2004 by Southwest Power Pool, Inc. All rights reserved.
Market Protocols
Revisions
Revision
0.a
0.b
0.c
0.d
0.e
0.f
1.0
1.a
1.b
1.c
1.d
2.0
2.1
2.1a
2.1b
Date
05/28/2004
06/29/2004
08/23/2004
08/27/2004
09/08/2004
09/23/2004
10/05/2004
11/10/2004
11/18/2004
11/23/2004
12/01/2004
01/06/2005
03/11/2005
04/11/2005
05/25/2005
2.2
2.3
2.3a
07/12/2005
09/01/2005
09/21/2005
2.4
2.4a
10/21/2005
10/21/2005
2.4b
11/21/2005
2.5
12/02/2005
2.5a
2.5b
12/14/2005
01/27/2006
2.5c
02/22/2006
2.6
04/13/2006
2.6a
4/21/06
Version 14.0a
Description of Modification
Draft
Added additional diagrams and explanatory wording
Settlement section and comments added
Update to the Settlement Section
Incorporated all comments from members
Comments from Conference Call
Comments from MWG meeting
Additional Comments incorporated
Comments from MWG meeting
Replaced diagrams and cleaned up references
MWG review and modifications
MWG adjustments to open items
Incorporation of PRR001, 002, and 003
Incorporation of PRR016
Incorporation of approved PRRs from 05/10 MWG
meeting
2.1b approved by the MOPC
Approval/Incorporation of PRRs by the MOPC
Incorporation of PRRs from 9/6 and 9/20 MWG
meetings
Approval of PRRs by the MOPC
Incorporation of PRR #s 30 and 37 from the 10/04
MWG meeting
Incorporation of PRR #38 and 46 from the 11/5 MWG
meeting
Incorporation of PRR #49 from 11/22 MWG
conference call
Incorporation of PRR #050 from 12/6 MWG meeting
Incorporation of PRR #044 from 1/10/06 MWG
meeting and removal of PRR #050 due to MOPC
rejection
Incorporation of PRR #040, 052-053 and 060-061 from
02/07/06 MWG meeting and PRR #055-059 and 063
from the MWG Conference Call on 02/21/06
Approval of the previous PRR’s in the 3/09/2006
MOPC meeting
Incorporation of PRR #065, 069-071, 073, 075, 077078 from the April 17-18, 2006 MWG meeting
02/24/2010
1
Market Protocols
2.6b
5/5/06
2.6c
5/8/06
2.7
5/16/06
2.7a
06/14/06
2.8
07/15/06
2.8a
07/17/06
2.9
7/24/06
2.9a
9/21/06
3.0
11/27/06
3.0a
11/27/06
3.0b
12/15/06
4.0
2/9/07
4.0a
2/9/07
Version 14.0a
Incorporation of PRR #062, 067, 086, and 087 from the
May 2-3, 2006 MWG meeting
Incorporation of PRR #083, 088, 090, 092, 093, 096
and 098 from the May 8, 2006 MWG conference call
Approval of the previous PRR’s in the 5/16/06 MOPC
meeting.
Incorporation of PRR #066, 084, 085, 089, 091, 094,
095, 099, 100, 102, and 103 from the June 6-7, 2006
meeting and June 9, 2006 conference call.
Approval of previous PRR’s in the 7/11-12/06 MOPC
meeting.
Incorporation of PRR #041 from the June 26, 2006
MWG conference call and PRR #111 from the July 1819, 2006 MWG meeting, and PRR #094, which was not
approved by MOPC in the 7/11-12/06 meeting.
Approval of PRR #094 and 111 in the 7/20/06 MOPC
conference call, without PRR #041 included as it was
not approved by the MOPC in the 7/11-12/06 or the
7/20/06 MOPC meetings.
Incorporation of PRR 041, 094, 095, 104 and 106 from
the August 8-9, 2006 and September 5-6, 2006 MWG
meetings. This version does NOT include PRR’s 074,
081, 097, 101, 107, 109, 110, and 113 that were
approved by the MWG but require Impact Analysis
before additional approval and incorporation.
PRR 080 was approved in the October 3-4, 2006 MWG
meeting but it also awaiting an impact analysis so the
language is not yet incorporated.
Approval of PRR #094, #104, and #106 in the 10/10/06
MOPC meeting. The group withheld action on PRR
#041 and #095 so those have been removed from this
version.
Incorporation of PRR #116, 120 and 128 from the
November 8-9 and 17th, 2006 MWG meetings.
Correct excel illustrations throughout document and
incorporation of PRR #109, 114, 119, 120, 121, 125,
127, 128, 129, 132, 134 and 135.
Approval of PRR #109, 114, 116, 119, 120, 121, 125,
127, 128, 129, 132, 134 and 135 in the January 16,
2007 MOPC meeting.
Incorporation of PRR #137 approved in the February 67, 2007 MWG meeting.
02/24/2010
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Market Protocols
4.0b
2/21/07
4.0c
3/2/07
4.0d
3/22/07
5.0
4/25/07
6.0
7/18/07
7.0
5/1/08
7.0a
5/1/08
7.0b
6/5/08
7.0c
6/9/08
8.0
8/5/08
8.0a
8/5/08
8.0b
10/6/08
9.0
11/10/08
9.0a
11/10/08
Version 14.0a
Approval of PRR #123, 124, 136 and 138 in the
February 16, 2007 MWG conference call.
Approval of PRR #139, 140, 143 and 144 in the
February 23, 2007 MWG conference call.
Approval of PRR #142 in the March 6-8, 2007 MWG
meeting.
Approval of PRR #107, 110, 124, 134, 140 and 143 in
the April 10-11, 2007 MOPC meeting. Incorporation of
PRR #095 that was approved in the January 16-17,
2007 MOPC meeting.
Approval of PRR #081, 113, 122, 123, 126, 130, 131,
136, 139, 142, 144, 151 and 159 in the July 9 -11, 2007
MOPC meeting.
Incorporation of PRRs 138, 146, 154, 160,163, 167,
170 and 171 that were language changes approved by
MOPC in their April 8, 2008 meeting. This version
removes PRRs 081, 113, 130, 131 and 137 as they are
still pending projects and will be incorporated into
Protocols v7.0a (except for 113).
Incorporation of PRRs 068, 081, 097, 101, 130, 131,
147, 148, 153, 155, 156, and 172. These items will be
grey boxed and provide project numbers and any known
completion dates.
Incorporation of PRR 113 (Impact Analysis was
approved in the 5/21/08 MWG meeting)
Incorporation of PRR 141, 152, 166 and 169 that are
pending FERC approval.
Incorporation of PRR 161, 179 and 180 that were
language changes approved by the MOPC in their July
15 -16, 2008 meeting.
Incorporation of PRR 157, 161, 165, 173, 174, 175,
178, 181 and 185. These items will be grey boxed and
provide project numbers or FERC submittal
information and any known completion dates.
Incorporation of PRR 137a as it was supposed to be
incorporated into 7.0a but was missed.
PRR 113 was implemented on October 28, 2008 so this
version is incorporating the PRR. PRR 184 is the
correction to the language in PRR 113 but is pending
FERC approval for the related Tariff changes. It will be
added once FERC has approved.
Incorporation of PRRs 184 and 186 which are pending
FERC filing and approval.
02/24/2010
3
Market Protocols
10.0
4/30/09
10.0a
4/30/09
10.0b
6/17/09
11.0
8/11/09
11.0a
8/11/09
11.0b
8/28/09
11.0c
11.0d
10/22/09
10/22/09
12.0a
01/22/10
13.0a
02/05/10
14.0a
02/24/10
Version 14.0a
Incorporation of PRR 141, 152 and 185. FERC
approval on December 27, 2008. Approval of PRRs
192, 197 and 198 in the April 14-15, 2009 MOPC
meeting. PRR 189 gray boxed until Future Market.
PRRs 166 and 169 received FERC approval on
December 27, 2008. PRRs 176, 184 and 186 filed with
FERC; docket # ER09-748; awaiting FERC approval.
PRR 196 approved at April 14-15, 2009 MOPC
meeting. Awaiting Board and FERC filing for approval
of language revision.
Incorporation of PRR 081, 172, 174, 191, 193. All
completed and operational.
Approval of PRR 165. Implementation of PRR 169 on
July 29, 2009. Implementation of PRR186, per FERC
approval and order, to remove the penalty for not
following dispatch instructions for six consecutive
intervals. Language changes made in Protocols.
PRR166 added to Project List on June 22, 2009 with
Project Request # PR20090015.
Incorporation of PRR 156 and 184. Both implemented
and operational.
Removed gray boxed area on PRR 189.
Updated Protocols with PRR137a (already in progress)
to reflect the system operations.
Incorporation of PRRs 201 and 202 that was language
change only and approved at the January 12, 2010
MOPC meeting. PRR202 removes PRR097. PRR195
approved by MOPC on 1/12/10 for additional tariff
changes; pending FERC order and approval. PRRs 204
and 205 approved by MOPC on 1/12/10 – pending
projects.
Incorporation of PRRs 178 and 181. Both implemented
and operational.
Incorporation of PRRs 130 and 196 Both are
implemented and operational.
Incorporation of PRRs 157, 175 and 188. All were
implemented on February 16, 2010 and are operational.
02/24/2010
4
Market Protocols
Table of Contents
Glossary ..................................................................................................................................................... 12
1
Introduction ....................................................................................................................................... 19
2
Timeline ............................................................................................................................................. 21
2.1
3
SPP Operational Information Exchange .................................................................................... 21
Resource Plans................................................................................................................................. 25
3.1
Introduction ................................................................................................................................ 25
3.2
Contents..................................................................................................................................... 26
3.3
Timing and Submission Mechanisms ........................................................................................ 29
3.4
Use of Data ................................................................................................................................ 29
3.5
SPP Manual Overrides .............................................................................................................. 29
3.6
Load Forecast ............................................................................................................................ 30
3.6.1 Market Participant Load Forecasting .................................................................................... 30
3.6.2 SPP Load Forecast ............................................................................................................... 30
3.6.3 Actual Resource Production and Load Actual Gross-up for Demand Response Dispatched
31
4
Ancillary Service Plan ...................................................................................................................... 31
4.1
4.2
4.3
4.4
4.5
5
RESOURCE OFFERS CURVE .......................................................................................................... 33
5.1
5.2
5.3
5.4
6
Introduction ................................................................................................................................ 31
Contents..................................................................................................................................... 31
Timing and Submission Mechanism .......................................................................................... 32
Use of Data ................................................................................................................................ 32
SPP Manual Overrides .............................................................................................................. 33
Introduction ................................................................................................................................ 33
Contents..................................................................................................................................... 33
Timing and Submission Mechanism .......................................................................................... 34
Use of Data ................................................................................................................................ 35
Energy Schedules ............................................................................................................................ 36
6.1
Introduction ................................................................................................................................ 36
6.2
Content ...................................................................................................................................... 36
6.3
Timing and Submission ............................................................................................................. 37
6.4
Use of Data ................................................................................................................................ 37
6.5
Schedule Corrections ................................................................................................................ 38
6.5.1 NLPS and Tagged Energy Schedules .................................................................................. 38
6.5.2 Tagged Dynamic Schedules ................................................................................................. 38
6.6
Scheduling Requirements.......................................................................................................... 38
6.6.1 External Resource Tags ........................................................................................................ 38
6.6.2 Load Scheduling Requirements ............................................................................................ 38
6.6.3 Resource Scheduling Requirements ..................................................................................... 39
6.6.4 Network/Native Load and Portfolio Scheduling ..................................................................... 40
6.6.5 Reserve Sharing Scheduling ................................................................................................. 44
6.6.6 Loss Compensation ............................................................................................................... 47
6.7
SPP Operational Information Exchange .................................................................................... 53
6.8
Schedule Curtailment/Adjustment under SPP Congestion Management ................................. 54
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6.8.1 SPP Congestion Management under TLR Operations ............................................................. 54
6.8.2 IDC/CAT Schedule/tag Management Identification............................................................... 55
6.8.1 6.8.3 Market Flow .................................................................................................................. 56
6.8.2 Maintaining Feasibility under TLR Operations........................................................................... 57
6.8.3 6.8.4 NERC IDC Curtailments ............................................................................................... 58
6.8.5 Market Flow Curtailments/Adjustments ................................................................................... 59
6.8.3 6.8.6 NLPS Tool Adjustments for Curtailments ..................................................................... 61
6.8.6 ............................................................................................................................................... 62
6.8.7 SPP Congestion Management Curtailment/Adjustment Notification .................................... 62
7
Simultaneous Feasibility Studies ................................................................................................... 62
7.1
Supply Adequacy ....................................................................................................................... 63
7.2
Deliverability............................................................................................................................... 64
7.2.1 Schedule Infeasibility ............................................................................................................. 64
7.2.2 Market Infeasibility ................................................................................................................. 65
8
Inadvertent Management ................................................................................................................. 65
8.1
Management of pre-Market Inadvertent Balances .................................................................... 65
8.2
Management of post-Market Inadvertent Balances ................................................................... 66
8.3
Post-market Implementation Inadvertent Accounting Steps: .................................................... 67
8.4
Inadvertent Payback Reporting ................................................................................................. 67
8.5
Uninstructed Deviation ............................................................................................................... 67
8.5.1 Resource Operating Tolerance ............................................................................................. 69
8.5.2 Uninstructed Deviation Charge Calculations ......................................................................... 70
8.5.3 Uninstructed Deviation Calculations during Reserve Sharing Events .................................. 72
8.5.4 Intermittent Resources .......................................................................................................... 72
8.5.5 Other Grounds for Exemption ............................................................................................... 73
8.5.6 Uninstructed Deviation Charge Payment .............................................................................. 74
9
Deployment ....................................................................................................................................... 76
9.1
Introduction ................................................................................................................................ 76
9.1.1 Application of VRLs ............................................................................................................... 76
9.1.2 Impact of VRLs on LIPs and Uninstructed Deviation Charges ............................................. 77
9.1.3 Determination of VRLs .......................................................................................................... 77
9.1.4 VRL Reporting ....................................................................................................................... 78
9.2
Content ...................................................................................................................................... 79
9.2.1 Dispatch Instruction ............................................................................................................... 79
9.2.2 Out of Merit Energy (OOME) ................................................................................................. 82
9.2.3 Net Scheduled Interchange ................................................................................................... 85
9.2.4 Inadvertent Interchange ........................................................................................................ 86
9.2.5 Real-Time Deficit and Excess condition in Dispatchable Ranges ........................................ 87
9.3
Timing ........................................................................................................................................ 89
9.4
Use of Data ................................................................................................................................ 89
9.4.1 Provision of Data to the Balancing Authority ......................................................................... 91
10
Pricing ............................................................................................................................................... 92
10.1
Introduction ................................................................................................................................ 92
10.2
Content ...................................................................................................................................... 92
10.2.1
Locational Imbalance Pricing ............................................................................................ 92
10.2.2
Calculation of Settlement Location Prices for Load .......................................................... 92
10.2.3
Calculation of Settlement Location Prices for Resources ................................................. 93
10.2.4
Calculation of Settlement Locations for External Resources ............................................ 93
10.3
Timing and Submission ............................................................................................................. 94
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10.4
11
Use of Data ................................................................................................................................ 94
Settlement and Invoice .................................................................................................................... 95
11.1
Introduction ................................................................................................................................ 95
11.2
Settlement Data ......................................................................................................................... 95
11.2.1
Metering Standards for Settlement Data........................................................................... 95
11.2.2
Settlement Data Reporting Procedures ............................................................................ 95
11.2.3
Schedule Data for Settlements ......................................................................................... 95
11.2.4
Public Market Data for Settlement .................................................................................... 96
11.3
Settlement Statements .............................................................................................................. 96
11.4
Settlement Components ............................................................................................................ 97
11.4.1
Energy Imbalance Service ................................................................................................ 97
11.4.2
Charges for Under-Scheduling and Over-Scheduling .................................................... 100
11.4.3
Revenue Neutrality Uplift Procedure............................................................................... 103
11.5
Settlement Statement Process ................................................................................................ 105
11.5.1
Daily Settlement Statement ............................................................................................ 105
11.5.2
Settlement Statement Access ......................................................................................... 105
11.5.3
Settlement Statement Data ............................................................................................. 105
11.6
Type of Settlement Statements ............................................................................................... 106
11.6.1
Initial Settlement Statements .......................................................................................... 106
11.6.2
Final Settlement Statements ........................................................................................... 106
11.6.3
Resettlement Statements ................................................................................................ 106
11.6.4
Settlement Timeline ........................................................................................................ 107
11.7
Invoice...................................................................................................................................... 109
11.8
Timing and Content of Invoice ................................................................................................. 109
11.8.1
Invoice Calendar ............................................................................................................. 110
11.8.2
Holiday Invoice Calendar ................................................................................................ 110
11.9
Disputes ................................................................................................................................... 111
11.9.1
Dispute Submission Timeline .......................................................................................... 112
11.9.2
SPP Dispute Processing ................................................................................................. 113
11.10
Invoice Payment Process .................................................................................................... 114
11.10.1 Overview of Payment Process ........................................................................................ 114
11.10.2 Invoice Payments Due SPP ............................................................................................ 115
11.10.3 SPP Payments to Invoice Recipients .............................................................................. 115
11.11
Billing Determinant Anomalies ............................................................................................ 115
11.11.1 Tolerance Levels and Substitution Criteria ..................................................................... 115
12
Registration ..................................................................................................................................... 116
12.1
Introduction .............................................................................................................................. 116
12.2
Content .................................................................................................................................... 116
12.2.1
Registration of Generation Resources and Loads Acting as Resources ....................... 117
12.2.2
Registration of Load ........................................................................................................ 118
12.2.3
Registration of Meter Agent ............................................................................................ 119
12.2.4
Registration of a Joint Owned Unit ................................................................................. 119
12.2.5
Registration of an External Resource ............................................................................. 120
12.3
Timing and Submission ........................................................................................................... 120
12.4
Model Update Timeline ............................................................................................................ 129
12.5
Use of Data .............................................................................................................................. 130
13
Outage Handling and Error Handling ........................................................................................... 130
13.1
13.2
13.3
Real Time System Outages ..................................................................................................... 130
SPP Market Outage Scenarios ................................................................................................ 130
Procedures for Correcting LIPs Resulting From Market Software and Data Input Errors ....... 134
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13.3.1
13.3.2
13.3.3
14
Procedure for Evaluating and Correcting Market Software and Data Input Errors ......... 134
Procedures for Revising LIPs in Response to Market Software and Data Input Errors . 135
Disputes and Resettlement Provisions ........................................................................... 139
Market Monitoring and Mitigation ................................................................................................. 140
14.1
Introduction .............................................................................................................................. 140
14.2
Purpose and Objective ............................................................................................................ 140
14.3
Market Monitoring .................................................................................................................... 141
14.3.1
Market Monitor ................................................................................................................ 141
14.3.2
Market Monitoring ........................................................................................................... 142
14.3.3
Inquires ........................................................................................................................... 144
14.3.4
Compliance and Corrective Actions ................................................................................ 146
14.3.5
Reporting ......................................................................................................................... 148
14.3.6
Performance Indices, Metrics and Screens .................................................................... 149
14.3.7
Market Behavior Rules .................................................................................................... 150
14.3.8
Market Manipulation ........................................................................................................ 150
14.3.9
Monitoring for Potential Transmission Market Power Activities ...................................... 150
14.3.10 Data Access, Collection and Retention........................................................................... 151
14.3.11 Miscellaneous Provisions ................................................................................................ 153
14.4
Market Power Mitigation .......................................................................................................... 153
14.4.1
Purpose and Definitions .................................................................................................. 153
14.4.2
Economic Withholding .................................................................................................... 154
14.4.3
FERC Imposed “Safety-Net” Offer Cap .......................................................................... 158
14.4.4
Physical Withholding – Energy Market Power ................................................................ 158
14.4.5
Unavailability of Facilities – Energy Market Power ......................................................... 158
14.4.6
Maintenance and Implementation of the Mitigation Protocols ........................................ 158
15
Process for Protocol Revision Requests ..................................................................................... 159
15.1
Introduction .............................................................................................................................. 159
15.2
Submission of a Protocol Revision Request ............................................................................ 159
15.3
Protocol Revision Procedure ................................................................................................... 160
15.3.1
Review and Posting of Protocol Revision Requests ....................................................... 160
15.3.2
Comments on a PRR ...................................................................................................... 160
15.3.3
Operations Reliability Working Group Review ................................................................ 161
15.3.4
Regional Tariff Working Group Review........................................................................... 161
15.3.5
Initial Impact Analysis...................................................................................................... 162
15.3.6
Market Working Group Review and Action ..................................................................... 162
15.3.7
Updated Protocol Revision Request Impact Analysis and MWG Action ........................ 163
15.3.8
Withdrawal of Protocol Revision Request ....................................................................... 164
15.3.9
Expedited Requests ........................................................................................................ 164
15.3.10 Appeal of Decision .......................................................................................................... 165
15.3.11 Market and Operations Policy Committee Action ........................................................... 165
15.3.12 Process Flow Chart for Protocol Revision Requests ...................................................... 167
16
Market Process and System Change Process ................................................................................ 1
Appendix ...................................................................................................................................................... 2
A – Registration Package ........................................................................................................................... 3
B – XML Specifications ............................................................................................................................... 1
C – Meter Technical Protocols ................................................................................................................... 1
1
Scope ................................................................................................................................................... 2
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2
Purpose ............................................................................................................................................... 2
3
Definitions ........................................................................................................................................... 2
4
Applicable Standards ......................................................................................................................... 2
5
General ................................................................................................................................................ 3
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
6
Timing Standard ................................................................................................................................. 4
6.1
6.2
7
Introduction .................................................................................................................................. 3
Existing Facilities ......................................................................................................................... 3
Physical Location of Meter........................................................................................................... 3
Metering of Tie lines (Interchange) .............................................................................................. 3
Metering for Resources ............................................................................................................... 3
Metering for Loads ....................................................................................................................... 3
Measurement Quantity Verification ............................................................................................. 4
Measurement Governance .......................................................................................................... 4
Remote Terminal Unit (RTU) Freeze Contact ............................................................................. 4
Accuracy ...................................................................................................................................... 4
Meters .................................................................................................................................................. 4
7.1
Measurement Quantities .............................................................................................................. 4
7.2
Measurement Configuration ........................................................................................................ 4
7.3
Accuracy ...................................................................................................................................... 5
7.4
Testing ......................................................................................................................................... 5
7.4.1 Testing Equipment .................................................................................................................. 5
7.4.2 Acceptance Testing ................................................................................................................. 5
7.4.3 In-Service Testing ................................................................................................................... 5
7.4.4 Verification Records and Retention ......................................................................................... 6
7.5
Real Time Metering ..................................................................................................................... 6
7.5.1 General .................................................................................................................................... 6
7.5.2 Measurement Configuration .................................................................................................... 6
7.5.3 Accuracy .................................................................................................................................. 6
7.5.4 Testing ..................................................................................................................................... 7
7.6
New Current and Voltage Sensing Technologies ........................................................................ 8
7.7
Current Transformers .................................................................................................................. 8
7.7.1 Nameplate ............................................................................................................................... 8
7.7.2 Polarity..................................................................................................................................... 8
7.7.3 Burden Testing ........................................................................................................................ 9
7.7.4 Paralleling ................................................................................................................................ 9
7.8
Coupling Capacitor Voltage Transformers .................................................................................. 9
7.8.1 General .................................................................................................................................... 9
7.8.2 Nameplate ............................................................................................................................... 9
7.8.3 Polarity................................................................................................................................... 10
7.8.4 Burden ................................................................................................................................... 10
7.9
Wire Wound Voltage Transformers ........................................................................................... 10
7.9.1 Nameplate ............................................................................................................................. 10
7.9.2 Polarity................................................................................................................................... 10
7.9.3 Burden ................................................................................................................................... 10
7.10
Ancillary Devices ....................................................................................................................... 11
7.10.1
Wiring ................................................................................................................................ 11
7.11
Metering Site Procedures .......................................................................................................... 12
7.11.1
General ............................................................................................................................. 12
7.11.2
Site Verification Procedure ............................................................................................... 12
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7.11.3
Periodic Test Procedure ................................................................................................... 12
7.12
Node Loss Compensation ......................................................................................................... 14
7.12.1
General ............................................................................................................................. 14
7.12.2
Methods for Compensation ............................................................................................... 16
7.12.3
Node Loss Compensation Variables and Calculations ..................................................... 16
7.13
Record Retention ....................................................................................................................... 21
Appendix D– Settlement Metering Data Management Protocols ........................................................... 1
1
Scope ................................................................................................................................................... 2
2
Purpose ............................................................................................................................................... 2
3
Definitions ........................................................................................................................................... 2
4
Meter Participants .............................................................................................................................. 2
4.1
4.2
Responsibilities ............................................................................................................................ 2
Metering Agent(s) Designation .................................................................................................... 2
5
Metering Agent ................................................................................................................................... 3
6
Data Format ......................................................................................................................................... 3
6.1
6.2
6.3
6.4
7
Unit of Measure ........................................................................................................................... 3
Sign Convention of Data .............................................................................................................. 3
Meter Technical Standards .......................................................................................................... 3
Data Submission Standards ........................................................................................................ 4
Settlement Meter Data Types ............................................................................................................ 4
7.1
Resources (Generation) Metering ............................................................................................... 4
7.1.1 Net ........................................................................................................................................... 4
7.1.2 Joint Owned Unit (JOU) Generation........................................................................................ 4
7.1.3 Generation Loss Compensation .............................................................................................. 4
7.2
Load Metering .............................................................................................................................. 4
7.2.1 General .................................................................................................................................... 4
7.2.2 Load Loss Compensation ........................................................................................................ 5
7.2.3 Residual Load.......................................................................................................................... 5
7.2.4 Behind-the-Meter Generation .................................................................................................. 5
7.2.4 Adjustments for Demand Response ........................................................................................... 5
7.3
Net Actual Interchange (NAI) ....................................................................................................... 5
7.3.1 General .................................................................................................................................... 5
7.3.2 Settlement Area Net Actual Interchange (SA NAI) .................................................................. 6
7.3.3 1st Tier NAI with Non-SPP Control Area (1st Tier Non-SPP) ................................................... 6
7.3.4 NAI with SPP Settlement Area ................................................................................................ 7
7.3.5 Substitution of NSI for missing NAI Metering Data ................................................................. 7
8
Settlement Location Anatomy ........................................................................................................... 8
8.1
General ........................................................................................................................................ 8
8.2
Making of a Settlement Location ................................................................................................. 8
8.2.1 Resource Settlement Locations .............................................................................................. 8
8.2.2 Load Settlement Locations .................................................................................................... 11
8.2.3 Overview of Settlement Area Load Settlement Locations ..................................................... 12
9
Loss Compensation for Settlement Locations .............................................................................. 13
9.1
9.2
General ...................................................................................................................................... 13
Loss Compensation Types ........................................................................................................ 14
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9.2.1 Flat Percentage ..................................................................................................................... 14
9.2.2 Engineered Adjustment with Assumptions ............................................................................ 17
9.2.3 Engineered Adjustment ......................................................................................................... 17
9.3
Truncate and Carry Application ................................................................................................. 17
9.3.1 NERC interchange and Whole MWhs ................................................................................... 18
9.3.2 Truncate and Carry Process ................................................................................................. 18
10
Settlement Data Reporting .............................................................................................................. 18
10.1
Submission Timeline .................................................................................................................. 18
10.2
Meter Data Exchange and Submission ..................................................................................... 19
10.2.1
Actual Meter Data (Idata) .................................................................................................. 19
10.2.2
Profile Data (Pdata)........................................................................................................... 20
10.2.3
Alternate Settlement Meter Data ....................................................................................... 20
11
Data Source and Estimating ............................................................................................................ 21
11.1
Actual Meter Data (Idata – Actual) ............................................................................................ 21
11.1.1
Primary Data Sources ....................................................................................................... 21
11.1.2
Backup Data Sources ....................................................................................................... 21
11.2
Estimated Meter Data (Idata – Estimated) ................................................................................ 21
11.2.1
Estimation Methods........................................................................................................... 21
11.2.2
Replacing Estimated Meter Data ...................................................................................... 22
12
Verification Meter SL Values ........................................................................................................... 22
12.1
Data Types and Verification Methods ........................................................................................ 23
12.1.1
Telemetered Pulses via Remote Terminal Unit (RTU) ..................................................... 23
12.1.2
Register Transfer via Other Communication Options ....................................................... 23
12.1.3
Interval Data Recorder Collection System (IDRCS) ......................................................... 23
12.1.4
Inter Control Center Protocol (ICCP) Data ....................................................................... 24
12.1.5
Alternate Data for Verification ........................................................................................... 24
12.2
Periodicity of Verification ........................................................................................................... 24
12.2.1
Telemetered Pulses via Remote Terminal Unit (RTU) ..................................................... 24
12.2.2
Other Data Transfers ........................................................................................................ 24
12.3
Verification Uncovers Discrepancy ............................................................................................ 24
12.3.1
Identify the Cause for the Discrepancy ............................................................................. 24
12.3.2
Impact to Settlement Location Values Submitted ............................................................. 25
13
Real Time Data Reporting by Settlement/Balancing Authority ................................................... 25
14
Record Retention.............................................................................................................................. 26
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Glossary
Aggregate Price Node (APNode)
A collection of Price Nodes (PNode) whose prices are averaged with a defined weighting
component to determine and aggregate price.
Balancing Authority (BA)
The responsible entity that integrates Resource plans ahead of time, maintains Loadinterchange-Resource balance within a Balancing Authority Area, and supports
Interconnection frequency in real-time.
Calibration Allocation Factor (CAF)
The percentage used in allocation of Calibration Energy to the profiled (or consumption
metered) Load. This percentage is load weighted for profiled and interval Load.
Calibration Energy
Energy representing the difference between Net Area Input and the sum of metered Load
for a Settlement Area and Settlement Interval. Losses are considered in the calculation as
an adjustment to the data.
Central Prevailing Time (CPT)
Clock time for the season of a year, i.e. Central Standard Time and Central Daylight
Time.
Control Area
Defined in the Open Access Transmission Tariff.
Counter Party
Defined in the XML Document as Attachment XXX in the Protocols.
Day Ahead Period (DA)
The time period starting at 0700 and ending at 1530 of the day prior to the Operating
Day.
Deployment Interval
The interval for which SPP issues dispatch instructions for Energy Imbalance Service.
The dispatch interval is currently 5 minutes.
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Dispatch Instructions
Expressed as the value at the end of the Deployment Interval.
Dispute
Defined in the SPP Open Access Transmission Tariff.
Distributed Generation
An electrical Resource greater than 1 MW peak capacity which is connected to a
distribution system.
Dynamic Schedule
A telemetered reading or value that is updated in real time and used as a schedule in the
Automatic Generation Control/Area Control Error equation and the integrated value of
which is treated as a schedule. Commonly used for “scheduling” jointly owned Resources
or remote Load to or from another Control Area.
Electrical Node (ENode)
A physical node of the network model where electrical equipment and components are
connected.
Emergency
As defined in the LGIA attachment, page 262, to the SPP OATT.
Energy Imbalance Service (EIS)
EIS is an ancillary service used to compensate for differences between the scheduled and
the actual withdrawal of energy or between the scheduled and the actual output of a
Resource.
Energy Management System (EMS)
The software system used by SPP for the real-time acquisition of operating data and
operations.
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Energy Schedule
Defined in the Open Access Transmission Tariff.
Flowgate Constraints
The NERC registered flowgate constraints that are also found in the IDC and are eligible
for TLR to be called for relief.
Generator Shift Factor (GSF)
As defined in the NERC Glossary Terms used in Reliability Standards.
Hour Ahead Period (HA)
The time period following the close of the Day-Ahead Period and ending at the thirty
minutes before the Operating Hour.
Intermittent Resource
A Resource powered solely by wind, solar energy, run-of-river hydro or other
unpredictable energy source for which a Market Participant can not reasonably forecast
or control the Resource output on an hour ahead basis. SPP will determine whether a
Resource qualifies as an Intermittent Resource based upon review of the MP’s request.
Interval Data (Idata)
End-use customer or wholesale Load data that is measured using an interval data recorder
(IDR) with settlement interval granularity.
Locational Imbalance Pricing (LIP)
The calculation of prices for Energy Imbalance Service at Settlement Locations using the
state estimator and a security constrained economic dispatch concept. (e.g. The price to
provide least-cost incremental unit of energy at that location)
Manual Constraints
Those monitored element and contingency combinations that SPP enters manually.
These also are non-flowgates.
Market Operations System
The real-time systems responsible for the operational aspects of ancillary service offers,
deployment, and Locational Imbalance Pricing calculations.
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Market Participants (MP)
Defined in the Open Access Transmission Tariff.
Market Power
The ability to cause prices to deviate from competitive levels by controlling the provision
of generating or transmission capacity to the market, whether by “physical” withholding
or “economic” withholding.
Megawatt (MW)
A measurement unit of the instantaneous demand for energy.
Metering Agent (MA)
An entity responsible for the acquisition of end-use meter data, application of losses,
aggregation of meter data, application of data to Settlement Intervals and transfer of data
to SPP. This entity can be a traditional utility entity or other competitive entity. The
Market Participant registers their Metering Agent(s) with SPP.
Meter Participant
A Market Participant or their designated agent that is settled through the SPP energy
market and is subject to the energy imbalance settlement process.
Metering Parties
All parties, identified in a transmission service agreement, that have a vested interest in
the accuracy of the meter data. Typically this would include SPP, Control Area Operator,
Wire Facilities Owner(s), Meter Owner, and Meter Participant.
Meter Settlement Location
Defined in the Open Access Transmission Tariff.
Native Load Schedule
Defined in the Open Access Transmission Tariff.
Net Actual Interchange
The algebraic sum of all energy flowing into or out of a Settlement Area during a
Settlement Interval.
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Net Scheduled Interchange (NSI)
The algebraic sum of all energy scheduled to flow into or out of a Settlement Area during
a Settlement Interval. NSI includes the ramp on a 4 second interval to achieve the
Dispatch Instructions at the end of the Deployment Interval.
Node
A specific electrical bus location in the SPP EMS transmission model for which a
settlement price is calculated.
North American Electric Reliability Council (NERC)
A non-profit organization whose mission is to ensure that the bulk electric system in
North America is reliable, adequate, and secure.
Offer Curve
The Supply Curve is a set of price/quantity pairs that represents the offer to provide
energy or curtail.
Operating Day (OD)
The daily period beginning at midnight for which transactions within SPP are scheduled.
Operating Hour (OH)
A 60 minute period of time during the Operating Day corresponding to a clock hour.
This can also be expressed as the Hour Ending.
Operating Reserve – Spinning
Defined in the Open Access Transmission Tariff.
Operating Reserve – Supplemental
Defined in the Open Access Transmission Tariff.
Price Node (PNode)
A pricing point representing the location where Locational Imbalance Prices are
calculated. Each PNode is associated with one and only one ENode establishing the
linkage between the commercial model and the physical model.
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PNode Constraints
A second type of Manual Constraint in which SPP identifies a PNode or set of PNodes
along with static shift factors and a limit. The flow on each PNode when multiplied by
its shift factor cannot exceed the stated limit when this constraint is activated.
Portal
Internet interface between SPP’s computer systems related to market operations and
settlement and the Market Participant.
Portfolio Schedule
Energy Schedules which are sourced from Market Participant’s fleet of commonly
dispatched generation and not a specific Resource. The Settlement Location
corresponding to the source of the transaction will be the Market Participant’s load
Settlement Location.
Profile Data (Pdata)
End-use customer Load data that is not measured using an interval data recorder (IDR)
with settlement interval granularity. This includes un-metered and consumption metered
data.
Real Time Period
The time period following the close of the Hour Ahead Period during which SPP or the
control area operator balances the system by deployment of energy from Energy
Imbalance Service, Regulation Service, Operating Reserve- Spinning, Operating
Reserve- Supplemental.
Regulation Type
See Regulation and Frequency Response Type as defined in the NERC Operating
Manual. The market separates Regulation into Up and Down.
Resources
Assets which are defined within the Market System which inject energy into the
transmission grid, or which reduce the withdrawal of energy from the transmission grid,
and may be discretely directed by the RTO or ISO. These Resources include generation
and controllable Load.
Resource/Obligation Type
Defined in the XML Document as Attachment XXX in the Protocols.
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Resource Test Mode
Operation of new facilities not yet commercially accepted by the owner of the Resource
designed to assist in commercial acceptance of the Resource by the owner or the
operation of a Resource that has been off-line due to an extended maintenance period.
This operation must be coordinated with the SPP Market Operator to the extent possible.
RTCA Constraints
Constraints found to be at risk by the SPP Real-Time Contingency Analysis Application
that are not defined as flowgates.
Self-Dispatched Resource
A Resource that is not available for dispatch by SPP to support Market Operations.
Settlement Area
A geographic area for which transmission interval metering can account for the net area
Load. A settlement area is typically a Control Area, and must be completely contained in
a single Control Area
Settlement Interval
The period of time for which the market is financially settled. This period of time is
coincident with scheduling granularity and Energy Imbalance Service price calculation
intervals. The settlement interval is currently one hour.
Settlement Location
Locations defined for the purpose of commercial operations and settlement. A
Settlement Location is the location of finest granularity for calculation of Imbalance
Settlements. The data required must be at this level of granularity in schedules, meter
data, and pricing.
Settlement Statement
A statement of the market and other tariff charges related to the Settlement for a Market
Participant.
Shut-down Mode
A period of time after the Resource operates below its Minimum Capacity Operating
Limit as indicated in the Resource Plan, but not to exceed one hour before and after the
scheduled time for a Resource to be removed from the electrical grid, during which a
Resource will be exempt from Uninstructed Deviation Penalties.
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SPP Region
The geographic area of the Transmission System for which SPP is the Transmission
Provider.
Start-up Mode
A period of time before the Resource reaches its Minimum Capacity Operating Limit as
indicated in the Resource Plan, but not to exceed 2 hours before and after the scheduled
time for a Resource to synchronize to the grid, during which a Resource will be exempt
from Uninstructed Deviation Penalties.
State Estimator
The computer software used to estimate the properties of the electric system based on a
sample of system measurements.
Transaction Distribution Factor (TDF)
As defined in the NERC Glossary of Terms used in Reliability Standards.
Watch List Constraints
Constraints found to be loaded at or above their limit during the MOS Hour Ahead
Balancing studies and , optionally, Day Ahead Congestion Management studies during the
Contingency Analysis phase of those applications that are also not defined as flowgates.
Wire Facilities Owner(s)
Entity that owns transmission or distribution system infrastructure.
1 Introduction
The SPP Market Protocol document serves as a companion to the Tariff, the Business Practices,
and the Criteria.
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BY-LAWS
MEMBERSHIP
AGREEMENT
Establishes Organizational framework,
structure and purpose
Establishes obligations of SPP and
Members pursuant to membership
TARIFF
SPP CRITERIA
Establishes services to be provided, and
rights and obligations of the parties
pursuant to those services
BUSINESS
PRACTICES
Rules that clarify specific areas of the
Tariff that have been challenged and
resolved.
Rules to promote and protect system
reliability that members are obligated
to follow
MARKET
PROTOCOLS
Reference document for rules and procedures
for participation in Energy Imbalance Service
market offered under the Tariff
The Market Protocol document specifically defines the terms, procedures, Energy Obligations
and responsibilities of SPP and Market Participants (MP) relating to the SPP Market functions.
SPP’s Board of Directors has adopted a phased implementation approach to comply with FERC
Order 2000 requirements for wholesale markets. The first phase is an Energy Imbalance Service
(EIS) market with the following major features:
This is an imbalance energy only market and does not supersede any MP’s Energy 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.
All SPP MPs with Loads and/or Resources will be subject to EIS under this market. All
participants must register with the SPP market. Entities wishing to provide EIS energy will
submit offers to the market.
All Loads and Resources are located at Settlement Locations. EIS offers are submitted for each
Resource participating in the EIS market. These offers are tied to the Settlement Location at
which the Resource is located. SPP will use a Security Constrained Economic Dispatch (SCED)
to determine the lowest cost increment of energy that can be delivered to each location
considering the submitted offers, transmission limitations and system topology. EIS dispatch
instructions will be calculated for Dispatchable Resources, and Locational Imbalance Prices
(LIP's) will be calculated for each Settlement Location on the system.
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Resources will be settled based on the LIP associated with their Settlement Location. .
Resources are only settled nodally. Load may choose to be settled either zonally or nodally.
The LIP’s are based on the Resource offers and are locational.
Energy Imbalance Service is calculated by subtracting scheduled MWh from actual MWh.
Settlement will be the quantity of EIS energy times the LIP at that Settlement Location for a
given Operating Hour. When scheduled quantities equal actual quantities, EIS energy and
settlement are zero. The data used in Market Settlement must be submitted by Settlement
Location (node or zone).
This Market will be facilitated such that SPP maintains revenue neutrality. Any difference
between charges for EIS and payments will be uplifted (see Settlement Section 4.2).
The general organization of this document is in relation to the timeline.
2 Timeline
2.1 SPP Operational Information Exchange
The operation of the SPP system and EIS market requires the exchange of a variety of
information between the SPP and market participants.
The specific timeline and responsibilities for the provision of this information are defined in the
sections that follow.
Day-Ahead Activities
Timeline
Market Participant
Action
0700 of Operating Day-1 (OD-1)
0730 of OD –1
SPP Action
Day prior to operating day
Next Day’s -Ancillary Service
(AS) obligations for each
Market Participant and the SPP
region are sent to the MP via the
Portal.
For the next 7 days, beginning
with the Operating Day the SPP
will post hourly Load Forecast
by Settlement Area and the SPP
region
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Day-Ahead Activities
Timeline
1100 of OD –1
Market Participant
Action
Market Participants submit
Load Forecasts, Resource
Plan and Ancillary Service
Plan (see Sections 3 and 4)
1200 of OD –1
By 1300 of OD –1
Review Market Participant
Ancillary Service Plans and
notify applicable Control Areas
and MP’s when they do not
balance and/or mismatched.
Make necessary updates to
Ancillary Service Plans to
address deficiencies
(mismatched and
unbalanced), and revise
Resource Plans if needed
By 1400 of OD-1
Review Market Participant
Ancillary Service Plans and
notify applicable Control Areas
and MP’s of deficiencies. In
event of unit contingency the
SPP operator may update A/S
Plans to accommodate the
situation.
Perform contingency analysis,
including a simultaneous
feasibility test utilizing the
Resource Plan, schedules, and
Load projection. Notify
appropriate parties of
infeasibility.
Between 1300 and 1530 of OD –1
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Operating Day EIS Market Activities
Timeline
Market Participant Action SPP Action
OD-7 to
OD OH - 45 minutes
(OH is start of operating hour)
Submit Offer Curves for
upcoming hours all or
portion of OD. Based on
Offers, Resources will be
deployed on 5-minute
intervals (See Section 5 For
Offer Curve details).
Lock Resource Plans for OH
Submit energy schedules if
necessary.
30 minutes prior to start of tagged
schedules
20 minutes prior to start of NLS
schedules
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Due to the NERC approval
guidelines (approval may
take 10 minutes), tagged
schedules must be
submitted at least 30
minutes prior to the start of
the tagged schedule. All
Energy Schedules must
have received approvals at
least 20 minutes prior to the
start of the tagged schedule.
The process of submitting
an NLS results in automatic
approval, due to prevalidation of Designated
Network Resources. All
Energy Schedules must
have received approvals at
least 20 minutes prior to the
start of the NLS schedule.
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Market Protocols
Operating Hour Activities
Timeline
Market Participant
Action
SPP Action
Beginning of Deployment Interval
–5 minutes
Beginning of Deployment Interval
–5 minutes up to Beginning of
Deployment Interval -1 minute
(Delivery is upon completion and
should be prior to Beginning of
Deployment Interval -5 minutes)
Beginning of Deployment Interval
End of Deployment Interval
1. Project Load Forecast
2. Accept State Estimator
solution
3. Process OH schedules
4. Calculate Security
Constrained Economic
Dispatch (SCED)
Send Dispatch Instructions for
the end of the Deployment
Interval (including LIP in the
XML message)
Begin ramp to achieve
Dispatch Instructions for
end of Deployment
Interval
Resources at instructed
levels
SPP calculated NSI reflects the
ramp in 4-second values,
including the impact of TLR’s
and ARS events.
Within OH + 15 minutes
SPP makes LIP accessible on
the Portal for limited queries.
SPP makes available LIP,
including Meter Settlement
Locations, on www.spp.org
website.
Within OH + 15 minutes
Approximately every 4 seconds
Net Scheduled Interchange
(NSI) is modified and sent out
to Control Area (CA) to
support the ramp to achieve
the Dispatch Instructions. The
NSI accounts for the impacts
of TLR and ARS events.
Post-Operating Day Activities
Timeline
By 4 days after the OD
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Market Participant
Action
Submit Load, Resource,
and interconnection Meter
Data
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By 5 days after the OD
Initial settlement statements by
Settlement Location, Hour,
and Market Participant
Final settlement statement by
Settlement Location, Hour,
and Market Participant
By 45 days after the OD
Updates to Operating Day Data
Timeline
Market Participant
Action
Immediately following an RSS
event
0100 following the OD+3
containing an RSS event
0100 following the OD + 3
SPP Action
Assisting Control Area Load to
Contingent Control Area Load
schedules are created, in the
scheduling system, for each
participant involved in the RSS
event. One schedule is created
from the Contingent Control
Area Load to the Contingent
Resource for the amount lost.
See Operating Reserves
Criteria 6.
Participants have the
opportunity to offset the
Load schedules created by
the RSS event by entering
Resource to Load
schedules, reflecting
generation Resources
actually utilized to assist in
the event for use in
Settlement.
Estimated Dynamic
Schedules may be updated
Performs checkouts, including
Dynamic Scheduling
3 Resource Plans
3.1 Introduction
The Resource Plan is submitted by Market Participants with registered Resources to enable the
SPP Market Operation System (MOS) to assess Resource and Ancillary Service adequacy for the
SPP region, each SPP control area, and each Market Participant. The operator of the Control
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Market Protocols
Area remains responsible for the balance of Load and Resources within the Control Area
boundary. See Appendix 7 of SPP Criteria for requirements of data submission.
External Resources have the same requirements for submitting a Resource Plan as those
Resources within the SPP Market Footprint, except as specified below. For such External
Resource capacity as is offered into the SPP Market, (i) only status available to External
Resources is “Available” or “Unavailable”; (ii) the Min MW must be set to zero and (iii) the
Max MW may not exceed the transmission service arrangements associated with the External
Resource. If tagged, the Max MW may not exceed the tag value, including the curtailment limit
adjusted by the NERC Interchange Distribution Calculator (IDC).
Market Participants shall submit Resource Plans for Demand Response Resources (DRR) with
the exceptions as noted in Section 3.2.
3.2 Contents
The Resource Plan covers a seven-day horizon (with hourly detail) beginning with the Operating
Day. See SPP Criteria Appendix 7 and XML Specifications for additional details. Specifically,
the Resource Plan contains entries for each Resource for each hour of the seven day horizon,
unless otherwise provided, similar to and includes the following:

Resource ID - Unique identifier for Resource in SPP Market

Resource Type - GEN-Generation, VDD – or Variable Dispatch Demand Response
(VDDR), BDD - Block Dispatch Demand Response, CLD-Controllable Load, or PLTPlant

(why keep the CLD?)

Planned Megawatts - Anticipated dispatch of unit Resource independent of energy
imbalance deployment (This value is within the dispatchable range of the Resource).
VDDR Resources DRR will submit a value of 0 MW for this field.

Minimum Capacity Operating Limit - Resource physical minimum sustainable output for
each Operating Hour (“MinMW”). Block Variable Dispatch Demand Response
Resources must have a 0 MinMW.

Minimum Economic Capacity Operating Limit - Resource economic minimum output
selected by Market Participant for each Operating Hour (“MinEconMW”). Must be
equal to or greater than value provided for Minimum Capacity Operating Limit. Block
Variable Dispatch Demand Response Resources must have a 0 MinEconMW.

Minimum Emergency Capacity Operating Limit - Resource physical minimum
emergency output for each Operating Hour (“MinEmerMW”). Must be equal to or less
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than value provided for Minimum Capacity Operating Limit. . Block Variable
Dispatch Demand Response Resources must have a 0 Min EmerMW.

Maximum Capacity Operating Limit - Resource physical maximum sustainable output
for each Operating Hour (“Max MW”). For Demand Response Resources, Max MW
will be the maximum amount of response or interruption that can be provided.

Maximum Economic Capacity Operating Limit - Resource economic maximum output
selected by Market Participant for each Operating Hour (“MaxEconMW”). For Demand
Response Resources, this will be the maximum amount of response or interruption that
can be provided under normal market operations. Must be equal to or less than value
provided for Maximum Capacity Operating Limit.

Maximum Emergency Capacity Operating Limit - Resource physical maximum
emergency output for each Operating Hour (“MaxEmerMW”). For Demand Response
Resources, this will be the maximum amount of response or interruption that can be
provided under emergency operating conditions. Must be equal to or greater than value
provided for Maximum Capacity Operating Limit.

Ramp Rate - Rate at which Resource can change output in MW/min
Market Participants will submit their Ramp Rates through a segmented profile. The profile will
require at least 1 segment and may have up to n segments where n will be defined by SPP,
initially set to 10.
o Breakpoint Limit 1– Resource MW output at which segment 1 Ramp Rates will
apply. If the value is not less or equal to actual measured MW during
deployment, the values in segment 1 will apply back to the actual measured MW.
o Block 1 Rate Up – Rate at which Resource can change output upward in
MW/min at output levels greater than or equal to Breakpoint Limit 1.
o Block 1 Rate Down – Rate at which Resource can change output downward in
MW/min at output levels greater than or equal to Breakpoint Limit 1.
o Block 1 Rate Emergency – Rate at which Resource can change output upward or
downward in MW/min at output levels greater than or equal to Breakpoint Limit
1 during an emergency.
o Breakpoint Limit n– Resource MW output at which Ramp Rate changes from
previous segment values to segment n values.
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o Block n 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
o Block n 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
o Block n Rate Emergency – Rate at which Resource can change output upward or
downward in MW/min at output levels greater than the Breakpoint Limit 1 and
less than Breakpoint Limit 2 during an emergency.

Resource Status:
o Available – Resource is online and available for SPP Deployment.
o Available Quick Start – Resource is off line, available for SPP deployment,
capable of closing the breaker, synchronizing to the grid, and reaching the
operating level consistent with the dispatch instruction.
o Unavailable – Resource is offline and unavailable for SPP Deployment or other
uses.
o Supplemental – Resource is offline and available for satisfying Supplemental
Reserve requirements. The Resource will NOT be dispatched by the MOS
system.
o Manual - Resource is
(a) Not capable of following Dispatch Instructions, either by virtue of: (1) being
an Intermittent Resource; or (2) undergoing a Resource Test, Startup,
or Shutdown Mode; and
(b) Not capable of adhering to a Schedule either by virtue of: (1) being an
Intermittent Resource; or (2) operating in Resource Test, Startup, or Shutdown
Mode where the inception, termination, or duration of the testing, Start-up or
Shut-down process cannot be confirmed or predicted.
Manual status is not a valid status for VDD Resources.
Resources in manual status will be permitted to report Ancillary Services if the limitations on
their ability to follow Dispatch Instructions or adhere to their Schedules do not preclude them
from providing said Ancillary Services.
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Market Protocols
o Self-dispatched – Resource is online and unavailable for SPP Deployment. SelfDispatched is not a valid status for a VDD Resource.
Note that the meaning and format and current required fields of this submission are fully defined
in the XML Specification document.
The Resource Plan may not be the only source of Resource data required by SPP, in its roles as
the Regional Reliability Coordinator and Transmission Service Provider, for the purposes of
maintaining system reliability and granting transmission service. Market Participants with
registered Resources, or the Balancing Authorities within which such Resources are located, may
be requested to provide to SPP additional Resource information beyond that contained in the
Resource Plan through mechanisms other than the Portal or API, as deemed necessary by SPP
and consistent with its authority as the Regional Reliability Coordinator and Transmission
Service Provider.
3.3 Timing and Submission Mechanisms
Market Participants with registered Resources will be required to submit Resource Plans and are
required to keep the plan up to date throughout the Operating Day. The first submission of
Resource Plans for an Operating Day and beyond is by 1100 the day preceding the Operating
Day. This data for any individual hour may be updated until 45 minutes prior to the beginning of
that Operating Hour.
This data will be submitted via the Portal or the Application Program Interface (API).
3.4 Use of Data
The Resource Plan data is used for both market and reliability purposes. SPP will utilize the
Planned Megawatts to perform contingency analysis and to determine the transmission service
available for sale the following day. SPP will also utilize the Planned Megawatts to assist with
determining whether a Resource is in Start-Up Mode or Shut-Down Mode. Energy Schedules
that are submitted by 1100 the day ahead of the Operating Day are included in the contingency
analysis (which includes an evaluation of simultaneous feasibility) of next day schedules. SPP
will also utilize Resource Plan data along with the Offer Curves, Load Forecasts, and the State
Estimator to determine the Dispatch Instruction for EIS Resources. If a Resource is on and
unavailable, to the Market, it is considered a Self-dispatched Resource and will only be
dispatched by SPP in a system emergency (of type “out of merit energy” or “OOME” dispatch
instruction).
3.5 SPP Manual Overrides
Market Participants are required to keep the data up-to-date during the Operating Day. In the
event of a required change in the Resource Plan 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. Customers shall
remain responsible for accurately reflecting Resources in their Resource plan submissions for
subsequent hours.
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3.6 Load Forecast
SPP uses Load forecast information for the following EIS Market purposes:




Determine amount of Resources necessary to be dispatched by the market
Estimate the amount of Market Flow on flowgates for next-hour
Perform simultaneous feasibility studies
Determine supply adequacy
3.6.1 Market Participant Load Forecasting
The Market Participant Load forecast for Resource planning purposes shall be submitted as
specified herein. By 11:00 a.m. CPT on the day prior to the operating day, each Market
Participant that has registered a load Settlement Location shall submit to SPP the amount of
Load it expects to serve by Settlement Area for each hour of the next Operating Day. The
Market Participant may update its forecast for any Operating Hour as late as 45 minutes prior to
that Operating Hour. This information shall be submitted via the Portal or Application Program
Interface (API). The Load Forecasts provided by the Market Participants shall be used by SPP to
evaluate Market Participants’ Resource Plans and to compare with Load forecasts submitted by
Balancing Authorities pursuant to SPP Criteria and those Settlement Area forecasts developed by
SPP. The Market Participants’ Load forecast should be net of “behind-the-meter” generation
that is not registered as a Resource. When a registered Resource is electrically located behind a
load settlement location meter the total load will be calculated by summing the load meter and
the generator meter..
SPP will use the Load forecasts submitted by the Market Participants as described above in
conjunction with those Market Participants’ Resource Plans and schedules to determine if each
Market Participant has committed sufficient capacity to supply its Energy Obligations. To
ensure that the Market Participant load forecasts are reasonable for this purpose, SPP will
aggregate the Load forecasts submitted by Market Participants by Settlement Area and compare
to the Settlement Area forecast developed by SPP, as discussed in Section 3.6.2, and to the
Balancing Authority Area Load forecast submitted by the Balancing Authority. SPP will
investigate and analyze where significant differences exist.
3.6.2
SPP Load Forecast
Short-term and mid-term Settlement Area forecasts are developed by SPP. The short-term
forecast produces a value every 5 minutes for the next 15 minutes. The mid-term forecast
produces hourly values for the next hour through 7 days out. SPP aggregates its Settlement Area
short-term Load forecasts along with schedules into and out of the market footprint to determine
the amount of Resources to be dispatched by the market for the upcoming dispatch cycle. The
mid-term forecast is an input used to estimate the amount of Market Flow on flowgates for the
next-hour and to perform simultaneous feasibility studies. To ensure that SPP’s forecasts are
reasonable for these purposes, SPP will compare its Settlement Area forecasts with the Load
forecasts submitted by Balancing Authorities pursuant to SPP Criteria. If SPP’s Load forecast
for a particular Settlement Area appears to be consistently inferior to the associated Balancing
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Authority’s Load forecast or if SPP’s Load forecasting engine fails to produce a forecast, the
Balancing Authority forecast will be used.
3.6.3 Actual Resource Production and Load Actual Gross-up for Demand
Response Dispatched
The MP that registers a DRR, the registered owner of the load Settlement Location and their
respective Meter Agents will agree to the methodology to calculate the Actual Resource
Production (ARP), add that response into the appropriate real time specific loads, metered actual
for the Settlement Location and provide the ARP to SPP and the BA. The BA, as necessary, will
use the ARP to account for DRR activity in the load actual sent to SPP.
4 Ancillary Service Plan
4.1 Introduction
Each MP submits its Ancillary Service Plan to enable the SPP Market Operation System to
confirm each MP is satisfying its Ancillary Service obligations. The Ancillary Service Plan
indicates transfers of Energy Obligations between MPs and, when self provided, which
Resources are providing these services. Ancillary services are supplied and procured in
accordance with the provisions of the SPP tariff and applicable SPP criteria.
MP’s must indicate on the AS Plan Reserves and Regulation (Spin, Supp, Upreg, Downreg)
sufficient to meet their Energy Obligations. MP’s may also designate Reserves and Regulation
in excess of their Energy Obligations for reliability purposes.
4.2 Contents
Resources will submit Ancillary Service Plans identifying designations similar to the following:

Operating Day

Operating Hour

Counter Party

Counter Party Type (MP, PLT, GEN, CLD, RTO)

A/S Schedules (Resource or Obligation)

Megawatts

Control Area
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
Regulation Reserve Type – Up/Down

Operating Reserve – Spinning

Operating Reserve – Supplemental
MP’s with Loads will submit Ancillary Service Plans identifying the MP’s with Resources
providing reserves. See XML Specifications for further details. Note that the meaning and
format and currently required fields of this submission are fully defined in the XML
Specification document.
4.3 Timing and Submission Mechanism
MP’s who are required to provide ancillary services, and those who have made arrangements to
self-provide in whole or part, are required to submit an Ancillary Service Plan to indicate how it
intends to satisfy its ancillary service obligations. An Ancillary Service Plan for each hour of an
Operating Day must be submitted no later than 1300 the day prior to the operating day. The
Ancillary Service Plan for any individual hour may be updated until 45 minutes prior to the
beginning of that Operating Hour. The adequacy and validation of capability to provide the
ancillary services will be assessed by SPP and any discrepancies will be reported back to the MP
to enable modification of the Ancillary Service Plan.
If a Market Participant’s Ancillary Service Plan has not resolved a deficiency in meeting its
Ancillary Services Obligation prior to the Ancillary Services Plan deadlines (both day prior and
operating day) the Market Participant is required to inform SPP how the deficiency will be
satisfied, including if necessary the declaration of Other Extreme Conditions (OEC), per Criteria
6.
This data will be submitted via the Portal or the Application Program Interface (API).
4.4 Use of Data
SPP will post daily Ancillary Service requirements for each MP and the SPP region for the
Operating Day. SPP will validate MP’s Ancillary Service Plans against SPP calculations and
identify shortages, and coordinate with affected Control Areas. The Ancillary Service Plans will
also be used by the Market Operations System to ensure that EIS deployment does not consume
unloaded capacity being utilized for other Ancillary Services.
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4.5 SPP Manual Overrides
Market Participants are required to keep the data up-to-date during the Operating Day. In the
event of a required change in the Ancillary Service Plan 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.
Customers shall remain responsible for accurately reflecting Resources in their Ancillary Service
plan submissions for subsequent hours.
5 RESOURCE OFFERS CURVE
5.1 Introduction
To submit an offer an Market Participant must have executed the service agreement as specified
in Tariff Attachment AH. Offer Curves are submitted by Resource. Resources that offer energy
into the SPP EIS market must specify an offer price. The price is specified using an Offer Curve.
The Offer Curve allows Resources to offer multiple points at different prices. An Offer Curve is
submitted for each Resource with up to ten monotonically increasing pairs of MWh and price.
The price may be positive or negative and may be capped. See Section 11 for further details.
Owners of Joint Owned Units may agree to register the units as separate Resources.
5.2 Contents
5.2.1 Offer Curves
The Offer Curve allows Resources to offer multiple points at different prices. An Offer Curve is
submitted with up to ten monotonically increasing pairs of MWh and price. For Generator, Plant
and Variable Dispatch Demand Response Resources, the Offer Curve will include the following
components:

Date

Hour Ending

Resource

Megawatts

Price/MWh
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Example of an Offer Curve from the Portal :
5.3 Timing and Submission Mechanism
Offer Curves may be submitted as early as 7 days prior to the Operating Day and may be
submitted or revised until 45 minutes prior to the Operating Hour. If a Resource Plan indicates
that the Resource is available for SPP dispatch and an Offer Curve is not submitted, the most
recent Offer Curve will be used for deployment. If an Offer Curve has not been submitted to
MOS within the last 7 days, consistent with the MOS data purge timeline, the default offer curve
price will be $0 for the entire available capacity.
This data will be submitted via the Portal or the Application Program Interface (API) as defined
in Appendix B.
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5.4 Use of Data
The Offer Curve is used in the calculation necessary for deployment and the resulting Locational
Imbalance Price (LIP). 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. The first Pricing Point must correspond to the zero (0) MW loading
level regardless of whether the unit is capable of operating at that level. The last Price Point on
the Offer Curve is used for all MWs between that point and the Maximum Capacity from the
Resource Plan. These examples illustrate the Offer Curve used in the deployment calculations
that were developed from the submitted price MW pairs.
Example 1
Data
$
$0.00
$20.00
$25.00
$25.01
$50.00
Offer Curve for Dispatch
$60.00
$50.00
$40.00
$/MWh
Submitted
MW
0
100
200
400
500
$30.00
$20.00
$10.00
$0.00
0
100
200
400
500
MW
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Example 2
Data
$
$0.00
$20.00
$25.00
$25.01
$30.00
$30.01
$40.00
$40.01
$45.00
$45.01
Offer Curve for Dispatch
$50.00
$45.00
$40.00
$35.00
$/MWh
Submitted
MW
0
20
21
40
41
60
61
80
81
100
$30.00
$25.00
$20.00
$15.00
$10.00
$5.00
MW
The deployment is calculated using a security constrained economic dispatch to arrive at a least
cost solution. When transmission constraints cause a re-dispatch by SPP, the LIP’s may differ.
6 Energy Schedules
6.1 Introduction
Energy schedules are submitted reflecting bilateral and Self-dispatched activities. Source and
sink information on the energy schedules must match the NERC Registry. Schedules that source
or sink within the SPP Market will be rejected if they are submitted without an appropriate SPP
source and/or sink mapped to a Settlement Location. SPP requires all scheduled injections to
equal scheduled withdrawals plus losses. Although scheduling of all Load is not required,
principles observed are (1) Market Participants will not be paid (due to under-scheduling) for
providing counterflow when serving firm Energy Obligation (Resources providing energy that
serves their firm Energy Obligation), and (2) Market Participants will not be allowed to profit
from submitting schedules in excess of their firm Energy Obligations.
6.2 Content
Energy Schedules consist of hourly values for each Settlement Location must be submitted by 30
minutes prior to the start of the schedule for tagged transactions or 20 minutes prior the start of
the schedule for the NLPS transactions and must have been approved at least 20 minutes prior to
start of schedule. Due to the NERC approval guidelines, approval may take 10 minutes on
tagged transactions. These schedules do not have to include all Load for which the MP is
responsible; however, the energy withdrawn and the energy received must match for each hour.
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100
95
90
85
80
75
70
65
60
55
50
45
40
35
30
25
20
15
10
5
0
$0.00
Market Protocols
Energy Schedules will be classified as one of two types under the SPP Market depending on the
Resource Status submitted in the Resource Plan. If the source for the Energy Schedule is a SelfDispatched Resource, the schedule will be a Physical Schedule. If the source for the Energy
Schedule is offered into the Market for SPP Dispatch or the source is a Settlement Location for
Load, the schedule will be considered a Market Schedule.
MP’s may submit schedules and Offers for each of their Resources. If the MP submits both a
schedule and an offer, the dispatch system will ignore the scheduled output for each Resource
and calculate a Dispatch Instruction for the Resource based on the Offer Price and the
information in the Resource Plan. In this case the Energy Schedule will be considered a Market
Schedule since the scheduled amount is only relevant to Market Settlement and the physical
operation of the unit will be driven by the economics of its offer. If the MP submits an Energy
Schedule sourcing from a Self-Dispatched Resource, that schedule will be considered a Physical
Schedule. This is due to the fact that a Self-dispatched Resource will be expected to physically
operate to its scheduled amount. In this case the schedule still goes to the Settlement process but
the Resource will also receive a Dispatch Instruction based on the total scheduled amount for the
Self-Dispatch Resource.
Energy Schedules are submitted through SPP’s Regional Transmission Operator Scheduling
System (RTO_SS) and Native Load and Portfolio Scheduling Tool (NLPS), utilizing the
procedures found in scheduling documentation.
For Energy Schedules within, out of, or into the SPP Market to be approved, NERC registry
entries for SPP Market sources and sinks must be mapped to valid Settlement Locations. SPP
maps the Purchasing Selling Entity (PSE) and Transaction System Information Network (TSIN)
Sink/Source entry to Settlement Locations based on request. Contact your SPP Customer
Relations representative for assistance in the mapping.
6.3 Timing and Submission
Modified Energy Schedules, must be submitted and approved under the same timing as Section
6.2. Market Participants shall submit actual values for Dynamic Schedules to SPP prior to 0600
CPT on the business day prior to the 5th calendar day following the Operating Day in time for the
Initial Settlement. Reserve Sharing schedules identifying Resources may be input until 0100
three days after the Operating Day.
6.4 Use of Data
Energy Schedules that are submitted by 1100 the day ahead of the Operating Day are included in
the contingency analysis (which includes an evaluation of simultaneous feasibility) of next day
schedules
Energy Schedules are also used in the calculation of generation needs (imports/exports from the
SPP footprint), used in the SPP dispatch of Resources and the resulting SPP NSI calculations and
the calculation of EIS charges. See Section 7 on Deployment.
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6.5 Schedule Corrections
The modification of schedules (all types) will be allowed when the scheduled interchange is
invalid in RTO_SS and/or the SPP Market Settlement System. The modifications will be made
so that the schedule values will match in SPP’s schedule system and market system to the new
values. Any schedule changes, initiated by a MP, after the issuance of the Initial Settlement
statement must be initiated through the dispute procedures outlined in the Market Protocols.
Upon notification through a dispute or SPP finding the issue, the schedule will be investigated to
determine the required action to correct the schedule. After receiving approval from the
Balancing Authorities that are either the Point of Receipt or Point of Delivery on the schedule
and the Market Participants that are either the source or the sink on the schedule, SPP will
correct the values in the settlement system.
6.5.1 NLPS and Tagged Energy Schedules
Energy Schedule modifications are permitted when a system failure such as a failure to properly
transfer data from ETAG to RTO_SS, causes the schedules to be incorrectly reflected in all the
applicable computer systems.
6.5.2 Tagged Dynamic Schedules
Dynamic Schedule modifications are permitted when a system failure or other error (includes
non-SPP computer systems), such as an incorrect calculation or a revision to the associated
metered data, causes the previously reported actual schedule value to be incorrect.
6.6 Scheduling Requirements
6.6.1 External Resource Tags
All External Resources utilizing the Pseudo-Tie methodology will submit an hourly NERC tag.
The MW amount of such tag will be the same amount of its maximum MW offer, which should
be the same value as the Resource’s Max-MW value as submitted in its Resource Plan. The
Pseudo-Tie tags will be utilized by NERC IDC.
The Transmission Provider will not forward these Pseudo-Tie tags to the Market Operations
System (“MOS”) or its Commercial Operations System (“COS”). The Transmission Provider
will not utilize these tags as bilateral transactions.
6.6.2 Load Scheduling Requirements
Market Participants are not required to submit schedules to cover their anticipated firm Energy
Obligations at each Settlement Location for each Settlement Interval, but Market Participants
that do not schedule Load accurately may be subject to disgorgement of profits pursuant to
Section 11.4.2.
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In order to determine the amount of revenue a MP must disgorge from a failure to submit
counterflow schedules, the following general process will be applied for each Settlement
Location:
 After real-time operations, a MP’s Resources and Load are placed in order from lowest to
highest LIP and differences between the schedules and actuals are computed.
 Starting with the lowest LIP Resource, the scheduled output or actual output (whichever
is greatest) is counted towards meeting the MP’s Load Scheduling Requirement, starting
with the lowest LIP Load
 Schedules on congested paths (i.e., where the Resource LIP is < the Load LIP) would not
be added or adjusted
 Continue moving up the MP’s Resource stack until all of the MP’s Loads are accounted
for or the MP runs out of Resources
 If an MP’s Resource LIP exceeds the MP’s Load LIP before all of the MP’s Load is
accounted for, the excess output up to the MP’s firm Load requirement is considered
unscheduled counterflow. An MP’s actual generation above what is needed to serve its
firm Load requirements is not considered unscheduled counterflow.
 The MP will be charged the difference in LIPs between the schedule’s source and sink
multiplied by the unscheduled counterflow MWs.
 This process will be applied during all applicable settlement periods (Initial, Final, and
any Resettlement)
 For this process, SPP submitted ARS Schedules are considered as the MP’s firm Load
requirement.
In order to determine the amount of revenue a MP must disgorge from submitting schedules that
exceed a MP’s firm Load requirement, the following general process will be applied:
 After real-time operations, a MP’s Resources are placed in order from highest to lowest
LIP and differences between the schedules and actuals are computed.
 For overscheduled Load, the overscheduled MWh from highest priced Resources,
moving through the stack, are reduced until the overscheduled amount of Load is offset.
 The schedules from Resources are not reduced below the actual output of the Resource.
 Schedules from counterflow Resources will not be reduced.
 The MP will be charged the difference in LIPs between the schedule’s source and sink,
where the sink price is higher, multiplied by the overscheduled MWs.
 This process will be applied during all applicable settlement periods (Initial, Final, and
any Resettlement)
 For this process, SPP submitted ARS Schedules are considered as the MP’s firm Load
requirement
6.6.3 Resource Scheduling Requirements
The sum of Market Participant schedules sourcing from a Self-Dispatch Resource shall not
exceed the “MaxMW” of the Resource submitted in the Resource Plan for any Settlement
Interval.
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Each Market Participant is required to provide sufficient energy available to SPP to serve the
MP’s obligations at all times. MPs must satisfy their energy obligations by scheduling energy
from third parties, causing its Self Dispatched Resource to operate at Scheduled Megawatt levels
and/or making its Resources available to SPP for dispatch with sufficient dispatchable operating
range such that in aggregate they are capable of producing sufficient energy to be capable of
serving the MPs obligations at all times. MPs must satisfy their ancillary services obligations,
including operating reserve requirements, by submitting an Ancillary Services Plan which
demonstrates their ancillary service requirements are being met.
Examples of Satisfying Energy Requirements
A Market Participant with an obligation of 500 MW at Settlement Location(s) in a particular
hour and two Resources, each having a MinEconMWlimit of 60 MW and MaxEconMW limit of
300 MW, could do any of the following:
(1)
(2)
(3)
100% Self Dispatch - Self Dispatch both of its Resources, indicate it intends to
operate its Resources on its Resource Plan at an aggregate of 500 MW and
generate in real time 500 MW, consistent with the schedules. The MP must also
schedule an aggregate of 500 MW from its Resource Settlement Locations to
meet its Energy Obligations.
100 % Offered for dispatch - Make both of its Resources available for SPP
dispatch such that SPP can calculate economic base points within the their
operating range of 60 MW to 300 MW on each unit. While not explicitly
required, the MP could also choose to schedule from its Resource Settlement
Locations.
Hybrid - Make one of its Resources available for SPP dispatch such that SPP can
calculate economic base points within its operating range of 60 MW to 300 MW.
Self Dispatch its other Resource by indicating on its Resource Plan that it intends
to operate that Resource at some level at or above 200 MW and generate in real
time consistent with that indication. The MP must also schedule 200 MW from
the Self-Dispatched Resource Settlement Location. Self-Dispatch of the second
unit at or above 200 MW is required so that the remaining requirements can be
covered by the Resource that is made available for SPP dispatch. While not
explicitly required, the MP could also choose to schedule from its offered
Resource Settlement Locations.
6.6.4 Network/Native Load and Portfolio Scheduling
A Native Load and Portfolio Schedule (NLPS) is a unilateral schedule between one or more
Resource Settlement Locations and Load Settlement Locations registered by the same
Transmission Customer in the same Control Area. NLPS schedules do not utilize NERC
tags.
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Transmission Customers will have the ability to enter their NLPS into SPP’s Native Load
and Portfolio Scheduling Tool (NLPS). Transmission Customers are not required to use
NLPS. Such schedules will be included with all other schedules sent to the SPP’s settlement
system, and will have the same impact on settlement as any other type of schedule. Due to
their special nature as unilateral schedules, NLPS schedules are subject to special rules.
Special rules applied to NLPS are as follows:

NLPS will be allowed only between Settlement Locations registered by the same
Transmission Customer

NLPS will be allowed only between Settlement Locations in the same Control Area.

NLPS will be validated against the capacity list for Designated Resources. This list shall
be maintained by SPP.

