Current Revision market... · Web viewA Resource Offer may be submitted for each Combined Cycle Resource combustion turbine and/or steam turbine and each component will be dispatched

WESTERN ENERGY IMBALANCE SERVICES MARKET PROTOCOLS

By Market Design

Published on 03/24/2020

Version .11a

WEIS Market Protocols

CURRENT REVISIONRevision Date Description of Modification

.1a 1/27/2020 Initial draft

.2a 2/09/2020 Continued policy development and general editing

.3a 02/13/2020 Edits to capture discussion from WPRTF meeting on 2/11/2020 and other general clean-up

.4a 02/20/2020 Edits to capture discussion from WPRTF meeting on 2/13/2020

.5a 02/28/2020Edits to capture discussion from WPRTF meeting on 2/21/2020 and 2/25/2020. Accepted changes reviewed by group and many typographical changes

.6a 03/02/2020Edits to capture discussion from the WPRTF on 02/28/2020 meeting. Typographical edits. Beginning to incorporate and cross check terms.

.7a 03/05/2020 Edits to accept typographical changes, reviewed to address action items completed.

.8a 03/19/2020

Edits to accept typographical changes, regulatory and legal edits to address use of Asset Owner, SPP edits to update language related to Combined Cycle Resources, incorporated comments and edits provided by MEAN, updated the glossary, updated exhibits.

.9a 03/20/2020

Edits to accept changes made by the WPRTF during the 3/20/2020 net-conference, updates to the glossary, updates to exhibits, accepted language proposed by SPP and reviewed by the WPRTF during the 03/20/2020 net-conference.

.10a 03/23/2020Grammatical and typographical error clean-up, added final exhibits. Cleaned-up incorrect settlements calculations in A.3.2.

.11a 03/24/2020Closed final action items and removed MEAN comments since calls are scheduled to address. Made clean-up changes to correct settlement calculation errors.

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Southwest Power Pool, Inc.

1 TABLE OF CONTENTSCURRENT REVISION..................................................................................................... ILIST OF EXHIBITS......................................................................................................151 GLOSSARY..........................................................................................................152 INTRODUCTION..................................................................................................302.1 Related Documents and Training.........................................................303 WESTERN ENERGY IMBALANCE SERVICE (WEIS) MARKET OVERVIEW................303.1 WEIS Market........................................................................................314 WEIS MARKET PROCESSES.................................................................................324.1 System Requirements..........................................................................33

4.1.1 Forecasting..........................................................................................334.1.1.1 Short-Term and Mid-Term Load Forecasting........................................33

4.1.1.1.1 Conforming Load.............................................................................334.1.1.1.2 Non-Conforming Load.....................................................................334.1.1.1.3 Losses.............................................................................................344.1.1.1.4 Demand Response Adjustments.....................................................344.1.1.1.5 Load Distribution.............................................................................34

4.1.1.2 Wind-Powered Generation Resource Output Forecasts........................344.1.1.3 Wind-Powered Generation Resource Data Requirements....................354.1.1.4 Solar-Powered Generation Resource Output Forecasts........................394.1.1.5 Solar-Powered Generation Resource Data Requirements....................39

4.1.2 Violation Relaxation Limits...................................................................444.1.2.1 Impact of VRLS on SCED......................................................................45

4.1.2.1.1 Modification To VRLs.......................................................................464.1.3 Outage Scheduling and Reporting.......................................................47

4.2 Offer Submittal....................................................................................474.2.1 Resource Offer Parameters..................................................................474.2.2 Resource Status Used for Resource Plans and Ancillary Service Plans 514.2.2.1 Commitment Status for the Resource Plan..........................................51

4.2.3 Resource Modeling...............................................................................514.2.3.1 Dispatchable Demand Response (DDR) Resource...............................524.2.3.2 Combined Cycle Resource...................................................................53

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4.2.3.3 Dispatchable Variable Energy Resources.............................................534.2.3.4 Non-Dispatchable Variable Energy Resources and Partial Participation

Resources............................................................................................554.2.4 Energy Schedules................................................................................55

4.3 Supply Adequacy Analysis...................................................................564.3.1 Purpose................................................................................................564.3.2 Inputs...................................................................................................564.3.3 Formulaic Descriptors..........................................................................564.3.3.1 Upward Supply Adequacy....................................................................564.3.3.2 Downward Supply Adequacy................................................................57

4.3.4 Types...................................................................................................574.3.4.1 Capacity...............................................................................................574.3.4.2 Deliverability........................................................................................58

4.3.5 Notifications and Resolution................................................................584.4 Operating Day Activities......................................................................59

4.4.1 Western Real-Time Balancing Market..................................................594.4.1.1 WRTBM Inputs......................................................................................60

4.4.1.1.1 Pre-Operating Hour Inputs..............................................................604.4.1.1.2 In-Operating Hour Inputs................................................................604.4.1.1.3 Control Status.................................................................................61

4.4.1.2 WRTBM Execution................................................................................624.4.1.3 WRTBM Results....................................................................................634.4.1.4 Out-of-Merit Energy (OOME) Disptach..................................................63

4.4.1.4.1 Fixed OOME....................................................................................644.4.1.4.2 OOME Cap and OOME Floor............................................................65

4.4.1.5 Congestion Management.....................................................................664.4.2 Energy Deployment.............................................................................664.4.2.1 Dispatchable Variable Energy Resource Dispatch................................674.4.2.2 Non-Dispatchable Variable Energy Resource and Partial Participation

Resource Dispatch...............................................................................674.4.2.3 Reserve Sharing Group Scheduling Procedures...................................674.4.2.4 Uninstructed Resource Deviation.........................................................68

4.4.2.4.1 URD Exemptions.............................................................................694.5 Post Operating Day and Settlement Activities.....................................70

4.5.1 Settlement Sign Conventions...............................................................714.5.2 Commercial Model...............................................................................72

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4.5.2.1 Nodes...................................................................................................724.5.2.2 Pricing Nodes.......................................................................................72

4.5.2.2.1 Aggregated Pricing Nodes...............................................................734.5.2.3 Meter Data Submittal Locations (MDSL)...............................................734.5.2.4 Settlement Locations...........................................................................734.5.2.5 Asset Owners.......................................................................................734.5.2.6 Market Participants..............................................................................74

4.5.3 Calculation of LMPs and LMP Components...........................................764.5.3.1 LMP Calculations and LMP Components...............................................76

4.5.4 Settlement Location LMPS and LMP Components................................764.5.4.1 Calculation of LMP at a Load APNode Settlement Location..................774.5.4.2 Calculation of LMP at an External Interface Settlement Location.........78

4.5.5 Precision and Rounding........................................................................784.5.6 Energy Imbalance Market Settlement..................................................794.5.6.1 Energy Imbalance Service Amount......................................................80

4.5.6.1.1 Calculate Adjusted Meter Data.......................................................804.5.6.1.2 Calculate Residual Amount and Calibration to Loads Within SA.....824.5.6.1.3 Calculate Billable Meter Data..........................................................824.5.6.1.4 Calculate Imbalance Energy by Asset Owner for Native Load

Hedging..........................................................................................834.5.6.1.5 Calculate Imbalance Energy Unhedged Quantity............................864.5.6.1.6 Calculate Energy Imbalance Service Amount.................................86

4.5.6.2 Real-Time Out of Merit Amount............................................................864.5.6.3 Uninstructed Resource Deviation Amount...........................................884.5.6.4 Miscellaneous Amount.........................................................................894.5.6.5 Revenue Neutrality Uplift Distribution Amount....................................89

4.5.7 Settlement Statement Process.............................................................904.5.7.1 Meter Data...........................................................................................904.5.7.2 Daily Settlement Statement.................................................................914.5.7.3 Settlement Statement Access..............................................................924.5.7.4 S7 Scheduled Settlement Statements..................................................924.5.7.5 S53 Scheduled Settlement Statements................................................924.5.7.6 S120 Scheduled Settlement Statements..............................................934.5.7.7 Resettlement Statements....................................................................934.5.7.8 Settlement Timeline.............................................................................94

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4.5.8 Settlement Invoice...............................................................................984.5.8.1 Timing and Content of Invoice.............................................................984.5.8.2 Invoice Calendar................................................................................1004.5.8.3 Holiday Invoice Calendar...................................................................100

4.5.9 Disputes.............................................................................................1014.5.9.1 Dispute Submission Timeline.............................................................1014.5.9.2 SPP Dispute Processing......................................................................102

4.5.9.2.1 Dispute Status..............................................................................1034.5.10 Invoice Payment Process...................................................................1054.5.10.1..................................................................Overview of Payment Process

...........................................................................................................1054.5.10.2..................................................................Invoice payments Due to SPP

...........................................................................................................1054.5.10.3........................................................SPP Payments to Invoice Recipients

...........................................................................................................1054.5.11 Billing Determinant Anomolies...........................................................106

5 WEIS MARKET REGISTRATION..........................................................................1065.1 Registration of Resources..................................................................108

5.1.1 Responsibilities of the Resource Market Participant..........................1095.1.2 Common Bus......................................................................................1095.1.3 Dispatchable Demand Response Resources......................................1105.1.4 Combined Cycle.................................................................................1105.1.5 Dispatchable Variable Energy Resource............................................1115.1.6 Non-Dispatchable Variable Energy Resource.....................................1115.1.7 Resources External to the WEIS Market Footprint..............................1125.1.7.1 Resource External to the WEIS Market Footprint Pseudo-Tying in.....112

5.1.8 Resource Auxiliary Load Modeling.....................................................1125.2 Registration of Load...........................................................................113

5.2.1 Responsibilities of the Load...............................................................1145.2.2 Non-Conforming Load........................................................................1145.2.3 Demand Response Load Asset...........................................................1155.2.4 Dispatchable Demand Response Load Settlement Location..............1155.2.5 Loads External to the WEIS Market Footprint Pseudo-Tying in...........115

5.3 Registration of the Meter Agent.........................................................1165.4 Network and Commercial Model Updates..........................................1165.5 Naming Conventions for WEIS Market Assets....................................118

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5.5.1 General Requirements.......................................................................1195.5.2 Resource Settlement Location/Asset Name.......................................1205.5.3 Load Settlement Location Name/Asset Name....................................1205.5.4 Tie Interface Meter Data Submittal Location (MDSL) Name...............1215.5.5 Source/Sink Name..............................................................................1225.5.6 Market and/or Reliability Data Developed and Named by SPP...........123

6 MARKET SYSTEM OUTAGE AND ERROR HANDLING..........................................1236.1 Market System Outages.....................................................................1236.2 Procedures for Correcting LMPs Resulting from Market Software and Data Errors 124

6.2.1 Procedures for Revising Prices in Response to Market Sofware and Data Errors 1246.2.1.1 Notice to Market Participants and the Public.....................................1256.2.1.2 Process for Recalculating WEIS Market Prices....................................1256.2.1.3 Compensatory Payments to Market Participants...............................125

6.2.2 Disputes and Resettlement Provisions...............................................1257 MARKET MONITORING AND MITIGATION..........................................................1267.1 Market Monitoring Plan......................................................................126

7.1.1 Purpose and Objective.......................................................................1267.1.2 Resolution of Conflicts.......................................................................1277.1.3 Independent Market Monitor..............................................................1277.1.3.1 Staffing and Resources......................................................................1277.1.3.2 Relationships and Notifications..........................................................1277.1.3.3 Standards of Conduct.........................................................................128

7.1.4 Market Monitoring..............................................................................1287.1.4.1 Markets to be Monitored....................................................................1297.1.4.2 Monitoring Activities..........................................................................1297.1.4.3 Instances of Market Power.................................................................1317.1.4.4 Market Participant Behavior Warranting Possible Mitigation..............131