NLPS may be adjusted for a given Operating Hour no later than 20 minutes prior to the
beginning of the schedule start or change (beginning of ramp).
Schedules conforming to these rules shall be automatically accepted.
6.6.4.1 Portfolio Schedules
Market Participants may make portfolio sales from their commonly dispatched Resources.
Schedules for these sales will be treated as Portfolio Schedules (PS). PSs will be scheduled by
the Market Participant from its Load Settlement Location. PSs must be supported by
Transmission Service purchased for this purpose. The portion of the NLPS attributable to the
Market Participants Network Transmission Service will be determined by subtracting (a.) the
sum of the Portfolio Schedules; from (b.) the NLPS to that load Settlement Location.
6.6.4.2 Native Load and Portfolio Scheduling Tool
The Native Load and Portfolio Scheduling Tool (NLPS Tool) will be used to submit a single
NLPS from each Resource to the Market Participant’s load Settlement Location. Within the tool,
the NLPS will be maintained as two components to account for the usage of each NLPS that is
serving Native Load (i.e. NLS) and that which is supporting Portfolio Schedules (i.e. NLPR).
6.6.4.3 Process for determining NLS and NLPR
The Market Participant will have the option to specify an amount of NLPR for each Resource
and have any additional NLPR needed to support all PSs allocated in an automated fashion.
The following outlines the steps for determining the NLS and NLPR amounts of each NLPS
schedule.
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1. The NLPS Tool shall sum all of the PSs sourcing from the MP’s load Settlement
Location.
2. The NLPS Tool will subtract any manual NLPR amount specifically identified as
supporting PSs.
3. The remainder will be allocated among the resources within the MP’s Resources
identified in the NLPS Tool.
a. For each NLPS, the Market Participant will submit a participation factor for use in
the automatic prorating process. This field should be a percentage from 0-100%
representing the maximum percentage of the NLPS the MP wants to allow for
support of PS.
b. For each NLPS, the Market Participant will submit a prioritization identifier.
This will be an integer value with 1 being the highest priority for the automated
allocation process. The same prioritization identifier may be used for multiple
NLPS.
c. The Tool shall create ‘NLPR’ schedules sourcing from the resources on a priority
basis using the priority identifier described in step 3b. If multiple NLPS have the
same prioritization identifier, all NLPS in that priority group will be prorated
based on NLPS weighted by the participation factor of the NLPS.
4. In the case that the sum of the NLPS amounts times the respective participation factors
are insufficient to meet the total PS, the deficit amount will be allocated using the
following pecking order:
a. Resources without Manual NLPR schedules prorated by any remaining NLPS not
used in the initial process. This would include any Resources with a 0%
participation factor.
b. Resources with Manual NLPR schedules prorated by any remaining NLPS not
specified in the Manual NLPR
5. In the case that the sum of all NLPS submitted does not meet the total PS, all NLPS
submitted will be allocated as NLPR and NLS for NITS will be 0 on all Resources.
6. NLPR Schedules shall be subtracted from the submitted NLPS Schedules on each
resource. The result will be NLS (Native Load Schedules utilizing Network Integrated
Transmission Service (NITS))
This schedule creation logic shall run every 5 minutes for the current and next operating
hour.
NLPR and NLS Determination Example:
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External CA
(IDC curtailable)
Schedule A
285MW
NLPS B
150MW
NLPS D
200MW
Market CA
(CAT curtailable)
Schedule B
MP_MP (Load
Settlement
Location)
300MW
NLPS A
100MW
NLPS C
200MW
An MP has a 300 MW NLPS with 100% participation factor priority 1, one 285 MW NLPS with
a 70% participation factor priority 2, one 100 NLPS with 100% participation factor priority 2 and
a 150 MW NLPS with a 0% participation factor. The sum of the Portfolio Schedules is 400MW,
and the scheduler creates a 50MW manual ‘NLPR’ from the resource with a 0% participation
factor. The 400 MW total Portfolio Schedule value is reduced by the 50 MW manually created
NLPR resulting in a 350MW requirement to be automatically allocated. The 300 MW NLPS has
the highest priority and with a 100% participation factor. The first 300 MW will be allocated to
this NLPS. The remaining 50 MW will be allocated to NLPS B and C that both have priority 2.
Using the weighted participation, the allocation would be (285*.7)*50/(285*.7 + 100*1) = 17
MW for NLPS B and (100*1)*50/(285*.7 + 100*1) = 33 MW for NLPS C.
Resource
A
B
C
D
Total
Version 14.0a
Capacity
300
400
100
200
900
Submitted
NLPS
300
285
100
150
735
NLPR
(Manual)
Total
Portfolio
Schedules
50
50
400
02/24/2010
Participation
Factor %
100
70
100
0
Prioritization
Identifier
1
2
2
1
43
NLPR
(Automatic
300
17
33
0
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6.6.5 Reserve Sharing Scheduling
NERC policy and SPP Criteria 6 will continue to dictate reserve sharing deployment. Whereas
SPP facilitates the reserve sharing program, the energy schedules implemented through the
reserve sharing deployment are settled as bilateral transactions and will continue to remain so in
the context of the EIS market. As with all bilateral transactions in the SPP EIS Market, however,
any deviation between the schedules and actual meter values at each settlement location will be
subject to EIS at the appropriate LIP.
An Operating Reserve Contingency, as defined in Criteria 6, should be immediately reported to
the SPP Reliability Coordinator via the SPP Reserve Sharing System (RSS). This includes
Resources owned by Market Participants that are not Reserve Sharing Group (RSG) Members.
The SPP RSG includes members that may not directly participate in the EIS market, i.e., are not
members of the SPP RTO. Nothing in the EIS Market Protocols should prohibit these entities
from continuing to participate in the RSG; nothing in the EIS Market Protocols should subject
these entities to changes in their internal business practices provided these entities follow SPP
Criteria 6.
The RSS automatically creates replacement energy schedules for contingencies. The
automatically generated schedules created by reserve sharing events are treated and settled as
bilateral transactions in the context of the EIS market. These bilateral transactions are
considered Market Schedules. For each contingency, up to three types of schedules will be
automatically created: 1) a schedule from a designated Load Settlement Location of the
contingent Control Area to the Settlement Location of the lost Generation Resource, 2) schedules
sourced from designated Load Settlement Locations of the supplying Control Areas to the
designated Load Settlement Location of the contingent Control Area, when assistance is needed,
and 3) schedules from the specific Resources expected to be deployed to the designated Load
Settlement Location of each Control Area required to respond to the event.
Market Participants providing assistance for a reserve sharing event deploy specific Resources at
their discretion to respond to the event. This process will continue in the context of the EIS
market. Schedules of energy deployment from Operating Reserves will ensure that Selfdispatched Resources are sent consistent instructions and allow the MOS to utilize capacity from
Market Resources allocated as Spinning and/or Supplemental Operating Reserves in the
applicable Ancillary Service plans. Market Participants may provide such schedules using one
of the following methods.
1. Enter Resource specific RSS schedules immediately.
2. Supply a default distribution prior to real-time that will automatically generate RSS
schedules.
3. Supply a default distribution and override the default with Resource specific RSS
schedules.
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Absent these schedules from one of the above methods, the Market System will send dispatch
instructions based upon pre-event operating limits. To the extent actual response differs from the
schedules automatically created, Market Participants are expected to supply in RSS schedules
from the actual Resources deployed during the event by no later than 0100 three days after the
Operating Day in which the event occurred for settlement purposes.
In instances where the SPP’s market systems have collected data for the next deployment
calculation wherein a resource contingency has occurred but corresponding RSS schedules have
not been received by MOS, SPP shall utilize the previous interval deployment for the contingent
resource in calculating deployments for the intervals between the contingency occurrence and
receipt of RSS Schedules in order to prevent both RSS and MOS deployment for the loss of the
resource. SPP staff will apply criteria to determine which contingencies trigger this event.
These criteria may include; MW magnitude, Breaker status, and/or MW rate-of-change
thresholds and SPP Staff may revise the criteria from time to time with approval from the Market
Working Group and Operating Reliability Working Group.
6.6.5.1 Reserve Sharing Transmission Service
SPP will create Emergency Transmission Service reservations from the responding areas to the
contingency location for the MW amount of support from each responding area when applicable.
The Market Participant responsible for the contingency Resource will be the Transmission
Customer for the Emergency Transmission Service charges.
6.6.4.2 Operating Reserve Contingency inside the RTO footprint
Contingency Area (Control Area/RSG member experiencing an Operating Reserve Contingency)
1. According to Criteria 6, submit request for support to SPP.
2. Continue to Follow Dispatch Instructions for Resources not designated as carrying
Contingency Reserves in A/S Plan.
3. Ramp own other Resource(s) designated as carrying Contingency Reserves in A/S Plan
to meet Reserves obligation.
4. SPP will create Reserve Sharing Schedule from the Contingency Area’s Load Settlement
Location to lost Resource’s Settlement Location for the entire amount of the loss.
5. Continue to operate according to the NSI as adjusted by SPP for RSS Schedules.
6. By 0100 three days after the Operating Day in which the event occurred, and consistent
with the scheduling requirements of Section 6.5, the responding market participant will
enter or update Resource specific schedules from those Resources ramped to meet the
Assistance Schedules.
7. Return to following Dispatch Instructions for all units for the Deployment Interval
ending 16-20 minutes after the contingency. If uneconomic Contingency Reserve
Resources are physically unable to get to new set point, ramp towards set point to the
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best of the unit’s ability. Uninstructed Resource Deviation penalties will not apply to the
units carrying Contingency Reserves for the full duration of the reserve sharing event.
Internal Responding Area (EIS Market/RTO Participating Control Area/RSG member
providing Reserve support)
1. SPP will create Reserve Sharing Schedule from Responding Area’s Load Settlement
Location to Contingency Area’s Load Settlement Location. RTO_SS NSI will be
automatically updated.
2. Continue to Follow Dispatch Instructions for Resources not designated as carrying
Contingency Reserves in A/S Plan.
3. Ramp Resources identified in the latest A/S Plan as carrying Contingency Reserves to
respond to request for Reserves support.
4. Continue to operate according to the NSI as adjusted by SPP for the RSS Schedules.
5. By 0100 three days after the Operating Day in which the event occurred, and consistent
with the scheduling requirements of Section 6.5, the responding market participant will
enter or update Resource specific schedules from those Resources ramped to meet the
Assistance Schedules.
6. Return to following Dispatch Instructions for all units for the Deployment Interval ending
16-20 minutes after the contingency. If uneconomic Contingency Reserve Resources are
physically unable to get to new set point, ramp towards set point to the best of the unit’s
ability. Uninstructed Resource Deviation penalties will not apply to the units carrying
Contingency Reserves for the full duration of the reserve sharing event.
External Responding Area (RSG Member Control Area not participating in SPP RTO and/or EIS
Market)
1. Respond to Reserves Request according to SPP Criteria 6.
6.6.4.3 Operating Reserve Contingency outside the RTO footprint but in an RSG
Member Control Area
Internal Responding Area
1. SPP will create schedules from Load Settlement Location to External RSG Member’s
NERC registered POD/Sink. RTOSS NSI will be updated accordingly.
2. Continue to Follow Dispatch Instructions for Resources not designated as carrying
Contingency Reserves in A/S Plan.
3. Ramp Resources identified in the latest A/S Plan as carrying Contingency Reserves to
meet request for Reserve support.
4. Continue to operate to NSI received from SPP
5. By 0100 three days after the Operating Day in which the event occurred, and
consistent with the scheduling requirements of Section 6.5, the responding market
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participant will enter or update Resource specific schedules from those Resources
ramped to meet the Assistance Schedules.
6. Return to following Dispatch Instructions for all units for the Deployment Interval
ending 16-20 minutes after the contingency. If uneconomic Contingency Reserve
Resources are physically unable to get to new set point, ramp towards set point to the
best of the unit’s ability. Uninstructed Resource Deviation penalties will not apply to
the units carrying Contingency Reserves for the full duration of the reserve sharing
event.
External Responding Area
7. Respond to Reserves Request according to SPP Criteria 6.
6.6.6 Loss Compensation
The Tariff requires Transmission Customers to replace transmission loss energy owed to the
Transmission Owner(s) on a real time basis. Losses associated with all transactions shall be
determined in accordance with the provision of Attachment M of the Tariff.
6.6.6.1 Through and Out Transactions
Losses associated with all transactions through and out of the Transmission System shall be
settled by self-supply or financially pursuant to the provisions for the Optional Annual Purchase
of Loss Energy as described in Attachment M. This election to self-supply or financially settle
losses will be used to determine loss compensation for transactions through and out of the SPP
transmission system (Through and Out transactions).
Example of how system(s) currently work
0101
 Resource XYZ, generating 500 MW, trips offline.
 Balancing Area ABC’s ACE goes from 0 MW to -500 MW.
0105
 MOS takes snapshot for the 0115-0120 interval. MOS sees that 500 MW of generation is
missing and no assistance schedules are present.
0108
 XYZ Reserve Sharing Request entered into RSS
0109
 RSS assistance schedules (450 MW from outside of Balancing Area ABC) generated
sinking into Balancing Area ABC.
 Balancing Area ABC’s ACE goes from -500 MW to -50 MW to reflect change in
RTO_SS NSI due to RSS.
0110
 MOS takes snapshot for the 0120-0125 interval. MOS sees 450 MW of assistance
schedules arriving at Balancing Area ABC.
0114
 Balancing Area ABC provides its share of assistance and its ACE goes from -50 MW to 0
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MW.
0115
 MOS takes snapshot for the 0125-0130 interval. MOS sees ABC has deployed 50 MW
reserves.
0120
 Balancing Area ABC’s EI-NSI decreases by 500 MW to reflect additional import due to
loss of generation within the ABC control area without any RSS schedules.
 As a result, ABC’s ACE goes from 0 MW to +500 MW.
0125
 Balancing Area ABC’s EI-NSI increases by a 450 MW from what was sent at 0120 to
reflect RSS schedules recognized by MOS (a net increase of 50 since 0115).
 As a result, ABC’s ACE goes from +500 MW to +50 MW.
0130
 Balancing Area ABC’s EI-NSI increases by additional 50 MW based on the 0115
snapshot. As a result, ABC’s ACE goes from +50 MW to zero.
0155
 RSS assistance schedules to Balancing Area ABC begin ramping to zero.
0205
RSS assistance schedules ramped out.
6.6.6.1.1 Handling of Self-Provided Losses
For any through or out transaction using SPP transmission service owned by a Transmission
Customer that has elected to self-provide losses, the appropriate amount of losses to be provided
must be specified on the tag. For through transactions, the MP will also specify the appropriate
Designated Balancing Authority (DBA) as a Scheduling Entity on the tag. For out transactions,
the POR will serve as the DBA. In real-time, SPP will deliver the losses identified on the tag to
the pre-determined Settlement Location identified by the DBA. The Transmission Provider will
charge the Market Participant representing that Settlement Location for the benefit of receiving
the Loss Energy at a cost equal to the LIP of that Settlement Location (“DBA Loss Charge”).
Each Transmission Owner will receive revenue equal to the Loss Energies deemed to be supplied
by each Transmission Owner multiplied by the LIP of the pre-designated Settlement Location,
for loss purposes, associated with the Transmission Owner’s load. Any over or under collection
will be resolved through the provisions of Section 10.4.2 Revenue Neutrality Uplift Procedure in
these Market Protocols.
6.6.6.1.2 DBA for Transactions with Self-Provided Losses
SPP will require all MPs associated with BAs to notify SPP of their registered Settlement
Location(s) to be used for receiving self-provided losses.
SPP will permit all potential DBAs to register a unique loss Settlement Location to be used
exclusively for the purpose of receiving losses as the DBA. The LIP associated with that unique
loss Settlement Location shall be the LIP for the DBA’s load Settlement Location. Such loss
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Settlement Locations shall not have any associated metered Resources or Loads and shall not be
subject to any of the scheduling provisions found in section 6.5.
The credit reflected in the settlement for Energy Imbalance Service for the loss Settlement
Location identified by the DBA will be offset exactly by the amount of the DBA Loss Charge on
each settlement statement.
SPP will perform an analysis by October 31 of each year to determine the DBA for through
transactions. For a Transmission Owner having multiple load Settlement Locations this analysis
will also select the load Settlement Location to be associated with the loss Settlement Location
for the next calendar year. SPP will calculate the regional loss weighted average cost for the
prior 12 months by dividing the total Loss payments to the MPs associated with Transmission
Owners by the total MWH of self provided losses in the same period. From the BAs
representing minimum loads in the upcoming calendar year of at least 500 MW, SPP shall select
the DBA associated with the Settlement Location having the average LIP for the prior 12 months
closest to this regional loss weighted average cost. Provided, however, that AEP will act as the
DBA for first calendar year following implementation of the market.
6.6.6.1.3 Financial Settlement of Losses
For any Through and Out transaction using SPP transmission service owned by a Transmission
Customer that has elected to financially settle losses, no losses will be specified on the tag. SPP
will determine the appropriate amount of loss energy associated with the transaction. For
transactions through and out of the Transmission System, losses will be compensated at the sum
of the Loss Energies deemed to be supplied by each Transmission Owner multiplied by the LIP
of the pre-designated Settlement Location, for loss purposes, associated with the Transmission
Owner’s Load. Each Transmission Owner will receive revenue equal to the Loss Energies
deemed to be supplied by each Transmission Owner multiplied by the LIP of the pre-designated
Settlement Location, for loss purposes, associated with the Transmission Owner’s Load.
6.6.6.1.4 Into and Within Transactions
A Market Participant (MP) may meet its obligation to replace loss energy under the Tariff that is
associated with all transactions into or within the Transmission System (Into and Within
transactions) through self-supply and/or purchase of Imbalance Energy. Losses associated with
all Into and Within transactions shall be priced in conjunction with the operation and settlement
of the EIS Market.
6.6.6.1.5 Settlement Examples
There are only two types of schedules that are explicitly subject to loss charges in the SPP EIS
Market. These types of schedules are through and out. A THROUGH schedule represents a
schedule sourced and sunk outside of SPP, such as AMRN to CLEC. An OUT schedule
represents a schedule sourced from within SPP and sunk outside of SPP such as OKGE to
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ERCOTE. Accordingly, schedules INTO such as AMRN to SPS and WITHIN such as SPS to
WR are not explicitly subject to loss charges.
A Market Participant (MP) that elects annually to self-provide (SP) losses will NOT be charged
for losses. The registered owner of the Settlement Location (SL) of the Designated Balancing
Authority (DBA) is the MP that is billed the SP loss charge. The MP electing to SP losses adds
the loss energy component to their schedule by determining the loss % from the SPP price matrix
on OASIS. In the event that the source/sink on the schedule is not a valid record in the loss
matrix, the POR/POD is used to locate a valid loss matrix record. The Resource SL and Load SL
portions of the schedule will differ by the loss energy that is received by the DBA.
An MP that elects annually to financially settle (FS) losses will be charged for losses. There is
no DBA in a FS loss schedule. The Resource SL and Load SL portions of the schedule will be
the same amount of energy. There is no need for the MP to determine the loss % from the SPP
price matrix on OASIS when submitting their tag.
EXAMPLE:
Self-Provided Loss Option (OUT Schedule)
• 3 MWh loss schedule from OKGE-ERCOTE
• OKGE resource to OKGE load 103 MWh
• OUT - OKGE load to ERCOTE 100 MWh
• DBA: OKGE as POR.
DBA = OKGE is billed at Loss MWh per Schedule* $LIP (DCA Load SL): 3 MW * $30 = $90
The Transmission Owner Loss Matrix is posted on the SPP OASIS Price Matrix Rate Query
page. Loss Matrix Percentages for each Transmission Owner for Source/Sink record of OKGEERCOTE obtained from Loss Matrix:
SJLP (.02) + SPA (.09) + AEP (.55) + GRDA (.11) + OKGE (.64) + WFEC (.06) + MIDW (.07)
+
WR (.8) + WPEK (.07) + MPS (.05) + KCPL (.11) +EDE (.05) + SPRM (.01) + SPS (.27) =
(Total) 2.9%
Since loss energy of 3 MWh has already been calculated, the loss matrix is only used to calculate
the pro-rata share to be compensated to each TO.
LIP at SL of Load for each TO:
SJLP $25, OKGE $30, SPA $45, AEP AND SPRM $30, GRDA and EDE $15,
WR $40, WFEC and SPS $20, MIDW and WPEK $50, MPS and KCPL $10
• Each Transmission Owner will be compensated for loss revenues as follows:
Loss MWh per Schedule * (Loss Matrix % TO / Σ (Loss Matrix % TO)) * $LIP TO Load SL
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Transmission Owner MWh Calculation:
SJLP
3 mw * (.02/2.9) * $25 = $0.52
SPA
3 mw * (.09/2.9) * $45 = $4.19
AEP
3 mw * (.55/2.9) * $30 = $17.06
GRDA
3 mw * (.11/2.9) * $15 = $1.71
OKGE
3 mw * (.64/2.9) * $30 = $19.86
WFEC
3 mw * (.06/2.9) * $20 = $1.24
MIDW
3 mw * (.07/2.9) * $50 = $3.62
WR
3 mw * (.80/2.9) * $40 = $33.10
WPEK
3 mw * (.07/2.9) * $50 = $3.62
MPS
3 mw * (.05/2.9) * $10 = $0.52
KCPL
3 mw * (.11/2.9) * $10 = $1.14
EDE
3 mw * (.05/2.9) * $15 = $0.78
SPRM
3 mw * (.01/2.9) * $30 = $0.31
SPS
3 mw * (.27/2.9) * $20 = $5.59
SUM of TO loss compensation =$93.26
The $3.26 difference between the $90 charge to OKGE as the DBA and the sum of $93.26
compensated to all the Transmission Owners will be handled as part of the existing revenue
neutrality uplift procedure. Loss revenue credits for the Transmission Owners are calculated
through the market settlement system and passed through to the transmission service settlement
system to compensate the Transmission Owners.
OKGE also receives an EIS credit of $90 based on loss schedule of 3 mw times $30 LIP, which
equally offsets the loss charge. Keep in mind that the loss EIS credit only exists because a
unique loss SL, OKGE _Loss, is used solely to track the loss component of the schedule to
OKGE. No other schedules and no meter actuals are reported using the OKGE _Loss SL. Only
the loss component of schedules where OKGE is the DBA utilizes this SL. If the OKGE _Load
SL had been used to track losses, OKGE would have no way of distinguishing these schedules
from all other schedules that utilize the OKGE _Load SL. The unique loss SL was only added to
the protocols as a tracking tool for the DBA to track the SP loss charges against the loss energy
they received. The true offset from an OKGE perspective, is the energy they receive for free, 3
mw of losses in this case, against the loss charge for 3 mw times the OKGE LIP. The OKGE
LIP used for the loss charge and the EIS credit will equal the OKGE _Load SL. This same
methodology will also apply to any of the other SPP control areas that serve as a DBA for Out
schedules where they are the Point-of_Receipt (POR) and for the DBA that serves for the
Through schedules.
EXAMPLE:
Self-Provided Option (THROUGH schedule)
• 3 MWh loss schedule from AMRN-CLEC
• AMRN resource to DBA load 103 MWh
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• DBA load to CLEC 100 MWh
• DBA: AEP
• The calculation would be very similar to the previous example for an Out schedule.
• The only difference would be the TO loss percentages obtained from the Loss Matrix for
Source/Sink of AMRN-CLEC.
• The DBA for a through schedule must be shown on the tag as a scheduling Entity.
Since SWPP must also be shown as a scheduling entity for correct checkout, the
DBA will often be sandwiched between SWPP as is currently done for DC ties. The assignment
of the DBA can change yearly per market protocols for all through schedules.
EXAMPLE:
Financial Settlement of Losses (THROUGH or OUT schedule)
• Example uses same data for Loss Percentage and LIP Loss Revenue Credits
FS=Loss MW per Schedule x (Loss Matrix %TO /100) x LIP$TO LOAD SL
The Transmission Owner Loss Matrix is posted on the SPP OASIS Price Matrix Rate Query
page. In the event that the source/sink on the schedule is not a valid record in the loss matrix, the
POR/POD is used to locate a valid loss matrix record.
SJLP (.02) + SPA (.09) + AEP (.55) + GRDA (.11) + OKGE (.64) + WFEC (.06) + MIDW (.07)
+
WR (.8) + WPEK (.07) + MPS (.05) + KCPL (.11) +EDE (.05) + SPRM (.01) + SPS (.27) =
(Total) 2.9%
SPS
SPRM
EDE
KCPL
MPS
WPEK
WR
MIDW
WFEC
OGE
GRDA
AEP
SPA
SJLP
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100 MWh * (.27/100) * $20 = $5.40
100 MWh * (.01/100) * $30 = $0.30
100 MWh * (.05/100) * $15 = $0.75
100 MWh * (.11/100) * $10 = $1.10
100 MWh * (.05/100) * $10 = $0.50
100 MWh * (.07/100) * $50 = $3.50
100 MWh * (.80/100) * $40 = $32.00
100 MWh * (.07/100) * $50 = $3.50
100 MWh * (.06/100) * $20 = $1.20
100 MWh * (.64/100) * $25 = $16.00
100 MWh * (.11/100) * $15 = $1.65
100 MWh * (.55/100) * $30 = $16.50
100 MWh * (.09/100) * $45 = $4.05
100 MWh * (.02/100) * $25 = $0.50
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Loss Revenue Charge to MP = $86.95
There is no need for revenue uplift on the option of financially settled losses, since the MP is
billed the sum of the loss revenues compensated to all Transmission Owners.
6.7 SPP Operational Information Exchange
Updates to Operating Day Data
Timeline
Immediately following an RSS
event
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Market Participant
Action
May enter Resource
specific RSS schedules for
responding Resources as
outlined in Section 6.5.4
Reserve Sharing
Scheduling.
Deploy energy in response
to the RSS event.
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SPP Action
One Schedule for the amount
lost is created in RSS from the
Contingent Control Area Load
Settlement Location to the
Settlement Location for the
Contingent Generator
Resource. Schedules from the
Load Settlement Locations of
the assisting Control Areas to
the Load Settlement Location
of the Contingent Control Area
are created in RSS. Resource
specific schedules are created
in RSS from the Resources
expected to be deployed in
response to an event to the
Load Settlement Location of
the control area responding to
the event. See Operating
Reserves Criteria 6.
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Market Protocols
0100 three days after the OD in
which the RSS event occurs
Schedules representing
actual reserves deployed
during an event are
submitted in RSS from
each Resource to the Load
Settlement Location of the
Control Area responding to
the event.
6.8 Schedule Curtailment/Adjustment under SPP Congestion
Management
Except as provided for Emergency conditions in Section 1, when a constraint is observed in realtime, a SPP Congestion Management Event (CME) will be initiated and the constraint will be
activated in the MOS. The CME can be initiated through declaration of a TLR or an activation
of a constraint in MOS. SPP will declare a TLR if IDC curtailable schedules/NNL exist in IDC
above the curtailment threshold. If there are no such IDC curtailable schedules/NNL, SPP will
initiate the CME directly in MOS and not issue a TLR.
The CME will cause MOS to deploy Dispatchable Resources to provide appropriate reduction in
flows to relieve the constraint. An analysis will be performed to determine if curtailable
schedules/NNL exist in IDC above the curtailment threshold for the current operating hour and
the next hour. In conjunction with the constraint activation, SPP Curtailment/Adjustment Tool
(SPP CAT) will manage curtailments of Energy Schedules as appropriate. SPP will use the
combination of CAT and MOS to reliably manage and economically maximize the flow of
power on flowgates to within the applicable operating limits as prescribed by NERC.
During an SPP Congestion Management event, EIS impacts greater than zero in a particular
priority will be removed before curtailing any existing schedules in the same priority. Since the
current SPP Market Structure provides no mechanism to directly assign the cost associated with
relieving congestion to the schedules impacting a particular constrained flowgate, the CAT shall
curtail/adjust schedules to achieve a relieving impact equal to the amount of Energy Imbalance
supporting scheduled flows. On those flowgates for which SPP is the Reliability Coordinator,
the result of such curtailment procedure will be that flows resulting from the EIS market dispatch
will not provide counter-flows to support schedule flows that are to be curtailed as described
earlier.
6.8.1 SPP Congestion Management under TLR Operations
If there are curtailable schedules/NNL in IDC at the SPP Congestion Management Event
priority level in either current operating hour or next hour, a TLR will be requested through the
IDC. When TLR is requested, MOS, the NERC IDC and the SPP Curtailment/Adjustment Tool
(SPP CAT) will work with each other to manage congestion on constrained flowgates and
handle curtailments of Energy Schedules as appropriate.
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The appropriate level of TLR must be requested in the IDC. The IDC will prescribe curtailments
of those tags that are not included in Market Flows. The IDC will also prescribe curtailment of
Market Flows. SPP will then activate or continue activation of the constraint in MOS. In the
meantime; CAT will receive the Market Flow relief obligation from the IDC. Used in
conjunction with Market Flows received from MOS, CAT will calculate EIS and appropriately
curtail/adjust those schedules included in Market Flow. All curtailments are fed into RTOSS
from the IDC and CAT to facilitate proper generation response for Self-dispatched Resources.
LIPs will not be updated after a schedule curtailment until those curtailments are recognized in
the Market dispatch.
6.8.2 IDC/CAT Schedule/tag Management Identification
1
Dispatchable Resource
SPP BA
2
Dispatchable Resource
SPP BA
3
4
5
6
7
Self-Dispatched
Resource
Self-Dispatched
Resource
Self-Dispatched
Resource
Load Settlement
Location
Load Settlement
Location
8
External
9
External
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SPP BA
Curtailed/
Adjusted by
Sink BA
Sink
Source BA
Source
Schedule
The following table is provided to describe those types of schedules that the IDC is responsible
to explicitly curtail and those that CAT is responsible for curtailing and/or adjusting. For
purposes of this section of the Protocols, the term “curtailment” is used to describe an action
taken with respect to a schedule that is expected to elicit a specific generation response in near
real-time, while the term “adjustment” is used to describe an action taken to a schedule to reflect
generation dispatched by the Market in real-time for after-the-fact settlement purposes.
External
Load Settlement
Location
External BA
IDC
SPP BA
CAT
External
External BA
IDC
Load Settlement
Location
Load Settlement
Location
SPP BA (where GCA =
LCA)
CAT
SPP BA
External
External BA
IDC
SPP BA
Load Settlement
Location
SPP BA
CAT
External
External BA
IDC
Load Settlement
Location
SPP BA
IDC
SPP BA
SPP BA
External
BA
External
BA
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SPP BA
IDC
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Market Protocols
6.8.1 6.8.3 Market Flow
As required by the Congestion Management Process (CMP) prescribed by the SPP-MISO Joint
Operating Agreement, SPP will determine and submit to the NERC IDC its Market Flows on all
SPP Coordinated Flowgates (CFs) and Reciprocal Coordinated Flowgates (RCFs). SPP’s CFs
are those flowgates identified as being impacted by activities within SPP. SPP’s RCFs are those
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.
SPP’s Market Flows represent impacts from one or more of the following components:
1) The Native Load Schedule component of NLPS from both Market and Self-dispatched
Resources. NLPR impacts are considered implicit in the Portfolio Schedules they are
supporting and therefore are not included in Market Flow.
2) Tagged intra-Balancing Authority schedules from both Market and Self-dispatched
Resources
3) Tagged schedules where the source is a market Resource or Load Settlement Location
and the sink is a Load Settlement Location
4) Any unscheduled output from generation resources offered into the EIS Market and
dispatched by SPP in accordance with these Protocols (hereinafter referred to as “EIS
impact.”)
In accordance with the CMP, Firm Flow Limits are derived for CFs while both Firm and Nonfirm Network limits are derived for RCFs. For CFs, SPP will establish a Firm Flow Limit equal
to the sum of firm transmission reservations and Gen-to-Load impacts. For RCFs, SPP will
establish a Firm Flow Limit based upon the allocation of Flowgate Capacity determined pursuant
to the reciprocal coordination process. On both CFs and RCFs, SPP will assign Firm (F-7)
curtailment priorities to those Market Flows that are scheduled (i.e., categories 1-3 from the
above list) using firm transmission service, up to the applicable Firm Flow Limit. On CFs, any
remaining Market Flows will be assigned Non-firm Network (NN-6) curtailment priorities. On
RCFs, SPP will assign Non-firm Network (NN-6) curtailment priorities to those Market Flows
that are scheduled using transmission service having a priority greater than Non-firm Hourly and
any remaining Market Flow that is unscheduled, up to the Non-Firm Network Limit. On RCFs,
any Market Flow in excess of the Non-firm Network Limit will be prioritized as Non-firm
Hourly (NH-2). See the following example for an illustration of how real-time Market Flow
might be assigned on a RCF over a 24-hour period.
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Example of SPP Market Flow Assignment on a RCF
Legend
400
Limits
350
F-7
NN-6
300
Market Flows
250
F-7
Scheduled F-7
200
NN-6
Scheduled NN-6
150
Scheduled NM-5
100
Scheduled NW-4
Scheduled ND-3
50
EIS
NH-2
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Scheduled NH-2
EIS
At least every 15 minutes, SPP will send Market Flow values for all CFs and RCFs to the IDC in
the appropriate priority levels for the current hour and next hour. During an SPP Congestion
Management event, the IDC will use this information to prescribe appropriate reductions in
Market Flows and curtailments of tags whose impacts are not reflected in Market Flows. SPP
systems will identify Market Flows that must be curtailed to achieve any obligation assigned by
the IDC by binding of the constraint in the security constrained economic dispatch system.
SPP will determine the amount of Market Flows associated with EIS impacts by subtracting
scheduled Market Flows from total Market Flows. For CFs, EIS impacts are considered to have
Non-firm Network priority. For RCFs, any EIS impacts that cannot be allocated to the Non-firm
Network priority will be considered to have Non-firm Hourly priority.
6.8.2 Maintaining Feasibility under TLR Operations
For the purposes of maintaining feasibility during TLR Operations, EIS flow will be adjusted
first, based on the appropriate curtailment priority of the effective TLR. If EIS flow is increasing
the congestion on a flowgate the EIS flow will be removed through redispatch. If EIS flow is
providing relief on a flowgate, the schedule impacts are adjusted to remove the need for EIS
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relief, to provide schedule feasibility. This process applies to flowgates in the SPP Reliability
Coordination footprint, for which TLR is called.
The EIS flow on a given flowgate is determined by subtracting the sum of the net of CAT
scheduled impacts with impacts >0% from the net market flow with impacts >0% calculated by
the Market Flow Calculator (MFC).
The Physical Feasibility component is determined by subtracting the Real-Time Balancing
Calculated Flow (calculated real-time flow from the Market Operations System) of the flowgate
from the Effective Limit of the flowgate (limit placed on the constraint in the market dispatch
system).
CAT shall sum both the EIS flow component and the Physical Feasibility component. If the
result is negative, CAT shall curtail that amount of scheduled impacts. If the result is positive,
CAT will reload the scheduled impacts and/or MOS will redispatch as appropriate.
CAT Curtailment Requirement = Market Flow (>0%) – Impact of CAT schedules (>0%) +
Effective Limit of the constrained flowgate – Real-Time Balancing Calculated Flow of the
constrained flowgate.
Example 1: CAT Curtailment Requirement = 300MW (Market Flow) – 400MW (Impact of
CAT schedules) + 350 (Effective Limit) – 325MW (Real-Time Balancing Calculated Flow) = 75MW.
In example 1, because the sign is negative, indicating the CAT schedules are infeasible, CAT
shall curtail 75MW of scheduled impacts. If infeasibility continues after all non-firm
curtailments have been exhausted, a TLR Level 5 shall be issued.
Example 2: CAT Curtailment Requirement = 500MW (Market Flow) – 400MW (Impact of
CAT schedules) + 350 (Effective Limit) – 325MW (Real-Time Balancing Calculated Flow) =
125MW.
In example 2, because the sign is positive, indicating the CAT schedules are feasible, CAT will
reload 125MW of CAT curtailed schedules and/or MOS will redispatch as appropriate.
6.8.3 6.8.4 NERC IDC Curtailments
The NERC IDC will receive all tagged transactions involving SPP. Under SPP Market
Operations, the NERC 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 through its Market Operations.
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The NERC IDC will be responsible for prescribing curtailment of only those tags involving SPP
for which impacts are not included in SPP’s Market Flows (see section 6.7.1). These include
tags for schedules with external parties that are sourced or sunk in the SPP Market and tags for
Interchange Transactions from Self-Dispatched Resources.
Those tags for which impacts are included in SPP’s Market Flows will not be explicitly curtailed
by the IDC. As stated in section 6.7.1, included in SPP’s Market Flows are impacts of tagged
schedules where the source is a Resource or Load Settlement Location and the sink is a Load
Settlement Location. In order for the IDC to distinguish those tags, MOS will communicate a
market flag for each such Resource to the IDC each hour based on information in the Resource
Plan.
At least every 15 minutes, SPP will also send to the IDC the Balancing Authority(ies) wherein
the marginal unit(s) reside. This information will be used by the IDC to calculate Transaction
Distribution Factors (TDFs) for those schedules with external parties that source in the SPP
Market. This is reflected in the IDC as the SWPP_EXP marginal zone. If a generation resource
in the SPP Market footprint is self-dispatched and has tagged schedules with external parties, the
IDC will use resource level granularity in determining the TDF impact on flowgates.
The above paragraph will read:
If a generation resource in the SPP Market footprint has tagged schedules with external parties,
the IDC will use resource level granularity in determining the TDF impact on flowgates.
6.8. 4.1
External Resource Tag Curtailment
In the event the IDC prescribes curtailment for the External Resource tags, the Market
Participant responsible to such Resource will need to modify the Resource Plan. The Market
Participant will need to modify the Max-MW value of the Resource Plan to reflect the curtailed
tag MW value, i.e., the adjusted Max-MW value cannot exceed the pre-curtailment MW value
less the curtailed MW amount. Market Participant will be responsible for notifying the Market
Operator for these changes. Market Participants must complete its adjustments and notification
no later than 15 minutes after receipt of curtailment notification.
The adjusted MW value of the tag, post curtailment, may be higher than the Deployment
Instruction for the External Resource. The adjustments are necessary to ensure that the
Transmission Provider will not deploy the External Resource beyond the available transmission
capability as a result of IDC curtailment.
6.8.5 Market Flow Curtailments/Adjustments
CAT will be used to compute curtailments/adjustments of those schedules for which impacts are
included in Market Flows. These include the following types of schedules:
1) Native Load Schedules from both Market and Self-dispatched Resources
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2) Tagged intra-Balancing Authority schedules from both Market and Self-dispatched
Resources
3) Tagged schedules where the source is a market Resource or Load Settlement Location
and the sink is a Load Settlement Location
Any curtailments or adjustments made by CAT will be based on the Market Flow relief
responsibility determined by the IDC, during a TLR event, or the amount of EI supporting
schedules, during a SPP Congestion Management event where TLR is not initiated. In all cases,
it is SPPs responsibility to achieve the required Market Flow relief.
SPP will first determine if the EIS component of the Market Flows at the priority is sufficient to
achieve required Market Flow relief. If so, then EIS will be reduced to provide the required
relief and no schedule curtailments or adjustments will be necessary. However, if the adjustment
of the EIS component of Market Flow is not sufficient to achieve the required relief, the
scheduled curtailments will be handled as outlined in the following sections. The TDF of a
schedule to be curtailed/adjusted by CAT will be determined by using the Resource or Load
Settlement Location identified as the source on the schedule and the Resource or Load
Settlement Location identified as the sink on the schedule.
The SPP CAT will communicate any curtailments/adjustments to RTO_SS. If any SelfDispatched Resources identified in NLS are required to be curtailed, SPP CAT will also send the
aggregate curtailment responsibility to each Resource owner for its curtailed Resources.
Generator Shift Factors (GSF’s) will also be provided through a viewer to the Market
Participants. These may be used by the Market Participants to determine how to best modify
their Self-Dispatch Resource schedules while still maintaining the total level of reduction
required.
The SPP CAT will run automatically, at least once every hour, and will produce solutions that
will be communicated to RTO_SS. CAT will also run at the beginning of the next Dispatch
Interval immediately following a Congestion Management status change.
As warranted, the SPP CAT will also receive from the IDC the re-load amounts for Market Flows as a
flowgate starts to become unconstrained. SPP CAT will use this information to re-load any curtailed or
adjusted schedules.
Internal Flowgates
If the EIS component is positive and is not sufficient to achieve the required Market Flow relief,
SPP will reduce the EIS and then curtail and/or adjust schedules, both in order of priority, to
provide the required relief.
If the net EIS component is negative, SPP will curtail Schedules so that the net negative EIS
impact on the flowgate is eliminated and the requested relief is achieved. SPP will increase the
TLR or SPP Congestion Management level as necessary up to and including Level 5.
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External Flowgates
If the EIS component is positive and is not sufficient to achieve the required Market Flow relief,
SPP will reduce the EIS and then curtail and/or adjust schedules, both in order of priority, to
provide the required relief.
If the net EIS component is negative, SPP will curtail Schedules so that the net negative EIS
impact on the flowgate is as close to zero as possible. SPP will only curtail schedules up to and
including the TLR level declared by the external entity that manages the flowgate. In the event
SPP is unable to remove all negative EIS impacts through schedule curtailments, this may result
in a revenue neutrality shortfall.
In all cases, it is SPPs responsibility to achieve the required Market Flow relief.
6.8.3 6.8.6 NLPS Tool Adjustments for Curtailments
Option 1
Only the NLS components of the NLPS are sent to the MFC and CAT. Following any
curtailment or adjustment of Portfolio Schedules by the IDC or CAT, the NLPS Tool will
automatically adjust the NLPR components of the NLPS. This action will result in an overall
adjustment to the total NLPS submitted for the Resource and will be accounted for in integrated
schedule amount forwarded to Market Settlement. The following example shows the results of a
curtailment scenario for the example in Section 6.6.3.3.
External CA
(IDC curtailable)
Schedule A
150MW
NLPS D
285MW
NLPS B
300MW
NLPS A
200MW => 75 MW
MP_MP (Load
Settlement
Location)
100MW
NLPS C
Market CA
(CAT curtailable)
Schedule B
200MW => 50 MW
In this example, the two Portfolio Schedules are curtailed to 150 and 175 MW respectively. That
results in a total PS curtailment of 75 MW. The curtailment will first be applied based on the
normalized factors and then if necessary to the Manual NLPR. Since the lowest priority group is
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priority 2, the automatic NLPR in that group will be reduced first. The total in that group is 50
MW resulting in adjustment to 0 for both. The remaining 25 MW of adjustment would be made
to NLPS A. To prevent the curtailment process from potentially putting a Market Participant in
a position of having a total NLS component larger than its Native Load, the NLS component will
not be adjusted by the NLPS Tool for curtailments of PS. This will result in the total NLPS for
each Resource being reduced for the period of the curtailment.
Resource
A
B
C
D
Total
Capacity
300
400
100
200
900
Submitted
NLPS
300
285
100
150
735
NLPR
(Manual)
Total
Portfolio
Schedules
50
50
400=>325
Participation
Factor %
100
70
100
0
Prioritization
Identifier
1
2
2
Adjustments initiated by the Purchasing Selling Entity will not be considered as curtailments.
Any adjustment of PS or NLPS submitted by the Participant would trigger recalculation of the
components against the scheduled amounts and a curtailment routine for NLPR would follow if
PS schedules are still being curtailed for TLR.
6.8.6 6.8.7 SPP Congestion Management Curtailment/Adjustment Notification
For schedules/tags during a CME that are exclusively curtailed/adjusted by CAT, SPP will notify
the Market Participants by OASIS or XML within 10 minutes of the schedules/tags adjustments
of the constraint and the flowgate responsible for the curtailment. For TLR events, existing
notification process continues. For SPP Congestion Management metrics and reporting, both
CME and TLR events shall be reported.
7 Simultaneous Feasibility Studies
SPP shall perform a simultaneous feasibility study and a supply adequacy analysis. The supply
adequacy analysis, determines if each Market Participant has sufficient energy supply available
to the market to meet its Load obligations. The Simultaneous Feasibility Study is a deliverability
analysis that determines if the Market Participants’ can reliably deliver those energy Resources
to its Energy obligations. Both types will be performed for each hour of the next Operating Day
(OD) with results available by 1500 day prior to the OD. In addition to the daily study, by the
top of every Operating Hour, SPP will provide results of a supply adequacy analysis for the next
Operating Hour (for example, results for Hour Ending 1300 will be available by 1100). This
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(Automatic
275
0
0
0
75
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information shall be submitted via the SPP OASIS website or Application Program Interface
(API) Notification.
Constraint Types and Severity used in reporting:
 Binding Constraint – a constraint whose flow is exactly at its limit (2 subtypes)
o Binding Economic (BE) – constraint is at its limit as a result of a more economic
dispatch than the Planned Generation submitted by the MPs.
o Binding Feasible (BF) – the secure economic dispatch was necessary to unload
the impacts of the Planned Generation submitted by the MPs.