7.1.5 Inquiries.............................................................................................1327.1.5.1 Requests............................................................................................1327.1.5.2 Conducting Inquiries..........................................................................1327.1.5.3 Reporting...........................................................................................132

7.1.6 Compliance and Corrective Actions...................................................1337.1.6.1 Compliance........................................................................................1337.1.6.2 Corrective Actions for Market Designs...............................................133

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7.1.7 Reporting...........................................................................................1347.1.7.1 Annual State of the Market Report.....................................................1357.1.7.2 Monthly, Quarterly and Annual Reports.............................................1357.1.7.3 Communication of Market Monitoring Reports...................................1357.1.7.4 Other Reports.....................................................................................136

7.1.8 Performance Indices, Metrics and Screens.........................................1367.1.8.1 Development.....................................................................................136

7.1.9 Referrals to the Commission..............................................................1367.1.10 Market Manipulation..........................................................................1367.1.11 Monitoring for Potential Transmission Market Power Activities..........1377.1.12 Data Access, Collection and Retention..............................................1387.1.12.1..........................................................................................Confidentiality

...........................................................................................................1387.1.12.2........................................................Access to SPP Data and Information

...........................................................................................................1387.1.12.3.................................Access to Market Participant Data and Information

...........................................................................................................1387.1.12.4........................................................Data Created by the Market Monitor

...........................................................................................................1407.1.13 Miscellaneous Provisions....................................................................1417.1.13.1...............................................................................Rights and Remedies

...........................................................................................................1417.1.13.2...................................................................................................Disputes

...........................................................................................................1417.1.13.3........................................................................Review of Market Monitor

...........................................................................................................1417.2 Market Power Mitigation and Monitoring............................................141

7.2.1 Purpose and Objectives.....................................................................1417.2.2 Economic Witholding.........................................................................1417.2.2.1 Mitigate Only in the Presence of Local Market Power.........................1427.2.2.2 Mitigation Measures...........................................................................1427.2.2.3 Mitigation Measures for Energy Offer Curves.....................................1427.2.2.4 Local Market Power Test....................................................................146

7.2.2.4.1 Frequently Constrained Areas.......................................................1467.2.2.5 Additional Mitigation Measures for Resource Offer Parameters.........1477.2.2.6 Market Impact Test............................................................................1497.2.2.7 Mitigated Offer Development Guidelines...........................................149

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7.2.3 Uneconomic Production.....................................................................1507.2.4 Offer Caps and Floors.........................................................................1517.2.5 Physical Withholding..........................................................................1517.2.5.1 Thresholds for Identifying Physical Withholding of Resource Capacity

...........................................................................................................1527.2.5.2 Thresholds for Identifying Physical Withholding of Transmission

Facilities.............................................................................................1537.2.5.3 Sanctions for Physical Withholding....................................................153

7.2.6 Maintenance and Implementation of the Mitigation Protocols...........1538 WEIS MARKET PROCESS AND SYSTEM CHANGE PROCESS...............................154APPENDIX A SETTLEMENT CALCULATIONS AND EXAMPLES...................................158A.1 Introduction.......................................................................................158

A.1.1 Purpose..............................................................................................158A.1.2 Definitions of Terms...........................................................................158

A.2 WEIS Market Model............................................................................160A.2.1 Commercial Model.............................................................................160A.2.1.1 Financial Entities and Relationships...................................................160A.2.1.2 Network Entities and Relationships....................................................162

A.3 Settlement Calculations.....................................................................163A.3.1 Energy Imbalance Service Amount....................................................163A.3.2 Real-Time Out-Of-Merit Amount.........................................................185A.3.3 Uninstructed Resource Deviation Amount.........................................194A.3.4 Miscellaneous Amount.......................................................................205A.3.5 Revenue Neutrality Uplift Distribution Amount..................................208

APPENDIX B NETWORK AND COMMERCIAL MODEL UPDATE TIMING......................216APPENDIX C SETTLEMENT METERING DATA MANAGEMENT PROTOCOLS...............225C.1 Scope.................................................................................................225C.2 Purpose..............................................................................................226C.3 Definitions..........................................................................................226C.4 Market Participants............................................................................226

C.4.1 Responsibilities..................................................................................226C.4.2 Meter Agent(s) Designation...............................................................226

C.5 Meter Agent.......................................................................................227C.6 Data Format.......................................................................................227

C.6.1 Unit of Measure..................................................................................227C.6.2 Sign Convention of Data....................................................................228

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C.6.3 Meter Technical Standards................................................................228C.6.4 Data Submission Standards...............................................................228

C.7 Settlement Meter Data Types............................................................228C.7.1 Resource Metering.............................................................................229C.7.1.1 Generation Loss Compensation.........................................................229

C.7.2 Load Metering....................................................................................230C.7.2.1 General..............................................................................................230C.7.2.2 Load Loss Adjustment........................................................................230C.7.2.3 Residual Load.....................................................................................230

C.7.3 Settlement Area Tie-Lines..................................................................230C.7.3.1 Substitution for Missing Data.............................................................231

C.8 Settlement Location Anatomy...........................................................231C.8.1 General..............................................................................................231C.8.2 Making of a Settlement Location.......................................................232C.8.2.1 Resource and Load Settlement Locations..........................................232C.8.2.2 Overview of Settlement Area Load Settlement Locations..................233

C.9 Loss Compensation............................................................................236C.9.1 General..............................................................................................236C.9.2 Node Loss Compensation Examples..................................................236C.9.2.1 Loss Compensation to Node when Meter is on Distribution System...238C.9.2.2 Methods for Compensation................................................................239C.9.2.3 Loss Compensation to Node when Meter at Different Location..........240C.9.2.4 Loss Compensation to Node – Example 2 Assumptions.....................240C.9.2.5 Transmission and Secondary Line Losses..........................................241

C.9.3 Meter Data Exchange and Submission...............................................241C.9.3.1 Alternate Settlement Meter Data.......................................................242

C.10 Verification Meter SL Values..............................................................242C.11 Real-Time Data Reporting to SPP.......................................................242C.12 Record Retention...............................................................................243APPENDIX D MITIGATED OFFER DEVELOPMENT GUIDELINES.................................243D.1 Introduction.......................................................................................243

D.1.1 About these Guidelines......................................................................243D.1.2 Intended Audience.............................................................................243D.1.3 What is in this Manual........................................................................244D.1.4 Purpose..............................................................................................244

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D.1.5 Mitigated Offer Methodology Approval Process.................................244D.2 Policies for all Resource Types...........................................................245

D.2.1 Heat Rate...........................................................................................245D.2.1.1 Heat Content of Fuel..........................................................................246D.2.1.2 Heat Rate Curve.................................................................................247

D.2.2 Performance Factors..........................................................................247D.2.2.1 Engineering Judgment in Performance Factors..................................248D.2.2.2 Current Methods of Performance Factors...........................................248D.2.2.3 “Like” Resources for Performance Factors.........................................250

D.2.3 Fuel Cost Policies...............................................................................250D.2.3.1 Modifications to Fuel Cost Policies.....................................................251D.2.3.2 Fuel Cost Calculation..........................................................................252D.2.3.3 Total Fuel Related Costs....................................................................253D.2.3.4 Types of Fuel Costs............................................................................253D.2.3.5 Variable Fuel Transportation Equipment............................................254D.2.3.6 Emission Allowances..........................................................................255D.2.3.7 Total Fuel Related Cost Variable Operations and Maintenance..........256

D.2.4 Total Variable Operation and Maintenance Costs..............................256D.2.4.1 Escalation Index.................................................................................257D.2.4.2 Maintenance Period...........................................................................258D.2.4.3 Average VOM Cost.............................................................................258

D.2.5 Mitigated Energy Offer Curve.............................................................259D.3 Nuclear Unit Guidelines.....................................................................260

D.3.1 Nuclear Heat Rate..............................................................................260D.3.2 Performance Factor............................................................................261D.3.3 Fuel Cost............................................................................................261D.3.3.1 Basic Nuclear Fuel Cost......................................................................261D.3.3.2 Total Fuel Related Costs for Nuclear Units.........................................261

D.3.4 VOM Cost...........................................................................................261D.3.4.1 Configuration Addition VOM Cost.......................................................262D.3.4.2 Calculation of the Configuration Addition VOM Cost:.........................262D.3.4.3 Reductions in Total VOM Costs..........................................................263

D.4 Fossil Steam Unit Guidelines..............................................................263D.4.1 Heat Rate...........................................................................................263D.4.2 Performance Factor............................................................................263

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D.4.3 Fuel Costs..........................................................................................264D.4.4 VOM Cost...........................................................................................264D.4.4.1 Configuration Addition VOM Cost.......................................................264D.4.4.2 Calculation of the Configuration Addition VOM Cost..........................265D.4.4.3 Reductions in Total VOM Costs..........................................................265

D.5 Combined Cycle (CC) Guidelines.......................................................266D.5.1 Heat Rate...........................................................................................266D.5.2 Performance Factors..........................................................................266D.5.3 Fuel Cost............................................................................................267D.5.4 VOM Cost...........................................................................................267

D.6 Combustion Turbine (CT) and Reciprocating Engine Guidelines........267D.6.1 Combustion Turbine and Reciprocating Engine Heat Rate.................267D.6.2 Performance Factors..........................................................................268D.6.3 Fuel Cost............................................................................................268D.6.3.1 Combustion Turbine other Fuel-Related Costs...................................268

D.6.4 VOM Costs..........................................................................................268D.7 Hydro Guidelines...............................................................................268

D.7.1 Pumping Efficiency (Pumped Hydro Only)..........................................269D.7.2 Performance Factor............................................................................270D.7.3 Fuel Cost............................................................................................270D.7.3.1 Total Energy Input Related Costs for Pumped Storage Hydro Plant

Generation.........................................................................................271D.7.4 VOM Cost...........................................................................................271

D.8 Demand Response Guidelines...........................................................271D.8.1 Demand Response (DDR) Cost for Behind-The-Meter Generation.....271D.8.2 Dispatchable Demand Response Cost for Demand Reduction...........272

D.9 Wind Guidelines.................................................................................272D.9.1 Foregone Credits................................................................................272D.9.2 VOM...................................................................................................272

D.10 Solar Guidelines.................................................................................273D.10.1 Foregone Credits................................................................................273D.10.2 VOM...................................................................................................273

D.11 Energy Market Opportunity Cost Guidelines......................................274D.11.1 Basis for Opportunity Cost to be included in Mitigated Offers............274D.11.1.1.......................................................Environmental Run-Hour Restriction

...........................................................................................................274

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D.11.1.2...............................................................Physical Equipment Limitations...........................................................................................................274

D.11.1.3................................Non-Regulatory Opportunity Cost: Fuel Limitations...........................................................................................................274

D.11.2 Calculation Method............................................................................275D.11.2.1.........................................Overview of the Opportunity Cost Calculation

...........................................................................................................275D.11.2.2..........................................................Daily Opportunity Cost Calculation

...........................................................................................................276D.11.2.2.1.............................................Step 1: Forecast Hourly Resource LMPs

......................................................................................................276D.11.2.2.2.....Step 2: Calculate the Price-Cost Margin for each Hour of the Day

......................................................................................................277D.11.2.2.3........................Step 3: Determine the Opportunity Cost Component

......................................................................................................278D.11.2.3.................................................Long Term Opportunity Cost Calculation

...........................................................................................................278D.11.2.3.1....Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average

LMPs..............................................................................................278D.11.2.3.2....Step 2: Derive Historical Monthly LMP Basis Differential between

the Resource Settlement Location and the SPP Real-Time Marginal Energy Component of LMP............................................................281

D.11.2.3.3..........Step 3: Derive Hourly Volatility Scalars to Incorporate Hourly Volatility into the LMP Forecast.....................................................284

D.11.2.3.4................Step 4: Create Three Sets of Hourly Forecasted Resource Settlement Location Values..........................................................286

D.11.2.3.5.......................................Step 5: Create a Daily Fuel Volatility Scalar......................................................................................................288

D.11.2.3.6.........................Step 6: Create Three Daily Delivered Fuel Forecasts......................................................................................................289

D.11.2.3.7......Step 7: Create Resource(s) Cost for each of the Three Forecasts......................................................................................................292

D.11.2.3.8.....Step 8: Calculate the Margin for every Hour in the Three Hourly Forecasts......................................................................................294

D.11.2.3.9........................Step 9: Determine the Opportunity Cost Component......................................................................................................297

D.11.2.4................................................Short Term Opportunity Cost Calculation...........................................................................................................298

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LIST OF EXHIBITSExhibit 3-1: WEIS Markets Processes Timeline.......................................................................36

Exhibit 4-1: VRL Values.............................................................................................................48

Exhibit 4-2: Energy Offer Curve Development........................................................................52

Exhibit 4-3: Resource Limit Relationships................................................................................53

Exhibit 4-4: Operating Day Activities Timeline.......................................................................62

Exhibit 4-5: Post Operating Day Activities Timeline...............................................................74

Exhibit 4-6: Example of Commercial Model Relationships....................................................78

Exhibit 4-7: Input Data Precision and Rounding Assumptions..............................................82

Exhibit 4-8: Meter Profiling Example.......................................................................................84

Exhibit 4-9: Settlements Timeline – Non Holiday Example....................................................98

Exhibit 4-10: Settlements Timeline –Holiday Example.........................................................100

Exhibit 4-11: Contents of Notice Dispute Form......................................................................105

Exhibit 5-1: Model Update Implementation Timeline...........................................................122

1 GLOSSARYAffiliate

As defined in the WEIS Tariff

Aggregate Price Node (APNode)

A collection of Price Nodes (PNodes) whose prices are averaged with a defined weighting component to determine an aggregate price.

Ancillary Service


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Ancillary Service Plan


Asset Owner (AO)


Balancing Authority (BA)


Balancing Authority Area (BAA)


Behind-The-Meter Generation


Business Day


Calendar Day


Central Prevailing Time (CPT)


Commercial Model


Commission


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Commitment Status

A parameter submitted as part of a Resource Offer that specifies the option under which the Resource is to be committed.

Common Bus


Confidential Information


Contingency Reserve

As defined in the SPP Tariff.

Control Status

A parameter communicated electronically to SPP by a Market Participant at any time during an Operating Hour indicating a Resource’s ability to follow Setpoint Instructions.

Curtailment


Data Error


Demand Response Load


Dispatch Instruction The communicated Resource target energy MW output level at the end of the Dispatch Interval, rounded to one decimal place.

Dispatch Interval

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Dispatch Status

A parameter submitted as part of a Resource Offer that specifies the option under which the Resource is to be dispatched once the Resource has been committed and becomes a Synchronized Resource.

Dispatchable Demand Response Resource


Dispatchable Maximum Limit


Dispatchable Minimum Limit


Dispatchable Resource


Dispatchable Variable Energy Resource (DVER)

A Variable Energy Resource registered in the WEIS Market that is capable of incrementally dispatched by the Market Operator.

Electrical Node (“ENode”)


Emergency Condition


Energy

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Energy Imbalance Service


Energy Offer Curve

A set of price/quantity pairs that represents the offer to provide Energy from a Resource.

Energy Schedule


Electrical Node (ENode)

A physical node represented in the Network Model where electrical equipment and components are connected.

External Interface

A Settlement Location representing a physical interconnection point(s) between the SPP Balancing Authority Area and an External Balancing Authority Area.

FERC


Imbalance Energy


Interchange Transaction


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Joint Dispatch Transmission Service:


Joint Dispatch Transmission Service Customer


Joint Dispatch Transmission Service Provider


Locational Marginal Price (LMP)


Locational Marginal Price (“LMP”)


Local Emergency Condition


Local Reliability Issue


Manual Dispatch Instruction


Marginal Congestion Component

The calculated portion of the Locational Marginal Price at a Settlement Location representing transmission congestion cost between that Settlement Location and a reference location as calculated under Section 4.5.3.1.

Marginal Energy Component

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The calculated Locational Marginal Price at a reference location.

Market Monitor


Market Participant


Maximum Economic Capacity Operating Limit:


Maximum Capacity Operating Limit


Meter Agent


Meter Data Submittal Location


Meter Settlement Location


Mid-Term Load Forecast

A load forecast developed by SPP on a rolling basis for the next seven days for input into Reliability Unit Commitment.

Minimum Capacity Operating Limit:


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Minimum Economic Capacity Operating Limit


Mitigated Energy Offer Curve

A set of price/quantity pairs that represents the mitigated energy offer, where such offers are developed in accordance with guidelines detailed in Appendix G, to provide Energy from a Resource.

Net Scheduled Interchange (NSI)


Network Model


Non-Conforming Load

Load that cannot be accurately forecasted by SPP because it does not follow a predictable pattern.

Offer

A commitment to sell a quantity of Energy at a specific minimum price such as a Resource Offer at a specific minimum price, where such quantities may be submitted in 0.1 MW increments.

Operating Day


Operating Hour


Operating Reserve

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Operating Tolerance


Out-of-Merit Energy (OOME):


Partial Participation Resource (PPR)


Portal

Internet interface between SPP and its Members.Post Operating Day

The time period starting with the day immediately following the Operating Day.

Price Node (PNode):


PURPA

Public Utility Regulatory Policies Act

Qualifying Facility


Ramp-Rate-Down

A curve specifying MW/minute ramp rates applicable between Resource operating ranges that is used to dispatch Resources in the down direction.

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Ramp-Rate-Up

A curve specifying MW/minute ramp rates applicable between Resource operating ranges that is used to dispatch Resources in the up direction.

Real-Time

The continuous time period during which the RTBM is operated.

Reference Bus

The location on the SPP Transmission System relative to which all mathematical quantities, including shift factors and penalty factors relating to physical operation, will be calculated.

Regulation-Down Quantity

The amount of regulation-down reserve carried by a Resource declared in the Ancillary Service Plan.

Regulation-Up Quantity

The amount of regulation-up reserve carried by a Resource declared in the Ancillary Service Plan

Reliability Unit Commitment (RUC)

The process performed by SPP to assess Resource and operating reserve adequacy for the Operating Day, commit and/or de-commit Resource as necessary, and communicate commitment or de-commitment of Resources to the appropriate Market Participants as necessary.

Reported Load


Reserve Sharing Event

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A request for assistance to deploy Contingency Reserve by any Reserve Sharing Group (RSG) member following the sudden loss of a Resource.

Resettlement


Resources


Resource Offer

For a Resource, the combination of its Start-Up Offer,No-Load Offer, Energy Offer Curve, Transition State Offer, Regulation-Up Service Offer, Regulation-Down Service Offer, spinning reserve Offer and supplemental reserve Offer.

Resource Plan


S7 Scheduled Settlement Statement






Security Constrained Economic Dispatch (SCED)

An algorithm capable of clearing, dispatching, and pricing Energy and Operating Reserve on a co-optimized basis that minimizes capacity costs while enforcing multiple security constraints.

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Scheduled Settlement


Scheduled Settlement Statement


Setpoint Instruction


Settlement Area


Settlement Determinant Report

A daily report of interval input, intermediate calculation and settlement result data with full Settlement Location and transactional detail which is generated for each Asset Owner and Operating Day settled, either on a Scheduled Settlement or Resettlement basis. Separate reports are available for 1) 5-minute data and 2) hourly and daily data.

Settlement Invoice


Settlement Location


Settlement Statement


Shadow Price

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Short-term Load Forecast

A load forecast developed by SPP on a rolling 5-minute basis for the next 120 Dispatch Intervals for input into the Real-Time Balancing Market.

Software Error


Spinning Reserve Quantity

The amount of spinning reserve carried by a Resource declared in the Ancillary Service Plan.

SPP


State Estimator


Statutory Obligation


Supplemental Reserve Quantity

The amount of supplemental reserve carried by a Resource declared in the Ancillary Service Plan.

Tariff


Uninstructed Resource Deviation (URD) Charge

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Variable Energy Resource


Violation Relaxation Limit (VRL)


WEIS Forecast Area

A geographic area within the WEIS footprint defined by SPP for the purposes of developing load forecasts.



Western Energy Imbalance Service (WEIS)


Western Energy Imbalance Service Market (WEIS Market)


Western Energy Imbalance Service Market Footprint (WEIS Market Footprint)


Western Energy Imbalance Service Region (WEIS Region)


Western Interconnection


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Western Real-Time Balancing Market (WRTBM)


2 INTRODUCTIONThe WEIS Market Protocols developed by SPP provide background information, guidelines, business rules, and processes for the operation and administration of the WEIS Market, including market settlements, billing, and accounting requirements.

2.1RELATED DOCUMENTS AND TRAININGAdditional technical documents for interfacing with the WEIS Market are located on the SPP Change Working Group website. Additional references for details of offering, tagging, clearing, and settling in the WEIS market are located in the SPP Learning Center.

3 WESTERN ENERGY IMBALANCE SERVICE (WEIS) MARKET OVERVIEW

SPP operates and administers the Western Energy Imbalance Service (WEIS) Market. The WEIS Market does not supersede any Market Participants’ obligations with respect to any other capacity or Ancillary Service obligations. The responsibilities in regards to capacity adequacy, reserves, and other reliability-based concerns do not change as a result of this WEIS Market.

3.1WEIS MARKETThe WEIS Market processes include Market Participant participation in a price-based real-time Energy Imbalance Service called Western Real-Time Balancing Market

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(WRTBM). Additionally SPP will perform the Supply Adequacy Analysis as described in Section 4.3 to assess the supply adequacy of operating capacity scheduled in each Market Participant’s Resource Plan prior to each Operating Day and prior to each Operating Hour.The WRTBM provides Market Participants with the ability to submit offers to sell Imbalance Energy. The objective function of optimization will be the minimization of the total production costs in the WRTBM for Imbalance Energy subject to reliability constraints. Key features of the WRTBM include:1) The WRTBM operates on a 5-minute basis and calculates Dispatch Instructions

for Imbalance Energy on a least cost basis and accounts for each Resource’s congestion and Energy cost to minimize the overall production cost;

2) Resource settlement is performed on a 5-minute basis. Imbalance Energy charges and credits are calculated as the Resource’s calculated Imbalance Energy MW amount multiplied by the Settlement Location LMP;

3) Load settlement is performed on a 5-minute basis. Imbalance Energy charges and credits are calculated as the load’s calculated Imbalance Energy MW amount multiplied by the Settlement Location LMP; and

4) Charges are imposed on Market Participants for failure to respond to Imbalance Energy as dispatched.

Exhibit 3-1 provides a timeline-based illustration of the sequencing and interaction of the key WEIS Market functions for a representative Operating Day (1/31).

Exhibit 3-1: WEIS Markets Processes Timeline

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4 WEIS MARKET PROCESSESThe WEIS Market processes consist of activities beginning seven days prior to the Operating Day and activities following the end of the Operating Day (Post Operating Day). All time referenced throughout this Section Error: Reference source not found is Central Prevailing Time (CPT). A detailed description of the activities in each of these periods and key market design elements for the WEIS Market functions depicted in Exhibit 3-1 are provided in the following subsections.

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4.1SYSTEM REQUIREMENTSPrior to and in parallel with the WEIS Market processes, SPP performs several related activities as follows.