Violated Constraint – available market dispatch as submitted in the Resource Plan lacks
the depth to maintain the flow on the constraint at its limit and still meet the Market Load
(2 subtypes)
o Violated Feasible (VF) – constraint is able to be eliminated by curtailing all
Import/Export/Through schedules and changing all Self-Dispatch Resources
available.
o Violated Infeasible (VI) – constraint is unable to be eliminated through any means
given the submitted Resource Plans. Schedule curtailments and Manual
Deployments of Self-Dispatched Resources cannot relieve the situation.
SPP may perform additional deliverability analyses as it deems necessary.
7.1 Supply Adequacy
The supply adequacy analysis will be based on Load forecast information, Resource Plans,
Ancillary Service Plans, and schedules received from Market Participants. SPP will determine
each Market Participant’s Energy Obligation. A Market Participant’s Energy Obligation shall be
computed as follows:
Load forecast + scheduled sales – scheduled purchases
SPP will compare the Market Participant’s Energy Obligation against the sum of its Max
Dispatchable-MW and the sum of its Min Dispatachable-MW calculated from its Resource Plan
and Ancillary Service Plan as defined in Section 8.4 of these Protocols. A Market Participant
shall be deemed as having insufficient energy supply if the following condition is met:
sum of Max Dispatchable-MW < Energy Obligation
A Market Participant shall be deemed as having too much energy supply if the following
condition is met:
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sum of Min Dispatchable-MW > Energy Obligation
If either condition is met, the Market Participant is deemed to have inadequate supply. SPP will
then compare the aggregation of the Market Participants’ Resource Plans and schedules by each
Balancing Authority Area within the EIS Market footprint against SPP’s Load forecast and
Ancillary Service requirements for each Balancing Authority Area. If this analysis indicates that
a particular Balancing Authority Area has inadequate supply, SPP will notify the Market
Participant(s) deemed inadequate and its host Balancing Authority. This information shall be
submitted via the Portal or Application Program Interface (API). The Market Participant shall
resolve this energy supply inadequacy by modifying its Load Forecast, Resource Plan and/or
schedules. The Market Participant shall make the appropriate modifications by 1700 day prior to
the OD for any energy supply inadequacy revealed by the daily study. The Market Participant
shall make the appropriate modifications no later than 45 minutes prior to the Operating Hour
(OH) for any energy supply inadequacy revealed by the hourly study. SPP shall provide a copy
of any modified Resource Plans and/or schedules to the affected Balancing Authorities.
In the event a Market Participant does not resolve the issue and it contributes to a reliability
problem at or prior to real-time, the Market Participant will be subject to interruption of Load,
interruption of Resources, curtailment of schedules and or manual deployment of Resources, if
deemed necessary. All instances where the Market Participant fails to resolve an identified issue
at or prior to real-time and it contributes to a reliability problem will be reported to FERC on an
after-the-fact basis.
7.2 Deliverability
After completing the supply adequacy analysis, SPP shall perform an analysis of deliverability.
This analysis is based on Resource Plans, Offer Curves, and schedules submitted by the Market
Participants. This analysis will use SPP’s Load forecast for the Balancing Authority Areas in the
SPP Region. It includes an analysis of the impacts of single transmission facility contingencies
on a set of monitored transmission facilities.
7.2.1 Schedule Infeasibility
If SPP’s deliverability analysis projects a system constraint that can be resolved through
redispatch of Dispatchable Resources, SPP will post a notification, via the SPP OASIS website
or Application Program Interface (API), identifying the projected constraint.
A Market Participant, upon receiving such notification of schedule infeasibility, may choose to
modify its Resource Plan and/or schedule(s). Otherwise, SPP may curtail the Market
Participant’s schedules in real time; any imbalance resulting from the curtailments shall be
settled at the Market Participant’s LIP. If SPP is unable to supply a Market Participant’s real
time demand by deploying Dispatchable Resources that MP’s Load may be subject to
interruption or other actions by the MP’s host Balancing Authority under the appropriate NERC
Standards, SPP Criteria, and/or other applicable agreements.
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7.2.2 Market Infeasibility
If SPP’s analysis projects a system constraint that cannot be resolved through redispatch of
Dispatchable Resources, SPP will run a second infeasibility analysis that simulates potential
impacts that a TLR may have on the constraint. To simulate TLR SPP will, for the purposes of
this study only, remove external schedules and change all self-dispatched Resources as
Dispatchable Resources. SPP will post a notification, via the SPP OASIS website or Application
Program Interface (API), identifying the projected constraint and that TLR may be necessary to
resolve the issues. This notification, provided on the SPP OASIS or Application Program
Interface (API), will include the expected constraint, and that TLR may be necessary. SPP shall
notify the Market Participant’s host Balancing Authority of that analysis. If the constraint in the
above analysis is not resolved, SPP will post a notification on the API identifying the projected
constraint and that the set of Resource Plans submitted for the study period are not feasible.
8 Inadvertent Management
SPP shall maintain inadvertent accounts and administer inadvertent payback for all control areas
participating in the SPP market. 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.
8.1 Management of pre-Market Inadvertent Balances
Until the beginning of the market, each control area is responsible for the management of their
accumulations and are expected to adjust their balances as close to zero as possible. Starting the
month prior to the market, SPP will verify and monitor accumulated inadvertent account
balances. SPP will encourage individual control areas with inadvertent to schedule payback
between member control areas during that month prior to the market. Control Areas should
continue to perform needed control area interconnect meter corrections to the inadvertent
account balances.
Following the start of the market, SPP will facilitate the reconciliation and payback of premarket balance accumulations using the following steps:
Step 1 – Verify Account Balances
SPP staff will manually verify the accumulated inadvertent balances (On and Off peak) for the
hour prior to market implementation. These previously accumulated inadvertent account
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balances will be kept in accounts that will be accounted for separately from market Inadvertent
accounts
Step 2 - Schedule inadvertent payback
SPP will schedule, in consultation with the control areas, inadvertent payback between member
control areas or between a member control area and the applicable interconnection. Interchange
Schedules for payback will be run in real-time. Payback schedules will be created by SPP and
included in the energy market dispatch, creating an obligation for the payback schedule on the
applicable Control Area. Payback will only be initiated when there is sufficient dispatch range
available for dispatch to service the payback schedule. After the schedules have been run and
checked out the schedules will be passed to the energy market settlement process, and removed
from Control Area energy accounting to allow actual adjustment to Inadvertent.
For reliability purposes, inadvertent payback will be limited to the Control Area Lsub10. On and
Off peak balances will be maintained separately. Inadvertent payback schedules can be halted at
the discretion of the Reliability Coordinator or the Control Area for reliability reasons.
Inadvertent payback of pre-market accumulations will continue until each control areas has
reached zero.
8.2 Management of post-Market Inadvertent Balances
There will be no inadvertent within the SPP market. All deviations from schedules with Market
Participants will be settled financially.
NERC WAIVER – FINANCIAL INADVERTENT SETTLEMENT
SPP (along with MISO) requested and was granted a waiver relating to inadvertent
accumulations. The waiver allows SPP to adjust participating control area’s hourly inadvertent
through an RTO financial settlement process while assuring that the method of payback will not
affect non-participating control areas or the net inadvertent owed to the applicable
interconnection. SPP will follow this waiver when Market Operations begins to settle inadvertent
financially.
NERC WAIVER – INADVERTENT INTERCHANGE ACCOUNTING
(NERC Standard BAL-006-0-Inadvertent Interchange, Effective April 1, 2005)
The SPP RTO will also request a waiver relating to Inadvertent Interchange Accounting. MISO
has a similar waiver. In this waiver, Control area participants will request that the SPP RTO be
given an Inadvertent Interchange account which will facilitate the financial settlement of
inadvertent within the SPP market.
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8.3 Post-market Implementation Inadvertent Accounting Steps:
Step 1 – Set up new inadvertent account balances
SPP will set up new inadvertent account balances for each Control Area beginning with hour one
of the market implementation.
Step 2 - Settle inadvertent account balances financially
Inadvertent for post-Market operation will be maintained and managed by the SPP RTO. Each
hour each control area will calculate its contribution to the SPP RTO Inadvertent accumulation
for the hour by subtracting the Net Actual Interchange (NAI) from the Net Schedule Interchange
(NSI). These figures will be calculated by each control area and reported to the SPP each hour.
SPP will sum all of the SPP Control Area figures to arrive at the SPP RTO inadvertent
accumulation for that hour.
Step 3 - Schedule SPP Inadvertent Payback
SPP will manage SPP inadvertent payback with the applicable interconnection. Payback
obligation will be created by SPP and included in the energy market dispatch, creating an
obligation for the payback on the energy market. Payback will only be initiated when there is
sufficient dispatch range available for dispatch to service the payback schedule.
8.4 Inadvertent Payback Reporting
The SPP RTO will report its Inadvertent Interchange balance with the applicable
interconnection. SPP reporting will be consistent with the requirements and timelines for
Balancing Authorities outline in NERC Reliability Standard BAL-006-0. In addition SPP will
maintain records of Inadvertent Interchange financially settled with each control area and will
provide AIE data (pre and post settlement) for any surveys or formal data requests.
The SPP RTO will manage and pay back its post market net Inadvertent Interchange balance
following NAESB WEQBPS-005-000 Inadvertent Interchange payback Inadvertent 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.
8.5 Uninstructed Deviation
Uninstructed Deviation is the difference in the Dispatch Instruction and the real time operating
level as indicated via SCADA for the Resource. SPP will calculate and retain the Uninstructed
Deviation at the end of each Deployment Interval based on SPP’s clock synchronized to True
Time GPS Satellite.
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Boxed Text to substitute current section 8.5 upon system implementation:
8.5 Uninstructed Deviation
Uninstructed Deviation is the difference in the Dispatch Instruction and the real time
operating level. SPP will calculate and retain the Uninstructed Deviation at the end of
each Deployment Interval based on SPP’s clock synchronized to True Time GPS Satellite.
The real time operating level of the Resource will be determined by utilizing real time
data from the following sources in order of priority:
(1) Valid SCADA reading for the Resource provided by the Transmission Operator
(2) Valid SCADA reading for the Resource provided by the Market Participant for the
Resource
(3) Estimated loading from the SPP state estimator from a valid state estimator
solution
(4) The last valid reading from the end of an interval from above sources.
The real time operating level values captured will be reconciled to the metered values for
the Resource, so that the integration/average of the twelve values for a particular
Operating Hour matches the metered values utilized in settlements for the Resource.
Example 1
Time
1205
1210
1215
1220
1225
1230
1235
1240
1245
1250
1255
1300
Integration
Version 14.0a
Reconciled
Real Time
Operating
Operating Metered Level Used
Level
MWH
for URC
432
450
442
460
456
475
470
489
480
500
490
510
509
530
523
545
509
530
485
505
480
500
485
505
480
500
500
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8.5.1 Resource Operating Tolerance
A Resource operating tolerance will be defined based on an acceptable amount of dispatching
error with an adjustment for regulation services being maintained on the Resource. The
operating tolerance is intended allow SPP to maintain the efficiency of the EIS dispatch and
provide additional financial incentives for Market Participants to cause their Resources to
perform, whether offered for SPP Dispatch or Self Dispatched, within an acceptable range. The
portion of the operating tolerance based on the Resource’s Capability will be the acceptable dead
band percentage multiplied by the MaxEconMW and limited to a minimum of 5 MW and
maximum of 25 MW. A Resource will be considered to be operating within acceptable Resource
operating tolerance so long as its current operating level is between the high and low operating
tolerance limits defined as follows:
RHi = Max (5, Min ((MaxMWi * DBP), 25)) + REGUPo
RLi = Max (5, Min ((MaxMWi * DBP), 25)) + REGDNo
Where:
RH=
Resource High operating tolerance or over generation limit (MW)
RL=
Resource Low operating tolerance or under generation limit (MW)
MaxMW =
Maximum Capacity Operating Limit - Resource physical maximum
sustainable output for each Operating Hour from Resource Plan.
DBP =
Dead Band Percentage for all Resources is initially set to 10 % above and
below the Max Econ MW of the Resource (MaxEconMW), but is subject
to change by subsequent Protocol Revision Request.
REGUPo =
Regulation Up service being maintained on the Resource as indicated in
the Ancillary Service Plan (MW) for the Operating Hour.
REGDNo =
Regulation Down service being maintained on the Resource as indicated
in the Ancillary Service Plan (MW) for the Operating Hour.
i=
Dispatch interval within Operating Hour.
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MaxEconMW
MaxDispatchableMW
Dispatch Instruction + RH
Acceptable
Operating
Range
Dispatch Instruction
Dispatch Instruction - RL
MinDispatchableMW
MinEconMW
8.5.2 Uninstructed Deviation Charge Calculations
In addition to the settlement for EIS, Uninstructed Deviation Charges will be assessed to any
Resource that operates outside the defined Resource operating tolerance. A Resource operating
outside the tolerance will incur a charge based on the amount the Resource is outside the
operating tolerance and a percentage of the LIP for the applicable hour with the charge
increasing with the amount of uninstructed deviation. The calculation of the charge shall be as
follows:
UDC
=
ABS ((Min (UDMW, 25) * 10 % + (Max (0, UDMW – 25) *
25 %)) * LIPo)
UDMW
=
( i 1 ABS( Max ( Max( 0, ARPi – ( EOLi + RHi )) , Max(
12
0 , ( EOLi - RLi ) – ARPi ) ) ) / n )
Where:
UDC =
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UDMW =
Average absolute MW deviation outside the operating tolerance for all
intervals in the hour.
RH =
Resource High operating tolerance or over generation limit (MW) as
defined in Section 8.5.1 for the interval.
RL =
Resource Low operating tolerance or under generation limit (MW) as
defined in Section 8.5.1 for the interval.
ARP =
Actual Resource Production at the end of the Dispatch Interval.
EOL =
Expected Operating Level for the Dispatch Interval.
LIP =
Locational Imbalance Price for the Operating hour and Resource
Settlement Location.
i=
Dispatch interval within Operating Hour.
o=
Operating Hour
n=
Number of intervals in an Operating Hour or twelve (12).
The Uninstructed Deviation Charge is anticipated to be an interim measure until a regulation
ancillary service market is established and including alternative performance incentives.
Example 1
Generator A is available for SPP Dispatch
600 Maximum Capacity Limit
250 Minimum Capacity Limit
5 MW Regulation Up from the Ancillary Service Plan
5 MW Regulation Down from the Ancillary Service Plan
100 Scheduled Amount from Settlement Location associated with the Resource.
$55 Locational Imbalance Price for the hour
Time
1205
1210
1215
1220
1225
1230
1235
1240
1245
1250
1255
1300
Actual
Dispatch
SCADA
Instruction Operation
500
450
500
460
500
475
500
490
500
500
500
510
500
530
500
545
500
530
500
505
500
500
500
505
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RH
RL
30
30
30
30
30
30
30
30
30
30
30
30
UD
30
30
30
30
30
30
30
30
30
30
30
30
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-50
-40
-25
-10
0
10
30
45
30
5
0
5
UD Outside
Range
20
10
0
0
0
0
0
15
0
0
0
0
3.75 UDMW
$20.63 UDC
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Example 2
Generator A is Self Dispatched
600 Maximum Capacity Limit
250 Minimum Capacity Limit
0 MW Regulation Up from the Ancillary Service Plan
0 MW Regulation Down from the Ancillary Service Plan
5 Ramp Rate reported on the Resource Plan
300 Scheduled Amount from Settlement Location associated with the Resource for each interval.
$55 Locational Imbalance Price for the hour
Time
1205
1210
1215
1220
1225
1230
1235
1240
1245
1250
1255
1300
Actual
Dispatch
SCADA
Instruction Operation RH
300
310
300
320
300
330
300
340
300
350
300
360
300
520
300
535
300
520
300
505
300
500
300
495
RL
25
25
25
25
25
25
25
25
25
25
25
25
UD
25
25
25
25
25
25
25
25
25
25
25
25
-10
-20
-30
-40
-50
-60
-220
-235
-220
-205
-200
-195
UD Outside
Range
0
0
5
15
25
35
195
210
195
180
175
170
100.416667 URMW
$1,174.48 URC
8.5.3 Uninstructed Deviation Calculations during Reserve Sharing Events
For Resources carrying spin and non-spin capacity, the uninstructed deviation incurred during an
SPP Automated Reserve Sharing event will be set to zero for the purposes of determining
uninstructed deviation.
8.5.4 Intermittent Resources
The difficulty in predicting the actual output of intermittent Resources makes it difficult to
predict their actual operating level for the end of each Dispatch Interval and makes such
Resource’s ability to respond to Dispatch Instructions limited. As a result Intermittent Resources
may take the following action in order to minimize the error unpredictable operation introduces
into the SPP market dispatch as well as minimize their exposure to Uninstructed Deviation
Charges.
The Market Participant will indicate the Resource is Market Dispatched with a minimum and
maximum capability reflecting the limitations of the Resource and a ramp rate of zero (0) MW
per minute.
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SPP will begin generating Dispatch Instructions consistent with the information provided and as
a result Dispatch Instructions will equal the operating level of the Resource at the time of the
dispatch calculations for the Dispatch Interval. While Resource actual operation during the
Dispatch Interval is expected to vary based on the actual conditions, the Resource will not be
subject to Uninstructed Deviation Charges based on these Dispatch Instructions.
8.5.5 Other Grounds for Exemption
Resources shall not be subject to Uninstructed Deviation Charges for any Uninstructed Deviation
Megawatts caused by: (1) Manual Dispatch Instructions (2) redeployment by the Balancing
Authority (3) Test Mode; or (4) Start-up or Shut-down Mode of either a Resource or each
generating unit individually if multiple generating units are registered collectively as a single
Resource; or (5) Instances when a Resource trips or is derated after receiving Dispatch
Instructions (6) the Resource is an Intermittent Resource; or (7) the dispatch instructions issued
to a Resource were beyond the reported capabilities in the Resource Plan due to the application
of a VRL.
The Transmission Provider may also waive Uninstructed Deviation Charges to the extent a
Market Participant can demonstrate such deviation was caused solely by events or conditions
beyond its control, and without the fault or negligence of the Market Participant. The Market
Participant must provide the Transmission Provider with adequate documentation through the
invoice dispute process in order for the Market Participant to be eligible to avoid such
Uninstructed Deviation Charges. The Transmission Provider shall determine through the dispute
process whether such Uninstructed Deviation Charges should be waived.
Uninstructed Deviation Penalty exemptions will be granted automatically for any hour during
which a Market Participant has utilized the Start-up / Shut-down Indicator in the Resource Plan.
However, SPP shall monitor the use of this indicator for any of the following items as
appropriate:



Plan MW less than Min MW as a start-up indicator;
Substantial changes in Min MW and Max MW from one hour to the next, or intra-hour,
that are indicative of generating unit start-ups and shut-downs. Market Participants
should provide SPP with information regarding the typical minimum size of Min MW
and Max MW changes to expect when unit start-ups and shut-downs occur for a
Resource; and
SCADA data at the individual unit levels, changing from zero to non-zero or non-zero to
zero, value
If these items are not found during, before or after the hour in which the Start-up / Shut-down
Indicator in the Resource Plan is selected, SPP will disallow the Market Participant’s exemption
from UD Penalties during such hour. The Market Participant may then avail itself of the
settlement dispute process to supply additional information to SPP to contest the exemption
denial. Upon review of such information, by SPP, it may reinstate the exemption from the UD
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Penalties for the Market Participant for such hour, if SPP determines that a UD Penalty
exemption was appropriate.
8.5.4.1 Exception Request Documentation
If the Balancing Authority redeploys a unit it shall provide documentation justifying that
redeployment to SPP and the Market Monitors. SPP and the Market Monitors shall investigate
and review the documentation and determine if the appropriate action was taken.
8.5.6 Uninstructed Deviation Charge Payment
The Uninstructed Deviation Charges from Resources will be uplifted though Revenue Neutrality
Uplift Procedure as in found in Section 9.
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Boxed text to become 7.5.8 upon system implementation
7.5.1 Uninstructed Deviation Charge Payment to Regulation Providers
During the period prior to the implementation of a regulation ancillary service market and until the
SPP operates as a Control Area, it is recognized that the Control Area host for the Resource, as a
result of its control performance obligations, is responsible for regulating up or down to offset
uninstructed deviation within its area. In order to maintain operation within NERC control
performance standards, uninstructed deviations by non-regulating Resources within the control area
will be offset by equal and opposite regulation deployments by the Resources in the Control Area
providing regulation services (“Regulating Resources). In such situations Regulating Resources are
forced to be price takers either purchasing or selling power at the LIP. The amount of the offsetting
regulation deployments is the net of the Uninstructed Deviations on all of the non-regulating units in
the Settlement Area. A portion of the Uninstructed Deviation Charges collected from non-regulating
Resources in each Settlement Area and all of the Uninstructed Deviation Charges from regulating
generators in each Settlement Area will be allocated to the Regulating Resources within that same
Settlement Area.
The portion of the Uninstructed Deviation Charges from non-regulating Resources, allocated to the
Resources in that Settlement Area, will be based on a ratio of the net uninstructed MW from nonregulating units to the net absolute uninstructed MW from non-regulating units in the Settlement
Area and is calculated as follows:
A = Total Uninstructed Deviation $ from non-regulating resources
B = Total absolute MW of uninstructed deviations from non-regulating resources
C = Total net MW of uninstructed deviation from non-regulating resources
D = Amount to be credited back to regulating resources
D = A * (C / B) ple:
Three identical Resources
R1 – UDC MW = + 100
UDC Charge = $1000
R2 – UDC MW = -100 UDC Charge = $1000
R3 – UDC MW = +25
UDC Charge = $250
A = $2250
B = 225
C = 25
D = $2250 * ( 25 / 225 ) = $250 credited back to regulation providers & $2,000 credited to market
overall through uplift.
The collections to be distributed to the regulating units will be distributed proportionally to the
Resources based on the amount of regulation service reflected on the Ancillary Service Plan. The
portion of the Uninstructed Deviation Charges from non-regulating Resources not allocated to the
Regulating Resources in that Settlement Area will be uplifted though Revenue Neutrality Uplift
Procedure as in found in Section 9.
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9 Deployment
9.1 Introduction
SPP shall determine the least costly means of obtaining energy to serve the next increment of
Load at each injection/withdrawal node and each interface with each adjacent Balancing
Authority Area. Each injection/withdrawal node is defined in the State Estimator for the SPP
Market Footprint. The least costly means of obtaining energy is calculated by the Scheduling,
Pricing, and Dispatch (SPD) program. The following limiting factors are utilized by SPD:
o The system conditions described by the most recent power flow solution produced by the
State Estimator program;
o Resource parameters provided in Resource Plans and Ancillary Service Plans;
o Energy Offer Curves;
o Activated transmission constraints
In certain situations, enforcing all such limiting factors 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 SPD.
SPD uses an incremental linear optimization method to minimize energy costs and assumes Self
Dispatched Resources will be operating at their scheduled Megawatt level indicated on the
RTO_SS schedules, including NLPS, at the end of each Dispatch Interval. :
Deployment calculated by SPD determines the Dispatch Instructions for Resources that have
offered to provide EIS. The Resource Dispatch Instructions are based upon the Offer Curve,
Resource Plan, and Ancillary Services Plan. Resources that have elected to be dispatched by
SPP will have:
o The entire MW capability available for SPP dispatch, subject to the MaxEconMW,
MinEconMW;
o Ramp Rate and Ancillary Service parameters specified by the Market Participant in the
Resource and Ancillary Service Plans.
9.1.1 Application of VRLs
When necessary to avoid excursions in shadow prices and to ensure a programmatic solution in
all cases, SPD applies VRLs. 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 SPD to balance the
market’s energy obligations, a higher VRL will be applied. In the case of the Operating
Constraint VRL, the value limits the cost of the dispatch needed to balance system injections and
withdrawals by capping the shadow price.
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The four categories of VRLs are:
 Operational Constraints (OCs); subcategories being:
o Flowgate constraints
o RTCA constraints
o Watch list constraints
o Manual constraints
o PNode constraints
 Resource ramp rate limits
 Market balance (generation to load)
 Resource capacity maximum/minimum output limits
When an OC limit is reached but not exceeded, it is referred to as “binding.” In this state, VRLs
are not applicable.
SPP shall provide a standard XML market notification via programmatic interface to all Market
Participants for each instance that SPP implements a VRL. All VRL notifications shall identify
the type of limit relaxed/VRL category, the MW amount of relaxation, and the associated
flowgate or Resource name. The Resource name will only be provided to the Market Participant
to whom the Resource is registered and will not be provided to all other Market Participants.
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
9.1.2 Impact of VRLs on LIPs and Uninstructed Deviation Charges
The VRL value applied by SPD is not used directly in determining the LIP for any Resource.
LIPs are determined by the Resource Dispatch Instructions issued by MOS.
In the event that a Dispatch Instruction resulting from the application of a VRL violates a
Resource Plan parameter, Uninstructed Deviation Charges (UDC) shall not be applied.
9.1.3 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
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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.
During at least the first 12 months of the market, SPP shall report the following information to
MWG and ORWG on at least a monthly basis within 15 days of the last day of the month:
a.
b.
c.
d.
e.
f.
g.
The number of times that VRL values were applied by SPD during the
month, and associated detail regarding the VRL type and value for each
incident;
The value of each LIP in excess of the safety net offer cap or below zero
during the month;
The number and duration of each incident where a VRL was employed
with respect to the same flowgate for two or more consecutive intervals.
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 LIP during the violation period.
The assessment of regulation requirement from application of a VRL.
The number of CPS violations coincident with the application of a VRL.
The number and magnitude of Manual Dispatch Instructions issued
coincident with the application of a VRL.
9.1.4 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.
9.1.4.1 Quarterly Metric 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:
a. A summary report and supporting detailed data identifying:
 Number of times, each month, the application of VRL was required to provide a market
solution
 VRL type and value
 Amount of the limiting condition
 Amount exceeding the limit
 Resulting shadow prices for each incident
 Number and duration of each incident where a VRL was employed with respect to the
same flowgate for six or more consecutive intervals
 Number and magnitude of manual dispatch instructions issued coincident with the
application of a VRL
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b. An assessment of how effective the VRLs have been at achieving the stated objectives.
9.1.4.2 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.
9.2 Content
9.2.1 Dispatch Instruction
The dispatch instruction is a MW set-point for the end of the Deployment Interval. They are sent
to every Resource in the Market Footprint for every interval. The Dispatch Instruction is
determined differently depending on the Status of the Resource in the Resource Plan. Details for
this are described in Section 9.4 Use of Data. The following items, however, make up the
components of every Dispatch Instruction.







Resource Name
Resource Type (GEN, generator or VDDR, PLT, VDDCLDVDD, BDD)
Date
Interval Ending (HH MM)
Dispatch Type (EIS, other)
MW set-point
Price $/MWH
For JOUs, SPP shall develop an aggregate dispatch instruction to be sent via XML and ICCP
representing the total of all dispatch instruction for each JOU co-owner. This aggregate dispatch
instruction shall consist of the following:




Resource Name per each JOU co-owner’s registration
Date
Interval Ending (HH,MM)
MW set-point
In the example below, the Resource has both scheduled energy and offered into the imbalance
market. Every 5 minutes a new dispatch instruction is sent (represented by the yellow area) and
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the Resource is ramping to achieve the dispatch (represented by the red line). Regulation results
in the Resource moving around the ramp (represented by the black line).
Generator 1
500
MWh = 363.703
MWh = 411.461
450
ARS Command
400
MW
Instruction
Schedule
Ramp (Incl ARS)
350
Actual (incl Reg.)
300
MWh = 300
250
1300
1315
1330
MWh = 346
1345
1400
1415
1430
1445
1500
Time
Note that the schedules (represented by the blue line) are not the same thing as dispatch
instructions. The schedules also change when reserve deployment occurs (shown as the cyan
area and an increase in the blue schedule line). The integrated MWh from the actual
performance and the schedules are reflected for hours ending 1400 and 1500. An imbalance
payment would result from the above example for both hours, regardless of the regulation down
impacts. The impact of reserve deployment is offset by the change from the net scheduled
amount, resulting in no increase in imbalance. Reserves are settled through the reserve sharing
agreement.
SPP’s dispatch instruction may exceed the Ramp Rate in the Resource Plan for a particular
Resource under the following conditions:


A Resource ramp rate VRL is triggered for the SPP system; or
A parameter in a Resource Plan or Ancillary Service Plan is modified such that the
change in the Dispatchable Range of the Resource, from one Deployment Interval to the
next, is greater than the Ramp Rate capability.
Where a constraint has been bound on a transmission line and market units redispatched to limit
flow across that line, MOS will not release the bound constraint until such time as the flow on
the line has been reduced, by an amount determined by SPP no greater than x on a flowgate by
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flowgate basis, of the total line limit. Delaying release of the bound constraint is designed to
prevent oscillating dispatch up and dispatch down instructions on the marginal unit impacting the
line.
9.2.1.1 Uninstructed Deviation
Uninstructed Deviation is the difference between the dispatch instructions and the aActual
performance of the ResourceResource Production (ARP). Uninstructed Deviation is calculated
for all Resources. The difference is calculated for the end of each Deployment Interval (BDDR).
. These differences are captured for integration purposes and further analysis.
Any Resource that deviates from SPP Dispatch Instructions more than 10%, adjusted for
regulation capacity and limited to a minimum of 1 MW, for 6 consecutive intervals will be
removed from the dispatch process of the market for the remainder of the day and the day after
such deviation is noted. This will result in those identified Resources being designated as Selfdispatched units. For Resources carrying spin and non-spin capacity, the intervals during an SPP
Automated Reserve Sharing event will be ignored for the purposes of determining uninstructed
deviation.
Uninstructed Deviation vs. Imbalance Example 1
Generator A is available for SPP deployment
Schedule for hour ending 1300:
Generator A to Load A
Time
1215
1230
1245
1300
Schedule
100 MW
100 MW
100 MW
100 MW
100 MWh
Dispatch Instantaneous Uninstructed
Settlement
Instruction Measurement
Deviation
Measurement
100 MW
85 MW
-15 MW
120 MW
129 MW
9 MW
110 MW
130 MW
20 MW
100 MW
100 MW
0 MW
110 MWh
Imbalance = (Actual MWh - Scheduled MWh)
Imbalance = (110 MWh - 100 MWh) = 10 MWh surplus
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Uninstructed Deviation vs. Imbalance Example 2
Generator A is available for SPP deployment
Schedule for hour ending 1300:
Generator A to Load A
Time
1215
1230
1245
1300
100 MWh
Dispatch Instantaneous Uninstructed
Settlement
Schedule Instruction Measurement
Deviation
Measurement
100 MW
125 MW
110 MW
-15 MW
100 MW
125 MW
110 MW
-15 MW
100 MW
125 MW
110 MW
-15 MW
100 MW
125 MW
110 MW
-15 MW
110 MWh
Imbalance = (Actual MWh - Scheduled MWh)
Imbalance = (110 MWh - 100 MWh) = 10 MWh surplus
9.2.2 Out of Merit Energy (OOME)
SPP may dispatch any Resource through manual processes only where necessary to resolve
Emergency conditions that the EIS market through SCED cannot resolve. SPP will issue manual
instructions (referred to in the system as “OOME,” or out of merit energy) at the MW level the
resource is expected to produce until such time as an appropriate constraint can be recognized by
MOS and the IDC. SPP will make every effort to define and activate the constraint in MOS and
the IDC within one hour of the manual reconfiguration. The reliability issues identified by the
Balancing Authority, with solutions, will be coordinated with SPP for the purpose of SPP
incorporating into the deployment of any Resource, whether through SCED or manual processes.
When an OOME is created notifications will immediately be issued for all future intervals for
which an EIS Dispatch Instruction has already been sent. The OOME notification for future
intervals not yet dispatched will be sent directly following the EIS Dispatch Instruction for those
intervals. So Market Participants will receive an OOME Dispatch Instruction for each interval
that supersedes the EIS Dispatch instruction for the same interval
More than one OOME may be initiated for the same Resource within a given interval. In such a
case the OOME instruction indicating the latest timestamp will be utilized.
The end of an OOME event will be noted by the absence of an OOME notification.
Uninstructed Deviation will be automatically waived and Uninstructed Deviation Charges will
not be assessed for a Resource for each interval it receives an OOME instruction consistent with
section 8.5.6.
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Below is an overview of the OOME communication process.
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Emergency Deployment Process
Generation
Generation
Operator
Operator
SPP
SPPMarket
Market
Operator
Operator
SPP
SPPReliability
Reliability
Coordinator
Coordinator
Balancing
BalancingAuthority
Authority
Start
SPP RC
Recognizes
Emergency
Situation requiring
OOME
SPP RC declares
emergency via
OASIS and NERC
RCIS
SPP RC
determines course
of action and
notifies BAs and
SPP MO
SPP MO notifies
affected Market
Participant(s) via
telephone
SPP Reliablity
Coordinator issues
TLR
BAs coordinate
with GOPs to
ensure appropriate
action is taken
SPP MO enters
“OOME” in MOS
MOS sends
“OOME”
deployments for
each resource
every interval
GOPs implement
OOME
deployment
SPP RC
Recognizes
Emergency
Situation has
ended
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Emergency Deployment Process
Generation
Generation
Operator
Operator
SPP
SPPMarket
Market
Operator
Operator
SPP
SPPReliability
Reliability
Coordinator
Coordinator
Balancing
BalancingAuthority
Authority
SPP RC notifies
SPP MO and BAs
SPP MO notifies
affected Market
Participant(s) via
telephone
SPP Reliablity
Coordinator
updates TLR as
necessary
BAs coordinate
with GOPs to
ensure appropriate
action is taken
SPP market
operator
terminates
“OOME” in MOS
MOS discontinues
“OOME”
deployment
instructions
GOPs follow “EIS”
deployment
instructions
End Process
9.2.3 Net Scheduled Interchange
Net Scheduled Interchange is calculated as a net of all approved inter Control Area schedules in
SPP’s Electronic Scheduling System, RTO_SS and for use in additional MOS calculations. This
includes schedules from NERC Tags, schedules that are a result of an Automated Reserve
Sharing (ARS) event and Loss Repayment schedules that are created within RTO_SS. Dynamic
schedules are not included in the calculation of NSI.
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Every 4 seconds the following occurs:
RTO_SS will send real time NSI values to SPP’s Energy Management System Real Time
Manager (EMS RTSMGR). The RTSMGR will sum the real time NSI from RTO_SS
with the EI component from Market Operations System (MOS) and send this signal to
SPP Control Areas via ICCP on an approximate 4-second interval. SPP shall provide a
backup mechanism for SPP Control Areas to receive the EI NSI.
Every 5 minutes the following occurs:
1. SCED is performed for the next 5 minute interval using four primary sets of inputs under
normal circumstances.
 The first set of inputs includes the latest generation values collected from the SPP
EMS AGC (fed from ICCP).
 The second input includes the Resource ramp rates and availability flags in effect for
that interval.
 The third input includes the Resource offers for EIS.
 The fourth input includes Resource requirements based on the short term SPP Control
Area forecast and the net of schedules flowing into or out of the SPP footprint
(obtained from RTO_SS).
2. MOS calculates the total SPP NSI and RTO_SS CA NSIs using the schedules that were
collected from RTO_SS.
 MOS performs security constrained economic dispatch using SPP NSI and control
area Load Forecasts for the interval.
 The generation for each Control Area is summed and the Control Area Load Forecast
is subtracted from that generation to calculate the Economic Dispatch NSI (ED NSI).
 MOS subtracts the CA NSI from the ED NSI to produce the Energy Imbalance NSI
(EI NSI).
3. MOS sends the EI NSI component (one per SPP control area) to the EMS.
9.2.4 Inadvertent Interchange
SPP shall maintain inadvertent accounts and administer inadvertent payback for all control areas
participating in the SPP market. 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 imbalance prices over time.
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9.2.5 Real-Time Deficit and Excess condition in Dispatchable Ranges
A real-time deficit condition occurs when SPP does not have adequate dispatchable resources to
meet real-time imbalance energy demand. A real-time excess condition occurs when SPP is
unable to meet real-time imbalance energy demand without violating the minimum dispatchable
range of dispatchable resources. SPP shall address these conditions by adjusting the NSI values
of that Balancing Area(s) where the Market Participant causing the deficit or excess condition.
9.2.5.1 Identification of MP causing Deficit or Excess condition
In the Day Ahead Simultaneous Feasibility Test (DASFT) and the intra-operating day capacity
adequacy tests performed for each operating hour, SPP shall evaluate all MP’s forecast load and
the sufficiency of offered EIS resources. SPP will estimate each MP’s real-time EIS demand
based on the information available at the time these checks are performed. SPP shall also
evaluate whether each MP has arranged for adequate capacity to meet their real time load
obligation, if any.
MPs within that BA(s) shall be notified that an excess or deficit condition exists within the BA,
and SPP will assist the BA to maintain reliable operations. BA(s) shall coordinate with SPP all
action necessary according to Attachment AN of the SPP OATT.
9.2.5.2 Declaration of Deficit condition
SPP shall evaluate, on a forward looking basis, at the time it calculates the dispatch instruction
for the applicable dispatch interval, whether it is able to meet the EIS demand of the Market
footprint for that dispatch interval. If SPP determines that it is unable to meet the anticipated
EIS demand for that dispatch interval because of a lack of deliverable EIS resource(s), it will
declare a deficit condition for the EIS Market. At this time, SPP shall also determine which
Balancing Areas are specifically deficient. SPP shall post a notification to all BAs of the Market
deficit condition. SPP shall also send notice of deficit conditions to all MPs within the deficient
BA(s).
9.2.5.3 Declaration of Excess condition
SPP shall evaluate, on a forward looking basis, at the time it calculates the dispatch instruction
for the applicable dispatch interval, whether it is able to meet the EIS demand of the Market
footprint for that dispatch interval. If SPP determines that it is unable to meet the anticipated
EIS demand for that dispatch interval because of it would have to violate the minimum
dispatchable range of deliverable EIS resource(s), SPP will declare an excess condition for the
EIS market and notify all Balancing Areas. SPP shall also identify the specific BA(s) that will
be affected by the excess condition, and send notifications to all MP within those BA(s) of that
excess condition.
9.2.5.4 Data provided to BA and MP Notification
At the time SPP determines if an excess of deficit condition exists within a Balancing Area, SPP
shall provide the following information to the Balancing Authority.
 Dispatch Interval
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
MW amount of anticipated mismatch

MP net Schedule total and net Deployment Instructions

Estimated NSI bias amount
9.2.5.5 NSI Adjustment
For those Balancing Authorities where excess or deficit condition exists, an NSI adjustment
totaling the shortage or excess demand will be shared pro-rata in real-time depending on how
over or short each Balancing Area is estimated to be. SPP will coordinate the NSI bias and BA
actions to minimize the effect on reliability and the BA’s ability to regulate and/or utilize
spinning reserve(s), and to avoid the need to declare an OEC or EEA.
9.2.5.5.1 Deficit Condition
If in real-time SPP has a generation dispatch deficit, the deficit MW will be distributed among all
BAs with generation shortage to be reflected in their NSI. The adjusted BA NSI for BAs with
capacity shortage is equal to:
Total Balancing Authority Area (BAA) Resource Dispatched MW (-) BAA Load
Forecast (+) BAAs pro rata share of the system shortage
BA s with shortage will be identified as having a positive value for:
BAA Load Forecast (-) BAA Total Maximum Dispatchable Generation (+) BAA Net
Scheduled Export
In this event, the LIP of all resources that were identified as AGC resources in the Balancing
Authorities A/S plan, will be set to the highest SPP wide cleared offer.
9.2.5.5.2 Excess Condition
If in real-time SPP has a generation dispatch excess, the excess MW will be distributed among
BAs with excess energy to be reflected in their NSI. The adjusted BA NSI for BAs with
generation excess is equal to:
Total BAA Resource Dispatched MW (-) BAA Load Forecast (+) BAAs pro rata share of
the system excess
BAs with excess will be identified as having negative value for:
BAA Load Forecast (-) BAA Total Minimum Dispatchable Generation (+) BAA Net
Scheduled Export
In this event, the LIP of all resources that were identified as AGC resources in the Balancing
Authorities A/S plan will be set to the lowest SPP wide cleared offer.
9.2.5.6 Balancing Area and SPP
SPP work collaboratively with the Balancing Authority to determine and instruct the proper
actions to be taken including interruption or other actions by the MP’s host Balancing Authority
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under the appropriate NERC Standards, SPP Criteria, and/or other applicable agreements. The
SPP-Balancing Area Agreement shall dictate indemnification.
9.2.5.7 Exemption
Any resource deployment by the Balancing Authority to mitigate any excess or deficit conditions
will be exempt from Uninstructed Deviation and Over/Under-Scheduling penalties.
9.2.5.8 Post Analysis
Within 24 hours of completion of an excess/deficit condition, SPP shall prepare a report to the
effected BA(s) and MP(s).
9.3 Timing
Dispatch instructions are calculated every 5 minutes beginning at 0000. The instruction is a set
point for the end of the Deployment Interval and is communicated 5 minutes before the
beginning of the Deployment Interval. The instructions are communicated through the Internet
to a listener and use XML format as the primary delivery mechanism. The MW set point portion
of the instruction will also be available through an ICCP point defined for each Resource. SPP
will communicate the ICCP Deployment Instructions through the SPP Net. The XML
instruction will be the basis for all settlement calculations and resolution of any disputes. NSI is
calculated every 4 seconds and incorporates the ramping data from the Resource Plans and
RTO_SS. The NSI is communicated using ICCP.
The interval between the communication of a Dispatch Instruction and the beginning of the
Deployment Interval will be periodically reviewed to determine whether the time lag can be
reduced.
9.4 Use of Data
Data from the Offer Curves, Resource Plan, and Ancillary Services Plans are used, along with
the State Estimator, to calculate the dispatch instruction. If a Resource indicates availability for
SPP dispatch control through the Resource Plan, the Security Constrained Economic Dispatch
requests movement within the dispatchable range. If a resource is in ‘Self-dispatched’ status,
then MinDispatchableMW = MaxDispatchableMW = the sum of the schedules sourcing from
that resource.
For a unit in Available Quick Start status, while the Resource breaker is open, the SPP MOS will
treat the Resource just like other Resources Available for SPP Dispatch with a Minimum
Capacity Operating Limit of zero (0) MW. For a unit in Available Quick Start status, when the
Resource breaker is closed, the SPP MOS will treat the Resource just like other Resources
Available for SPP Dispatch with a Minimum Capacity Operating Limit as indicated on the
Resource Plan.
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The dispatchable range for Resources in “Available” status is calculated using the data from the
Resource Plan and reserve designations (a.k.a. Ancillary Service Plan), as illustrated below:
MinDispatchableMWi = MinEconMWo + REGDNo
MaxDispatchableMWi = MaxEconMWo – REGUPo – MAX (SPINo + SUPPo - RSSi, 0)
Where:
MinDispatchableMWi
=
Minimum Limit of Dispatchable Range (MW)
MaxDispatchableMWi
=
Maximum Limit of Dispatchable Range (MW)
MinEconMWo =
Minimum Economic Capacity Operating Limit (MW) as
indicated on the Resource Plan for the hour of the Dispatch
Interval (MW)
MaxEconMWo =
Maximum Economic Capacity Operating Limit (MW) Limit
as indicated on the Resource Plan for the hour of the
Dispatch Interval (MW)
SPINo
=
Spinning Reserves being maintained on the Resources as
indicated in the Ancillary Services Plan for the hour of the
Dispatch Interval (MW)
SUPPo
=
Supplemental Reserves being maintained on the Resource as
indicated in the Ancillary Services Plan for the hour of the
Dispatch Interval (MW)
REGUPo
=
Regulation Up service being maintained on the Resource as
indicated in the Ancillary Service Plan for the Operating
Hour (MW).
REGDNo
=
Regulation Down service being maintained on the Resource
as indicated in the Ancillary Service Plan for the Operating
Hour (MW).
RSSi
=
Energy scheduled, through the Reserve Sharing System, from
the reserves being maintained on the Resources in response
to an ARS event for the Dispatch Interval (MW), as defined
in Section 6
o
=
Operating Hour
i
=
Dispatch interval within Operating Hour.
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SPIN/SUPP
DRS
URS
Dispatchable
Range
0 MW
Max MW
Min MW
Min Econ
MW
Maximum
Capability
Max Econ
MW
Dispatch instructions are generated within the range titled Dispatchable Range. Operators of
Resources use the dispatch instructions to operate their Resources. SPP dispatch instructions
will not deploy below the “Min Dispatchable-MW”, nor above the “Max Dispatchable-MW”.
The Control Area operators regulate the Control Area based on the provided NSI.
9.4.1 Provision of Data to the Balancing Authority
SPP shall make the following information available to the Balancing Authority/Transmission
Operator for each Settlement Area within that Balancing Authority Area:
 Hourly Resource Plan (original and if updated)
 Ancillary Service Plan (original and if updated)
 Hourly Load Forecast
 5-minute dispatch instruction, excluding price
 Schedules (if any)
 Native Load and Portfolio Schedules (if any)
 Energy Imbalance calculation for each Settlement Area
 Scheduled and Actual Settlement Area Load and/or Generation
 Registration information consisting of unit-to-plant groupings and associated settlement
location names as well as information needed to associate SPP’s network and SCADA
models with the corresponding models maintained by the host Balancing Authority
SPP shall make this information available to the Balancing Authority/Transmission Operator
immediately after it receives or calculates the above information.
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10 Pricing
10.1 Introduction
The Security Constrained Economic Dispatch (SCED) has an objective of minimizing the total
cost of energy while honoring the constraints and results in dispatch instructions to deploy EIS
Resources. The SCED does not take into account the differences in loss factors between
Resources when calculating dispatch instructions. Deployment of these Resources results in
Locational Imbalance Prices (LIP). The LIP for a Settlement Location is the integration of the
LIPs for the Settlement Location across the 5 minute Deployment Interval. LIP is calculated for
each Settlement Interval. Settlement Locations may be zonal or nodal for Load, but are only
nodal for Resources.
10.2 Content
10.2.1 Locational Imbalance Pricing
SPP calculates the price of energy at all Settlement Locations required for the operation of the
EIS Market on the basis of Locational Imbalance Pricing in accordance with this Section. The
pricing data for each Settlement Location includes:




Date
Time
Settlement Location
$/MWh
10.2.2 Calculation of Settlement Location Prices for Load
The price used for settlement of Loads is the LIP at the Load’s Settlement Location. A
Settlement Location price is calculated as the load weighted average of its individual Meter
Settlement Location LIPs.
For each Dispatch Interval:
LIPSLDI = SUM[(LIPMSL * MWMSLSE)]
SUM (MWMSLSE)
For each Settlement Interval:
LIPSL = SUM (LIPSLDI) / # DI per Settlement Interval
SL = Settlement Location
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MSL = Meter Settlement Location
SE = State Estimator
DI = Deployment Interval
LIP is calculated in real-time using State Estimator data. For locations that report Load for
multiple Settlement Locations, the State Estimator will require data to determine the proper
allocation of the real time values among the multiple Settlement Locations.
10.2.3 Calculation of Settlement Location Prices for Resources
The price used for settlement of Resources is the LIP at the Resource’s Settlement Location.
The LIP is the offer price to meet the next MW in a security constrained economic dispatch. The
Settlement Location price will be the calculated LIP.
For each Settlement Interval:
SUM (LIPSLDI) / # DI per Settlement Interval
SL = Settlement Location
DI = Deployment Interval
Setting Price
In general, a Resource sets price when its output meets the two following conditions.
1.
The Resource is under SPP dispatch and is deployed.
2.
The Resource is not limited in its ability to change output to comply with economic
dispatch of EIS energy. Limitations may include the Resource operating at the
minimum or maximum of its dispatchable range, ramp rate limitations, other
Resource operating limitations, transmission constraints, etc.
A Resource that is not free to change output to move along its offer curve in response to SPP’s
dispatch instructions will not set price.
10.2.4 Calculation of Settlement Locations for External Resources
The LIP calculated for the External Resource Settlement Location is the product of (i) the
estimated distribution of modeled energy flows across specific interface points between SPP and
adjacent Balancing Authorities and (ii) the Locational Imbalance Price at each interface point.
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10.3 Timing and Submission
During the Operating Day, the LIP is calculated every 5 minutes producing a set of Real-time
Prices. The prices produced at deployment intervals are integrated to determine the LIPs for each
Settlement Interval. No later than fifteen minutes following each Operating Hour, the
Transmission Provider shall post the Locational Imbalance Prices for each Settlement Location
and Meter Settlement Location for that Operating Hour on its website and shall indicate in that
posting which Meter Settlement Locations were utilized in the calculation of Locational
Imbalance Prices for each aggregated load Settlement Location. Since frequent and extensive
querying of this data through the SPP Portal is likely to adversely impact SPP market system
operations, SPP may curtail, suspend, or otherwise limit a Market Participant’s ability to query
such data if necessary to prevent such adverse impacts, after an initial warning is provided to the
Market Participant regarding its querying practices.
An XML (extensible markup language) file containing this same LIP information shall be posted
on the SPP website www.spp.org. LIP data shall be posted on an hourly basis during the
Operating Day and thereafter shall be consolidated into a daily file, which daily file shall reflect
any updated or revised LIP information, and shall indicate the date of revision. LIP information
shall remain available on the SPP website for three years after the Operating Day. Thereafter,
SPP shall archive LIP data until the later of seven years from the Operating Day or until there are
no disputes pending related to that Operating Day. SPP shall make such archived data available
to any individual upon request. The data provided in the XML file shall clearly indicate for each
nodal LIP the Settlement Location with which it is affiliated. The data provided in the XML file
shall also clearly indicate the aggregate LIP for each Settlement Location.
To reduce unnecessary constraints on SPP and Market Participant bandwidth and systems all
data will be available via a programmatic interface as well as a web page. This programmatic
interface will allow users to query for subsets of the LIP data to reduce file size. The
programmatic interface will support query by date, time, and location (Settlement Location,
PNode, or other nodal value).
SPP will make LIPs available for download by Market Participants by Settlement Location, as
well as by PNode, through a programmatic settlement interface.
10.4 Use of Data
The integrated LIP for the Settlement Interval is the numerical average of the individual
Deployment Interval prices in a Settlement Interval. The SPP shall use the resulting settlement
prices to settle all imbalance energy in the SPP’s EIS Market.
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11 Settlement and Invoice
11.1 Introduction
This section serves as a resource concerning the Settlement Statements and Invoicing
procedures.
SPP will produce daily Settlements Statements and weekly Invoices for each Market Participant.
The calculations for the charges/credits are based upon meter and schedule data for each
Settlement Location for each hour, and settled at the Locational Imbalance Price (LIP) for that
Settlement Location.
11.2 Settlement Data
11.2.1 Metering Standards for Settlement Data
Metering Standards procedures are specified in the Meter Technical and Data Reporting
Protocols, Sections 1 through 4; Appendix D of the Market Protocols.
11.2.2 Settlement Data Reporting Procedures
Settlement Data Reporting processes are specified in the Meter Technical and Data Reporting
Protocols, Sections 1-3, 5-6; Appendix D of the Market Protocols.
11.2.3 Schedule Data for Settlements
See Scheduling Protocols section 6 of this document.
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11.2.4 Public Market Data for Settlement
The Commercial Model, COS Entity Validation (SL to TSIN mapping), and SPP Loss Matrix
shall be available to all market participants for download via the SPP portal and via the
Commercial Operations Systems Programmatic Interface. The data will consist of a separate
XML file for each . Each file will contain the following information:

Commercial Model shall contain SPP’s transaction point list with details of transaction point type
(i.e.e.g. GEN, (generator or VDD, R), AGG, LOADPLT, VDDR,etc), start date, and end date. This list
will be maintained by SPP and communicated when transaction points are added, changed, and/or
deleted.

COS Entity Validation (SL to TSIN mapping) shall contain the relationship between Settlement
Location, PNode, NERC Source/Sink Name, Start Date, End Date, PSE, and Control Area. This list
will be maintained by SPP and communicated when transaction points are added, changed, and/or
deleted.

SPP Loss Matrix shall contain Season, Source, Sink, and the loss % for each Transmission Owner
for each Source/Sink pair in the SPP Loss Matrix table.
11.2.5.1 Posting of Recalculated LIP
An XML (extensible markup language) file containing the recalculated LIP information shall be
posted on the SPP website www.spp.org. The data provided in the XML file shall clearly
indicate for each nodal LIP the Settlement Location with which it is affiliated. The data
provided in the XML file shall also clearly indicate the aggregate LIP for each Settlement
Location, and the hour for which the recalculated LIP is effective.
All data will be available via a programmatic interface using XML as well as a web page. This
programmatic interface will allow users to query for subsets of the recalculated LIP data to
reduce file size. The programmatic interface will support query by date, time, and location
(Settlement Location), and for changes across a date range. Notification shall be provided to
market participants whenever a recalculated LIP is posted.
11.3 Settlement Statements
Settlement Statements are produced and published for each Operating Day. In order to issue
Settlement Statements, SPP will use actual, estimated, disputed or calculated meter and schedule
data.
A single Operating Day will have both an Initial and Final Settlement Statement, and may
contain a Resettlement Statement. Resettlement Statements can be created for any given
Operating Day, having met the guidelines for Resettlement.
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11.4 Settlement Components
The following sections describe the components that make up the calculation of the Settlement
Statements.
11.4.1 Energy Imbalance Service
An energy imbalance settlement is calculated for each settlement interval based on the difference
between the Market Participant's Settlement Location Actual Metered and Scheduled Data.
Energy Imbalance service does include–regulating energy.
11.4.1.1 Calculation of Energy Imbalance Service
All energy deviations between actuals and schedules are settled as Energy Imbalance Service
(EIS). Allocation of EIS by Settlement Area is calculated through two steps; 1) Calibration of
Load Settlement Location meter data to Net Area Input, and 2) Difference between Calibrated
Load Settlement Location Meter Data (CLMD) and Resource Settlement Location meter data for
each Market Participant to their respective schedules. The Net Area Input equals the total
injections to a Settlement Area, adjusted for net interchange and SPP provided losses. The SPP
provided losses are invoiced through tariff billing, and are removed from the calculation of the
Calibration Energy in order to prevent rebilling in the market settlement. Load data is a required
input for the settlement calculation.
11.4.1.2 Calculation of Market Participant Settlement Quantity
EIS= ((Actual Energy SL + Calibration Energy SL) – Scheduled Energy SL) * LIP SL
Where:
Resources: Calibration Energy SL =0
Load: Calibration Energy SL is calculated as shown below.
11.4.1.3 Calculation of Calibration Energy
For each Settlement Area the amount of Calibration Energy represents the difference between
the energy input into the Settlement Area and total Load in the Area. This difference is allocated
among the Interval Metered (Idata) and Profiled (Pdata) Loads by a ratio calculated through load
weighting the Calibration Allocation Factor (CAF) established by the RTO for Market
Settlement.
The CAF is set to 80%, which results in 80% weighting of Pdata, on a per MWh basis, and 20%
weighting of Idata, on a per MWh basis, in allocation of the Settlement Area Calibration Energy.
Currently SPP Market does not include retail choice; therefore, Pdata will only be used for
substitution data. If substituted (Appendix E Section 10.2.3) metering data is used, it will be
treated as PDATA.
Per Settlement Area (SA):
Net Area Input = (Generation Metering + Net Interchange + SPP Provided Transmission
Losses)
SA Calibration Energy (SACE) = Net Area Input - (Pdata + Idata)
Weighted CAF Divisor = (Pdata * CAF) + (Idata * (1 – CAF))
“Pdata” CAF = (Pdata * CAF)/Weighted CAF Divisor
“Idata” CAF = (Idata * CAF)/Weighted CAF Divisor
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“Pdata” SA Calibration Factor (PSAFA) = (SACE * ”Pdata” CAF)/  Settlement Area “Pdata”
“Idata” SA Calibration Factor (ISAFA) = (SACE – (PSAFA * Settlement Area “Pdata”))/ 
Settlement Area “Idata”
Per Load Serving Entity (LSE) within a Settlement Area:
Calibrated Load Entity “Pdata” (CLE-Pdata) = LSE “Pdata” + (PSAFA * LSE “Pdata”)
Calibrated LSE “Idata” (CLE-Idata) = LSE “Idata” + (ISAFA * LSE “Idata”)
Calibrated Load Meter Data (CLMD) = CLE-Pdata + CLE-Idata
Calibration Examples:
Legend
Column
Explanation of value/calculation
A
B
C
D
E
F
G
H
I
J
K
L
M
N
O
P
Q
R
S
T
U
V
Sum of Interval Data for Load SL's reported within the Settlement Area
Sum of Profiled Data for Load SL's reported within the Settlement Area
B + C = Total Load Settlement Locations within the Settlement Area
Sum of Resource SL's reported within the Settlement Area
Reported Net Metered Interchange for the Settlement Area
SPP Transmission Losses within the Settlement Area
D + E - F = SA Net Area Input
(G * -1) - C = Difference between SL Load and Settlement Area Load. The amount that will be calibrated to all Load SL's within the SA.
Interval Calibration Allocation Factor + 1 - J Note: Sum of I + J will equal 1.
Profiled Calibration Factor = ((80% * B)/((80% * B)+(1-80%)*A)
SA CAF for Interval Data = H * I / A
SA CAF for Profiled Data = H * J / A
Reported Load Settlement Location A Interval Data
Reported Load Settlement Location A Profiled Data
Interval Settlement Location A Load with calibration included = M + (M * K)
Profiled Settlement Location A Load with calibration included = N + (N * L)
Sum of O + P = Total Settlement Location A Calibrated Load
Reported Load Settlement Location B Interval Data
Reported Load Settlement Location B Profiled Data
Interval Settlement Location B Load with calibration included = M + (M * K)
Profiled Settlement Location B Load with calibration included = N + (N * L)
Sum of O + P = Total Settlement Location B Calibrated Load
W
Sum of Calibration Loads of Settlement Location A and B. This value will equal G: Settlement Area Net Area Input
Example 1: INTERVAL DATA ONLY: Calibration Example with NO Profiled Data within the Settlement Area
Legend
Hour
1
2
3
M
A
B
Settlement
Area Load
Interval
1438
1453
1542
C
Settlement
Area Load
Profiled
N
Load for
Load for
Settlement Settlement
Location A Location A
Interval
Profile
(Idata)
(Pdata)
0
0
0
O
Calibrated
Interval
Load
Settlement
Area Total
Load
1438
1453
1542
P
D
E
Settlement
Area (SA)
Settlement
Total
Area Net
Generation
Interchange
-1971
486
-2059
559
-2171
632
Q
R
F
H
I
J
Settlement
Area
Settlement
Calibration
Area Loss
SA Net
Volume
SA Weighted SA Weighted
Schedules Area Input (Difference)
ICAF
PCAF
1
-1486
48
1.0000000
0.0000000
1
-1501
48
1.0000000
0.0000000
1
-1540
-2
1.0000000
0.0000000
S
G
T
Total for
Load for
Load for
Settlement Settlement Settlement
Calibrated Location A Location B Location B
Profile
Calibrated
Interval
Profile
Load
Load
(Idata)
(Pdata)
Calibrated
Interval
Load
U
V
Total for
Settlement
Calibrated Location B
Profile
Calibrated
Load
Load
431
0
445.387
0.000
445.387
1007
0 1040.613
0.000 1040.613
436
0
450.403
0.000
450.403
1017
0 1050.597
0.000 1050.597
463
0
462.399
0.000
462.399
1079
0 1077.601
0.000 1077.601
- - - - - - - - - - - Settlement Location A - - - - - - - - - - - - - - - - - - - - - - - - - Settlement Location B - - - - - - - - - - - - -
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K
L
SA CAF
Interval
3.34%
3.30%
-0.13%
SA CAF
Profile
0.00%
0.00%
0.00%
W
Total SA
Calibrated
Load
1486.000
1501.000
1540.000
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Example 2: PROFILED DATA ONLY: Calibration Example with NO Interval Data within the Settlement Area
Legend
A
B
C
Hour
Settlement
Area Load
Interval
Settlement
Area Load
Profiled
Settlement
Area Total
Load
1
2
3
0
0
0
M
N
1438
1453
1542
O
Load for
Load for
Settlement Settlement
Location A Location A
Interval
Profile
(Idata)
(Pdata)
Calibrated
Interval
Load
D
Settlement
Area (SA)
Settlement
Total
Area Net
Generation Interchange
1438
1453
1542
-1971
-2059
-2171
486
559
632
P
Q
R
Calibrated
Profile
Load
0
431
0.000
0
436
0.000
0
463
0.000
- - - - - - - - - - - Settlement Location A -
E
F
G
Settlement
Area Loss
Schedules
SA Net
Area
Input
1
1
1
445.387
450.403
462.399
---------
445.387
450.403
462.399
---
0
0
0
------------
I
J
K
Settlement
Area
Calibration
Volume
SA Weighted SA Weighted SA CAF
(Difference)
ICAF
PCAF
Interval
-1486
-1501
-1540
48
48
-2
T
U
V
W
Calibrated
Profile
Load
Total for
Settlement
Location B
Calibrated
Load
Total SA
Calibrated
Load
S
Total for
Load for
Load for
Settlement Settlement Settlement
Location A Location B Location B
Calibrated
Interval
Profile
Load
(Idata)
(Pdata)
H
Calibrated
Interval
Load
0.0000000
0.0000000
0.0000000
1007
0.000
1040.613
1017
0.000
1050.597
1079
0.000
1077.601
- Settlement Location B - - - - - - -
1.0000000
1.0000000
1.0000000
1040.613
1050.597
1077.601
------
0.00%
0.00%
0.00%
L
SA CAF
Profile
3.34%
3.30%
-0.13%
1486.000
1501.000
1540.000
Example 3: BOTH INTERVAL & PROFILED DATA Reported: Calibration Example with both within the Settlement Area
Legend
Hour
1
2
3
A
Settlement
Area Load
Interval
1000
1000
1000
B
Settlement
Area Load
Profiled
438
453
542
D
C
Settlement
Area Total
Load
1438
1453
1542
E
Settlement
Area (SA)
Settlement
Total
Area Net
Generation
Interchange
-1971
486
-2059
559
-2171
632
M
N
O
P
Load for
Load for
Settlement Settlement
Location A Location A
Interval
Profile
Calibrated
Calibrated
(Idata)
(Pdata)
Interval Load Profile Load
300
131
305.233
140.140
300
136
305.121
145.286
300
163
299.811
162.588
- - - - - - - - - - - Settlement Location A - - - - - - - - - - - -
F
G
H
Settlement
Area
Settlement
Calibration
Area Loss
SA Net
Volume
Schedules Area Input (Difference)
1
-1486
48
1
-1501
48
1
-1540
-2
I
J
SA
Weighted SA Weighted
ICAF
PCAF
0.3633721
0.6366279
0.3556188
0.6443812
0.3156566
0.6843434
Q
R
S
T
U
Total for
Load for
Load for
Settlement Settlement Settlement
Location A Location B Location B
Calibrated
Interval
Profile
Calibrated
Calibrated
Load
(Idata)
(Pdata)
Interval Load Profile Load
445.372
700
307
712.209
328.419
450.407
700
317
711.949
338.644
462.399
700
379
699.558
378.043
- - - - - - - - - - - - - Settlement Location B - - - - - - - - -
K
SA CAF
Interval
1.74%
1.71%
-0.06%
L
SA CAF
Profile
6.98%
6.83%
-0.25%
V
W
Total for
Settlement
Location B
Total SA
Calibrated
Calibrated
Load
Load
1040.628
1486.000
1050.593
1501.000
1077.601
1540.000
----
11.4.1.4 XML Files for Calibration Billing Determinants
Calibration billing determinant data for each settlement area shall be available to all market
participants for download via the SPP portal. The data will consist of a separate daily XML file
created for each settlement area. Each settlement area file will contain the following
information:

SA Name

SA Operating Date

SA Settlement Type(Initial, Final and Resettlement)

SA Total Actual Resource Meter Data

SA Total Substituted Resource Meter Data
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
SA Total Resource Data

SA Total Actual Load Meter Data

SA Total Profiled Load Meter Data

SA Total Substituted Load Meter Data

SA Total Load Meter Data

SA Interchange Data

SA Net Area Input

SA Load Calibration Volume

SA Actual Interval Calibration Factor

SA Profile Calibration Factor
11.4.1.5 Calculation of Energy Imbalance Service Charges
For each settlement interval, the EIS charge is based on the EIS energy multiplied by the LIP. A
Load that is one megawatt or greater may choose nodal rather than zonal pricing as described in
the Pricing Protocols.
11.4.1.6 Settlement for VDD Resources
For VDD Resources, the hourly integrated ARP as described in section 3.6.3 will be used in
settlements.
11.4.2 Charges for Under-Scheduling and Over-Scheduling
11.4.4.1 Under-Scheduling Charges
During any hour, if Locational Imbalance Prices diverge and a Market Participant’s Load
imbalance is more than 4% (but at least 2 MW) at an applicable Settlement Location in that hour,
that Market Participant may be subject to an Under-Scheduling Charge. If the Reported Load is
greater than the Scheduled Load by more than 4% of Reported Load (but at least 2 MW), UnderScheduling Charges will be determined as follows:
a) For Resource Settlement Locations, the Transmission Provider shall sort the Market
Participant’s negative Imbalance Energy amounts in ascending order according to each
Resource’s Locational Imbalance Price, with a secondary sort in ascending alphanumeric
order of the Resource name for any Resources that have the same Locational Imbalance
Price.
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b) For Load Settlement Locations at which Scheduled Load is less than 96% of Reported
Load and the imbalance is at least 2 MW, the Transmission Provider shall sort the Market
Participant’s positive Imbalance Energy amounts in ascending order according to each
Load’s Locational Imbalance Price.
c) Utilizing the sorted lists developed under Sections 11.4.2.1(a) and (b) above, and starting
with the Resource with the lowest Locational Imbalance Price, the Transmission Provider
shall match each Resource’s Imbalance Energy against that Market Participant’s Load
Imbalance Energy, starting with the Load Imbalance Energy with the lowest associated
Locational Imbalance Price, until all of the Load Imbalance Energy has been accounted
for or until no additional Resources remain.
d) The following calculation is performed only for Resources that have a Locational
Imbalance Price greater than the Locational Imbalance Price for the associated Load
Settlement Location. A Market Participant’s Under-Scheduling Charge, for each
Resource identified under Section 11.4.2.1(c) as being required to match that Market
Participant’s Load Imbalance Energy, shall be calculated as follows:
Resource Under-Scheduling Charge = (LLIP – RLIP) * Resource Imbalance Energy,
where
RLIP = Locational Imbalance Price of the Resource Settlement Location,
LLIP = Locational Imbalance Price of the associated Load Settlement Location,
Resource Imbalance Energy = the amount of that Resource’s Imbalance Energy required
to offset the Market Participant’s Load Imbalance Energy as calculated under Section
11.4.2.1(c).
11.4.1.2 Over-Scheduling Charges
During any hour, if Locational Imbalance Prices diverge and a Market Participant’s Load
imbalance is more than 4% (but at least 2 MW) at an applicable Settlement Location in that hour,
that Market Participant may be subject to an Over-Scheduling Charge. If the Scheduled Load is
greater than the Reported Load by more than 4% of Reported Load (but at least 2 MW), OverScheduling Charges will be determined as follows:
a) For Resource Settlement Locations, the Transmission Provider shall sort the Market
Participant’s positive Imbalance Energy amounts in descending order according to each
Resource’s Locational Imbalance Price, with a secondary sort in ascending alphanumeric
order of the Resource name for any Resources that have the same Locational Imbalance
Price.
b) For Load Settlement Locations at which Scheduled Load is greater than 104% of
Reported Load and the absolute value of the imbalance is at least 2 MW, the
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Transmission Provider shall sort the Market Participant’s negative Imbalance Energy
amounts in descending order according to each Load’s Locational Imbalance Price.
c) Utilizing the sorted lists developed under Sections 11.4.2.2(a) and (b), and starting with
the Resource with the highest Locational Imbalance Price, the Transmission Provider
shall match each Resource’s Imbalance Energy against that Market Participant’s Load
Imbalance Energy, starting with the Load Imbalance Energy with the highest associated
Locational Imbalance Price, until all of the Load Imbalance Energy has been accounted
for or until no additional Resources remain.
d) The following calculation is performed only for Resources that have a Locational
Imbalance Price less than the Locational Imbalance Price for the associated Load
Settlement Location. A Market Participant’s Over-Scheduling Charge, for each Resource
identified under Section 11.4.2.2(c) as being required to match that Market Participant’s
Load Imbalance Energy, shall be calculated as follows:
Resource Over-Scheduling Charge = (LLIP-RLIP) * Resource Imbalance Energy,
where
RLIP = Locational Imbalance Price of the Resource Settlement Location,
LLIP = Locational Imbalance Price of the associated Load Settlement Location,
Resource Imbalance Energy = the amount of that Resource’s Imbalance Energy required
to offset the Market Participant’s Load Imbalance Energy as calculated under Section
11.4.2.2(c).
11.4.1.3 Market Monitor Review of Scheduling Practices
In order to monitor for other price arbitraging, if the Load of a Market Participant is missscheduled by more than 4% and the Market Participant’s aggregate Resource imbalance is less
than their Load miss-schedule while there is congestion, the Market Monitor will review the data
related to the miss-schedule.
In order to determine the frequency and significance of such market situations, the Market
Monitor is to identify over and under-scheduling relative to the Market Participant’s Reported
Load when congestion occurs, and to submit monthly reports to the Federal Energy Regulatory
Commission for one year after market start-up on the benefits gained by those Market
Participants, the charges made to Market Participants for over or under-scheduling, and any other
issue the Market Monitor deems relevant to over and under-scheduling. As a component of this
reporting, the Market Monitor is to evaluate, and recommend if needed, changes to the Market
Protocols to address any significant issues presented by this ongoing review.
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11.4.1.4 Market Monitor Review of Scheduling Relative to Uninstructed Deviation
In addition to Imbalance Energy that results from the difference between schedules and system
dispatch, Imbalance Energy can be created when Market Participants deviate from SPP
deployment instructions. The Market Monitor is to determine if any Resources appear to utilize
Uninstructed Deviations in order to profit from price differences resulting from congestion, and
to report on the results on a monthly basis.
11.4.1.5 Miscellaneous Adjustment Charge Types
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 appropriate
final or resettlement statement for the operating day in question. A miscellaneous charge type
will be utilized for each distinct charge type as follows:








Energy Imbalance Charge Amount - Adjustment
Uninstructed Deviation Charge Amount - Adjustment
Over Scheduling Charge Amount - Adjustment
Under Scheduling Charge Amount - Adjustment
Revenue Neutrality Uplift Charge Amount - Adjustment
Self-Provided Loss Charge Amount - Adjustment
Financially-Settled Loss Charge Amount - Adjustment
Miscellaneous Charge Amount
SPP will post supporting documentation for manual calculation of any miscellaneous charge to
the Portal no later than the time the settlement statement including the miscellaneous charge has
been posted.
11.4.3 Revenue Neutrality Uplift Procedure
SPP will remain revenue neutral for each hour of the settlement process. When this revenue
neutrality is breached and the cause cannot be determined or the benefit/cost of pinpointing
causation is not worth the magnitude of the event, SPP will apply an Uplift procedure. The uplift
and its application will be based on all participants’ absolute megawatt-hours in the hourly
market in the same time frame where the cause for uplift occurred. That is, all megawatt-hours
generated, purchased, and interchanged coincident in the hour(s) in which revenue neutrality was
breached will hold a responsibility for that uplift. The calculation of the amount to be uplifted
excludes explicit charges and credits related to congestion charges. Uplift will be assigned to
appropriate entities as illustrated below:
SPP Uplift = Total SPP receivables netted against total SPP payables for an operating
hour
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Settlement Location Allocation Factor = ABS (metered actual) +
 ABS (schedules to or from outside the SPP footprint)
Settlement Location Uplift = SPP Uplift *
(Settlement Location Allocation Factor /  All Settlement Location Allocation Factors)
Legend:
A
B
C
D
E
F
G
H
I
J
Net Schedules for this Settlement Location. This value from RTO Scheduling System.
Reported Metered Interchange for Settlement Location. This value from Metering Agent(s) Reporting.
B - A = Imbalance for Settlement Location
C * LIP ($10 for this example) = SL Imbalance Charge
Schedules to/from the SL with Non-SWPP Locations. This value from RTO Scheduling System.
Absolute value of B + Absolute value of E
Energy Imbalance Percentage = Column F's (Absolute for the SL / Sum of SL Absolutes)
G * D (Net SPP Revenue Imbalance)
D - H = SL Imbalance $ less SPP SL Uplifted $
Rounding Error is applied to the Largest Absolute (Col I) 100%. This is the final dollars to be transacted for each
Settlement Location from this hour.
Examples of SPP Revenue Neutrality Uplift Applied:
The assignment of the RNU amount to the appropriate Settlement Location will result in a
residual amount settled every hour as a result of rounding inputs at various stages in each
calculation. The residual amount is assigned to the Settlement Location with the largest
Settlement Location allocation factor for the settlement interval. The amount will be applied to
the charge type of Revenue Neutrality Uplift Charge – Adjustment. No other supporting detail is
required for use of this type of Adjustment charge.
SPP Revenue Neutrality Uplift Process
$10
Locational Imbalance Price (LIP) =
The SPP Revenues are balanced HOURLY with all Market Participants
Example of a single hour when SPP will over-collect revenues and how the Revenue Neutrality Uplift is applied.
HOUR 1
Settlement Location 1
Settlement Location 2
Settlement Location 3
Settlement Location 4
Settlement Location 4
Settlement Location 5
Settlement Location 6
Settlement Location 7
Settlement Location 8
Settlement Location 9
Settlement Location 10
SL
Scheduled
MWh
SL Actual
MWh
SL
SL
SL
Imbalance
Imbalance in
NON - SPP
in $
MWh
Schedules
(SPP Pays)
160.000
(100.000)
170.000
0.000
0.000
20.000
300.000
(600.000)
(200.000)
100.000
150.000
150.000
(110.000)
175.000
0.000
0.000
25.000
300.000
(450.000)
(210.000)
130.000
180.000
(10.000)
(10.000)
5.000
0.000
0.000
5.000
0.000
150.000
(10.000)
30.000
30.000
($100.00)
($100.00)
$50.00
$0.00
$0.00
$50.00
$0.00
$1,500.00
($100.00)
$300.00
$300.00
900.000
900.000
A
960.000
770.000
190.000
B
220.000
30.000
190.000
C
$2,200.00
$300.00
$1,900.00
D
10
(15)
20
0
(5)
(10)
0
0
0
0
0
Sum of All SLs
Sum SPP credit (receive)
Sum SPP debits (pay)
Net SPP credit (debit)
E
SL
Uplift
Absolute
MWh
160.000
125.000
195.000
0.000
5.000
35.000
300.000
450.000
210.000
130.000
180.000
1790.000
SL
Energy
Imbalance
%
8.94%
6.98%
10.89%
0.00%
0.28%
1.96%
16.76%
25.14%
11.73%
7.26%
10.06%
100.00%
SL
Energy
Imbalance $
$169.84
$132.68
$206.99
$0.00
$5.30
$37.15
$318.44
$477.66
$222.91
$138.00
$191.06
$1,900.03
Over-collections to be Uplifted
F
G
H
SPP Uplift $
(SPP Pays)
($269.84)
($232.68)
($156.99)
$0.00
($5.30)
$12.85
($318.44)
$1,022.34
($322.91)
$162.00
$108.94
Rounding Error
($0.03)
I
SPP shall post on its website on a monthly basis, by operating hour, the net uplift and the net of
each of the following charges types for that hour: (1) all energy imbalance service credits and
charges; (2) all uninstructed deviation charges; (3) all over scheduling charges; (4) all under
scheduling charges; and (5) by charge type, the net of any other credits or charges not
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encompassed within (1) through (4). Information for a month shall be posted no later than the
15th day of the succeeding month and shall be posted in a programmatic interface format.
11.5 Settlement Statement Process
11.5.1 Daily Settlement Statement
The settlement statement(s) will be made available for each Operating Day and will be published
for statement recipients electronically through the Portal on Business Days. The statement
recipient 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
and schedule information. An Initial and Final Statement will be created for each Operating Day.
Resettlement Statements can be created for any given Operating Day having met the disputefiling deadline and prior to twelve months elapsed time from the Operating Day. When actual
validated data and schedule information are available and all of the settlement and billing
disputes raised by Statement Recipients during the validation process have been resolved, SPP
shall recalculate the amounts payable and receivable by the affected Statement Recipient.
For each Market Participant, Settlement Statement(s) will denote:
 Operating Day,
 Statement Recipient’s name,
 Market Participant identifier,
 Type of charge (Initial, Final or Resettlement),
 Statement version number,
 Unique Statement identification code, and
 Market services settled.
Settlement Statements will include imbalance charges by the appropriate Settlement Interval and
Settlement Location.
11.5.2 Settlement Statement Access
Market Participants 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.
11.5.3 Settlement Statement Data
Settlement data used to prepare each Settlement Statement will include any available:
a)
b)
c)
d)
Actual interval and profiled consumption data for Market Participants by specific node;
Actual interval generation data for generation by specific node;
Net tie-line metering for each Settlement Area;
Resource schedules;
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e)
f)
g)
h)
i)
Load schedules;
Uplift charges.
LIP for each Settlement Interval;
Adjustments from approved disputes or errors in data components;
Tariff billing system inputs not otherwise contemplated above
11.6 Type of Settlement Statements
11.6.1 Initial Settlement Statements
SPP will use settlement data to produce the initial statements for each Market Participant for the
given Operating Day. Initial statements will be created at the end of the seventh (7th) calendar
day following the Operating Day. If the seventh (7th) day is not a Business Day, the initial
statement is issued no later than the next Business Day thereafter.
11.6.2 Final Settlement Statements
SPP will use settlement data to produce the final statements for each Market Participant for the
given Operating Day. Final statements will be created at the end of the forty-seventh (47th)
calendar day following the Operating Day. If the forty-seventh (47th) day is not a Business Day,
the final statement is issued on the next Business Day thereafter.
The final statement will reflect changes to settlement charges generated on the Operating Day’s
initial Settlement Statement.
11.6.3 Resettlement Statements
A resettlement 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. Resettlement statements 1
through 11 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 statement is issued on
the next Business Day thereafter.
Resettlement 1
Resettlement 2
Resettlement 3
Resettlement 4
Resettlement 5
Resettlement 6
Resettlement 7
Resettlement 8
Resettlement 9
Resettlement 10
Resettlement 11
Resettlement 12
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77 days after operating day
107 days after operating day
137 days after operating day
167 days after operating day
197 days after operating day
227 days after operating day
257 days after operating day
287 days after operating day
317 days after operating day
Ad Hoc
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Any settlement and billing dispute of initial statements resolved in accordance with Dispute
Resolution process of the Tariff will be corrected on the final statement for the Operating Day. In
the event that the final statement does not resolve a dispute from an initial statement for a given
Operating Day, SPP will resolve the dispute on a Resettlement Statement for that Operating Day.
Only Disputes for which the RTO is notified by the end of the time period for Dispute
Notification will be considered for Resettlement.
Any dispute of Initial and Final Statements resolved subsequent to the Final Statement, in
accordance with the Dispute Resolution process of the Tariff, will be corrected on the next
available invoice after the R2 Resettlement Statement run has been executed.
Any dispute resolved subsequent to the R2 Resettlement Statement, in accordance with the
Dispute Resolution process of the Tariff, will be corrected on the next available invoice after the
R4 Resettlement Statement run has been executed.
Resettlement 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 Statements R5 to R9 will
only be used to resolve Disputes of previous Resettlements, which are limited to incremental
changes. Resettlement 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.
Notice of Resettlement - SPP shall post a Resettlement Schedule through the Portal indicating
that a specific Operating Day will be resettled and the date the Resettlement Statement will be
issued by SPP.
11.6.4 Settlement Timeline
SPP shall create Settlement Statements daily for each Market Participant, detailing each Market
Participants cost responsibility. Settlement Statements are published through the Portal on each
business day. SPP shall prepare an invoice each billing cycle for each Market Participant
showing the net amount to be paid or received by the Market Participant. In order to issue a
settlement statement, SPP may use estimated, disputed or calculated meter data and schedule
information. Settlement Statements 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 to search for settlement statements by
issuance date, operating date, and invoice date.
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Settlements Timeline
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
The following example applies to all Thursday through Sunday holidays and similar logic will
apply to other 4 day holiday weekend scenarios:
Holiday Settlement Timeline Example
(4-day holiday)
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Sunday
Nov 14
Nov 21
Monday
Nov 15
Tuesday
Nov 16
Wednesday Thursday
Friday
Nov 17
Nov 18
Nov 19
Saturday
Nov 20
MD (11/11)
MD (11/12)
MD (11/13)
MD (11/14)
MD (11/15)
MD (11/16)
MD (11/17)
Nov 22
Nov 23
Nov 24
Nov 25
Nov 26
Nov 27
MD (11/18)
MD (11/19)
MD (11/20)*
MD (11/21)
MD (11/22)
Holiday
Holiday
Holiday
ISS (11/17)
ISS (11/18)
ISS (11/19)
Nov 28
Nov 29
Nov 30
Holiday
MD (11/23)
MD (11/24) *
MD (11/25)
MD (11/26)
ISS (11/20)
ISS (11/21)
ISS (11/22)
ISS (11/23)
Meter Data (MD) due by Noon on days indicated.
* Meter Data due by 3:00pm instead of normal noon deadline.
Initial Settlement Statement (ISS)
11.7 Invoice
SPP prepares weekly invoices from Settlements Statements. 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 protocol 10.8.2 Holiday Invoice
Calendar for exceptions). The Market Participant is responsible for accessing the 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
credit balance will receive the balance shown on the Invoice, adjusted for balances not collected
from Market Participants with net debit balances.
11.8 Timing and Content of Invoice
SPP will electronically post for each Invoice Recipient, an Invoice based on any Initial
Statements, Final Statements, and Resettlement Statements produced since the prior Settlement
Invoice. SPP shall post the Settlement Invoices to the Invoice Recipient in accordance with the
Settlement Calendar. The Invoice Recipient is responsible for accessing the information from the
Portal once posted by SPP.
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Invoices will be issued on a weekly basis as defined in the Settlement Calendar. 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:
a) Customer ID – the name, address and contact information for the customer being
invoiced
b) Net Amount Due/Payable – the aggregate summary of all charges owed or due by a
Market Participant summarized by Settlement Statement ID and Operating Date and
Settlement Date, both being identified by calendar date;
c) Amount Due/Payable by Charge Type, Operating Date and Settlement Date — the
aggregate of charges within each charge type owed or due by a Market Participant, listed
by Operating Day which shall be identified by calendar date;
d) Time Periods – the time period covered for each settlement statement run date identified
by a range of calendar dates;
e) Run Date – the date in which the invoice was created and published;
f) Invoice Reference Number – a unique number generated by the SPP applications for
payment tracking purposes;
g) Settlement Statement ID– an identification code used to reference each Settlement
Statement invoiced;
h) Payment Date and Time – the date and time that invoice amounts are to be paid or
received;
i) 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
Invoice Recipient are to be paid or of the Invoice Recipient’s account to which SPP shall
draw payments due;
j) Overdue Terms – the terms that would be applied if payments were received late;
k) Late fees; and
l) 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.
11.8.1 Invoice Calendar
Weekly invoices will be distributed every Thursday by no later than 8:00 a.m. CPT with the
exceptions described in the Holiday Invoice Calendar. Weekly invoices will include the seven
daily settlement statements (Initial, Final & Resettlements) produced for the previous
Wednesday through Tuesday cycle. Customer balances owed to SPP are due by 5:00 p.m. (CPT)
of the first Wednesday following the Thursday invoice date. Balances owed by SPP to
customers will be paid on the second Friday following the invoice date by 5:00 p.m. (CPT).
11.8.2 Holiday Invoice Calendar
The SPP invoice calendar will be posted annually on the SPP Portal. The Thursday invoice date
and the following Wednesday and Friday payment dates as described in Section 10.8.1 will be
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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 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):
Holiday
Invoice Date
Mon-Tue
Tue-Wed
Wed-Thu
Thu-Fri
Fri-Mon
Previous Thu
Following Mon
Following Mon
Following Mon
Normal Sched
Customer Pmt
Due Date
Fri
Fri
Fri
Fri
Fri
SPP Pmt Due
Date
Tue
Tue
Tue
Tue
Tue
11.9 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 Contents of Notice dispute form. See
Attachment AE Section 6.3(a) of SPP OATT for minimum content of a notice of dispute.
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11.9.1 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 Final
Settlement Statement for that Operating Day is issued. In the case of Resettlement 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 Statement or between
issuance of Resettlement Statements. A dispute relating to a Resettlement Statement must be
filed within 14 calendar days of issuance of the Resettlement Statement.
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.
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11.9.2 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. SPP shall make reasonable attempts to remedy any
informational deficiencies by working with the Market Participant(s).
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 thirty 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”.
SPP will issue a settlement and billing dispute resolution report containing information related to
the disposition of the dispute.
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 process.
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 through research 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.
Statement or Invoice Recipients 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.
11.9.2.1 Dispute Status
Each dispute will have a status as defined in the following paragraphs. Valid status designation
includes:
a) Open,
b) Denied,
c) Closed,
d) Granted, or
e) Granted with Exceptions.
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OPEN & CLOSED: A Dispute will be deemed “Open” when submitted in a timely and
complete manner. “Closed” is the final status for all Disputes.
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”.
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”.
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.
11.10 Invoice Payment Process
11.10.1
Overview of Payment Process
Payments shall be made in a two-step process where:
a) All Settlement Invoices due with net debits owed by Market Participant are paid by 5p.m.
(CPT) of the first Wednesday following the Thursday invoice date, and
b) All Settlement Invoices due with net credits owed to Market Participant are paid by 5p.m.
(CPT) of the second Friday following the invoice date
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Payments due to SPP and payments due to Market Participant will be made by Electronic Funds
Transfer (EFT) in U.S. Dollars.
11.10.2
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 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
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.
11.10.3
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 5p.m. (CPT) the
next day. Once each payout report has been finalized, they will be posted to the portal by 3p.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 Customer Relations Department on Thursday afternoon by 3p.m (CPT) should
Market Participants have any questions regarding the payout amounts posted to the Portal.
11.11 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 substitute
the following acceptable values.
11.11.1
Tolerance Levels and Substitution Criteria
SCADA - 5 minute interval value
High Tolerance Band - Greater than 120% of the Resource Plan MaxEmerMW
Substitution value – Dispatch Instructions (results in zero URD)
Low Tolerance Band – Less than Minimum Operating Capacity
Substitution value – Dispatch Instructions (results in zero URD)
Dispatch Instruction - 5 minute interval value
High Tolerance Band - Greater than 120% of the Resource Plan MaxEmerMW
Substitution value – Use SCADA value (results in zero URD)
Low Tolerance Band – Less than Zero
Substitution value – Use SCADA value (results in zero URD)
Resource Meter Data
High Tolerance Band - Trigger value supplied by meter agent/Market Participant
Substitution value – Schedule value
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Low Tolerance Band – Auxiliary negative value supplied by meter agent/Market Participant
Substitution value – Schedule value
Load Meter Data
High Tolerance Band - 150% of previous year annual peak
Substitution value – Schedule value
Low Tolerance Band – Zero value
Substitution value – Schedule value
Interchange Meter Data
High Tolerance Band - Trigger value supplied by meter agent/Market Participant
Substitution value – NSI
Low Tolerance Band – Trigger value supplied by meter agent/Market Participant
Substitution value – NSI
12 Registration
12.1 Introduction
All Loads and all Resources excluding Behind the Meter Generation less than 10 MW, must
register. Each Market Participant is required to execute the service agreement specified in Tariff
Attachment AH. Registration identifies each Load and/or Resource to Settlement Locations,
entity submitting settlement meter data, and settlement responsibilities.
A Market Participant may appoint a Designated Agent to perform its functions under these
protocols.
12.2 Content
Assets are the registered Loads and Resources at a Settlement Location and have a designated
Meter Agent. Market Participants have the legal relationship with SPP. The Market Participants
may participate in the market as any combination of Resource entities, Load serving entities,
Meter Agents, and/or power marketers.
The Market Participant is also responsible for
insuring that the Balancing Authority also receives Settlement Location Data from the Meter
Agent in a suitable electronic format.
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Illustration of Settlement Locations
12.2.1 Registration of Generation Resources and Loads Acting as Resources
Any MP operating Resources within SPP must register with SPP. To register a Resource, an
applicant must submit a Registration Package (Appendix A) 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
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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.
12.2.1.1 Responsibilities of the Resource
Each MP shall be responsible for conducting its operations in accordance with all applicable SPP
market rules and guidelines. Each MP shall supply operating characteristics of its Resource,
including, but not limited to: Capability, Ramp rate, Location of physical Resource, Legal
owner. To the extent that Resources are energy limited and/or intermittent it is the responsibility
of the MP to ensure that their Resource Plan reflects the proper availability. Registration shall
also include the Settlement Location and Settlement Area of the Resource. The MP is
responsible for ensuring that real-time settlement meter data is submitted to SPP.
12.2.4.2 Load Acting as a Resource
A MP providing EIS using Load as a Resource must provide a real time signal representing the
real power interrupted in response to the deployment of EIS.
12.2.1.3 Energy Production Prior to Completion of Market Registration
Market Participants will be allowed to generate energy prior to the effective date of a submitted
market registration packet under the following conditions:






The MP, 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.
If real-time data is not being provided via telemetry to SPP Reliability Coordinator (RC)
and the host BA, the MP or its agent shall provide to them hourly updates of current
output and expected output for each 5-minute interval of the upcoming hour. The actual
5 minute output for the previous hour shall also be provided.
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
RC.
Appropriate arrangements have been made for delivery of energy.
Energy shall be limited to a maximum of 10 MW, or a greater amount agreed to by the
SPP RC, interconnect TO and any MP with EIS energy that will be affected.
Energy generated under these provisions will not be recognized as EIS energy in the SPP
EIS settlement and SPP will not be responsible for making any compensation to the
generation owner or any Market Participant for the energy produced.
12.2.2 Registration of Load
Any MP with Load within SPP must register with SPP. To register Load, an applicant must
submit a Registration Package (Appendix A) 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
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Settlement Location or multiple Meter Locations. Load aggregation is within a Settlement Area.
Load may not be aggregated across Settlement Areas.
12.2.2.1 Responsibilities of the Load
Each MP shall be responsible for conducting its operations in accordance with all applicable SPP
market rules and guidelines. The MP is responsible for ensuring that settlement meter data is
submitted to SPP.
12.2.3 Registration of Meter Agent
All Meter Agents (MA) providing meter data under SPP tariff must register with SPP
(Registration Package – Appendix A). 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 the Balancing Authority also receives Settlement Location Data
from the Meter Agent in a suitable electronic format.
12.2.4 Registration of a Joint Owned Unit
In the SPP EIS Market there are two options for handling the registration of Joint Owned Units
(JOU’s).
1. Owners of a JOU may agree to register the unit on their own as separate Resource
settlement locations.
2. One owner can take responsibility for registering the unit’s settlement location.
Additionally, in either case, an owner may choose to have a Designated Agent represent the unit
in the market.
Each owner choosing to register the JOU as a settlement location will be able to submit offers for
the unit in to the SPP EIS market. The registration of an ownership share as a separate
Settlement Location results in the JOU being treated as any other Resource, meeting the
requirements for Resource Plans, Ancillary Service Plans, Scheduling, and metering.
For JOUs, there can only be one designated Meter Agent and each Market Participant must
designate the same Meter Agent. The default presumption is that the operating owner’s Meter
Agent will be the Meter Agent for that JOU unless there is unanimous agreement and registration
of a different Meter Agent.
If only one owner registers the entire unit, that owner will be the only party allowed to submit
offers for that Resource, and responsible for all the requirements associated with a Resource, and
will be solely financially responsible for EIS charges.
The operating owner must include in its settlement location any ownership by non-market
participants (i.e., those not under the SPP tariff).
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12.2.5 Registration of an External Resource
External Resources wishing to participate in the SPP Energy Market will pseudo-tie into an SPP
market Balancing Authority (BA) utilizing the SPP OATT Attachment AO or equivalent
agreement approved by the SPP. In addition to the responsibilities outlined in the Attachment
AO agreement, the External Resource will be responsible for registering and performing all
responsibilities that are required of any other Resource in the SPP Market.
12.3 Timing and Submission
*General Notes 1. The "Lead Time" 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 Models, systems, and/or databases such that the
change is effective in the Production (PROD) environment. The times in the table below indicate the lead time SPP
requires for the complete submission of new registration or updated information.
2. SPP will update the Models on the 1st day of each month for all changes effective that month.
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System Update Type
(Business Event)
New Market Registration
Transmission Customer
* Lead Time
45 Days / 2 months
Market Participant
6 Months
Designated Agent
45 days / 4 Months
* Comments
OASIS Change only if TC not a Market
Participant. Access to OASIS is part of
Process for Becoming a TC.
A minimum of 6 Months for this addition,
which is presumed to inlcude adding all
associated assets. (Especially if addition
involves changes to Market Boundary.)
Include in Applicable scheduled periodic
Model Update.
45 days if DA is current SPP TC.
4
months if a new DA that is not currently a
SPP TC or MP.
Asset Owner Information
Generation Company (GENCO)
4 Months
Load Serving Entity (LSE)
4 Months
Metering Agent (MA)
45 days / 4 Months
4 Months for this addition. (This for an
addition to a current MP.). Include in
Applicable scheduled periodic Model
Update.
A minimum of 4 Months for this addition.
Include in Applicable scheduled periodic
Model Update.
45 days if MA is current SPP TC.
4
months if a new MA that is not currently a
SPP TC or MP.
Asset Information
Settlement Location
45 Days / 4 months
Plant
Unit
Load
Load Pricing Zones
45 Days
45 Days
45 Days
45 Days
Settlement Area
4 Months / 6 Months
/ 4 months
/ 4 months
/ 4 months
/ 4 months
NERC Source (Via Trans Table)
2 weeks
NERC Sink (Via Trans Table)
2 Weeks
External Generator
4 Months / 6 Months
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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.)
(Same as note above.)
(Same as note above.)
4 months if SA is in a current SPP BA.
6 months if a SA is a new BA/CA 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.)
4 Months if change involves current MP.
6 Months (minimum) if change involves a
new Market Participant.
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Market Registration Changes
Contact Information Changes
2 weeks
Information is updated in COS and
forwarded to billing and credit.
Market Footprint Changes
Move Footprint BA/SA to 1st Tier
6 Months
Move 1st Tier BA/SA to Footprint
6 Months
Acquisition of one BA/SA by another BA/SA
4 Months / 6 Months
Merger of BAs/SAs
Name Changes
4 Months / 6 Months
Transmission Customer (Long Name)
45 Days
Transmission Customer (NERC ID)
45 Days
Market Participant
4 Months / 6 Months
Designated Agent
45 Days
Asset Owner Changes
Generation Company (GENCO)
Load Serving Entity (LSE)
Metering Agent (MA)
Asset Information Changes
4 Months
4 Months
4 Months
Settlement Location
45 Days / 4 months
Plant
Unit
Load
Load Pricing Zones
45 Days
45 Days
45 Days
45 Days
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/ 4 months
/ 4 months
/ 4 months
/ 4 months
02/24/2010
Implement in applicable scheduled
seasonal/periodic update.
Implement in applicable scheduled
seasonal/periodic update.
4 months if both BAs/SAs are in Market
footprint.
6
months if one BA/SA is outside.
(Same as note above.)
Name change only - TC must submit new
service agreements in new name.
(Process should be shortened and
improved for this task.)
(Same as note above.)
4 Months for typical scope changes.
6 Months (minimum) if involves changes to
Market Boundary and/or changes to all
associated assets.
45 Days - DA change of responsibility for
MP's Assets. (DA is a SPP TC.)
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
45 Days for limited scope changes.
Months for Moderate to large scope
changes.
(Same as note above.)
(Same as note above.)
(Same as note above.)
(Same as note above.)
4
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Settlement Area
4 Months / 6 Months
External Generator Changes
45 Days / 4 months
4 Months for limited scope changes.
6
Months for Moderate to large scope
changes. (Typically a Settlement Area will
not change unless the NERC ID changes
or there is a major Control Area
consolidation event.)
45 Days for limited scope changes.
4 Months for Moderate to large scope
changes. (Involves existing MP.)
Commercial Model Relationship Changes
Market Participant / Transmission Customer
Asset / Market Participant (GENCO / LSE)
45 Days / 4 months
45 Days / 4 months
45 Days for limited scope changes.
4
Months for Moderate to large scope
changes. (Typically this change would
occur when an MP to TC change occurs.)
45 Days for limited scope changes.
4
Months for Moderate to large scope
changes. (Typically this change would
occur when an MP to TC change occurs.)
45 Days for limited scope changes.
4
Months for Moderate to large scope
45 Days / 4 months
Settlement Location / Settlement Area
changes. (Very rare change, this should
only occur if a Settlement Area change
takes place.)
45 Days for limited scope changes.
4
Months for Moderate to large scope
changes. (Must register Meter Agent if
Settlement Location / Metering Agent
45 Days / 4 months
relationship change is not to existing Meter
Agent.)
Settlement Area / Metering Agent
45 Days / 4 months
(Same as note above.)
These changes must occur "as needed"
On the fly - 1 week at COS; TSIN Registry updates are
most. Due to scheduling, downloaded daily and need to be
NERC Source/Sink / Settlement Location
MP needs to be notified incorporated into WebData as soon as
when active.
possible. NERC to Siebel runs nightly.
Siebel to Webdata only runs weekly.
Implement in applicable periodic update.
De-aggregating a Plant to Individual Units
45 Days
Implement in applicable periodic update.
Aggregating Individual Units to a Plant
45 Days
Implement in applicable periodic update.
Breaking out an Individual Unit from a Plant
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 re-map units to Market
45 Days
IDC Mapping Changes
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)
Include in scheduled and coordinated
rolling type updates. (This type change
2 weeks
NERC Source/Sink Mapping Changes
may need to be implemented prior to the
next scheduled periodic Model Update.)
2 weeks
(Same as note above.)
DNR Designation Changes
Implement in applicable periodic update.
45 Days
Certification Changes
This change will impact EMS, MOS, RSS,
and NLS information (RTO_SS). (This
1 Week
type change may need to be implemented
Resource Reasonable Limit MW Value Changes
prior to the next scheduled periodic Model
Update.)
Implement in applicable periodic update.
45 Days
Load Pricing Zone Changes
45 Days for intra-CA/SA changes.
45 Days / 4 months
4 Months for Changes involving 2 or more
Individual Loads to Load Aggregate Changes
CAs/SAs
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Market Termination Request
Transmission Customer
Market Participant
Designated Agent
Asset Owner
Generation Company (GENCO)
Load Serving Entity
(LSE)
Metering Agent (MA)
Asset Information
Settlement Location
1 week for OASIS Change only if TC not a
Market Participant.
4
1 Week (Minimum) / 4
Months if TC is MP (TC may have
Months
outstanding requests, can not terminate
until end of contract.)
Implement in applicable periodic update.
4 months
45 Days - DA change of responsibility for
45 Days
MP's Assets. (DA is a SPP TC.)
4 months
4 months
4 months
45 Days / 4 months
Plant
Unit
Load Pricing Zone
Settlement Area
45 Days / 4 months
45 Days / 4 months
45 Days / 4 months
4 months
1st Tier CA/External Aggregate
45 Days / 4 months
NERC Source (via Translation Table)
2 Weeks
NERC Sink (via Translation Table)
2 Weeks
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Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
45 Days for limited scope changes.
4
Months for Moderate to large scope
changes. (Include in applicable periodic
Update)
(Same as note above.)
(Same as note above.)
(Same as note above.)
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.)
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Add EMS
NETMOM/GENMOM/SCADAMOM
Equipment
In Market Footprint
Control Area/EMS Company
4 months / 6 Months
Units
Loads
Other Equipment
ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC,
LS
In 1st Tier Entity
45 Days / 4 months
45 Days / 4 months
4 Months for limited scope changes.
6
Months for Moderate to large scope
changes. This change will also impact
COS, MOS, and other models. (Include in
applicable periodic Update)
(Same as note above.)
(Same as note above.)
(Same as note above.)
45 Days / 4 months
Control Area/EMS Company
4 months / 6 Months
Loads
Other Equipment
ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC,
LS
Beyond 1st Tier
45 Days / 4 months
4 Months for limited scope changes.
6
Months for Moderate to large scope
changes. This change will also impact
COS, MOS, and other models. (Include in
applicable periodic Update)
(Same as note above.)
(Same as note above.)
45 Days / 4 months
45 Days / 4 months
(Same as note above.)
Modify EMS
NETMOM/GENMOM/SCADAMOM
Equipment
Changes - In Market Footprint
Control Area/EMS Company
45 Days / 4 months
Units
Loads
Other Equipment
ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC,
LS
In 1st Tier Entity
45 Days / 4 months
45 Days / 4 months
Control Area/EMS Company
45 Days / 4 months
Loads
Other Equipment
ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC,
LS
All Other Changes
45 Days / 4 months
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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.)
(Same as note above.)
45 Days / 4 months
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.)
45 Days / 4 months
45 Days / 4 months
02/24/2010
(Same as note above.)
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Remove EMS
NETMOM/GENMOM/SCADAMOM
Equipment
In Market Footprint
Control Area/EMS Company
45 Days / 4 months
Units
Loads
Other Equipment
ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC,
LS
In 1st Tier Entity
45 Days / 4 months
45 Days / 4 months
Control Area/EMS Company
45 Days / 4 months
Loads
Other Equipment
ND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC,
LS
Beyond 1st Tier
45 Days / 4 months
4
45 Days for limited scope changes.
Months for Moderate to large scope
changes. (Include in periodic Update)
(Same as note above.)
(Same as note above.)
(Same as note above.)
45 Days / 4 months
4
45 Days for limited scope changes.
Months for Moderate to large scope
changes. (Include in periodic Update)
(Same as note above.)
(Same as note above.)
45 Days / 4 months
45 Days / 4 months
(Same as note above.)
Add EMS Contingency
In Market Footprint
2 weeks
In 1st Tier Entity
Beyond 1st Tier
2 weeks
2 weeks
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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.)
(Same as note above.)
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Market Protocols
Remove EMS Contingency
In Market Footprint
2 weeks
In 1st Tier Entity
Beyond 1st Tier
2 weeks
2 weeks
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.)
(Same as note above.)
AFC
Coordinated
Reciprocal
Temporary
45 Days
45 Days
45 Days
On the fly.
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement this type change as needed.
Coordinated
Reciprocal
45 Days
45 Days
Implement in applicable periodic update.
Implement in applicable periodic update.
AFC
Coordinated
Reciprocal
Temporary
45 Days
45 Days
45 Days
On the fly.
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement this type change as needed.
Coordinated
Reciprocal
45 Days
45 Days
Implement in applicable periodic update.
Implement in applicable periodic update.
AFC
Coordinated
Reciprocal
Temporary
45 Days
45 Days
45 Days
On the fly.
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
(Planned Function)
Coordinated
Reciprocal
45 Days
45 Days
Implement in applicable periodic update.
Implement in applicable periodic update.
Add New Flowgate
In SPP Region
In Other Regions
Modify Flowgate Data
Changes - In SPP Region
Changes - In Other Regions
Remove Flowgate
In SPP Region
In Other Regions
Define New ICCP Inbound
In Market Footprint
1 Week / 4 Months
In Reliability Area
1 Week /
1 Week /
1 Week /
1 Week /
PNODE
EMS Equipment or Station Name
IDC Bus or Machine ID
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4 Months
4 Months
4 Months
4 Months
02/24/2010
1 Week for basic ICCP/Scada Ref.
additions.
4
Months for Generation and load related
changes
(Same as note above.)
(Same as note above.)
(Same as note above.)
(Same as note above.)
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Market Protocols
Change ICCP Inbound
In Market Footprint
4 Months
In Reliability Area
4 Months
4 Months
4 Months
4 Months
PNODE
EMS Equipment or Station Name
IDC Bus or Machine ID
4 Months for Generation and load related
changes.
(Same as note above.)
(Same as note above.)
(Same as note above.)
(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.
Define New ICCP Outbound points
In Market Footprint
4 Months
In Reliability Area
4 Months
4 Months
4 Months
4 Months
PNODE
EMS Equipment or Station Name
IDC Bus or Machine ID
4 Months for Generation and load related
changes.
(Same as note above.)
(Same as note above.)
(Same as note above.)
(Same as note above.)
Change ICCP Outbound points
In Market Footprint
4 Months
In Reliability Area
4 Months
4 Months
4 Months
4 Months
PNODE
EMS Equipment or Station Name
IDC Bus or Machine ID
4 Months for Generation and load related
changes.
(Same as note above.)
(Same as note above.)
(Same as note above.)
(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.
4 Months
4 Months
4 Months
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
4 Months
4 Months
4 Months
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
4 Months
4 Months
4 Months
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
4 Months
4 Months
4 Months
Implement in applicable periodic update.
Implement in applicable periodic update.
Implement in applicable periodic update.
Add PLC Points
In Market Footprint
Plant
Unit
Other
In Reliability Area
Plant
Unit
Other
Change PLC Points
In Market Footprint
Plant
Unit
Other
In Reliability Area
Plant
Unit
Other
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IDC Model Change
IDC Bus Name or Machine ID Change
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 re-map 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)
RSS
Add New Resources
Change Resource Information
Delete Resource Information
1 Week
1 Week
1 Week
Change to RSS Model only. (This type
change may need to be implemented prior
to the next scheduled periodic Model
Update.)
(Same as note above.)
(Same as note above.)
1 Week
1 Week
1 Week
Change to NLS Model only. (This type
change may need to be implemented prior
to the next scheduled periodic Model
Update.)
(Same as note above.)
(Same as note above.)
NLS
Add New Resources
Change Resource Information
Delete Resource Information
12.4 Model Update Timeline
The following table is the Model Update Timeline. Market Registration related model changes
take place Bi-Monthly.
Production Model
Upload date
January 1st
February 1st
March 1st
April 1st
May 1st
June 1st
July 1st
August 1st
September 1st
October 1st
November 1st
December 1st
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Reliability-related model
changes
X
X
X
X
X
X
X
X
X
X
X
X
02/24/2010
Market Registration related
model changes
X
X
X
X
X
X
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12.5 Use of Data
Registration data is used for operation and settlement of the EIS market, identifying
responsibilities and identifying discrete entities. The registration data is also used in the
interaction of Customer Relations personnel with MP’s.
13 Outage Handling and Error Handling
13.1 Real Time System Outages
Outages in the real-time market systems can result in an inability to communicate deployment
instructions to participants as well as a potential loss of real-time pricing data used in
settlements. The following principles guide the policies for how to handle real-time system
outages:
1. Maintain reliability of the transmission system.
2. Financial settlement continues.
3. Pricing will provide incentive for scheduling of Load and Resources to minimize
imbalance.
In the event of a system outage or loss of critical system data, SPP will notify affected
participants to no longer participate in imbalance energy deployments. Upon receiving such
notification, participants should bring their affected Resources to scheduled levels over the next
30 minutes, except to the extent such Resources are used to provide regulation service. The
affected host control areas will also be notified.
In the event that a failure of SPP’s real-time market systems results in a loss of pricing
information, imbalance energy will continue to be settled financially under the Tariff. For each
transmission zone with missing data, each supplier of Regulation Service (under any OATT) for
that zone shall provide its Incremental Cost of providing such service within 24 hours of SPP’s
making request for such information. For each zone, the highest cost of energy produced or
procured for the supply of regulation service used in that zone will be substituted for missing
price data in that zone.
The following table details the appropriate actions that should be taken for several scenarios:
13.2 SPP Market Outage Scenarios
Actions
Scenario
Real-time
(Market/Reliability)
Settlements
1. Real-time market system
(MOS) is performing, with
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Actions
Real-time
(Market/Reliability)
Scenario
Settlements
a loss of state estimator data
a. Partial lost of state
estimator because of
SCADA.
1.
few buses (e.g.,
a single RTU
communication
circuit fails)
2. an entire
member’s data
Version 14.0a
The state estimator
will continue to solve. SPP
will have displays and
procedures whereby the
operators will observe MW
mismatch at adjacent buses.
As long as the mismatch is
minimal, the presumption
will be that the market can
continue operating on the
data.
If SPP is not
receiving telemetry then the
operator may override the
status of the unit to indicate
it is no longer under SPP
control (“self dispatch”).
None.
In all but extreme
cases, SPP’s state estimator
will continue to solve.
Operators can make
assumptions about what’s
going on in the control area
based on the mismatch of
the other side of tieline
measurements of the other
company, but cannot
observe Load changes what
individual units in the
company are doing.
SPP should notify
the affected participants that
None.
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Actions
Scenario
Real-time
(Market/Reliability)
their units should run at
scheduled levels except to
the extent that those units
are providing regulation
service.
SPP will work with
the effected area to provide
their NSI and energy
imbalance component. The
member can add the energy
imbalance deployment to
their RTO_SS NSI. As a
consequence, other market
participants will continue to
provide EIS service to the
effected area.
Settlements
2. MOS is performing, but the
state estimator and/or
SCADA has entirely failed
a. Less than 30
minutes
The market system
will continue to run with the
last-available state estimator
save case. That would mean
that Load and system
topology would remain
constant in the system. It is
expected that this would not
substantially impact the
solution for a period of time.
None.
b. 30 minutes or more
(or sooner if
reliability conditions
warrant)
Suspend imbalance
deployment and notify all
participants that they must
take necessary steps to either
self-provide imbalance or
make a third party, bilateral
arrangement.
Settlement data will
continue to be available.
Pricing information that
would otherwise come
from MOS will be
determined by the
production or procurement
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Actions
Scenario
Real-time
(Market/Reliability)
Market Deployment
should be ramped out over a
period, of time, ideally at
least 30 minutes.
Market Participants
are expected to minimize
Imbalance during this
period. Any remaining
imbalance will be tracked
after-the-fact and settled
financially.
Settlements
cost by suppliers of
Regulation Service for each
Zone in accordance with
the applicable provisions of
the Tariff.
3. MOS has failed
a. Up to twelve
consecutive 5minute Deployment
Intervals
Market deployments
and the associated energy
imbalance portion of NSI
will be frozen while
schedule NSI may continue
to change. Participants will
control generation in such a
manner as to minimize
control area ACE.
b. Over 12 consecutive
Suspend imbalance
5 minute
deployment and notify all
Deployment
participants that they must
Intervals(or sooner if take necessary steps to either
reliability conditions self-provide imbalance or
warrant)
make a third party, bilateral
arrangement.
Market Deployment
should be ramped out over a
period, ideally over at least
30 minutes.
Market Participants
are expected to minimize
Imbalance during this
period. Any remaining
imbalance will be tracked
after-the-fact and settled
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Settlement data will
continue to be available.
Pricing information that
would otherwise come
from MOS would be
duplicated from the last
known good interval for up
to one hour.
Settlement data will
continue to be available.
Pricing information that
would otherwise come
from MOS will be
determined by the
production or procurement
cost by suppliers of
Regulation Service for each
Zone in accordance with
the applicable provisions of
the Tariff.
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Market Protocols
Actions
Scenario
Real-time
(Market/Reliability)
financially.
Settlements
13.3 Procedures for Correcting LIPs Resulting From Market Software
and Data Input Errors
The SPP Staff, with the assistance of the MMU as appropriate, shall monitor for possible Market
Software and Data Input Errors by SPP in the SPP EIS Market. If Market Software and Data
Input Errors are identified, SPP shall impose corrective measures as specified below and take
immediate action to remedy such errors as soon as possible.
Market Software and Data Input Errors are a flaw in the design or implementation of software
and the data inputs for that software that result in LIPs that do not accurately reflect the
application of the Tariff.
Events that may result in Market Software and Data Input Errors include, but are not limited to:
o
o
o
o
o
o
Bad or missing SCADA
Load Forecast Error
Missing Schedules
Missing Intervals
Operator/Human Error
Delay in change of flowgate limit to support RSS Events
The occurrence of any of these events may warrant a revision to LIPs and are flagged by SPP.
SPP will investigate all such events and determine if a LIP revision is necessary.
13.3.1 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.
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13.3.2 Procedures for Revising LIPs in Response to Market Software and Data
Input Errors
13.3.1.1 Circumstances When SPP Shall Revise LIPs
SPP shall revise LIPs when they deviate from what would be produced absent an identified
Market Software and Data Input Error.
13.3.2.2 Notice to Market Participants and the Public
In any hour for which SPP reasonably believes that a Market Software and Data Input Error will
require correction of one or more LIPs, SPP shall post on its OASIS and website as soon as
reasonably practicable a notice that it is considering a correction for that hour. When SPP is
aware in advance that a price correction will be required for an hour, SPP will post a notice of a
proposed correction, and if possible a description of the proposed action, before bids are to be
submitted for such hour. If the circumstances do not permit advance notice, SPP shall post a
notice no later than 5:00 p.m. on the calendar day following the day in which the hour occurs for
which LIPs would be affected by the contemplated price correction.
Prior to making a price correction, if reasonably possible, SPP must post on its OASIS and
website a description of its proposed price correction. In any event, SPP must post a description
of the proposed price correction within five (5) calendar days after the date on which a notice of
a price correction is posted. If a description of the proposed price correction is not posted within
such period, the notice of proposed price correction shall be deemed to be withdrawn as to that
hour. If SPP determines that a price correction is not necessary, it shall withdraw the notice of
possible price correction from its OASIS and website as soon as reasonably practicable.
13.3.2.3 Price Corrections Identified After the End of the Notice Period
If SPP identifies a Market Software and Data Input Error requiring a price correction, 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 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
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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.
13.3.2.4 Process for Recalculating Prices
SPP shall recalculate LIPs in a manner that reflects, as closely as reasonably practicable, the
LIPs that would have resulted but for the Market Software and Data Input Error, and shall
substitute the recalculated LIPs for the prices that resulted from the Market Software and Data
Input Error. Such recalculated LIPs shall serve as the basis for Settlement. Such recalculated
LIPs shall be provided to Market Participants in the same manner as LIPs determined in the
ordinary course of business (i.e. in a programmatically downloadable file).
13.3.2.5 Compensatory Payments to Market Participants for a Decrease in LIP
If recalculated LIPs would result in a Market Participant being paid less than its offered price for
the actual output of a Resource as dispatched due to the Market Software and Data Input Error,
SPP will make a compensatory payment to the Market Participant to make up the difference
between the recalculated LIP and the offered price. Such compensatory payment shall be
uplifted to the EIS Market during settlement to ensure revenue neutrality for SPP.
Example 1: Price Adjusted Downward – Spot Energy Sale
Resource Offer = 100 MW @ $60/MWh
Schedule = 0 MW
Initial Settlement
Original LIP = $80
Actual Dispatch = 100 MW
Settlement
= LIP * (Scheduled Gen – Actual Gen)
= $80 * (0 MW – 100 MW)
= -$8,000 {RTO pays the Market Participant}
Recalculated LIP
Recalculated LIP = $30
Actual Dispatch = 100 MW
Settlement
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= LIP * (Scheduled Gen – Actual Gen)
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Market Protocols
= $30 * (0 MW – 100 MW)
= -$3,000 {RTO pays the Market Participant}
Additional Compensation for Incorrect LIP
Error Compensation = Actual Unscheduled Production * (Recalculated LIP Offer)
= 100 MW * ($30 - $60)
= -$3,000 {RTO pays the Market Participant}
Total Settlement
Total Settlement
= Recalculated LIP settlement + Error Compensation
= -$3,000 - $3,000
= -$6,000 {RTO pays the Market Participant}
End Result:
The final cost to the Market Participant is their cost of production ($6,000)
Example 2: Price Adjusted Downward – Scheduled and Offered
Resource
Resource Offer = 100 MW @ $60/MWh
Schedule = 100 MW
Initial Settlement
Original LIP = $80
Actual Dispatch = 100 MW
Settlement
= LIP * (Scheduled Gen – Actual Gen)
= $80 * (100 MW – 100 MW)
= $0
Recalculated LIP
Recalculated LIP = $30
Actual Dispatch = 100 MW
Settlement
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= LIP * (Scheduled Gen – Actual Gen)
= $30 * (100 MW – 100 MW)
= $0
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Market Protocols
Additional Compensation for Incorrect LIP
Error Compensation = Actual Unscheduled Production * (Recalculated LIP Offer)
= 0 MW * ($30 - $60)
= $0
Total Settlement
Total Settlement
= Recalculated LIP settlement + Error Compensation
= $0 + $0
= $0
End Result:
The final cost to the Market Participant is their cost of production ($6,000). However, note that
if the initial LIP had been correct, the Resource would not have been dispatched, and the Market
Participants cost would have been $3,000 (100MW * $30/Mwh). There will be no compensation
for this lost opportunity.
13.3.2.6 Make-Whole Payments to Market Participants for an Increase in LIP
If recalculated LIPs result in a Market Participant being charged more for imbalance energy
purchased as a direct result of the Market Participant’s Resources having been dispatched
incorrectly due to a Market Software and Data Input Error, SPP will make a make-whole
payment to that Market Participant in an amount that reflects the difference between the
recalculated LIP and the Market Participant’s offer from the Resource and the difference
between the Adjusted Dispatch and the Actual Dispatch.
Example: Price Adjusted Upward – Scheduled and Offered Resource
Resource Offer = 150 MW @ $60/MWh
Schedule = 100 MW
Initial Settlement
Original LIP = $30
Actual Dispatch = 0 MW
Settlement
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= LIP * (Scheduled Gen – Actual Gen)
= $30 * (100 MW – 0 MW)
= $3,000 {Market Participant pays the RTO}
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Market Protocols
Recalculated LIP
Recalculated LIP = $80
Actual Dispatch = 0 MW
Settlement
= LIP * (Scheduled Gen – Actual Gen)
= $80 * (100 MW – 0 MW)
= $8,000 {Market Participant pays the RTO}
If the LIP had been calculated correctly, the Market Participant’s Resource would have
been dispatched. The Market Participant’s cost would have been its cost of production
(100 MW * $60 = $6,000). As PRR 30 currently stands, no compensation is provided for
the RTO’s error. The Market Participant owes $8,000.
PROPOSED Additional Compensation for Incorrect LIP
Adjusted Dispatch
= lesser of Recalculated Dispatch or Scheduled injection
= Recalculated Dispatch of 150 MW, Schedule of 100 MW
= 100 MW
Error Compensation = (Adjusted Dispatch – Actual Dispatch) * (Offer – Recalc.
LIP)
= (100 MW – 0 MW) * ($60 - $80)
= -$2,000 {RTO pays the Market Participant}
Total Settlement
Total Settlement
= Recalculated LIP settlement + Error Compensation
= $8,000 - $2,000
= $6,000 {Market Participant pays the RTO}
End Result:
The final cost to the Market Participant is what their cost of production would have been had the
Market Software and Data Input Error not been made.
13.3.3 Disputes and Resettlement Provisions
If an SPP stakeholder does not agree with a price correction made by SPP within the allotted
time frame for such correction, the stakeholder may use the dispute and resettlement mechanism
provided in Section 10 of these Market Protocols to resolve such disagreement.
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14 Market Monitoring and Mitigation
14.1 Introduction
Market monitoring and mitigation is intended to provide for the monitoring of SPP’s Markets
and Services and mitigation of the potential exercise of horizontal and vertical market power by
Market Participants. Market monitoring and mitigation is an essential function for Regional
Transmission Organizations (RTOs) and is required by FERC’s Order 2000.
14.2 Purpose and Objective
A. Objective
The objective of the Market Monitoring function is to (a) protect consumers against abuse of
horizontal and vertical market power in SPP’s Markets and Services by any Market Participant
and (b) ensure that the design and implementation of SPP’s Markets and Services is as efficient
as possible, so that consumers may obtain the best deal based on price, risk and reliability. 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 to ensure that consumers obtain the best deal.
B. Independence of the 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.
C. Maintenance of Monitoring Protocols
The Market Monitor is responsible for reviewing and recommending updates to these market
monitoring protocols at least every three years and supporting SPP in obtaining approval from
FERC for any such updates with input and support from the MWG and SPP staff.
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14.3 Market Monitoring
14.3.1 Market Monitor
A. Staffing and Resources
The Market Monitoring function for SPP will be staffed by internal employees and external
contractors as deemed appropriated by the SPP Board of Directors. FERC in order109 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.”
SPP Board of Directors has determined that the SPP internal Market Monitoring Unit (MMU) is
responsible for all functions except what is assigned to the External Market Advisor (EMA).
The responsibilities, rights, and obligations of the EMA are defined in the SPP tariff Attachment
AJ-1 - EXTERNAL MARKET ADVISOR SERVICES AGREEMENT. The MMU and EMA
are jointly referred to as the Market Monitor.
B. 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 may at any time bring any matter to the attention of the Board, the officers
of SPP, FERC, or other affected state regulatory authorities, as deem necessary or appropriate.
After any initial inquiry, the Market Monitor shall also provide notification to the Board, the
President of SPP, and FERC Staff 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. 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.
C. 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. The EMA shall abide by the conflicts of interest and
code of ethics policies contained in its EMA Services Agreement with SPP, which shall be
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appropriate for establishing the professional and financial independence of the EMA and its
subcontractors, if any. The EMA, and its subcontractors, if any, shall certify compliance with
such policies to the Board.
14.3.2 Market Monitoring
The primary purposes of market monitoring are to (a) obtain objective information about SPP’s
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 SPP’s Markets and Services. Key
aspects of such market monitoring are (a) assessing the design and structure of SPP’s 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.
A. Markets to be Monitored
The Market Monitor will monitor SPP’s Markets and Services, which are the markets that are
operated by, and the services provided by, SPP 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
SPP’s Markets and Services, or the effects of SPP’s 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 effect of these markets and
services on SPP’s Markets and Services, or the effects of SPP’s Markets and Services on these
adjacent markets.
B. 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:
a) Resource and Ancillary Services (Capacity) Plans, schedules and Offer Curves
submitted for Resources in or affecting any of SPP’s Markets and Services;
b) Actual commitment and dispatch of Resources, including but not limited Resource
MW capability and output, MVAR capability and output, status, and outages;
c) Locational Imbalance Prices at all nodes and designated Settlement Areas in or
affecting any of SPP’s Markets and Services;
d) Control area data, including but not limited to control area demand, area control error,
net scheduled interchange, actual total net interchange, and forecasts of operating
reserves and peak demand;
e) Conditions or events both inside and outside SPP’s control areas affecting the supply
and demand for, and the quantity and price of, products or services sold or to be sold
in SPP’s Markets and Services;
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f) 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;
g) 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 SPP’s 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;
h) Settlement data, including but not limited to hourly integrated settlement location
MW;
i) Any information regarding collusive or other anticompetitive or inefficient behavior
in or affecting any of SPP’s Markets and Services; and
j) 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.
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.
C. 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 refer 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.
D. Monitoring for Portfolio Bidding
The Market Monitor shall monitor SPP’s Markets and Services for potential abuse associated
with portfolio bidding. When the Market Monitor determine there is sufficient credible
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information about a specific abusive practice, the issue will be referred to the Commission for
further review. Two specific types of potential abusive bidding practices are described below.
D.1.
Uneconomic Overproduction
The Market Monitor will look for cases where Self-dispatched Resources cause congestion on
transmission facilities on the exporting side of the constraint in an uneconomic manner that are
not justified by reliability concerns. The specific steps would be to:
a) Determine that the self dispatched generation is causing congestion;
b) Determine that the self dispatch is uneconomic (Resource incremental cost exceeds
Resource LIP);
c) Determine that 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.
D.2.
Strategic Withholding
The Market Monitor will look for cases where commonly owned or controlled Resources on the
importing side of a transmission constraint that are required to serve the load and that are not
subject to the Offer Cap, are causing the Locational Imbalance Price on the importing side of
such transmission constraint to be set at levels above the Offer Cap. The specific steps would be
to:
a) Identify the commonly owned or controlled Resources on the importing side of a
transmission constraint that do not meet the criteria set forth under section 15.4.1 – A.2.2.
(Determination of Offer Capped Resource) for imposing the Offer Cap;
b) Verify that the Resources identified in Section D.2.(a) are pivotal (i.e. are required to
serve the load on the importing side of the transmission constraint);
c) Document, beginning with the EIS Market Effective Date, the Locational Imbalance
Prices associated with all pivotal Resources identified under Section D.2.(b).
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.
14.3.3 Inquires
A. Requests
Any Market Participant or Interested Government Agency may submit in writing a complaint or
request for inquiry to either Market Monitor and indicate a preference for either or both Market
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Monitor to perform the assessment. Upon receipt of such complaint or request, the Market
Monitor receiving the request will notify the other Market Monitor, and the Market Monitor will
jointly 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 SPP’s 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. An inquiry will not be conducted if neither
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
any matter at any time that pertains to SPP’s Markets and Services that is part of their market
monitoring and/or market power mitigation obligation.
B. Conducting Inquiries
The MMU has primary responsibility for conducting inquiries, unless the Market Monitor
determines that the EMA should lead an inquiry. The EMA may directly participate in any
inquiry lead by the MMU at either the MMU’s request or its own option, but in any event, the
EMA shall be regularly informed of the progress and resolution of any inquiry, and the MMU
shall request the advice of the EMA during any inquiry. Market Participants shall cooperate
fully with the Market Monitor during any such inquiry. The process flow chart for conducting
an inquiry is shown below.
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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)
Is this
a Market
Design Issue?
4.0
Stage 3 Analysis
(Subject Party
Provided Data)
Are there
corrective
actions?
C. Reporting
The Market Monitor to whom a request for inquiry was made 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 State of the Market Report were
appropriate and consistent with inquiry procedures approved by the Board.
14.3.4 Compliance and Corrective Actions
A. Compliance
The Market Monitor may enforce SPP’s FERC-approved Mitigation Plan and remedy any actual
or potential abuse of market power or market design inefficiencies as part of an inquiry process.
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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:
a) Communicate with Market Participants to implement the mitigation and compliance
measures of these protocols;
b) Issue a demand letter requesting Market Participants causing the issue to arise to
change actions as the Market Monitor deem proper to achieve mitigation and/or
compliance; and
c) Implement any FERC-approved, applicable mitigation measure with or without prior
discussions or a demand letter, as appropriate.
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.
B. Corrective Actions for Market Design
If the Market Monitor discern any weaknesses or failures in market design and protocols,
including the determination that SPP’s 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, and FERC Staff. 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 both 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 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, either 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 SPP’s 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.
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14.3.5 Reporting
The Market Monitor, with the support and input 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 Directs. 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.
A. Annual State of the Market Report
The Annual State of the Market Report shall assess the performance of SPP’s Markets and
Services. Such report will discuss the progress made on the development of SPP’s markets and
inter-RTO coordination and will include any recommendations of the Market Monitor for the
improvement of SPP’s Markets and Services, or of the monitoring, reporting and other functions
undertaken pursuant to this Protocols. The 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 and 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 SPP web site. Confidential information will be
subject to redaction or other measures necessary for the protection of Protected Information.
B. 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 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 SPP markets with that of
other RTOs and ISOs. Copies of the reports shall be made publicly available by SPP through
posting on the SPP web site, subject to redaction or other measures necessary for the protection
of Confidential Information.
D. FERC Monthly Informational Filings
FERC Order Docket No. ER06-451-000 required SPP Market Monitor to file monthly
informational reports on three subjects for the first year of the SPP EIS market that started on
February 1, 2007. The last required filing will cover the month of January 2008. The three areas
to be covered in the monthly filings include depth of market, congestion resolution, and effects
of under scheduling.
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D1. Depth of EIS Market
The Market Monitor will monitor the effects of self-dispatch on the depth of the EIS Market, for
one year following the EIS Market Effective Date. The Market Monitor shall make monthly
information filings to the Commission regarding total megawatts of bids at each node relative to
the available megawatts of generation at each node.
D2. Congestion Resolution
The Market Monitor will develop detail assessments on how congestion and imbalance were
resolved, whether through TLR or imbalance market mechanisms. This information will be filed
monthly with the Commission for one year following the EIS Market Effective Date.
D3. Effects of Under Scheduling
For one year following the EIS Market Effective Date, the Market Monitor shall identify over
and under-scheduling relative to the Market Participant’s Reported Load when congestion
occurs, and submit monthly reports to the Commission on the benefits gained by those Market
Participants, the Over Scheduling Charges and Under Scheduling Charges made to Market
Participants, and any other issues the Market Monitor deems relevant to over and underscheduling. As a component of this reporting, the Market Monitor shall determine, and
recommend if needed changes to the Market Protocols to address any significant issues presented
by this ongoing review.
E. 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.
14.3.6 Performance Indices, Metrics and Screens
Performance indices, metrics and screens form the necessary objective basis for observing the
functioning of SPP’s Markets and Services, including the conduct of Market Participants in such
markets, and for providing reports and market analyses.
A. 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.
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B. Implementation
Whenever practicable, the Market Monitor should review data or other information collected in
accordance with the adopted indices, metrics and screens. However, the Market Monitor shall
not be prevented from conducting further or different review or evaluation of such data as
deemed appropriate.
14.3.7 Market Behavior Rules
All suppliers with market-based rates are required to comply with the Market Behavior Rules
defined in FERC Order No. 670 and the Conditions for Public Utility Market-Based Rate
Authorization Holders defined in FERC Order No. 674, as they may be amended from time to
time. The Market Monitor shall monitor for violations of these rules and report any suspected
violations to FERC Staff in accordance with the FERC’s reporting protocols for market monitor
in a timely manner. Market Participants are required to abide by these market behavior rules.
14.3.8 Market Manipulation
The Market Monitor will monitor the EIS Market 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 EIS Market in a timely manner.
14.3.9 Monitoring for Potential Transmission Market Power Activities
The Market Monitor shall monitor SPP’s Markets and Services for potential transmission market
power activities 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:
a) 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:
b) 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;
c) Unavailability of transmission facilities through planned and unplanned maintenance
outages that routinely exceed historical baselines.
d) Withholding of transmission capacity by transmission users through excess reservations
that are not actually used.
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The Market Monitor shall refer any instance(s) of potential transmission market power directly
to FERC. 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.
14.3.10
Data Access, Collection and Retention
The Market Monitor shall regularly collect and maintain Data and Information necessary for
monitoring SPP’s Markets and Services and implementing mitigation protocols.
A. Confidentiality
Market Monitor is subject to and will abide by the confidential rules as delineated in the SPP
OATT.
B. 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 the Market Monitoring section of these protocols. All Data and Information listed
in the Market Monitoring section shall be retained by SPP for a minimum period of three years.
C. Access to Market Participant Data and Information
Market Participants shall retain all Data and Information listed below, and in Section 15.3.3 of
this 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 MP. 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:
a) 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;
b) 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;
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c) 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;
d) 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;
e) All Data and Information relating to transmission system planning, including studies,
reports, plans, models, analyses, and filings with FERC or any state regulatory
commission;
f) 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.
g) 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
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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.
D. Certification and Auditing
The Market Monitor shall, from time to time, audit Market Participants and SPP to ensure
compliance with the data retention requirements established in these market monitoring
protocols. Market Participants and SPP shall cooperate with the Market Monitor in such audits.
The Market Monitor will annually destroy, and certify such destruction to the Board, information
in their possession which is no longer reasonably necessary.
14.3.11
Miscellaneous Provisions
A. 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.
B. 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.
C. Review of Market Monitor
The activities of the Market Monitor shall be reviewed from time to time by the Board of
Directors.
14.4 Market Power Mitigation
14.4.1 Purpose and Definitions
A. Purpose and Objective
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 is 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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B. Definitions
Generator-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”).
14.4.2 Economic Withholding
A. Energy Market Power
A.1.
Principles
There are two principles for mitigating Economic Withholding in the EIS Market operated by
SPP.
A.1.1.
Mitigate Only During Transmission Constraints
The electricity marketplace in the SPP Region is workably competitive, with an adequate supply
of electricity and diversity of suppliers, absent transmission constraints that may balkanize the
region. Therefore, mitigation will be applied only at the time of, and in places with, transmission
constraints.
A.1.2.
Do Not Mitigate Below Long Run Marginal Cost of New
Investment
Mitigation should not create or exacerbate a shortage by capping prices below the level needed
to attract investment that would relieve the shortage. This level shall be based on the long run
marginal cost of the least-cost generation supply that could be developed within the shortest
period of time, which is currently a new, natural gas-fired combustion turbine, peaking Resource.
A.2.
Mitigation Measure
When any transmission constraint is binding in the EIS Market, the Offer Curve associated with
Resources on the importing side of each constraint and Generator-to-Load Distribution Factors
that are equal to or greater than 5% shall have an effective offer no higher than the Offer Cap for
each Resource. The effective offer is what the Market Operating System uses in determining
prices and dispatch directions.
A.2.1.
Location and Determination of Binding Constraints
Binding transmission constraints in the EIS Market will be located on groups of transmission
elements designated as flowgates. The determination of whether a transmission constraint is
binding in the EIS Market will be based on the SPP Congestion Management process and the
EIS Market security constrained dispatch process for such determination.
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A.2.2.
Determination of Offer Capped Resources
An Offer Cap , as calculated in accordance with Section A.2.4 below, shall apply to certain
Resources, regardless of ownership, that are on the same side of a constrained flowgate as the
constrained load and within electrical proximity to the constrained flowgate. Such Resources
subject to the Offer Cap will be determined for each flowgate through the use of the Generatorto-Load Distribution Factors (GLDF). All Resources that are located on the importing side (side
with the constrained load) of a constrained flowgate that have GLDF greater than or equal to 5%
(i.e., for each 100 MW increase in Resource output, the imports across the flowgate are reduced
by 5 MWs or greater) shall be subject to an Offer Cap. If any of a Market Participant’s
Resources are subject to the Offer Cap based on the GLDF, all Resources owned by that Market
Participant that are located on the importing side of the same constrained flowgate shall also be
subject to an Offer Cap. A list of all Resources subject to an Offer Cap shall be posted
electronically, daily, at the www.SPP.org website for each flowgate. Further, SPP shall provide
through the Portal, to parties with access to information regarding each Resource, the list of
flowgates and the Resource-to-Load-Distribution Factor, for the Resource with respect to each
flowgate, that are above 5% for each Resource.
GLDF values will be reassessed at least once a year. GLDF values will also be reviewed and
revised if needed when there are significant changes to the transmission grid within or affecting
SPP EIS Market area.
A.2.3.3.
Reassessment of Offer Capped Status
The Market Monitor will reassess the status of Resources subject to Offer Caps when
transmission and Resource additions, changes, outages, or changes in ownership occur that may
reasonably cause the Resources’ Offer Capped status to change. In any event, the Market
Monitor will reassess the status of Offer Capped Resources on an annual basis.
A.2.4.
Calculation of Offer Caps
The Offer Cap for each Resource subject to an Offer Cap will be calculated daily, posted at the
www.SPP.org website and the SPP Portal for such Resource, and will be effective until replaced
by a new Offer Cap. Specifically, Offer Caps will be equal to the sum of (a) the estimated
annual fixed cost of a new, natural gas-fired, combustion turbine peaking generation facility in
$/megawatt-year divided by the annual hours of constraint, (b) an adder equal to the estimated
non-fuel variable operation and maintenance costs of a new, natural gas-fired, combustion
turbine peaking generation facility in $/megawatt-hour, and (c) the fuel cost of the peaking
facility in $/megawatt-hour calculated as the heat rate multiplied by a natural gas price index.
The formula for the calculation is as follows:
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Offer Cap = (AFC / AHC) + VOM + FC
Wherein the variables are defined as:
AFC
= Annual Fixed Cost (Annual Investment Recovery Requirement
($/megawatt-year) + Annual Fixed Operations and Maintenance Adder
($/megawatt-year))
AHC = Annual Hours of Constraint
VOM = Variable Non-Fuel Operations and Maintenance Adder ($/megawatthour)
FC
= Fuel Cost (Heat Rate * Natural Gas Price Index) ($/megawatt-hour)
Offer Caps do not function as price caps on the EIS Market because some Resources may not
subject to an Offer Cap and there are other factors that affect prices such as congestion costs.
Resources not subject to an Offer Cap may bid higher than, and set a price in the EIS Market that
is above an Offer Cap for another Resource. During periods of constraint on flowgates, the
market operating system limits the effective offer curve used in determining LIP to a maximum
equal to Offer Caps for a Resource subject to the Offer Cap. All Resources, including those
Resources identified subject to Offer Caps, will be charged/compensated based upon the
Locational Imbalance Price associated with each Resource.
A.2.4.1.
Annual Fixed Cost
The annual fixed cost of a new, natural gas-fired, combustion turbine peaking generation facility
shall be based on the calculated value of the annual carrying cost associated with the recovery of
the total fixed costs to develop, build and finance such a facility plus the fixed operation and
maintenance costs. Such cost shall be reviewed annually by the Market Monitor with input from
Market Participants and SPP. Any changes to such costs, along with justification for the
changes, shall be filed with the Commission for approval after such review. Such costs, along
with any studies justifying the costs, shall be reflected in the Tariff and posted electronically by
SPP. The Annual Fixed Cost currently approved by the Commission and contained in the SPP
OATT is $68,640/Megawatt-year.
A.2.4.2.
Variable Non-Fuel O&M Adder
The adder equal to the estimated non-fuel variable operation and maintenance costs of a new,
natural gas-fired, combustion turbine peaking generation facility shall be based on the non-fuel
operating and maintenance costs of such a facility not included in the calculation of annual fixed
costs as described above. Such cost shall be reviewed annually by the Market Monitor with
input from Market Participants and SPP. Any changes to such costs, along with justification for
the changes, shall be filed with the FERC for approval after such review. Such costs, along with
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any studies justifying the costs, shall be reflected in the Tariff and posted electronically by SPP.
The current approved rate contained in the SPP OATT is $3.43/Megawatt-hour.
A.2.4.3.
Annual Hours of Constraint
The annual hours of constraint will be calculated individually for each Resource subject to an
Offer Cap and will be based on the most recent 365 days (366 days for a leap year) of total hours
of constraint in the EIS Market for constrained flowgates affecting the Resource. In the event
that multiple constraints simultaneously affect a Resource, coincident hours of constraint will be
only be counted as one hour for the Offer Cap calculation for such a Resource.
During the first year of operation of the EIS Market, the hours of duration for TLR Level 3 and
above events for each flowgate shall be used as a proxy for hours of constraint in the EIS
Market. For each flowgate, this proxy shall apply for the period prior to the start of the EIS
Market that is included in the 12 month rolling sum calculation of annual hours of constraint.
The annual hours of constraint will be updated daily for inclusion in the daily calculation of the
Offer Cap on each Resource and will be posted electronically by SPP for each Resource on the
www.SPP.org website. The annual hours of constraint for each flowgate included in the daily
calculation of the Offer Cap on each Resource shall also be posted by SPP on the Portal by
flowgate for each Resource.
A.2.4.3.1 New Flowgates
When a new permanent flowgate is established, the annual hours of constraint used in the
calculation of the Offer Cap for each Resource that is pivotal to the new flowgate will be 32
hours until the actual number of hours of constraint on the flowgate has exceeded 32 or the
flowgate has been established for at least 12 months. Thereafter, the actual hours of constraint
will be used for the 12 month rolling sum. If a Resource is pivotal on a new flowgate, in
addition to other established flowgates, the annual hours of constraint for the Resource will be
the higher of the actual hours of constraint or 32 hours until the new flowgate has been
established for at least 12 months. SPP will post on the Portal by flowgate for each Resource
whether any flowgate included in the daily calculation of the Offer Cap on each Resource is
considered new as defined in this section.
A.2.4.4.
Fuel Cost
The fuel cost of a new, natural gas-fired, combustion turbine peaking generation facility shall be
based on the estimated full-load heat rate of the facility multiplied by a fuel price index. The
fuel price index for each Resource will be based on an industry accepted natural gas pricing
index for the natural gas pricing point nearest to the Offer Capped Resource(s) of each Market
Participant. The fuel price shall be further modified based on an estimate of the distribution cost
for moving natural gas to the Offer Capped Resource(s). Alternative pricing points and fuel
price modifiers shall be evaluated annually by the Market Monitor with input from Market
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Participants and SPP. The fuel price portion of each Offer Cap shall be recalculated daily for
inclusion in each Offer Cap and posted daily on the SPP.org website as well as on the Portal for
each Resource. The current approved heat rate contained in the SPP OATT is 10,450
btu/kilowatt-hour.
A.3
Imposition of Mitigation
Offer Caps will be imposed when any transmission constraint is binding in the EIS Market as
determined by SPP’s Market Operators through the SPP Congestion Management process and
the EIS Market security constrained dispatch process.
A.3.1.
Offer Cap Revisions
Market Participants with Offer Capped Resources may request an exception to an Offer Cap for
a Resource. If the Market Participant, after consultation with the Market Monitor determines
that an exception is reasonable, shall submit a filing with the Commission.
14.4.3 FERC Imposed “Safety-Net” Offer Cap
Beginning 91 days after the EIS Market Effective Date, submission of Offer Curves by Market
Participants will be limited to less than or equal to $1000/megawatt-hour. This limit will remain
in affect until such time as SPP demonstrates in a filing with the Commission that sufficient
demand response exists in the EIS Market to allow a higher Offer Curve price limit or removal
of the Safety-Net Offer Curve price limit.
14.4.4 Physical Withholding – Energy Market Power
No mitigation is necessary or warranted for Physical Withholding in the EIS Market, as the
market is voluntary. The Market Monitor will monitor participation to determine whether the
decisions to participate in the EIS Market have a significant adverse impact on market outcomes.
14.4.5 Unavailability of Facilities – Energy Market Power
No mitigation is necessary or warranted for Unavailability of Facilities in the EIS Market, since
participation in the market is voluntary. The Market Monitor will monitor for any potential
instances of Unavailability of Facilities and shall report on any such instances.
14.4.6 Maintenance and Implementation of the Mitigation Protocols
The Market Monitor is responsible for implementing the market power mitigation measures as
approved by FERC. The Market Monitor is also responsible for periodically reviewing and
recommending revisions to the mitigation protocols and supporting SPP in obtaining approval
from FERC for any such updates with input and support from the MWG and SPP staff.
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15 Process for Protocol Revision Requests
15.1 Introduction
A request to make additions, edits, deletions, revisions, or clarifications to these Protocols,
including any attachments and exhibits to these Protocols, is called a “Protocol Revision
Request” (PRR). Unless specifically provided in other Sections of these Protocols, this Section
shall be followed for all PRRs.
All decisions of the Market Working Group (MWG), and the Market and Operations Policy
Subcommittee (MOPC) and the SPP Board with respect to any PRR shall be posted to the SPP
Web Site within three (3) Business Days of the date of the decision. All such postings shall be
maintained on the SPP Web Site for at least one hundred eighty (180) days from the date of
posting.
The “next regularly scheduled meeting” of the MWG, MOPC or the SPP Board 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.
15.2 Submission of a Protocol Revision Request
The following Entities may submit a PRR:
(1)
Any Market Participant;
(2)
Any Entity that is an SPP Member;
(3)
Any staff member of a governmental authority having jurisdiction over the SPP or
any member company; and
(4)
SPP Staff
(5)
SPP Independent Market Monitor
(6)
Any SPP Committee or Working Group
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15.3 Protocol Revision Procedure
15.3.1 Review and Posting of Protocol Revision Requests
PRRs shall be submitted electronically to SPP by completing the designated form provided at the
SPP Web Site (PRR Request/Comment Forms). All PRRs are to be submitted to the email
address found on the SPP Web Site ([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 (PIA) (applicable only for a PRR submitted by SPP Staff);
(5)
list of affected Protocol Sections and subsections;
(6)
list of affected Tariff, Business Practice or Criteria sections;
(6)
general administrative information (organization, contact name, etc.); and
(7)
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 correct the PRR and 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 Web Site and distribute the PRR to the MWG within three (3) Business Days.
15.3.2 Comments on a PRR
Any interested entity that is qualified to submit a protocol revision request may comment on a
PRR. To receive consideration, comments on the PRR must be delivered electronically to SPP
in the designated format provided on the SPP Web Site within fourteen (14) days from the date
of posting/distribution of the PRR. Comments submitted after the due date of the fourteen (14)
day comment period may be considered at the discretion of MWG.
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Within one (1) Business Day of receipt of comments related to the PRR, SPP shall post such
comments to the SPP Web Site. The comments shall include identification of the commenting
Entity.
Comments submitted in accordance with the instructions on the SPP Web Site—regardless of
date of submission—shall be posted to the SPP Web Site and distributed electronically to the
MWG within one (1) Business Day of submittal.
MWG shall review the PRR and any posted comments to 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 will be reviewed at the subsequent regularly scheduled MWG
meeting.
15.3.3 Operations Reliability Working Group Review
The ORWG may review PRRs and submit comments for MWG’s consideration prior to the
MWG’s review or MWG taking action on a PRR.
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.
15.3.4 Regional Tariff Working Group Review
The RTWG may review PRRs and submit comments for MWG’s consideration prior to the
MWG’s review or MWG taking action on a PRR.
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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15.3.5 Initial Impact Analysis
SPP staff shall submit a Protocol Revision Request Impact Analysis (PIA), or indicate one is not
necessary on the PRR, with any PRR that SPP staff submits to the MWG based on the original
language in the PRR. The PIA will provide MWG with guidance as to what computer systems,
operations, or business functions could be affected by the PRR as submitted.
A PIA 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 on-going 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;
(4)
the identification of any manual workarounds that may be used as an interim
solution and estimated costs of the workaround; and
(5)
verification of review (if necessary) of the PRR by the Credit Working Group and
the impact of its review on the PIA.
(6)
the identification of any additional changes to the Tariff , SPP Criteria, or
Business practices that are required prior to the implementation of the PRR
Upon receipt of a PRR submitted by any Entity other than SPP, SPP shall perform an initial
evaluation of the impact on SPP and include the evaluation in SPP’s comments. The initial
evaluation will provide MWG with guidance as to what computer systems, operations, or
business functions could be affected by the PRR as submitted. SPP shall post its comments prior
to the MWG initial review of the PRR, if practicable.
15.3.6 Market Working Group Review and Action
The MWG is to review and recommend action to the MOPC on formally submitted PRRs.
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 PIA or updated PIA 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
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(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.
Within three (3) Business 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. Where a PRR has been approved subject to review of a new or
updated PIA, the recommendation report shall be titled “Preliminary PRR Recommendation
Report.” The SPP shall notify the Operations Reliability Working Group (ORWG) and the
Regional Tariff Working Groups (RTWG) via e-mail of the posting of PRR recommendation
reports. 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)
identification of authorship of comments;
(4)
proposed effective date(s) of the PRR;
(5)
priority and rank for any PRRs requiring a system change project; and
(6)
recommended action: approval, approval with modified language, or approval
subject to review of an Updated Protocol Revision Request Impact Analysis.
(7)
whether or not a new or updated PIA is required prior to forwarding the PRR
Recommendation Report to MOPC for review.
The MWG Chair shall notify MOPC of PRRs rejected by MWG.
15.3.7 Updated Protocol Revision Request Impact Analysis and MWG Action
If MWG approves a PRR contingent upon review of a new or updated PIA, SPP staff shall
prepare a PIA based on the PRR Recommendation Report to identify and evaluate the required
changes to the SPP Systems and staffing needs, including, but not limited to, SPP’s operating
systems, settlement systems, business functions, operating practices, SPP System operations,
and staffing needs.
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 PIA for the
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recommended PRR within twenty-five (25) days after MWG approval of the PRR. SPP shall
post the results of the completed PIA on the SPP Web Site. If a longer review period is required
for SPP Staff to complete a full PIA, SPP Staff shall submit a schedule for completion of the PIA
to the MWG chair.
MWG shall consider the Updated PIA at the first regular meeting after the completion of the
Updated PIA, or at such earlier date after completion of the Updated PIA established by the chair
of MWG. At such meeting, MWG shall either:
(1) recommend final approval of the PRR as set forth in the initial PRR Recommendation
Report or as modified, which recommendation may be subject to further evaluation of
impacts as directed by MWG;
(2) reject the PRR. A PRR shall be considered rejected and appealable if a majority of
MOPC members fail both to approve the PRR, either as submitted or modified, and
reject the PRR;
(3) defer action on the PRR;
(4) refer the PRR to a workgroup or task force as MWG deems appropriate.
After consideration of the Updated PIA, a revised PRR Recommendation Report shall be issued
by MWG to MOPC and posted on the SPP Web Site. Additional comments received regarding
the revised PRR Recommendation Report shall be accepted up to three (3) Business Days prior
to the MOPC meeting at which the PRR is scheduled for consideration. If MWG revises its
initial recommendation, SPP may issue an updated PIA at least three (3) Business Days prior to
the regularly scheduled MOPC meeting. If a longer review period is required for SPP Staff to
update the PIA, SPP Staff shall submit a schedule for completion of the PIA to the MOPC chair.
15.3.8 Withdrawal of Protocol Revision Request
Upon notice to the MWG, the submitter of a PRR may withdraw the PRR at any time prior to
final approval of the PRR by the MWG. SPP shall post a notice of the submitter’s withdrawal of
a PRR on the SPP Web Site within one (1) Business Day of the submitter’s notice to MWG.
Once finally approved by the MWG a PRR cannot be withdrawn except with approval of the
MOPC.
15.3.9 Expedited Requests
The party submitting a PRR may request that the PRR be considered on an expedited basis
("Expedited") only when the submitter can reasonably show that an 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 a settlement formula
and a provision of these Protocols.
If a submitter requests Expedited status for a PRR, or upon a valid motion in a regularly
scheduled meeting of the MWG and the MWG determines that such PRR:
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(1)
(2)
requires immediate attention from MOPC due to (a) serious concerns about SPP
System reliability or market operations under the unmodified language or (b) the
crucial nature of settlement activity conducted pursuant to any settlement formula;
and
is of a nature that allows for rapid implementation without negative consequence
to the reliability and integrity of the SPP System or market operations; then
MWG may designate the PRR for Expedited consideration. The MWG shall consider the
Expedited PRR at its earliest regularly scheduled meeting, or at a special meeting called by the
MWG chair to consider the Expedited PRR.
If approved, SPP shall submit an Expedited PRR Recommendation Report to the MOPC within
one (1) Business Days after MWG takes action. The MOPC chair may request action from
MOPC to accelerate or alter the procedures described herein, as needed, to address the urgency
of the situation.
Notice of an Expedited PRR pursuant to this subsection shall be posted on the SPP Web Site.
Any revisions to these Protocols that take effect pursuant to an Expedited request shall be subject
to an SPP PIA.
15.3.10
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 Web Site 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 Web Site 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) days in advance of the Board
meeting; otherwise the appeal will be heard by the Board at the next regularly scheduled Board
meeting.
15.3.11
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 Web Site for at least six (6)
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days or those accepted for expedited treatment by the MOPC. The following information must
be included for each PRR considered by MOPC:
(1)
the PRR Recommendation Report and PIA, 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 Web Site
within three (3) Business Days after the MOPC’s decision.
If the MOPC approves a change or changes to the Protocols, such change(s) shall be:
(1) posted on the SPP Web Site as a MOPC Action Report and
(2) incorporated into the Protocols posted on the SPP Web Site 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 grayboxed text that indicates the anticipated effective date of the PRR. At least two times
per year, MWG shall review all PRRs in gray-boxed text and determine whether it is
necessary to adjust the anticipated effective date of any PRR. MWG’s decision to
adjust an effective date may be appealed to MOPC and/or the Board in accordance
with the provisions for appeal of a rejected PRR.
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15.3.12
Process Flow Chart for Protocol Revision Requests
Protocol Revision Request Process
MWG reviews
queued/expedited
PRR's and related
documents at
scheduled MWG
meeting dates
Deferred
SPP Staff will do an
impact analysis on Yes
what computer
systems, operations,
or business
functions could be
affected by the PRR
Send notification to
submitter, within 5
days, of incomplete
status and
deficiencies to be
corrected
Participants/
Staff
Submit PRR/PRR
comments electronically
([email protected])
using the designated form
provided on the SPP
Website
Impact
Analysis
Required?
MWG submits new
comment form with
items captured
during meeting
Send PRR with
expectations and
timeline to
appropriate WG
or TF
(Evaluate and
present back to
MWG)
Appeal to rejection
submitted to SPP
within 10 days of
denial
Update Protocols
Action by MOPC
will be posted to
the web within 3
days of action
Accepted
BOD
MOPC
Referred to
another WG or
TF?
Post
Recommendation
Report with
accepted/rejected
text and distribute
to the MWG
Send
Recommendation
& Impact Analysis
to MOPC
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Accepted/
Rejected/
Deferred?
No
No
Post PRR and
distribute to the
MWG
No
SPP/MWG
Comments
Post and
distribute
electronically to
the MWG
Yes
Is PRR complete
based on PRR
Procedures?
Accepted/
Rejected
PRR
PRR or
Comments on
previous PRR?
Accepted/
denied
Denied
Action by MOPC will
be posted to the
web within 3 days of
action
Board remands
expectations and
instructions
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within 10 days of
action and posted
to the web
Board Review
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16 Market Process and System Change Process
The following protocol outlines the methods that govern SPP System changes that directly
impact members’ processes, systems, or interfaces with SPP systems. The intent of this protocol
is to ensure there is transparency when member-impacting changes occur to SPP processes
and/or systems.
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:
 The change will result in members having to make changes to their internal systems or
interfaces
 The change will require members to coordinate testing with SPP prior to the change
being released to Production systems
 The change will cause members to change their internal processes
 The change modifies or creates a system interface between SPP and its members
 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 member-impacting 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:
 Listing and description of planned member-impacting projects
 Updated current status of planned member-impacting projects
 Identifiable milestones of planned member-impacting projects, including, but not limited
to:
o Requirements Signoff
o Schedule of Testing and Training
o Communication of Expectations / Specifications
o Release of Required Documentation
o 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.