4.1.1 FORECASTING4.1.1.1 SHORT-TERM AND MID-TERM LOAD FORECASTING

SPP develops Short-Term Load Forecasts and Mid-Term Load Forecasts for each WEIS Forecast Area. The Short-Term Load Forecast produces values on a rolling 5-minute basis. The Mid-Term Load Forecast produces hourly values for the next hour through seven (7) days. Load forecasts are derived through a combination of conforming load and Non-Conforming Load forecasts for each WEIS Forecast Area as described under Sections 4.1.1.1.1 and 4.1.1.1.2. The WEIS Forecast Areas’ Short-Term Load Forecasts and Mid-Term Load Forecasts are then summed up to WEIS Market Short-Term Load Forecast and Mid-Term Load Forecast. These forecasts include an estimate of losses. The Short-Term Load Forecast is distributed to the Price Node (PNode) level for modeling purposes for use in the WRTBM processes as described under Section 4.1.1.1.5. The Mid-Term Load Forecasts will be used in determining day-ahead Supply Adequacy Analysis.

4.1.1.1.1 CONFORMING LOADConforming load is load that changes in a reasonably predictable, uniform ratio that is environmentally driven (i.e. changes in temperature) as opposed to process driven (i.e. large industrial or irrigation processes). SPP uses a load forecasting tool to produce the Short-Term Load Forecast and Mid-Term Load Forecast for conforming load within each WEIS Forecast Area. The load forecasting tool uses historical actual conforming load values as well as temperature, wind speed, dew point and any other environmental variables determined necessary to accurately forecast the conforming load within each WEIS Forecast Area.

4.1.1.1.2 NON-CONFORMING LOADMarket Participants with registered Non-Conforming Load, as described in Section 5.2.2, submit hourly load forecasts of Non-Conforming Load consumption to SPP by 11:00 CPT, for the next Operating Day. Once the initial submission is received, Market Participants are allowed to submit hourly load forecasts of Non-Conforming Load after SPP begins the day-ahead Supply Adequacy Analysis process up to thirty

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minutes before the Operating Hour. Market Participants are encouraged to submit a forecast for each registered Non-Conforming Load for two (2) hours following the current interval for each 15-minute interval that the forecast deviates from the hourly profile. If the 15-minute forecast is unavailable, SPP shall interpolate using the submitted hourly Non-Conforming Load forecast. Market Participants shall also submit a forecast on a 5-minute rolling 15-minute ahead basis. The submitted Non-Conforming Load will be added to the conforming load forecasts to create the total forecast for the WEIS Forecast Area. Market Participants are required to submit actual Non-Conforming Load data for each Non-Conforming Load for which metering is available or estimates of Non-Conforming Load for which metering is not available (submitted forecast value can be used as actual).

4.1.1.1.3 LOSSESBoth the short-term and the mid-term gross load forecasts for each WEIS Forecast Area include an estimate of losses and the WRTBM dispatches to that forecast. SPP will not calculate losses separate from the load forecast.

4.1.1.1.4 DEMAND RESPONSE ADJUSTMENTSReserved for future use.

4.1.1.1.5 LOAD DISTRIBUTIONFor the WRTBM, the Short-Term Load Forecast will be distributed to each PNode weighted by the load at each PNode from the latest State Estimator solution to account for, as accurately as possible, the forecasted load’s impact on transmission constraints.

4.1.1.2 WIND-POWERED GENERATION RESOURCE OUTPUT FORECASTS

SPP produces and updates an hourly Wind-powered Generation Resource (WGR) forecast that provides a rolling 48-hour hourly forecast of wind production potential from each WGR that is expected to exceed the WGR actual output 50% of the time (50% probability of exceedance forecast). This process uses a physical modeling technique that incorporates the relationships of the WGRs to wind speed, topography, atmospheric conditions, actual WGR output, and other variables that influence WGR production.

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SPP also produces and updates an hourly SPP Total Wind Power Forecast (TWPF) providing a probability distribution of the hourly production potential from all wind-powered Resources in SPP for each of the next 48 hours.

SPP produces the WGR forecast and TWPF using the information described in Section 4.1.1.3. This is in addition to the availability and actual output data required of all generation Resources.

SPP shall make available the WGR forecasts to Market Participants and their designated agents for their specific WGRs, subject to any applicable confidentiality protections. In addition, SPP shall provide all Market Participants with the TWPF. Historical TWPF data shall be immediately available on the Portal for seven (7) Calendar Days.

4.1.1.3 WIND-POWERED GENERATION RESOURCE DATA REQUIREMENTS

1) A Market Participant for a WGR must provide applicable and accurate static information to SPP using the spreadsheet based template provided by SPP. The Market Participant registering the Resource must provide SPP with current contact information for the wind farm owner and operator through the Model Change Submission Tool (MCST) User Guide. WGR static data should be updated as changes occur to ensure optimal WGR forecast and TWPF accuracy. In addition, SPP may request updated WGR static data as needed.

a) Geographical Data – Coordinates are required for individual wind turbines at each wind farm site and for either each met tower or nacelle anemometer. Wind instrument data must be measured from within 10 miles from the midpoint of the wind farm site and within 10 meters of the wind farm’s turbine hub height.

i) Wind Farm

(1) Latitude – Latitude of individual wind turbines must be submitted as degrees in decimal form rounded to four digits.

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(2) Longitude – Longitude of individual wind turbines must be submitted as degrees in decimal form rounded to four digits.

ii) Met Tower or Nacelle Anemometer

(1) Latitude – Latitude of the met tower or the nacelle anemometers, must be submitted as degrees in decimal form rounded to four digits.

(2) Longitude – Longitude of the met tower or the nacelle anemometers, must be submitted as degrees in decimal form rounded to four digits.

(3) Height – Height of the met tower or the nacelle anemometers. The value must be entered in meters (m) above ground level.

b) Turbine Data – Turbine data characterizes the wind farm. Provide the turbine specific data for each turbine at the wind farm site.

i) Manufacturer – Manufacturer of the wind turbine.

ii) Model – Model of the wind turbine. Provide any prefixes and suffixes, including software upgrades that affect power output and winglets on blades.

iii) Turbines – The number of turbines at the wind farm.

iv) Capacity – The nameplate capacity of each turbine and total wind farm site.

v) Hub Height – Height of the center of the turbine hub in meters (m) above ground level.

vi) Rotor Diameter – Diameter of the rotor blades of the turbine in meters (m).

vii)Temperature Range of Operation – Minimum and maximum operating temperature in degrees Celsius (C).

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viii) Cold Weather package:

(1) De-Icing Technology – Provide details on the ability of the wind farm site to detect blade icing and the ability of the wind turbines to de-ice blades to prevent turbine cut-out. Provide details on the ability of the wind farm to de-ice anemometer and wind vane.

ix) Software Upgraded Power Curve – Provide details on the ability of wind turbine to have a smoother cut-off/cut-in wind speed power curve, e.g. gradual ramp down at cut-off wind speed.

x) ICCP Object ID – The ICCP object IDs that the Market Participant will use to send ICCP data for a WGR

(1) Wind Speed

(2) Wind Direction

(3) Temperature

(4) Pressure

(5) Relative Humidity

(6) Real-Time Turbine Availability

(7) Real-Time Capability

xi) Contact Information – 24x7 contact information

(1) Wind Farm Owner

(2) Wind Farm Operator

2) A Market Participant for a WGR must provide Real-Time data through ICCP.

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a) Weather Data – A snapshot of the instantaneous value at the wind Resource site is requested at a maximum periodicity of 60 seconds taken directly from either the met tower or the nacelle anemometer as specified in (A)(1) above.

i) Wind Speed – Telemetered wind speed measured in meters per second (m/s).

ii) Wind Direction – Telemetered wind direction measured in compass heading degrees (1 – 360).

iii) Temperature – Telemetered temperature measured in degrees Celsius (C).

iv) Pressure – Telemetered barometric pressure measured in kilopascals (kPa).

v) Relative Humidity – Telemetered relative humidity measured in percent.

b) Real-Time Turbine Availability – Number of turbines at the wind Resource site that are able to generate power as a percentage (%) of the installed nameplate capacity of the site. A snapshot of the instantaneous availability at the wind Resource site is requested at a maximum periodicity of 60 seconds.

c) Real-Time Capability – The amount (MW) of real power output the Resource is capable of instantaneously producing, excluding any dispatch, deployment, or Curtailment instructions. This item is only required for Resources that are qualified to provide Operating Reserve.

3) A Market Participant for a WGR must provide planned and forced outage and availability data through the Control Room Operations Window (CROW).

a) Outage – Any planned or forced outage, where all turbines at the wind farm site are out of service or not operational, shall be added to CROW as an outage with the best approximation of the in-service date.

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b) Availability – Provide the planned hourly wind farm MW capability due to maintenance and any known power curve de-rate for the next 7 days. The threshold to submit, or update, availability reduction from nameplate capacity is 10% or 10MW whichever is smaller.

4.1.1.4 SOLAR-POWERED GENERATION RESOURCE OUTPUT FORECASTS

SPP shall produce an hourly Solar-powered Generation Resource (SGR) forecast that provides a rolling 48-hour forecast of energy from each SGR that is expected to exceed the SGR actual output 50% of the time.

SPP shall produce an hourly SPP Total Solar Power Forecast (TSPF) providing a rolling 48-hour probability distribution of the hourly production potential from all SGRs in SPP for each of the next 48 hours.

SPP shall make available the SGR forecasts to Market Participants and their designated agents for their specific SGRs, subject to any applicable confidentiality protections. In addition, SPP shall make available the TSPF to all Market Participants. Historical TSPF data shall be available on the Portal for seven (7) Calendar Days.

4.1.1.5 SOLAR-POWERED GENERATION RESOURCE DATA REQUIREMENTS

1) A Market Participant for a Solar-powered Generation Resource (SGR) must provide the following static information to SPP using the spreadsheet based template provided by SPP. The Market Participant registering the Resource must provide SPP with current contact information for the SGR owner and operator through the Model Change Submission Tool (MCST) User Guide, Appendix B. SGR static data changes should be updated as they occur to ensure optimal WGR forecast and TWPF accuracy. In addition, SPP may request updated SGR static data as needed.

a) Geographical Data – One set of latitude and longitude coordinates is required for the SGR site mid-point and the meteorological collection device station. Coordinates from the corners of the solar farm including, but not limited to, the northwestern, northeastern, southwestern and southeastern locations, in

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order to properly identify the exact footprint and area of the SGR. The placement of the met station shall be within the limits of the SGR site, preferably at the mid-point of the site.

i) Solar-Powered Generation Resource

(1) Latitude – Latitude of the Resource location, including the mid-point and four corners of the SGR, submitted as degrees in decimal form rounded to four digits.

(2) Longitude – Longitude of the Resource location, including the mid-point and four corners of the SGR, submitted as degrees in decimal form rounded to four digits.

ii) Met Station

(1) Latitude – Latitude of the met station submitted as degrees in decimal form rounded to four digits.

(2) Longitude – Longitude of the met station submitted as degrees in decimal form rounded to four digits.

b) Solar-Powered Generation Resource Data – Data related to the SGR technology employed at the SGR site. If there is more than one type, model, etc., provide the specific data for each unique device.

i) Manufacturer – Manufacturer of the SGR technology.

ii) Model – Model of the SGR devices. Provide any prefixes and suffixes if available.

iii) SGR Devices – The number of panels, mirrors, or thermal cells at the SGR.

iv) Capacity – The nameplate capacity of each unit both AC and DC capacity.

v) Degradation Factor – Yearly degradation factor percentage.

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vi) Temperature Coefficient – Percent over degrees Celsius.

vii)Tilt – Altitude angle or angle range for units.

viii) Azimuth Angle – Azimuth angle or angle range for units (alignment due south).

ix) Height – Elevation of panels above surface level.

x) Inverter Technology – Centralized inverters, string inverters, micro inverters and/or maximum power point trackers.

c) Tracking Data – Details related to the tracking system if equipped.

i) Type – Single or dual-axis tracking

ii) Manufacturer – Manufacturer of the tracker

iii) Model – Model of the tracker

d) ICCP Object ID – The ICCP object IDs that the Market Participant will use to send ICCP data for a SGR

i) Wind Speed

ii) Wind Direction

iii) Air Temperature

iv) Pressure

v) Relative Humidity

vi) Back Panel Temperature

vii) Irradiance

(1) Direct Irradiance

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(2) Global Horizontal Irradiance

(3) Plane of Array/Global Irradiance

viii) Real-Time Capability

e) Contact Information – 24x7 contact information

i) SGR Owner

ii) SGR Operator

2) A Market Participant for a SGR must provide Real-Time data through ICCP.

a) Weather Data – A snapshot of the instantaneous value at the SGR site is requested at a maximum periodicity of 60 seconds.

i) Wind Speed – Telemetered wind speed measured in meters per second (m/s) taken directly from the specified met station.

ii) Wind Direction – Telemetered wind direction measured in compass heading degrees (1 – 360) taken directly from the specified met station.

iii) Air Temperature – Telemetered air temperature measured in degrees Celsius (C) taken directly from the specified met station.

iv) Pressure – Telemetered barometric pressure measured in kilopascals (kPa) taken directly from the specified met station.

v) Relative Humidity – Telemetered relative humidity measured in percent (%) taken directly from the specified met station.

vi) Back Panel Temperature – Telemetered temperature measured in degrees Celsius (C) taken from a thermocouple probe attached to the back of a unit.

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vii) Irradiance – Telemetered irradiance measured in watt per square meter (W/m2) required for the type of SGR technology that the SGR employs. Irradiance requirements may be a combination of direct irradiance, global horizontal irradiance, or plane of array/global irradiance.

b) Real-Time Availability – Percentage of installed nameplate capacity of the SGR that is able to generate power. A snapshot of the instantaneous availability at the SGR site is requested at a maximum periodicity of 60 seconds.

c) Real-Time Capability – The amount (MW) of real power output the Resource is capable of instantaneously producing, excluding any dispatch, deployment, or Curtailment instructions. This item is only required for Resources that are qualified to provide Operating Reserve.

3) A Market Participant for a SGR must provide Planned and Forced Outage and Availability data through the Control Room Operations Window (CROW).

a) Outage – Any planned or forced outage, where the SGR is out of service or not operational, shall be added to CROW as an outage with the best approximation of the in-service date.

b) Availability – Provide the planned hourly SGR MW capability due to maintenance and any known power curve de-rate for the next 7 days. The threshold to submit, or update, availability reduction from nameplate capacity is 10% or 10MW whichever is smaller.

4.1.2 VIOLATION RELAXATION LIMITSThe Security Constrained Economic Dispatch (SCED) enforces a number of operating constraints in developing the co-optimized market solution. In certain situations, attempting to enforce all constraints may result in a solution that is not feasible at a Shadow Price less than an appropriately priced Violation Relaxation Limit (VRL). In such cases, SPP must apply VRLs in SCED.

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There are four categories of constraints and associated VRLs: (1) Resource Capacity Constraints; (2) Resource Ramp Constraint; (3) Global Power Balance Constraint; and (4) Operating Constraint (which includes PNode, Manual, Watch List, flowgate and Real-Time Contingency Analysis (RTCA) Constraints). A higher VRL value is an indication of the relative priority for enforcing the constraint type. For example, the VRL value assigned to a ramp rate limit exceeds that assigned to a flowgate limit indicating that the flowgate constraint should be relaxed before the ramp rate constraint. If the VRL with the lowest value will not allow SCED to balance the market’s energy obligations, a higher VRL will be applied. In the case of the Operating Constraint VRLs, the values limit the cost of the dispatch needed to balance system injections and withdrawals by capping the Shadow Price depending upon the level of the violation. Exhibit 4-1 provides a summary of the current VRL values by constraint type.

Exhibit 4-2: VRL Values

Constraint Type Description VRL [$/MW]

(1) Resource Capacity The minimum and maximum MW dispatchable output of a Resource as indicated in a Resource Offer.

100,000

(2) Global Power Balance Energy needed to balance Resources and load.

50,000

(3) Resource Ramp The ramp capability of a Resource as indicated in the Resource plan.

5,000

(4) Operating Constraint A MW limit that can be imposed on SPP related to MW flow across a market node, a manually-identified transmission constraint, a Watch List transmission constraint, a flowgate constraint, or a transmission constraint identified by SPP’s real-time contingency analysis.

$750 when the loading is greater than 100% and less than or equal to 101%

at each network constraint at each Operating Constraint.

$750 when the loading is greater than 101% and less than or equal to 102%

at each network constraint $1,000 when the loading is greater

than 102% and less than or equal to 103% at each network constraint

$1,250 when the loading is greater

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Constraint Type Description VRL [$/MW]

than 103% and less than or equal to 104% at each network constraint

$1,500 when the loading is greater than 104% at each network constraint

4.1.2.1 IMPACT OF VRLS ON SCED

The applicable VRLs impact SCED in the following manner: 1) When a Resource Capacity, Global Power Balance, Resource Ramp, or Operating

Constraint is reached but not exceeded, it is referred to as “binding.” In this state, VRLs are not applicable.

2) When an Operating Constraint is exceeded and cannot be resolved at a Shadow Price less than or equal to the applicable Operating Constraint VRL, the constraint is relaxed so that SCED can solve (i.e. the limit is increased by the amount of the violation). The VRL values applied by SCED in this case act as a cap on the Shadow Price on the applicable Operating Constraint. a) For example, assume flowgate A has a 100 MW limit and SCED is re-dispatching

to correct a limit violation. The SCED Shadow Price on flowgate A reaches $1500/MW at which point the SCED calculated flow on flowgate A is 107 MW. At this point, SCED will stop trying to re-dispatch to meet the 100 MW limit, the limit is then increased (“relaxed”) to 107 MW, and SCED concludes its solution using the new limit. The Shadow Price on flowgate A is calculated based on this new 107 MW limit and will be approximately equal to $1500/MW.

3) When a Resource Ramp Constraint for Energy in the up direction is exceeded and cannot be resolved, the Resource ramp rate constraint is relaxed in a subsequent SCED solution. The VRL values applied by SCED in this case act as a cap on the Shadow Price of the constraint.

4) When a Resource Ramp Constraint for Energy in the down direction is exceeded and cannot be resolved, the Resource ramp rate constraint is relaxed in a subsequent SCED solution. The VRL values applied by SCED in this case act as a cap on the Shadow Price of the constraint.

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4.1.2.1.1 MODIFICATION TO VRLSEach 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 WMEC for consideration.

Each year by November 1, taking into consideration the recommendations of stakeholders and staff, any changes to the VRLs or their associated values must be approved by the SPP Board of Directors and then filed with the Commission. The most recent FERC approved VRLs and their associated values shall be posted on the SPP’s website and also are found in the Section 4.1.2.

SPP shall post the following information on the Portal on at least a monthly basis within 15 days of the last day of the month:

1) The number of times that VRL values were applied by SCED during the month, and associated detail regarding the VRL type and value for each incident;

2) The value of each LMP in excess of the Safety-Net offer cap or below zero (0) during the month;

3) The number and duration of each incident where a VRL was employed with respect to the same flowgate for two or more consecutive intervals;

4) The number and magnitude of Out-of-Merit Energy (OOMEs) issued coincident with the application of a VRL.

4.1.3 OUTAGE SCHEDULING AND REPORTINGMarket Participants must submit transmission and generation outages following the guidelines in the SPP Outage Coordination Methodology document on spp.org.

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Outages will override any other Commitment Status submitted by the Market Participant.

4.2OFFER SUBMITTALBeginning seven days prior to the Operating Day, Market Participants may begin to submit Offers for use in the WRTBM, as further specified in technical documentation provided on the Portal. Offers may be updated up to 30 minutes prior to each Operating Hour. The following rules apply to Offer submittal:

1) Submitted Resource Offers roll forward hour to hour only when no Resource Offer has been submitted for that interval;

2) The Energy Offer Curve is limited by the offer caps and floors specified under Section 7.2.4.

3) Submitted Resource Offers are used by SPP to complete the Resource Plan and the Ancillary Service Plan.

4.2.1 RESOURCE OFFER PARAMETERSThe following Resource Offer parameters must be submitted to constitute a valid offer for use in WRTBM:

1) Resource Name (as specified during market registration and cannot be changed as part of Resource Offer submittal);

2) Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically non-decreasing $/MWh, increasing MW and slope or block option), not required for PPRs;

a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised by all block or all slope price/quantity pairs.

b) The price of all MWhs below the first pricing point MWh is equal to the first pricing point price. The price by all MWhs above the last pricing point MWh is equal to the last pricing point price.

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c) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-2 illustrates Energy Offer Curves developed from submitted price/MWh pairs for both the slope and block options.

Exhibit 4-3: Energy Offer Curve Development

MW $/MWh100 20.00200 40.00400 60.00500 80.00

Submitted Data

Slope Option

Block Option

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

0 100 200 300 400 500 600

$/M

Wh

MW

Energy Offer Curve

Slope Option

Block Option

3) Mitigated Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically non-decreasing $/MWh, increasing MW and slope or block option), not required for PPRs;a) Block and slope pairs may not coexist. The Resource Offer in effect for any

given period of time must be comprised of all block or all slope price/quantity pairs.

4) Ancillary Services Quantity consisting of the following:a) Regulation-Up Quantity (MW);b) Regulation-Down Quantity (MW);c) Spinning Reserve Quantity (MW);

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Maximum Economic Capacity Operating Limit

Minimum Economic Capacity Operating Limit

Off-Line

MWTotal Capacity of Reg-Up, Spin, and Supp Ancillary Service Quantity

Capacity of Reg-Down Ancillary Service Quantity


d) Supplemental Reserve Quantity (MW);The total capacity submitted for the Ancillary Services Quantity will be used to determine the Ancillary Service Plan’s obligation and the reserved capacity beyond the Minimum Economic Capacity Operating Limit and the Maximum Economic Capacity Operating Limit to be counted toward the Resource’s capacity in the Supply Adequacy Analysis.

Exhibit 4-4: Resource Limit Relationships

5) Minimum Economic Capacity Operating Limit (MW);6) Maximum Economic Capacity Operating Limit (MW);7) Ramp-Rate-Up (curve, MW/Minute). Ramp-Rate-Up submittal is through a

segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);a) Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Up will

apply. In the WRTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Up in Block 1 will apply back to the actual measured MW.

b) Block 1 Ramp Rate Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1.

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c) Breakpoint Limit n – Resource MW output at which Ramp-Rate-Up changes from previous segment values to segment n values.

d) Block n Ramp-Rate-Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to the Breakpoint Limit n

8) Ramp-Rate-Down (curve, MW/Minute). Ramp-Rate-Down submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);a) Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Down

will apply. In the WRTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Down in Block 1 will apply back to the actual measured MW.

b) Block 1 Ramp Rate Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1.

c) Breakpoint Limit n – Resource MW output at which Ramp-Rate-Down changes from previous segment values to segment n values.

d) Block n Ramp-Rate-Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to the Breakpoint Limit n.