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
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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.

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 four (4) weeks prior to implementation in production, or as
defined and agreed to by the CWG.

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 Group to determine the appropriate lead times
for documentation, testing, and implementation.

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:
o 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 email) 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.
Appendix
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2
Market Protocols
A – Registration Package
The current electronic version of the registration package is available from SPP Customer
Relations personnel. Following are sample forms in the registration package.
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3
Market Protocols
Southwest Power Pool
Market Registration
This workbook outlines the steps necessary to register your company for participation in SPP's
wholesale electricity market. Please return the completed package by end of business on October 17,
2003 to SPP Customer Registration, 415 North McKinley, #800 Plaza West, Little Rock, AR 722053020, ATTN: R.J. Robertson. This address is also listed below.
Instructions
Please complete and sign each application or form as appropriate. Check the corresponding box
below for each step that you complete. Completion of this package is critical to your company's
participation in SPP's wholesale electricity market.
Complete the steps listed below which apply to your company
Customer with Customer with
assets in SPP no assets in SPP
*
*
*
*
*
*
*
*
*
*
*
*
*
Step 1 - Application as a Transmission Customer for Market Operations
Step 2 - Point of Contact form
Step 3 - Local Security Administrator (LSA) form
Step 4 - Application for Generation Company (GenCo)
Step 4a - Generation Assets Form
Step 5 - Application for Load Serving Entity (LSE)
Step 5a - Load Asset Form
Step 6 - Metering Agent (MA) Form
Step 7 - Designated Agent Form
Step 8 - Third Party Scheduler Form
Designated Agent
If you choose to designate another transmission customer to be financially responsible for all or a portion of your
assets (for the purpose of scheduling, settlements, submission of resource plans, and submission of bid curves), please
contact your Customer Relations representative.
Upon completion of this package
Mail a copy of each completed form:
Southwest Power Pool
Customer Registration
415 North McKinley, #800 Plaza West
Little Rock, AR 72205-3020
ATTN: R.J. Robertson
Also save and send an electronic copy of this workbook to: [email protected]
NOTE: An electronic copy of this package will be accepted by SPP;
however, registration is not considered complete until all signed copies
have been received by SPP at the address listed above.
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Market Protocols
Southwest Power Pool
Market Registration Application
For Transmission Customer
(No Fee Required to Register)
INSTRUCTIONS:
Please complete this application for a Transmission Customer (TC). A Transmission Customer is the only entity that has a
legal and financial relationship with SPP. A Transmission Customer can register Generation Companies (GenCos), Load
Serving Entities (LSEs) and Metering Agents as market participants. Upon completion of this form, print , sign and mail to SPP
Customer Registration, 415 North McKinley, #800 Plaza West, Little Rock, AR 72205-3020, ATTN: R.J. Robertson
TC Contact Information
Today's Date
Company Name
Company Address
City
NERC ID
Duns #
State
ZIP
Primary Contact Name
Contact Address
City
Phone
Email Address
St
ZIP
Billing Contact Name
Billing Address
City
Phone
Email Address
St
ZIP
Acknowledgement from Transmission Customer
By signing this form, you are stating that all of the information above is correct.
Signature of Authorized Representative:
Job Title:
Date of Signature:
SPP Use Only
Date Received
Date Approved
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Market Protocols
Southwest Power Pool
Market Registration
Primary and Functional Points of Contact (POC)
INSTRUCTIONS:
Complete this form to identify the POCs for your company. Definitions of each POC is listed at the bottom of this worksheet.
Company Name
Company Address
City
State
Zip
NERC ID
Duns #
Today's Date
0
0
0
0
0
0
0
Contact Type
Name
Phone #
Email
Fax
Alternate Name
Primary Point of Contact
ICCP Data Exchange
Resource Data Exchange
Metered Data Submission
Operational Network Model
Market Operations
Credit
Financial Transfer
Settlements
Invoicing
Acknowledgement from Transmission Customer
By signing this form, you are stating that all of the information above is correct.
Signature of Authorized Representative:
Job Title:
Date of Signature:
SPP Use Only
Date Received
Date Approved
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Market Protocols
Local Security Administrator for
0
Duns #
NERC ID
0
0
Designate your company's LSA
INSTRUCTIONS:
Please complete the information listed below for the primary and backup Local Security Administrator (LSA). This person is usually the Security
Officer for a company but does not have to be in this role to become an LSA. The persons listed here are responsible for maintaining the security of
the Market System and setting up other users for the company listed above. Upon completion of this form, print, sign and mail to SPP Customer
Registration, 415 North McKinley, #800 Plaza West, Little Rock, AR 72205-3020, ATTN: R.J. Robertson
Name
Phone #
Fax #
Email Address
LSA
Backup LSA
Security Officer
Acknowledgement from Transmission Customer
By signing this form, you are stating that all of the information above is correct and that you understand the LSA will provide and maintain portal
or market system user information for your company.
Signature of Local Security Administrator :
Date of Signature
Signature of Security Officer (if different from LSA):
Date of Signature
SPP Use Only
Date Received
Date Approved
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7
Market Protocols
Southwest Power Pool
Market Registration
Application for Generation Company (GenCo)
(No Fee Required to Register)
INSTRUCTIONS - Complete one application for each GenCo that you are registering. Registering a GenCo also requires that
you complete the Generation Asset form. GenCos own generation or have controllable load that is interconnected to the SPP's
transmission grid. Upon completion of this form, print, sign and mail to SPP Customer Registration, 415 North McKinley,
#800 Plaza West, Little Rock, AR 72205-3020, ATTN: R.J. Robertson
GenCo Contact Information
Today's date
Company Name
Company Address
City
NERC ID
Duns #
State
ZIP
Primary Contact Name
Contact Address
City
Phone
Email Address
St
ZIP
Assignment for Designated Agent
If you choose to designate an SPP Transmission Customer to be financially responsible for all or a portion of your assets (for
the purposes of scheduling, settlements, submission of resource plans, and submission of bid curves), please contact your
Customer Relations representative.
Acknowledgement from GenCo
By signing this form, you are stating that all of the information above is correct.
Signature of Authorized Representative:
Job Title:
Date of Signature:
IMPORTANT - *** Complete GenCo Registration ***
NOTE: Please update the Generation Assets form listed in worksheet 'Step 4a Id Resources'
SPP Use Only
Date Received
Date Approved
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Market Protocols
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9
Market Protocols
Southwest Power Pool
Market Registration
Application for Load Serving Entity (LSE)
(No Fee Required to Register)
INSTRUCTIONS
Please complete one application for each Load Serving Entity (LSE) that you are registering. LSEs draw energy from
SPP's bulk transmission system to serve loads.
LSE Contact Information
Today's Date
Company Name
Company Address
City
NERC ID
Duns #
St
ZIP
Primary Contact Name
Contact Address
City
Phone
Email Address
St
ZIP
Assignment for Designated Agent
If you choose to designate an SPP Transmission Customer to be financially responsible for all or a portion of your assets
(for the purposes of scheduling, settlements, submission of resource plans, and submission of bid curves), please contact
your Customer Relations representative.
Acknowledgement from LSE
By signing this form, you are stating that all of the information above is correct.
Signature of Authorized Representative:
Job Title:
Date of Signature:
IMPORTANT - *** Complete LSE Registration ***
NOTE: Please complete the worksheet 'Step 5a Id Load Assets'
SPP Use Only
Date Received
Date Approved
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Market Protocols
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11
Market Protocols
Metering Agent Assignment
for
0
Duns #
NERC ID
0
0
INSTRUCTIONS - Complete one form for each metering agent listed in the load and generation tabs. This market participant is responsible for
the acquisition of end-use meter data, application of transmission and distribution losses, aggregation of data by entity representing end-use load,
application of data to settlements intervals and transfer of data to SPP.
Transmission Customer's assignment for Metering Agent
Assigned Metering Agent Contact Information
Today's Date
Company Name
Company Address
City
NERC ID
DUNS #
Contact Name
Company Address
City
Phone
Email Address
St
ZIP
St
ZIP
Acknowledgement from Transmission Customer
By signing this form, you are stating that all of the information above is correct and that you understand the MP assigned above will provide
metering services for your company.
Signature of Authorized Representative:
Job Title
Date of Signature
*** IMPORTANT ***
If you are using a metering agent other than yourself, SPP will send out a metering agent acknowledgement form to be signed by the transmission
customer and the metering agent. This form will verify which resources are assigned to the metering agent.
SPP Use Only
Date Received
Date Approved
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12
Market Protocols
Designated Agent Form
INSTRUCTIONS:
Please complete this form if your company will select an SPP Transmission Customer to act on behalf of your company for the
purpose of scheduling, settlements, and the submission of bid curves and resource plans. Upon completion of this form, print, sign and
mail to SPP Customer Registration, 415 North McKinley, #800 Plaza West, Little Rock, AR 72205-3020, ATTN: R.J. Robertson.
Designating Party Information
Company Name
Contact Name
Company Address
City
Phone
Email Address
State
ZIP
Designated Agent Information
Company Name
Contact Name
Company Address
City
Phone
Email Address
State
ZIP
Acknowledgement from Designating Party
By signing this form, you are stating that all of the information above is correct and that you understand the company serving as your
Designated Agent will function in the SPP market on your behalf for financial settlements and submission of market data.
Signature of Authorized Representative:
Print or type name:
Title
Date
Acknowledgement from Designated Agent
Signature of Authorized Representative:
Print or type name:
Title
Date
SPP Use Only
Date Received
Date Approved
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14
Market Protocols
B – XML Specifications
XML Specification Document
CHANGE RELEASE PLAN
MARKET SYSTEMS XML FILES, API OR PORTAL
Short-Term:
Non-emergency planned changes to Market Systems XML files, API, or SPP Portal will be
published to the SPP website along with a Market Alert notification to market participants at
least 4 weeks in advance of the change taking effect. The published change notice will include a
summary description document, xsd file and sample XML file.
Emergency changes to Market Systems XML files, API, or SPP Portal may be implemented with
less than 4 weeks advance notice with approval of the SPP Change Management Department.
An emergency change is defined as a systems change which if not implemented will cause
severe adverse harm to SPP, market, or market participants. Notifications of emergency changes
will be made through Market Alerts at least 24 hours prior to the effective time of any declared
emergency change. SPP shall publish to the SPP website a summary description document, xsd
file and sample XML file along with notifying participants of the posting. Within 30 days of any
emergency change, SPP will perform a root cause analysis of event and publish its findings to
the market participants. The analysis must identify the cause of the event and identify
recommendations to prevent any future reoccurrence.
Long-Term:
A 12 month calendar of future system releases for MOS and COS will be updated and published
at least monthly to reflect future enhancements and functionality. This calendar will be published
under Market Reference Documents > System Releases. Notifications of calendar updates will
be made through the Market e-Newsletter.
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1
C – Meter Technical Protocols
Meter Technical Protocols
Revision 0.e
MAINTAINED BY
Settlement Data and Meter Standards Task Force
Market Working Group
PUBLISHED: 02/27/2004
LATEST REVISION: 12/29/2005
Copyright © 2005 by Southwest Power Pool, Inc. All rights reserved.
Meter Technical and Data Reporting Protocols
Revisions
Revision
Date
0.a
02/27/2004
0.b
06/29/2004
0.c
07/06/2005
0.d
07/11/2005
7.9
Added the loss compensation section.
0.e
12/29/2005
6
Added time standard section
Rev. 0.e
Section
Description of Modification
Initial release of consolidated Meter Technical and Data Reporting
Protocols
Updated to include 1) M to MSL to SL Diagrams, 2) Truncate and
Carry option, 3) kWh and MWh reporting option, 4) types of Meter
data, and 5) process for resubmission of data.
PRR029: SPC Comment Coordinated with SDMSTF which separated
the Meter Technical Documents to be shown in an appendix by itself
which could be referenced in the SPP Criteria
12/29/2005
2
Meter Technical and Data Reporting Protocols
1 Scope
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 Market Metering Implementation.
2 Purpose
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 Market.
3 Definitions
The terms used in this document are defined in the SPP Market Glossary. Please refer to
this document for clarification of terms used in this document.
4 Applicable Standards
ANSI C12.1
ANSI C12.7
ANSI C12.9
ANSI C12.10
ANSI C12.11
ANSI C12.16
ANSI C12.20
ANSI C 93.1
IEEE Std 100
IEEE C57.13
IEEE C37.90.1
NFPA 70
Rev. 0.e
American National Standard For Watthour Meters, Code For Electricity Metering
American National Standard Requirements for Watthour Meter Sockets
American National Standard For Test Switches for Transformer-Rated Meters
American National Standard For Watthour Meters
American National Standard For Instrument Transformers For Revenue Metering,
10kV BIL through 350 kV BIL
American National Standard For Solid State Electricity Meters
American National Standard For 0.2 and 0.5 Accuracy Class
Standard Requirements for Power Line Coupling Carrier Capacitors and Coupling
Capacitor Voltage Transformers
The New IEEE Standard Dictionary of Electrical and Electronic Terms
IEEE Standard Requirement for Instrument Transformers
IEEE Standard Surge Withstand (SWC) Tests for Relays and Relay Systems
Associated with Electric Power Apparatus
National Electrical Code® 2005 edition, Chapter 1 General, Section II. 600 Volts,
Nominal, or Less, Article 110.26 Spaces About Electrical Equipment.
12/29/2005
2
Meter Technical and Data Reporting Protocols
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:

Meter Participant is capable of providing hourly MWh interval data information

The Metering Parties mutually agree that the existing metering facilities are
acceptable.

Meets other SPP transmission tariff requirements.
5.3 Physical Location of Meter
The SPP Meter 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 Tie lines (Interchange)
Sufficient metering, as defined in Section 7, shall be installed for the settlement of
interchange in accordance with the terms of the applicable Interconnection Agreement or
Network Operating Agreement.
5.5 Metering for Resources
Sufficient metering, as defined in Section 7, shall be installed for Resources either at the
Resource terminals or at the Meter Settlement Location in accordance with the terms of the
applicable Interconnection Agreement or Network Operating Agreement. All metered
Resource data values are to be supplied to the 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, shall be installed for the settlement of Loads in
accordance with the terms of the applicable Interconnection Agreement or Network Operating
Agreement.
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3
Meter Technical and Data Reporting Protocols
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
When an RTU requires a freeze contact and the meter has a timing element, the timing
contact shall be provided by the meter. All RTU’s will accept this freeze contact.
6.2 Accuracy
When the timing element of the meter is used to send a freeze contact and/or to control
interval data recording, 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 as per NIST.
7 Meters
7.1 Measurement Quantities
The meter shall be capable of reporting Wh and VARh for 4 quadrants.

Quadrant 1 shall measure active power and reactive power delivered by the SPP network.

Quadrant 2 shall measure active power received by the SPP network and reactive power
delivered by the SPP network.

Quadrant 3 shall measure active power and reactive power received by the SPP network.

Quadrant 4 shall measure active power delivered by the SPP network and reactive power
received by the SPP network.
The watthours and varhours 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:

Rev. 0.e
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 four-wire 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.
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Meter Technical and Data Reporting Protocols

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
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.
7.3 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.
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 SPP Meter 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 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 Meter
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.
Rev. 0.e
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5
Meter Technical and Data Reporting Protocols
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 7.8 of this document.
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 Meter 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:

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.

The results of all accuracy testing listed in Section 7.1.4.1 through 7.1.4.3 of this document.
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.
7.5.2 Measurement Configuration
The transducer shall be installed and configured in such a manner as to comply with the
following:

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 four-wire 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.

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.
Rev. 0.e
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6
Meter Technical and Data Reporting Protocols
Table 2
% Calibration
Watts
Power Factor
Tolerance %
100
1.0
±0.2
7.5.4 Testing
7.5.1.1 Testing Equipment
All transducer testing equipment shall be traceable back to National Institute of Standards
and Technology (NIST).
7.5.1.2 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
7.5.1.3 Operating Conditions
A transducer will maintain the accuracy as shown in Table 2 under the following conditions:




Temperature Range:
Humidity:
Potential Range:
Current Range:
-20°C to +70°C
0 to 95% non condensing
70 to 130% of nominal input voltage rating
0 to 200% of nominal current rating
7.5.1.4 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.
7.5.1.5 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 Meter 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 7.8 of this document.
Rev. 0.e
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7
Meter Technical and Data Reporting Protocols
7.5.1.6 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:

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.

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 Meter 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 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 Meter 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.
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Meter Technical and Data Reporting Protocols
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.

All current transformers must have the same nominal rating regardless of the circuits in
which they are connected.

All current transformers which have their secondaries paralleled must be connected to the
same phase of the primary circuits.

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.

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.

The secondary circuits must be so designed that the maximum possible burden on any
current transformer will not exceed its rating.

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.

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
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Meter Technical and Data Reporting Protocols
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.
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 Meter 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 Meter 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 Meter Participant to identify a
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.
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Meter Technical and Data Reporting Protocols
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.

Each current and voltage transformer shall have its own polarity conductor.

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.
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 over-voltages 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.
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Meter Technical and Data Reporting Protocols
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 Settlement Location meter is being tested, care should be taken to minimize the
potential impact on the Control Area Operator’s and/or Wires Facilities owner’s(s’) 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.
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.

Verification that the documentation and drawings accurately represents the equipment and
circuits installed at the specific location.

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 ).

The instrument transformers nameplate data shall match the drawings.

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.

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.

The meter shall meet the accuracy tests as stated in Sections 7.2.3 and 7.2.4 of this
document for watthour functions for both Quadrant 1 and 2. For auxiliary metered Loads
only the Quadrant 1 watthour function need to be tested.
Upon request, the Control Area Operator and/or Wires Facilities owner(s) 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.

Rev. 0.e
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.
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Meter Technical and Data Reporting Protocols

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.

The meter shall meet the accuracy tests as stated in Sections 7.2.3 and 7.2.4 of this
document for watthour functions for both Quadrant 1 and 2. For auxiliary metered Loads
only the Quadrant 1 watthour function need to be tested.
Upon request, the Control Area Operator and/or Wires Facilities owner(s) shall be provided
with a copy of all of the equipment owner’s documentation for the specific location.
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Meter Technical and Data Reporting Protocols
7.12 Node Loss Compensation
7.12.1 General
M
NODE & Meter
Settlement
Location
M
NODE & Meter
Settlement
Location
M
A2
A1
Transmission
Owner
Network
M
NODE & Meter
Settlement
Location
A3
Transmission
Owner
Network
Transmission
Owner
Network
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 Node
Point.




Rev. 0.e
Transformer No Load Loss
Transformer Full Load Losses
Distribution Losses
Transmission losses (excluding SPP Transmission Tariff Attachment M Losses)
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Meter Technical and Data Reporting Protocols
SPP Transmission System
Meter Settlement Location
L1
L2
Transmission
Owner
Network
Transmission
Owner
Network
X
Y1
M
Ln
L3
Transmission
Owner
Network
Transmission
Owner
Network
Yn
Y2
NODE
NODE
NODE
M
M
M
L1...Ln = Load Withdrawal Value
L1 = X + (SPP Transmission Tariff Attachment M Losses)
L2..Ln = Y1..Yn + (SPP Transmission Tariff Attachment M Losses)
X1 = Load Withdrawal Node 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 Node
Point.




Rev. 0.e
Transformer No Load Loss
Transformer Full Load Losses
Distribution Losses
Transmission losses (excluding SPP Transmission Tariff Attachment M Losses)
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Meter Technical and Data Reporting Protocols
7.12.2 Methods for Compensation
7.12.1.1 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:
Gen _ Injection _ Node _ value  meter _ value  1  adjustment _ percentage
Load _ Withdrawal _ Node _ value  meter _ value  1  adjustment _ percentage
7.12.1.2 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.
7.12.1.3 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
7.12.1.1 Transformer Test Data
Transformer Test Information
Rating of the Transformer or the 3 Transformer Bank**
Rated Primary Voltage (line to line)
Rated Secondary Voltage (line to line)
No Load Watts Loss at X°C*
Full Load Watts Loss at X°C*
Impedance at X°C*
Exciting Current at Rated Voltage and X°C*
Units
(TVA)
(RPV)
(RSV)
(NLWLT)
(FLWLT)
(IZ%)
(%I)
MVA
kV
V
kW
kW
Decimal
Decimal
*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.
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Meter Technical and Data Reporting Protocols
7.12.1.2 Calculating data not supplied with Transformer Test Data
Calculate the full Load amps (FLA) at rated secondary voltage.
TVA  1000
FLA 
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 

7.12.2.3 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 (rTL)
Ohms /
mile
The effective series reactance (xTL)
Ohms /
mile
The length of the line
mile
(LTL)
Calculation of the transmission load line watts loss.#
RSV


FLA2  rTL  LTL  

RPV  1000 

< {added}
FLWLTL 
1000
Calculation of the transmission load line VAr 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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Meter Technical and Data Reporting Protocols
RSV


FLA2  xTL  LTL  

RPV  1000 

< {added}
FLVLTL 
1000
Calculation of the transmission no load line watts loss. @
2
 NLWLT 
 RPV  3   rTL  LTL

NLWLTL  
< {added}
1000
Calculation of the transmission no load line VAr loss. @
2
 NLWLT 
 RPV  3   xTL  LTL

NLVLTL  
< {added}
1000
7.12.2.4 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 (rSL)
Ohms /
mile
The effective series reactance (xSL)
Ohms /
mile
The length of the line
mile
(LSL)
Calculation of the secondary line watts loss.#
FLA2  rSL  LSL
< {added}
FLWLSL 
1000
Calculation of the secondary line VAr loss.#
@
#
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.
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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Meter Technical and Data Reporting Protocols
FLVLSL 
FLA2  xSL  LSL
< {added}
1000
7.12.1.5 Totalization of losses
Summary of Losses
Transformer
No Load
Loss (kW)
Full Load
Loss (kW)
No Load
Loss
(kVArs)
Full Load
Loss
(kVArs)
NLWLT@
FLWLT Ф
NLVLT@
FLVLT Δ
Secondary
FLWLSL
FLVLSL
Transmission
NLWLTL
FLWLTL
NLVLTL
FLVLTL
Total Losses
NLWLTOT
FLWLTOT
NLVLTOT
FLVLTOT
7.12.1.6 Application to Meter
Site Information
@
Ф
Δ
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.
The Full Load Watts Transformer Loss Value (FLWLT) 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
(FLA) 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 and then applying the following formula.
  FLWLT   RSV  2


  1000 

TVA  1000   1000 

3  FLA2   
TVA  1000





  FLWL
T
1000
<{added}
The Full Load VAr Transformer Loss Value (FLVLT) 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 (FLA)
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 and then applying the following formula.
2
2


FLWLT   RSV 
 IZ % 2  
 
  1000 
 TVA  1000   1000 

3  FLA2  

TVA  1000




 FLVLT
1000
Rev. 0.e
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<{added}
19
Meter Technical and Data Reporting Protocols
Site Information
Current Transformer Ratio
Voltage Transformer Ratio
Meter Voltage
Meter Test Amps
Transformer Primary Tap (kV) to
which the transformer is set
Primary
(CTP)
Primary
(VTP)
VM
TA
TPV
/
Secondary (CTS)
/
Secondary (VTS)
Calculate the meter kVA
CTP VTP

CTS
VTS < {added}
VAM 
1000
CTP VTP
3  VM  TA 

CTS
VTS < {added}
VAM 
1000
3  VM  TA 
For a 3 element meter
For a 2 element meter
Calculating the No Load Watt Loss.
2

 VTP  TPV  1000 
V


 M  VTS 

RSV



  NLWLTOT

NLWLMTR
RPV  1000




3
Calculating the Full Load Watt Loss. #
2

 CTP  
 TA   CTS  


FLWLMTR   FLA   FLWLTOT




Calculating the No Load VAr 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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Meter Technical and Data Reporting Protocols
2

 VTP  TPV  1000 
VM   VTS  

RSV


  NLVLTOT
NLVLMTR  
RPV  1000




3
Calculating the Full Load VAr Loss. #
2

 CTP  
TA




 CTS   


FLVLMTR
FLVLTOT
FLA




6.5.5.1 Compensation Percentages
No Load Watts Loss Percentage
NLWL
MTR
 100
NLWL%  VA
MTR
Full Load Watts Loss Percentage
FLWL
MTR
 100
FLWL%  VA
MTR
No Load VAr Loss Percentage
NLVL
MTR
 100
NLVL%  VA
MTR
Full Load VAr Loss Percentage
FLVL
MTR
 100
FLVL%  VA
MTR
7.13 Record Retention
The Meter 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:




Rev. 0.e
Loss Percentages as agreed to by Metering Parties for each meter.
Compensation Methodology
SPP Transmission Tariff Facilities (Node) values
Meter testing documents
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Meter Technical and Data Reporting Protocols

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 seven years for independent auditing purposes
by the SPP or their designated party.
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22
Appendix D– Settlement Metering Data Management
Protocols
Settlement Metering Data Management
Protocols
Revision 0.b
MAINTAINED BY
Settlement Data and Meter Standards Task Force
Market Working Group
PUBLISHED: 11/28/2005
LATEST REVISION: 02/05/2010
Copyright © 2005 by Southwest Power Pool, Inc. All rights reserved.
Settlement Meter Data Management Protocols
Revisions
Revision
Date
0.a
11/28/2005
0.b
02/05/2010
Rev. 0.b
Section
Description of Modification
Created Appendix E. Added language to clarify Settlement
Meter Data calculation methodology including additional
diagrams. Update diagrams for SPP Node. Incorporate
Attachment M losses as part of the Settlement Meter Data
reported values. Additional language about Residual Load
calculations related to Attachment M Loss Application.
Incorporated PRR130 into Protocols – Section 10.2.3.
2/05/2010
2
Settlement Meter Data Management Protocols
1 Scope
This document will serve as a definitive Resource concerning the expected responsibilities,
duties, standards, processes, and liabilities with regard to the Meter Participants for the SPP
Market Settlement Meter Data.
2 Purpose
This document will provide the standards by which the Metering Agent, on behalf of the Meter
Participants and Settlement Areas (Control Areas), 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 Market.
3 Definitions
The terms used in this document are defined in the SPP Market Glossary. Please refer to that
document for clarification of terms used in this document.
4 Meter Participants
This document will define what is expected of the Meter Participant with regards to their
Settlement Locations and/or Net Actual Interchange data.
4.1 Responsibilities
The Meter 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 Market Settlements.
At all times, SPP maintains a financial, legal and operational relationship with the Meter
Participant, and not the Metering Agent.
4.2 Metering Agent(s) Designation
The Meter Participant must designate a Metering Agent for each of its Settlement Location(s)
and/or Net Actual Interchange(s) through the registration process. The Meter Participant will be
responsible for any and all data supplied by its designated Metering Agent.
The Meter Participant can have more than one Metering Agent, but only one designated
Metering Agent per Settlement Location or Net Actual Interchange value reported.
SPP will at all times use the data provided by the Metering Agent until such time as the Meter
Participant revokes the designation of an entity as its Metering Agent and replaces that entity
with a substitute entity.
Any dispute between the Metering Agent and the Meter Participant concerning the accuracy of
values reported to SPP shall be resolved between the two parties absent the involvement of SPP.
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5 Metering Agent
The Metering Agent is expected to fulfill the Meter Participant’s responsibility for submitting
Settlement Location and/or Net Actual Interchange data for which it is responsible and
registered.
The Metering Agent will adhere to the standards for calculating and reporting Settlement data as
defined in this document.
The Metering Agent will act on behalf of the Meter Participant to provide Settlement meter data
to SPP, the Meter Participant, and the entity responsible for residual Load.
6 Data Format
The Settlement Data must be submitted according to the following conventions.
6.1 Unit of Measure


Settlement Meter Data must be submitted in hourly intervals.
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.
 Settlement Location data can be submitted in fractional MWhs.
 Net Actual Interchange for Settlement/Control Areas must be submitted in whole
MWhs.
6.2 Sign Convention of Data


Settlement Locations:
 Net Injection into the SPP Transmission System will be negative [-].
 Net Withdraws out of the SPP Transmission System will be positive [+].
Settlement/Control Area Net Actual Interchange:
Net Actual Interchange will be reported based on the Settlement Area/Control 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 (Appendix D). The metering used for data
submission must meet all SPP interconnect guidelines.
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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 E)
for electronic format of submissions.
All data values are to be supplied to SPP as “net” values. In and Out Values are
netted.
7 Settlement Meter Data Types
There are three basic types of hourly interval Settlement Data required for the SPP Market.
 Settlement Locations:
o Resources (generation)
o Loads
 Settlement Area: Net Actual Interchange.
7.1 Resources (Generation) Metering
7.1.1 Net
Resource (Generator) Settlement Location data will be provided as net at the SPP Node.
According to the sign convention, a negative [-] value will indicate a net injection at the SPP
Node, where a positive [+] value will indicate a net withdrawal at the SPP Node (e.g., auxiliary
Load not covered by generation gross output) for that Settlement Location. The “net” shall be
determined by the “gross” output (reflected as a negative number) plus the unit auxiliary power
and applicable losses.
When metering limitations require “gross” values to be used, the “gross” to “net” calculation
method must be mutually agreed upon between SPP, Meter Participant, and Metering Parties.
7.1.2 Joint Owned Unit (JOU) Generation
JOU Settlement Location data reporting must be consistent with the JOU registration outlined in
Section 11.2.4.
7.1.3 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 document for the complete loss compensation requirements.
7.2 Load Metering
7.2.1 General
Load data must be submitted in 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.
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7.2.2 Load Loss Compensation
Metering for a Load must be compensated for any distribution and transmission losses.
When the meter is not at the SPP Node, the meter value must be loss compensated for losses up
to the SPP Node.
The SPP Node meter value will also be loss compensated by the Host Transmission Owner’s
SPP Transmission Tariff Attachment M Loss Percentage, when applicable.
Please reference Section 9 of this document for the complete loss compensation requirements.
7.2.3 Residual Load
Residual Load is the Settlement Area NAI plus sum of all Resource Settlement Locations
excluding all other Settlement Locations reported separately.
Residual Load is calculated slightly different from other Load Settlement Locations. The
calculation for Residual Settlement Location does not include the SPP Transmission Tariff
Attachment M Loss Percentage.
Residual Load is submitted in the same manner are other Settlement Locations for Loads.
7.2.4 Behind-the-Meter Generation
When a Market Registered generator is electrically located behind a load settlement location
meter the total load will be calculated by summing the load meter and the generator meter. The
amount of energy added to the Load settlement shall be without the addition of losses, as it has
no burden upon the transmission system.
7.2.4 Adjustments for Demand Response
The Meter Agent for any Load Settlement Location within which a DRR is located must gross up
the meter data submittal of the Load Settlement Location by the hourly integrated ARP of the
VDD Resource. This is to prevent double payment for the same EIS since the demand reduction
is settled as Resource output.
7.3 Net Actual Interchange (NAI)
7.3.1 General
There are three groups of data required by the Settlement Area to facilitate the SPP Market
Settlements: Net Actual Interchange (NAI) for 1) the entire Settlement Area, 2) 1st Tier NAI
with each Non-SPP Control Area, and 3) NAI with each SPP Settlement Area.
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Settlement Area NAI is typically equal to Control Area NAI, unless more then one Settlement
Area has been defined and approved by SPP within a single Control Area. Each Settlement
Areas is required to report NAI with all other Settlement/Control Areas. Please note that
Settlement Locations are not Settlement Areas.
The NAI is to only include SPP data. If a Control Area has Load in a non-SPP Transmission
Owner System, that interchange is to be excluded from the values reported.
This meter data must be submitted in hourly intervals according to the sign convention. NAI
reported based on the Settlement Area’s prospective. See Section 6: Data Format for sign
convention.
7.3.2 Settlement Area Net Actual Interchange (SA NAI)
The Settlement Area NAI is needed for the Calibration function of Settlements. SA NAI is the
net of all Settlement Area Interconnections with Non-SPP Control Areas and SPP Settlement
Areas. If a Settlement Area Point of Interconnection is not at the meter location, loss
compensation is needed unless all Metering Parties have agreed to another method. The
Settlement Area Metering Agent will report SA NAI.
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
7.3.3 1st Tier NAI with Non-SPP Control Area (1st Tier Non-SPP)
This value is a subset of SA NAI. This is the sum of all meters with a single Control Area that is
not a SPP member Control Area/Settlement Area. The SPP Market Settlement Area is required
to report each individual net NAI with all Non-SPP Control Areas with whom they are
connected.
NAI between a 1st Tier Non-SPP Control Area and a SPP Settlement Area will be provided by
the SPP Settlement Area Meter Agent only.
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SPP
Settlement
Area A
Non-SPP
Control
Area 1
SPP
Settlement
Area B
Sum of all Points of Interconnection between
Settlement Area A and a Non-SPP Control Area
7.3.4 NAI with SPP Settlement Area
This value is a subset of SA NAI. This is the sum of all meters with a single SPP Settlement
Area (Settlement Area are only within a SPP Control Area). The SPP Market Settlement Area is
required to report each individual net NAI with all SPP Settlement/Control Areas with whom
they are connected.
NAI between two SPP Settlement Areas will be provided by both SPP Settlement Area Metering
Agents. A Control Area is the Settlement Area unless more then one Settlement Area has been
defined and approved within a single Control Area by SPP.
SPP
Settlement
Area A
Non-SPP
Control
Area 1
SPP
Settlement
Area B
Sum of all Points of Interconnection between
Settlement Area A and a SPP Settlement Area
7.3.5 Substitution of NSI for missing NAI Metering Data
In the event that a Meter Agent fails to submit Net Actual Interchange metering data, SPP will
substitute the hourly integrated Net Scheduled Interchange (NSI) for Net Actual Interchange.
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8 Settlement Location Anatomy
8.1 General
These sections describe standards for providing meter data under the following conditions:








The actual meter location can be on a distribution voltage system or transmission
voltage system.
The physical meter is not at the defined Meter Settlement Location.
Aggregation of multiple Meter Settlement Locations for reporting a Settlement
Location.
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.
A SPP Node will be at the point of interchange with the facilities under the SPP
Transmission Tariff.
A Meter Settlement Location quantity is the value determined for a Meter
Settlement Location plus applicable SPP Transmission Tariff Attachment M
Losses for Loads. The SPP Node and Meter Settlement Location values are equal
for Resources.
A Settlement Location includes one or more Meter Settlement Locations. A
Settlement Area includes one or more Settlement Location(s). Settlement
Location(s) meter data is a component of the Settlement billing process.
Settlement Location meter data reported is effectively at a Resource bus (including
transmission losses).
8.2 Making of a Settlement Location
A Settlement Location is mad up of one or more Meter Settlement Locations.
A Meter Settlement Location is made of only one SPP Node. A SPP Node is made of only one
Meter. A Meter Settlement Location is simply a single Meter compensated for Losses, if
applicable.
Loss Compensation methods will be addressed later in this document.
8.2.1 Resource Settlement Locations
The following diagram provides a one-line view the Settlement Location anatomy for a
Resource.
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M
NODE & Meter
Settlement
Location
M
NODE & Meter
Settlement
Location
M
A2
A1
Transmission
Owner
Network
Transmission
Owner
Network
M
NODE & Meter
Settlement
Location
A3
Transmission
Owner
Network
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 Node Point.
 Transformer No Load Loss
 Transformer Full Load Losses
 Distribution Losses
 Transmission losses (excluding SPP Transmission Tariff Attachment M Losses)
The following diagram illustrates the components of the Settlement Location. 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.
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8.2.2 Load Settlement Locations
The following diagram provides a one-line view the Settlement Location anatomy for a
Resource.
SPP Transmission System
Meter Settlement Location
L1
L2
Transmission
Owner
Network
Transmission
Owner
Network
X
Y1
M
Ln
L3
Transmission
Owner
Network
Transmission
Owner
Network
Yn
Y2
NODE
NODE
NODE
M
M
M
L1...Ln = Load Withdrawal Value
L1 = X + (SPP Transmission Tariff Attachment M Losses)
L2..Ln = Y1..Yn + (SPP Transmission Tariff Attachment M Losses)
X = Load Withdrawal Node 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 Node Point.
 Transformer No Load Loss
 Transformer Full Load Losses
 Distribution Losses
 Transmission losses (excluding SPP Transmission Tariff Attachment M Losses)
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The following diagram illustrates the components of the Settlement Location. 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.
8.2.3 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 Meter 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.
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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
Load
Actual
Meters
4
Meters included in Coordination on Methods used with all entities
Settlement Location for Load x for meter x
A
A, B, C, D
Load B
Meter C
Load C
Meter D
Load D
Meter A and B
B
2
C, F
Load A
Meter C
Load D
Meter F
C
2
D, E
Load A
Meter D
Load D
Meter E
D
8
A, B, E, F,
Load A
Meter A and B
Residual
1, 2, 3, 4
Load B
Meter F
Load
Load C
Meter E
Others
Meters 1, 2, 3, 4
Others: defined as another Load Settlement Location, Control Area, and seam with another RTO/ISO
Settlement Area Boundary would be equal to the sum of meters 1, 2, 3, and 4 which is Net Actual
Interchange for the Settlement Area and/or Control Area.
9 Loss Compensation for Settlement Locations
9.1 General
The Metering Agent will submit Settlement Location data for Resources and Loads with the
applicable compensations. Load Settlement Locations may have line losses, transformer stepRev. 0.b
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downs, shared metering, etc. Resource 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 Meter Participants along with their Metering Agent will be responsible for appropriate meter
data adjustments and submissions.
9.2 Loss Compensation Types
9.2.1 Flat Percentage
This adjustment is made on the value delivered from the Meter to an external system and not in
the Meter. This is the typical type of loss compensation. The percentage will be an agreed upon
value between the metering parties and applied as shown below:
Gen _ Injection _ Node _ value  meter _ value  1  adjustment _ percentage
Load _ Withdrawal _ Node _ value  meter _ value  1  adjustment _ percentage
9.2.1.1 Flat Percentage Groups
There are two loss groups to consider: 1) Losses prior to the SPP Node and 2) Losses under the
SPP Transmission Tariff Attachment M from the SPP Node to the Meter Settlement Location.
9.2.1.2 Losses Prior to the SPP Node
There are several elements that can require loss compensation prior to the SPP Node. A couple
of example of this is: 1) Meter is located on the distribution system and needs to be adjusted to
the SPP Node and 2) Meter is located on the transmission system not at the SPP Node and needs
to be adjusted to the SPP 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 %).
If you have losses prior to the SPP Node and Attachment M Losses, these are to be calculated in
separate stages. Calculate the SPP Node with losses, and then calculate the Attachment M
Losses to obtain the Meter Settlement Location value.
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SPP
Node
Meter
Load
12kV
69-12kV Transformer
Losses across Transformer = 5%
69kV*
Example 1 – Loss Compensation to SPP Node when Meter is on Distribution System
Loss Compensation to SPP Node – Example 1 Assumptions:
 Meter is on distribution system @ 12 kV
 Transformer between distribution and transmission system requires compensation for
a transmission voltage at SPP Node.
 Actual meter reads 20000 kWh.
 Transformer loss is 5%.
 Transmission owner has modeled their network with transmission voltage at 69kV.
Calculating from Meter to SPP Node:
 Actual meter reads 20000 kWh divided by (1- 5%). 20000/(1–0.05) or 20000/0.9500
 SPP Node Value = 21052.631 kWh
 All resolution below kWh of 21052 is dropped
 If Truncate/Carry applied, convert to whole MWhs = 21 and carry fractional MWhs
or 052 kWh to next hour
 This rule can be applied when distribution line losses are required along with
transformer losses.
 The Meter 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 SPP Node value.
Calculating from SPP Node to Meter Settlement Location
 SPP Node Value divided by (1-Attachment M Loss Percentage will equal the Meter
Settlement Location Value.
 Reference the SPP Transmission Tariff Attachment M for the Transmission Owners
listed Loss Percentage to be used.
Calculating Aggregation of Meter Settlement Locations to report Settlement Location
 A Metering Agent can combine two or more Meter Settlement Locations for Loads to
report the registered Settlement Location.
 A Metering Agent may combine two or more Meter Settlement Locations for
Resources as long as all the combined MSLs are electrically equivalent.
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SPP
Node
Meter
Load
69kV*
Line Losses of 2%
Example 2– Loss Compensation to SPP Node when Meter and SPP Node not at same location
Loss Compensation to SPP Node – Example 2 Assumptions:


Meter is on transmission system @ 69kV
B
The SPP Node is not at the same location as the meter. (i.e. losses on line between
meter and SPP Node will be applied to provide the correct value at the SPP Node)
 Actual meter reads 20000 kWh.
 Line losses between meter and SPP Node is 2%
 This 69kV line starting at the SPP Node is under the SPP Transmission Tariff.
Calculating from the Meter to the SPP Node value:
 Actual meter reads 20000 kWh divided by (1- 2%)
 20000 / (1 – 0.02) or 20000 / 0.9800
 SPP Node value = 20408.163 kWh
 All resolution below kWh of 20408 is dropped
 If Truncate/Carry applied, convert to whole MWhs = 20 and carry fractional MWhs
or 408 kWh to next hour.
Calculating from SPP Node to Meter Settlement Location
 SPP Node Value divided by (1-Attachment M Loss Percentage will equal the Meter
Settlement Location Value.
 Reference the SPP Transmission Tariff Attachment M for the Transmission Owners
listed Loss Percentage to be used.
Calculating Aggregation of Meter Settlement Locations to report Settlement Location
 A Metering Agent can combine two or more Meter Settlement Locations for Loads to
report the registered Settlement Location.
 A Metering Agent may combine two or more Meter Settlement Locations for
Resources as long as all the combined MSLs are electrically equivalent.
9.2.1.3 Losses from SPP Node to Meter Settlement Location
Loads within a Settlement Area will be adjusted based upon the SPP Transmission Tariff
Attachment M loss percentage for the Transmission Owner. The calculation for the Meter
Settlement Location value is: SPP Node Value divided by (1-Attachment M Loss Percentage).
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9.2.1.4 Residual Load and Attachment M Losses
It is recognized that Residual Load calculation already includes all remaining Load and losses
within a Settlement Area; therefore, Attachment M losses are not to be added to the SPP Node
value of the Residual Load.
9.2.2 Engineered Adjustment with Assumptions
This type of adjustment is made on the meter quantities received by the external system using the
formulas shown below. These calculations would be completed in an EMS type system.
Gen _ Injection _ Node _ value  meter _ value  1  FLWL%   NLL _ const
Load _ Withdrawal _ Node _ value  meter _ value  1  FLWL%   NLL _ const
CTP VTP
NLL _ const  NLWLMTR  1hour 

CTS VTS
The variables that are used in these formulas shall be calculated as described in Section 7.9.3 of
the Meter Technical Standards (Appendix D) by either an engineer or a metering professional.
This method does not complete the entire loss compensation required for Loads. If you use the
Engineering Adjustment method in the meter or in the Meter Agents meter data calculation
systems, you will also need to add SPP Transmission Tariff Attachment M Losses on the Flat
Percentage Method.
9.2.3 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
7.9.3.7 shall be used in the meter. These shall be calculated as described in Section 7.9.3 of the
Meter Technical Standards (Appendix D) by either an engineer or metering professional. Refer
to Appendix D for the methods of calculation within the meter.
This method does not complete the entire loss compensation required for Loads. If you use the
Engineering Adjustment method in the meter or in the Meter Agents meter data calculation
systems, you will also need to add SPP Transmission Tariff Attachment M Losses on the Flat
Percentage Method.
9.3 Truncate and Carry Application
If Truncate and Carry is required for reporting Settlement/Control Area data the following
sections apply.
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9.3.1 NERC interchange and Whole MWhs
If a meter is for a Control/Settlement Area boundary, Truncate and Carry must be applied to
meet NERC Metered and Scheduled Interchange requirements of whole MWhs across Control
Area Boundaries.
9.3.2 Truncate and Carry Process
At any actual meter location where the output is in a unit of measure less then whole MWhs, the
Truncate and Carry process can be applied to report whole MWhs.
The Truncate and Carry is not required for intra-control area interconnections. The Control Area
Interconnections are required to be in whole MWhs.
If the Truncate and Carry process is applied, it must be performed on each hour to report in
whole MWhs. Any fractional MWh must be carried forward to the next hour. This process
allows for consistency of data processing across the SPP footprint.
If the Meter Participant is aggregating multiple Meter Settlement Locations for a Settlement
Location, the Metering Agent must sum all Meter Settlement Locations together before applying
the Truncate and Carry process to calculate the reported Settlement Location.
Hour
Endin
g
HE 01
HE 02
HE 03
HE 04
Actual
MWhs
20.500
19.400
18.800
20.200
Table 2 – Example of Truncate and Carry
Carry Forward
Carry Forward Formula
kWh (started at 0)
500
900
700
900
Reported Meter
Settlement Value
0 + 500
500 + 400
900 + 800 = 1.700*
700 + 200
20
19
19
20
*the whole MWh 1 of the 1.700 is added to the 18 for a reported 19 and the 700 is carried forward
10 Settlement Data Reporting
10.1 Submission Timeline
All Resource and/or Load 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 4 day holiday as discussed in
section 11.6.4 of these Protocols, reported values for an operating day must be received by Noon
according to the following schedule on the business day prior to:




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day 5 calendar day for inclusion in Initial Settlement statement.
day 45 calendar day for inclusion in Final Settlement statement.
day 75 calendar day for inclusion in Resettlement 1 statement.
day 105 calendar day for inclusion in Resettlement 2 statement.
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








day 135 calendar day for inclusion in Resettlement 3 statement.
day 165 calendar day for inclusion in Resettlement 4 statement.
day 195 calendar day for inclusion in Resettlement 5 statement.
day 225 calendar day for inclusion in Resettlement 6 statement.
day 255 calendar day for inclusion in Resettlement 7 statement.
day 285 calendar day for inclusion in Resettlement 8 statement.
day 315 calendar day for inclusion in Resettlement 9 statement.
day 345 calendar day for inclusion in Resettlement 10 statement.
day 375 calendar day for inclusion in Resettlement 11 statement.
10.2 Meter Data Exchange and Submission
Settlement Location meter data shall be entered, modified and retrieved solely via the XML
specification for submission of hourly interval Settlement Data.
The Settlement Location meter data will be available via the portal and include the files uploaded
from the Metering 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 Meter Participant.
Other parties may have access to Settlement Location data, as allowed by SPP.
10.2.1 Actual Meter Data (Idata)
If a Meter is installed to include interval data capabilities, then the Metering 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. 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.
2. 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.
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c. Estimated data can be short-term or long-term.
i. Short-term would be the use of a temporary estimate, until actual
interval data can be obtained, in order to meet a data reporting
timeline. Once the actual data is obtained, it should be resubmitted
as (A)ctual data, not (E)stimated.
ii. 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.
d. Loss Compensation applies to all types of estimated meter interval data.
3. Missing (9) - Missing meter interval data:
Do not use this type. If data is missing, estimate the data and submit as “E”.
10.2.2 Profile Data (Pdata)
Profile Data is meter data without interval capabilities. This includes meters that only have
meter dial reads without interval telemetering. Therefore, only total usage of a period of time is
available, no hourly intervals.
Profile Data is submitted as Channel 1 as outlined in the XML Data Submission Standards.
All Profile data must be reported with applicable Loss Compensation.
All reporting of Profile Data must be submitted based on the same Settlement Data Submission
Timeline.
In order to meet the submission timeline, it is understood that a forecasted hourly usage will be
provided. Once the actual usage of a specific time period is read at the meter, Profile data should
be resubmitted to match the total usage recorded on the meter(s), plus applicable losses. This
resubmission should be reported before the Final Settlement Statement Data Reporting Timeline.
10.2.3 Alternate Settlement Meter Data
Under circumstances where one or more Metering 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 11.4.1.3 for treatment of substitution data for calibration purposes.
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11 Data Source and Estimating
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,
Use a meter data estimating option.
11.1 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 10.2.1.1.
11.1.1 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.)
11.1.2 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.
11.2 Estimated Meter Data (Idata – Estimated)
11.2.1 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 10.2.1.2.
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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.
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
Data Shaping: This method uses data from previous and/or
subsequent hours around the missing data to estimate the use
during the missing hours.
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.).
11.2.2 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”.
12 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.
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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.
12.1 Data Types and Verification Methods
The listing that follows is not complete, but represents the majority of types with verification
method.
12.1.1 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.
12.1.2 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.
12.1.3 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.
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12.1.4 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.
The source of the ICCP would be one of the types listed above and the source would be
responsible for the verification.
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.
12.1.5 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.
12.2 Periodicity of Verification
12.2.1 Telemetered Pulses via Remote Terminal Unit (RTU)
Verification of telemetered meter data values shall be performed monthly.
12.2.2 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.
12.3 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.
12.3.1 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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12.3.2 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.
12.3.2.1 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.
12.3.2.2 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.
12.3.2.2.1 Requirement for Resubmission
If the Settlement Location value difference is greater then 100 MWhs over a verification period,
then the Settlement Location values must be corrected. See Section 13: Settlement Location
Value Corrections.
12.3.2.2.2 Good Utility Business Practices/Contractual Requirements
If the error value is not greater then 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.
13 Real Time Data Reporting by Settlement/Balancing
Authority
These values are to be reported as ICCP reliability data to SPP. This includes all Resources
(Generation) within the SPP Settlement/Control Area that has real time tele-metering available.
It does not exclude Resources (Generators) not operated by the company providing Control Area
services.
Data is required for all SPP Market Resources (generation), Loads, and Settlement/Control Area
NAI pairings. This data is used for market real-time operations, not settlement processing.
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Unit power output (MW)
Unit MVar output
Current Resource Capability (MW)
Current on/off line status
Current voltage regulator status (on/off)
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
Settlement Area NAI
14 Record Retention
The Meter 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:
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Raw Meter values
Loss Percentages as agreed to by Metering Parties for each meter.
Compensation Methodology
Truncate and Carry Process and Results
Meter Settlement Location values
Settlement Location values
Meter testing document
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 seven years for independent auditing purposes by
the SPP or their designated party.
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