9) Turn-Around Ramp Rate Factor (a value between 0.01 and 1.00). A Resource’s ramping direction in the next Dispatch Interval is compared against its ramping direction in the current Dispatch Interval. If these two ramping directions are different, then the Turn-Around Ramp Rate Factor is applied to the Dispatch Instruction in the next Dispatch Interval, except in circumstances where the Resource is being sent an OOME instruction. The ramping direction in the current Dispatch Interval is based on the actual output at the beginning of the current Dispatch Interval compared to the Dispatch Instruction at the end of the current Dispatch Interval. The direction of the next Dispatch Interval is determined by considering the actual output and ramp capability of the Resource at the time of the solution and comparing it to the next Dispatch Instruction;

10) Resource Status (see Section 4.2.2);

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4.2.2 RESOURCE STATUS USED FOR RESOURCE PLANS AND ANCILLARY SERVICE PLANS

In addition to the Resource Offer parameters specified under Section 4.2.1, Market Participants must also specify a Resource Commitment Status as part of the Resource Plan for each hour of the Operating Day. The Commitment Status selection indicates to SPP the operating schedule of the Resource in the Resource Plan. Commitment Status offers are describe in Section 4.2.2.1. If the Resource is on an approved outage as described under Section 4.1.3, the Commitment Status will default to outage and the Resource will not be available for dispatch during the outage period. Valid Commitment Status selections are:

4.2.2.1 COMMITMENT STATUS FOR THE RESOURCE PLAN

1) Self – The Market Participant is committing the Resource for the specified hour and SPP should include it as committed in the Resource Plan. This indicates the Resource will be committed and its output will be at least the Minimum Economic Capacity Operating Limit;

2) Outage – The Resource is unavailable due to a planned, forced, maintenance or other approved outage.

3) Not Participating – The Resource is offline and otherwise available. This Commitment Status may also be used for Resources carrying offline Supplemental Reserves.

4.2.3 RESOURCE MODELINGThe Resource Offer parameters specified under Sections 4.2.1 and 4.2.2 may be submitted for all Resource types with the understanding that some parameters may be optional for certain types of Resources. Jointly owned units that do not wish to register as a single Resource may model ownership shares using individual Resources. Special Resource modeling rules for such Resources are described for specific Resource types as follows:

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4.2.3.1 DISPATCHABLE DEMAND RESPONSE (DDR) RESOURCE

The following special modeling rules apply to a Dispatchable Demand Response (DDR) Resource.

1) A DDR Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind-the-meter unit that is dispatchable on a 5-minute basis;

2) A DDR Resource is modeled in the Commercial Model the same as any other Resource with a defined Settlement Location and associated PNode or APNode that corresponds to the associated Demand Response Load PNode or APNode definition;

3) A DDR Resource is also included in the Network Model as a generator;

4) A DDR Resource must have a corresponding Demand Response Load (DRL);

5) The Demand Response Load for a DDR Resource must have telemetering installed;

6) The Market Participant must submit the real-time value of the Demand Response Load to SPP via SCADA on a 10-second basis;

7) A DDR Resource submits mitigated Energy Offer Curves based on the criteria in Section 7.2.2.3(7). For purposes of these Resources, the short-run marginal cost may equal opportunity cost;

8) The amount of the response provided is sent directly to SPP via ICCP and will represent the real-time Resource production.

a) The Market Participant must determine the real-time Resource production and submit the value to SPP via SCADA on a 10-second basis.

b) After-the-fact integrated meter values will be submitted directly by the Meter Agent for the DDR Resource.

4.2.3.2 COMBINED CYCLE RESOURCE

Combined Cycle modeling will be accommodated as follows for Resources registered as a Combined Cycle Resource.

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Market Participants will have to select from one of the three following options regarding submitting Resource Offers for their registered Combined Cycle Resources which will need to be declared during asset registration as described under Section 5.1.4:

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

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

3) A Resource Offer may be submitted for each pseudo Combined Cycle Resource, where each pseudo Combined Cycle Resource will represent the combination of one combustion turbine and a portion of the steam turbine. Under this option, each pseudo Combined Cycle Resource must be capable of being dispatched independently the same as any other Resource and each pseudo Combined Cycle Resource will be settled the same as any other Resource.

4.2.3.3 DISPATCHABLE VARIABLE ENERGY RESOURCES

The following rules apply in the WRTBM to Resources registered as Dispatchable Variable Energy Resources (DVER):

1) The Minimum Economic Operating Capacity Limit must be submitted as zero MW. Otherwise, the Resource Offer will be rejected;

2) SPP will provide a dispatch flag to the DVER indicating whether or not the DVER should “follow” or “ignore” its Setpoint Instruction. Use of these dispatch flags in calculating Setpoint Instructions is described under Section 4.4.2.1. These flags are set as part of the WRTBM solution as follows:

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a) The default value of the dispatch flag will be “ignore”. When the dispatch flag is “ignore”, the DVER’s maximum operating limit is set equal to the DVER’s actual output at the time of the current WRTBM run;

b) The dispatch flag will be set to “follow” if (i) the DVER is dispatched below its maximum operating limit or (ii) the DVER is issued an OOME;

3) For the WEIS Market in the current WRTBM run, if the dispatch flag is “follow” as set by the previous WRTBM run, then the DVER’s maximum operating limit in each subsequent Dispatch Interval is set equal to either:

a) The lesser of (i) SPP’s output forecast for that DVER or (ii) the DVER’s Maximum Economic Capacity Operating Limit; or

b) The Maximum Economic Capacity Operating Limit as specified in the DVER Offer if the SPP output forecast is not available for that DVER; or

c) SPP’s output forecast for that DVER if the Maximum Economic Capacity Operating Limit:

i) Was not submitted in the DVER Resource Offer; or

ii) Was not updated in the Offer during the Operating Hour prior to the Operating Hour in which the Resource limit would apply but before the lead time described in Section 4.2; or

iii) Exceeds the maximum physical rating of the DVER that was submitted at market registration.

Such maximum operating limit continues to be set as described above until such time that the Resource’s Dispatch Instruction is equal to the maximum operating limit, after which, the DVER’s maximum operating limit is calculated as described under (3)(a) above.

4.2.3.4 NON-DISPATCHABLE VARIABLE ENERGY RESOURCES AND PARTIAL PARTICIPATION RESOURCES

The following rules apply to Resources registered as Non-Dispatchable Variable Energy Resources and Partial Participation Resources (“PPR”):

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1) For the WEIS Market, the Resource’s Energy Offer Curve shall not apply and is treated as the lowest priority supply for Native Load Hedging as described in Section 4.5.6.1.4. The Dispatch Instructions will be an echo of actual SCADA output as updated with every WRTBM except during the period of time an OOME is imposed; during such time, the Dispatch Instructions will be issued in accordance with Section 4.4.1.4. For PPRs, the submission of Control Status is not required. If it is not provided, it will be set to Manual.

4.2.4 ENERGY SCHEDULESMarket Participants submit Energy Schedules, including Interchange Transactions. Energy Schedules with a specified source and sink that are valid Settlement Locations will count as a reducer to the Market Participant’s load obligation when importing and as a reducer to the Market Participant’s supply when exporting. When an Energy Schedule cannot be mapped to valid Settlement Location(s), the schedule will impact the NSI for the Balancing Authority(s) in the WRTBM and will become Imbalance Energy for the Balancing Authority with the non-mapped source and sink at the Balancing Authority’s load weighted average LMP of the all the loads in the BA as described in section 4.5.6.1.5.

4.3SUPPLY ADEQUACY ANALYSIS4.3.1 PURPOSESPP will perform a Supply Adequacy Analysis to ensure that each Balancing Authority participating in WEIS Market and the Market Participants within those Balancing Authority Areas have sufficient generation in their operating plan to meet the load and Ancillary Service obligations of both the Market Participants and Balancing Authority. The Supply Adequacy Analysis will occur on both day-ahead and hour-ahead time horizons.

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4.3.2 INPUTSSPP will use the most recently updated Resource Offers, Resource Plan, Energy Schedules, and Ancillary Service Plan to determine maximum and minimum supply available for each period being analyzed. SPP will use the latest Ancillary Service Plan to determine the amount of Ancillary Services being carried for each period. The most recently updated load forecast projections will be used to determine the load forecast obligations for each period. SPP will use the latest state estimator model, topology, and potential operating constraints for the forward time points in deliverability portion of the analysis.

4.3.3 FORMULAIC DESCRIPTORS4.3.3.1 UPWARD SUPPLY ADEQUACY

A Market Participant is supply adequate in the upward direction when the following relationship is true:

Resource Capacity Maximum+ Imports >= Load + Exports + Reserve Obligation Up

Where a Market Participant’s Resource Capacity Maximum is the sum of all Maximum Economic Operating Limits and all fixed upward Ancillary Service MW from the Ancillary Service Plan. A Market Participant’s imports in a BAA are the sum of the imports associated with their Asset Owners in that BAA. A Market Participant’s exports in a BAA are the sum of the exports associated with their Asset Owners in that BAA. A Market Participant’s Reserve Obligation Up represents the capacity required to fulfill the needed operating reserves in the upward direction, i.e. the sum of all Market Participant Resources in BAA { Offered Fixed RegUp + Offered Fixed Spin + Offered Fixed Supp }.

4.3.3.2 DOWNWARD SUPPLY ADEQUACY

A Market Participant is supply adequate in the downward direction when the following relationship is true:

Resource Capacity Minimum + Imports <= Load + Exports - Reserve Obligation Down

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Where a Market Participant’s Resource Capacity Minimum is the sum of all Minimum Economic Operating Limits and all fixed downward Ancillary Service MW from the Ancillary Service Plan. A Market Participant’s imports in a BAA are the sum of the imports associated with their Asset Owners in that BAA. A Market Participant’s exports in a BAA are the sum of the exports associated with their Asset Owners in that BAA. A Market Participant’s Reserve Obligation Down represents the capacity required to fulfill the needed operating reserves in the downward direction (offered fixed regulation-down).

4.3.4 TYPES4.3.4.1 CAPACITY

SPP performs the capacity portion of the Supply Adequacy Analysis both before the Operating Day and before each operating hour. The capacity portion of the Supply Adequacy Analysis calculations will use the Balancing Authority load forecast generated by SPP. Supply adequacy will be analyzed bi-directionally. An over-supply situation will be defined as minimum generation being greater than the load plus sales minus downward Ancillary Service obligations and purchases. An under-supply situation will be defined as maximum generation being less than the load plus upward Ancillary Service obligations and sales minus purchases. The Market Participant will be deemed supply inadequate in the event that either an over-supply situation or under-supply situation occurs.

4.3.4.2 DELIVERABILITY

In addition to the capacity portion of the supply adequacy analysis , SPP performs a rolling 2.5 hour capacity and deliverability analysis throughout the operating day to provide additional visibility into potential deliverability issues associated with the submitted Resource Plans, Ancillary Service obligations, forecasted load and scheduled purchases and sales. This deliverability analysis incorporates both the Market Participant submitted data and SPP generated data to perform a full SCED for the WEIS footprint.

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The output data from the deliverability analysis will include potential operating constraint violations, Resource ramp violations, and load balance violations in 15-minute intervals. Any combination of the aforementioned violations could indicate a potential issue with the feasibility of the submitted Resource Plans and will allow both the Balancing Authority and SPP to have additional visibility into potential supply adequacy issues.

4.3.5 NOTIFICATIONS AND RESOLUTIONSPP will notify both the Market Participants and the associated Balancing Authority of the Supply Adequacy Analysis results.

The Market Participant must make the appropriate modifications no later than thirty (30) minutes prior to the Operating Hour (OH) for any supply inadequacy revealed by the hourly study, if provided by SPP. Such appropriate modifications should be made in coordination with the Balancing Authority who may take such actions as it deems are appropriate, in its discretion, to address reliability issues.

In all instances where the Market Participant fails to resolve an identified issue at or prior to real-time, and that failure contributes to an Emergency Condition, the instance will be reported to FERC on an after-the-fact basis.

4.4OPERATING DAY ACTIVITIESExhibit 4-4 provides a representative overall timeline of Operating Day activities.

Exhibit 4-5: Operating Day Activities Timeline

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4.4.1 WESTERN REAL-TIME BALANCING MARKETSPP operates the WRTBM on a continuous 5-minute basis. SPP clears the WRTBM by determining the security-constrained dispatch that is the least costly means of balancing generation and load (supply/demand) based on actual conditions, forecasted conditions, and submitted Resource Offers. WRTBM network configurations and constraints are determined from the most recent State Estimator results.

WRTBM operations consist of three steps: (1) Process WRTBM inputs; (2) Execute WRTBM and (3) Post WRTBM results. Each of these steps is described in the following subsections.

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4.4.1.1 WRTBM INPUTS

Inputs into the WRTBM algorithm consist of data provided prior to each Operating Hour and data provided within each Operating Hour.4.4.1.1.1 PRE-OPERATING HOUR INPUTS1) WRTBM Resource Offers;

2) Resource Plan

3) Ancillary Service Plan

4) Resource availability as determined by the Resource Plan;

4.4.1.1.2 IN-OPERATING HOUR INPUTS1) Latest State Estimator solution for:

a) Distribution of load forecast throughout the Network Model;

b) Latest transmission topology for the Network Model; and

c) Backup initial energy injection of Resources if SCADA not available.

2) Real-Time Resource data from latest SCADA snapshot to determine initial energy injection of Resources, Control Status, and generator outages;

3) BA NSI from latest SCADA snapshot;

4) Intra-Hour adjustments to NSI;

5) Active transmission constraints;

6) Intra-Hour adjustments to Resource Offer parameters;

a) Market Participants are required to keep their Resource Offer operating parameters up-to-date during the Operating Day. In the event of a required change in a Resource Offer operating parameter due to physical Resource changes during an Operating Hour, the Market Participant is responsible for notifying SPP of required changes and updating the outage scheduler tool for outages and derates per Section 4.1.3, and SPP will make the required modification for the current Operating Hour. Market Participants shall remain

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responsible for accurately reflecting Resource operating parameters in their Resource Offer submissions for subsequent hours.

7) SPP Short-Term Load Forecast (STLF) as described under Section 4.1.1.1;

a) SPP distributes the STLF down to the associated PNodes using weighting factors for modeling purposes as described under Section 4.1.1.1.5

8) Wind Resource output forecast as described under Section 4.1.1.2

9) Solar Resource output forecast as described under Section 4.1.1.4.

4.4.1.1.3 CONTROL STATUSThe Control Statuses below apply to all Resources.

1) Off-line (Control Status 0) – This Control Status indicates that the Resource is off-line and not available to the WRTBM. This status is reserved for Resources which are generating zero (0) MWs. This includes Resources which are disconnected from the grid for an approved outage and Resources lacking a current schedule.

2) Non-Regulating (Control Status 1) – This Control Status indicates that the Resource is on-line and capable of following a Dispatch Instruction

3) Regulating (Control Status 2) – This Control Status indicates that the Resource is on-line and capable of following a Dispatch Instruction and carrying Ancillary Services.

4) Manual (Control Status 3) – This Control Status indicates that the Resource is on-line but not capable of following a Dispatch Instruction. This status is reserved for generating Resources operating under the following conditions:a) Start-upb) Shut-downc) Testingd) Experiencing, or recovering from, a unit tripe) Generating at an output to which the Resource is not capable of responding

to a Dispatch Instructionf) Condensing

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g) Experiencing environmental, control or mechanical issues h) Qualifying Facility exercising its rights under PURPA to deliver its net output

to its host utility.

4.4.1.2 WRTBM EXECUTION

SPP will attempt to execute the WRTBM every 5-minutes for the next Dispatch Interval based on the inputs described above. SPP may adjust the Maximum Economic Operating Limit and the Minimum Economic Operating Limit when the Network Model or a CROW outage necessitates a derated limit. In the event SPP is unable to execute the WRTBM or to approve a valid solution for the WRTBM, the clearing from the last approved WRTBM will carry forward until the approval of a new WRTBM.

1) An optimization methodology utilizing a SCED algorithm is employed to calculate Resource Dispatch Instructions to meet the SPP Short-Term Load Forecast on a least cost basis using submitted Resource Offers while respecting Resource operating constraints and transmission constraints;

2) In certain situations, enforcing constraints may result in a solution that is not feasible at a Shadow Price less than an appropriately priced VRL. In such cases, SPP must apply Violation Relaxation Limits (VRLs) in SCED as described under Section 4.1.2;

3) Additionally, SPP executes a look-ahead SCED prior to the WRTBM. The look-ahead SCED results will be used to: (1) anticipate the need to adjust Dispatch Instructions for the current Dispatch Interval to prepare to meet forecasted changes in the load several Dispatch Intervals into the future and (2) forecast potential IE quantities by Balancing Authorities for future intervals.

4.4.1.3 WRTBM RESULTS

All Market Participants must have the capability to receive and follow Resource Dispatch Instructions. After the execution of the WRTBM the Resource Dispatch Instructions will be communicated to each Market Participant for its Resources. The

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Dispatch Instruction is a MW output target for the end of the applicable Dispatch Interval.

The Locational Marginal Prices (LMPs) for each Settlement Location and the Marginal Congestion Component (MCC) of LMP for each Settlement Location are communicated to all Market Participants.

The BAs will receive the aggregate WEIS Imbalance Energy for their BA. The aggregate WEIS Imbalance Energy will be the sum of all Imbalance Energy between the Asset Owners within the BA. This Imbalance Energy will be dynamically scheduled by the BAs and will be excluded from NLH calculations as described in Section 4.5.6.1.4.

4.4.1.4 OUT-OF-MERIT ENERGY (OOME) DISPTACH

An instruction by a Reliability Coordinator limiting a Resource’s output is reflected in the WEIS Market through an OOME. An OOME will specify either a fixed MW level or an OOME cap and/or OOME floor MW level the Resource is expected to produce until the issue can be resolved. When an OOME contains a fixed OOME MW, the Resource will receive a Dispatch Instruction equal to the specified fixed OOME MW. When an OOME contains an OOME cap MW and/or OOME floor MW, the Resource will receive a Dispatch Instruction to generate below the OOME cap MW and/or above the OOME floor MW respectively. Such MW levels may include (i) dispatch below a Resource’s Minimum Economic Capacity Operating Limit as system conditions warrant or (ii) dispatch above a Resource’s Maximum Economic Capacity Operating Limit as system conditions warrant. Resources will be compensated as described under Section 4.5.6.2, unless the Market Monitor determines that an OOME was issued in a discriminatory manner, the Resource will not be compensated as described under Section 4.5.6.2.

4.4.1.4.1 FIXED OOME1) During the period of time when a fixed OOME is imposed, SPP will ensure that

the following occurs:

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a) A Dispatch Instruction is immediately issued equal to the fixed MW level the Resource is instructed to produce and the OOME flag is set equal to “True”;

b) Setpoint Instructions, Minimum Economic Capacity Operating Limit and Maximum Economic Capacity Operating Limit for the current Dispatch Interval are immediately adjusted to the fixed MW level the Resource is instructed to produce; and

i) For VERs, the Minimum Economic Capacity Operating Limit and Maximum Economic Capacity Operating Limit for the current Dispatch Interval are immediately adjusted to the fixed MW level the Resource is instructed to produce and the Setpoint Instructions will be immediately adjusted to the lesser of the fixed MW level the Resource is instructed to produce or the echo of the actual SCADA.

c) Setpoint Instructions for future intervals and Minimum Economic Capacity Operating Limit and Maximum Economic Capacity Operating Limit not yet dispatched will be set to the fixed MW level the Resource is instructed to produce.

i) For VERs, the Minimum Economic Capacity Operating Limit and Maximum Economic Capacity Operating Limit not yet dispatched will be set to the MW level the Resource is instructed to produce and the Setpoint Instructions will be set to the lesser of the fixed MW level the Resource is instructed to produce or the echo of actual SCADA output.

d) Once the OOME has ended the Resource will return to normal operations as described in this Section.

4.4.1.4.2 OOME CAP AND OOME FLOOR1) During the period of time when an OOME contains an OOME cap and/or OOME

floor, SPP will ensure that the following occurs:

a) A Dispatch Instruction is immediately issued as defined in (i) to (iii) below and the OOME flag is set equal to “True”;

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i) If the current Dispatch Instruction is greater than the OOME cap MW, the Dispatch Instruction will be adjusted to the OOME cap MW.

ii) If the current Dispatch Instruction is less than the OOME floor MW, the Dispatch Instruction will be adjusted to the OOME floor MW.

iii) If the current Dispatch Instruction is less than or equal to the OOME cap MW and/or greater than or equal to the OOME floor MW, the Dispatch Instruction will not be adjusted.

b) Setpoint Instructions for the current Dispatch Interval are immediately adjusted;

i) If the current Setpoint Instruction is greater than the OOME cap MW, the Setpoint Instruction will be adjusted to the OOME cap MW.

ii) If the current Setpoint Instruction is less than the OOME floor MW, the Setpoint Instruction will be adjusted to the OOME floor MW.

iii) If the current Setpoint Instruction is less than or equal to the OOME cap MW and/or greater than or equal to the OOME floor MW, the Setpoint Instructions will not be adjusted.

c) Minimum Economic Capacity Operating Limits for the current Dispatch Interval are immediately adjusted to the OOME floor MW. Maximum Economic Capacity Operating Limits for the current Dispatch Interval are immediately adjusted to the OOME cap MW; and

d) For future intervals not yet dispatched the Maximum Economic Capacity Operating Limit will be set equal to the OOME cap MW. For future intervals not yet dispatched the Economic Minimum Limits will be set equal to the OOME floor MW;

e) Once the OOME has ended the Resource will return to normal operations as described in this Section.

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4.4.1.5 CONGESTION MANAGEMENT

A congestion management event is initiated by activating a market constraint in WRTBM under the instruction of a Reliability Coordinator in accordance with the Western Congestion Management Methodology document on SPP.org. A set of transmission constraints will be defined as market constraint(s) to limit flows on affected transmission element(s), and will be activated when necessary.

The congestion management event will cause WRTBM to redispatch available Resources to provide appropriate reduction in flows to relieve the constraint. SPP uses WRTBM to reliably manage and economically maximize the flow of power on the transmission constraint to within the applicable operating limits set by a Reliability Coordinator or through Western Interconnection Unscheduled Flow Mitigation Process (WIUFMP).

4.4.2 ENERGY DEPLOYMENTSPP dispatches Energy through the issuance of Dispatch Instructions via XML and ICCP to each Resource on a 5-minute basis.

Market Participants must have the capability to receive and follow Dispatch Instructions. Market Participants with Dispatchable Resources must have primary and secondary connections and be capable of following instructions from both. In the event of a communications failure, SPP will systematically communicate Energy Dispatch Instructions to Market Participants secondary connections.

4.4.2.1 DISPATCHABLE VARIABLE ENERGY RESOURCE DISPATCH

SPP shall systematically provide a binary signal flag which notifies the Dispatchable Variable Energy Resource (DVERs) to either “follow” or “ignore” the SPP Setpoint Instruction. When the “follow” signal is received, the Dispatchable Variable Energy Resource shall follow the Setpoint Instruction. In any Dispatch Interval in which the DVER follow flag is set to “ignore”, the Setpoint Instruction is calculated as the echo of actual SCADA output. In addition, DVERS will receive a “follow” dispatch flag according to the rules in 4.2.3 and 4.2.3.3.

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4.4.2.2 NON-DISPATCHABLE VARIABLE ENERGY RESOURCE AND PARTIAL PARTICIPATION RESOURCE DISPATCH

Non-Dispatchable Variable Energy (NDVERs) and Partial Participation Resources (PPRs) will be dispatched to an echo of actual SCADA output as recorded at the time of WRTBM execution.

4.4.2.3 RESERVE SHARING GROUP SCHEDULING PROCEDURES

SPP will obtain the projected NSI for ten minutes in the future and each Balancing Authority will telemeter the amount of deployed contingency reserves and the amount of interchange reserves. WRTBM offsets the NSI by the reserves deployed and interchange reserves, protecting against an oversupply of energy during a reserve sharing group deployment event. The energy schedules created for the reserve sharing group reserve deployment are settled consistent will all other Energy Schedules. After ten (10) minutes or once the reserve sharing group deployment event ends, whichever is longer, the load obligation offset will be removed.

Reserve sharing schedules are outside the scope of the protocols. The BA determines the processes around submitting those schedules.

4.4.2.4 UNINSTRUCTED RESOURCE DEVIATION

The following rules apply to the calculation of Uninstructed Resource Deviation (URD).

(1) URD is the difference between a Resource’s actual average MW output over the Dispatch Interval and the Resource’s average ramped MW Setpoint Instruction over a Dispatch Interval. For the purposes of determining URD exemptions for Resources that are part of a Common Bus as described under Section 4.4.2.4.1 each Resources’ combined average ramped MW Setpoint Instruction and combined actual average MW output at the Common Bus will

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be used to calculate URD at the Common Bus for the Dispatch Interval for each Asset Owner;

(2) A Resource accrues URD when operating outside of its Operating Tolerance. The accrued URD results in a charge based on the LMP described in Section 4.5.3.

a. A Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s registered Maximum Capacity Operating Limit adjusted for any derates multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

b. A Dispatchable Demand Response Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Economic Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

c. The Common Bus Operating Tolerance for each Resource registered at a Common Bus is equal to the sum of that Resources’ registered Maximum Capacity Operating Limit adjusted for any CROW derates for Resources that are on-line multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

d. The Resource Operating Tolerance is expanded to allow for any Operating Reserves deployed by the host Balancing Authority as defined in the Resource’s operating plan. The Operating Tolerance expands in the upward direction by the amount of regulation-up carried on the Resource for the Dispatch Interval. The Operating Tolerance expands in the downward direction by the amount of regulation-down carried on the Resource for the Dispatch Interval. The Operating Tolerance expands in the upward direction by the amount of Spinning and Supplemental Reserves carried on the Resource for a Dispatch Interval in which Contingency Reserves have been deployed.

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4.4.2.4.1 URD EXEMPTIONSA Resource will receive a URD exemption in a Dispatch Interval under the following situations:

1) The Resource trips or is derated after receiving Dispatch Instructions;

2) There is missing or bad Resource SCADA data in the Dispatch Interval;

3) If a Dispatch Instruction is issued to a Resource beyond the reported capabilities due to the application of a VRL;

4) If the Resource is part of a Common Bus and the URD calculated at the Common Bus is less than the Operating Tolerance calculated at the Common Bus;

5) A Resource will receive an Uninstructed Resource Deviation exemption to the extent a Market Participant can demonstrate the URD resulted from an event of force majeure or, in the case of a Variable Energy Resource, if the URD results from extremely high wind or other extreme weather-related conditions materially and directly impacting a Variable Energy Resource’s ability to provide Energy. For purposes of this subsection, the term force majeure shall have the meaning described under Section 5.1 of the WEIS Tariff except that acts of Curtailment shall not qualify for exemption.

6) The Resource is issued an OOME instruction for Energy.

In the event a Resource does not receive a URD exemption in a Dispatch Interval, the Market Participant may provide SPP with adequate documentation through the dispute process in order for the Market Participant to be eligible to avoid such Uninstructed Resource Deviation. SPP shall determine through the dispute process whether an exemption will be given. Adequate documentation may include but is not limited to an audio file documenting a call between the Market Participant and SPP.

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4.5POST OPERATING DAY AND SETTLEMENT ACTIVITIES

Post Operating Day activities begin on the day immediately following the Operating Day. SPP Settlement Statement process is outlined in Section 4.5.7. Settlement Statements will be configurable by Market Participants to show hourly net amounts or to show that Market Participant’s hourly and sub-hourly billing quantities at each Settlement Location to be paid or credited resulting from the settlement of the Western Energy Imbalance Service. All charge types and billing determinants defined under Sections Error: Reference source not found4.5.6, and Appendix A of this document are available on the Settlement Statement and Settlement Determinant Report unless specifically excluded as identified in the table definitions under each charge type. Settlement Invoices are issued weekly.

Metering standards associated with submittal of actual load and Resource Energy quantities are specified in Appendix B and settlement data reporting processes are specified in Appendix C to these WEIS Market Protocols. Detailed explanations of all WRTBM charges types, along with example calculations, are contained within Appendix A to these WEIS Market Protocols.

Exhibit 4-5 provides a representative overall timeline of Post Operating Day activities.

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Exhibit 4-6: Post Operating Day Activities Timeline

4.5.1 SETTLEMENT SIGN CONVENTIONSSettlement statements use negative signs to reflect payments to Market Participants and positive signs to reflect charges to Market Participants. Throughout the settlement calculations, multiplication by (-1) is used to attain the proper sign convention. The following sign conventions are applied for settlement calculations:

1) Import Interchange Transaction MWh is a negative value;

2) Export Interchange Transaction MWh is a positive value;

3) Dispatch Instruction MW is a positive value;

4) Setpoint Instruction and Dispatch Instructions are positive values;

5) Actual Meter values and telemetered/State Estimator values for Resource output is a negative value;

6) Actual meter values and telemetered/State Estimator values for Load consumption is a positive value;

7) Net Actual Interchange into a BA or SA is a negative value;

8) Net Actual Interchange out of a BA or SA is a positive value;

9) Supply Imbalance Energy MWh is a negative value;

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10) Obligation Imbalance Energy MWh is a positive value.

4.5.2 COMMERCIAL MODELThe Commercial Model describes the financial market relationships of the Market Participants and their designated Asset Owners (AOs), and the commercial relationships among the elements of the Network Model. The hierarchy of relationships along with their descriptions is as follows.

1) Node Level

2) Pricing Node Level (PNode) Level

a) Aggregate Pricing Node Level (APNode) Level

3) Meter Data Submittal Locations (MDSL)

4) Settlement Locations

5) Asset Owner Level

6) Market Participant Level

4.5.2.1 NODES

Nodes represent Electrical Nodes (ENodes) within the Network Model where LMPs are calculated. ENodes represent the physical connection points in the transmission system Network Model. ENodes include all locations in the Network Model where electrical equipment components (e.g. generators, loads, transmission lines, and transformers) connect but LMPs are calculated at only a subset of ENodes (i.e. Nodes).

4.5.2.2 PRICING NODES

Pricing Nodes (PNodes) provide the linkage between the Network Model and the Commercial Model and are the finest level of granularity in the Commercial Model and have a one-to-one relationship with a Node. PNodes are defined for all locations where energy is injected and/or withdrawn from the Transmissions System, as well as other commercially significant buses.

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4.5.2.2.1 AGGREGATED PRICING NODESThe Aggregated Pricing Node (APNode) represents an aggregation of two or more PNodes using weighting factors. For each APNode, the relationship of PNodes to APNodes determines how Energy at the APNode level is allocated at the PNode/ENode level and/or how prices at the PNode level are weighted at the APNode level. This nodal relationship is maintained in SPP’s registration system. However, weighting factors may vary based on projected or historical injection/withdrawal values at each PNode for the applicable market process.

4.5.2.3 METER DATA SUBMITTAL LOCATIONS (MDSL)

A Meter Data Submittal Location includes one or more Meter Settlement Locations (PNodes). A Settlement Area includes one or more Meter Data Submittal Location(s). Meter Data Submittal Location(s) meter data is a component of the settlement billing process and represents the level at which meter data is submitted. It is usually 1:1 with SL, but in certain cases multiple MDSLs may relate to a single SL. MDSLs are confined to a single SA (necessary for the purpose of calibration calculation) while a SL may span multiple SAs.

4.5.2.4 SETTLEMENT LOCATIONS

Settlement Locations represent the next hierarchical level in the Commercial Model and have a relationship to one or more MDSLs. Energy supply and demand is financially settled at the Settlement Locations based on the appropriate MDSL and Settlement Location energy injection or withdrawal level. There are three (3) types of Settlement Locations: Resource, Load, and Interface.

4.5.2.5 ASSET OWNERS

The Asset Owner is the next higher hierarchical level in the Commercial Model and typically, but not necessarily, represents a company. A company may choose to be registered as more than one Asset Owner. Within the Commercial Model, Asset Owners can represent any combination of generation and load assets within the WEIS Region. All Asset Owners must each be represented by a Market Participant. SPP calculates charges and produces market settlements statements at the Asset

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Owner level. Each Settlement statement provides the billing determinants for each transaction, along with the Asset Owner’s total financial obligation resulting from its transactions.

4.5.2.6 MARKET PARTICIPANTS

The Market Participant is the highest hierarchical level in the Commercial Model and is the entity in the Commercial Model that is financially obligated to SPP for market settlements. A single Market Participant represents one or more Asset Owners. A single Market Participant may authorize other entities to act on its behalf.

Exhibit 4-6 provides an illustration of potential relationships within the Commercial Model.

Exhibit 4-7: Example of Commercial Model Relationships

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In additional to these defined financial relationships, the Commercial Model is also used to define and represent Meter Data Submittal Locations and Demand Response Load. These relationships are defined under Section 5.

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Legend: AO = Asset Owner MP = Market

ParticipantG = GeneratorL = LoadD = Demand

Response


4.5.3 CALCULATION OF LMPS AND LMP COMPONENTSSPP uses a SCED model to compute Locational Marginal Prices (LMPs) for Energy at PNodes. The LMPs are then mapped to Settlement Locations in the Commercial Model. For the WRTBM, LMPs are calculated for each 5-minute Dispatch Interval. Inputs to SCED for the WRTBM are as described under Section 4.4.1.1.1 and 4.4.1.1.2. The following subsections further describe how LMPs and LMP components are calculated.

4.5.3.1 LMP CALCULATIONS AND LMP COMPONENTS

The LMP at a PNode is the cost of delivering an incremental MW of energy at that specific PNode, while satisfying all operational constraints including operational constraints that are relaxed as a part of a VRL described in section 4.1.2. The LMP at any PNode is the sum of two components; the marginal costs of Energy (Marginal Energy Component or MEC) and the marginal cost of congestion (Marginal Congestion Component or MCC).

LMP components at PNode i are calculated based upon the following formulas:

LMPi = MEC + MCCi

Where:

1) MEC is the component of LMPi representing the marginal cost of Energy;

2) MCCi is the component of LMPi representing the marginal cost of congestion at ENode i relative to the Reference Bus; and

3) The Reference Bus represents the network distributed load bus.

4.5.4 SETTLEMENT LOCATION LMPS AND LMP COMPONENTS

For Settlement Locations that are associated with more than one PNode, the following calculations are performed to calculate the Settlement Location LMPs and the associated LMP components. The LMPs for Settlement Locations associated

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with a single PNode are those LMPs directly calculated by the WRTBM software as described under Section 4.4.1.3. All nodal LMPs are subject to the price correction procedures described under Section 6.2.

4.5.4.1 CALCULATION OF LMP AT A LOAD APNODE SETTLEMENT LOCATION

SPP calculates an LMP for each APNode Load Settlement Location based on the LMPs for the set of PNodes that comprise the APNode Load Settlement Location. These Load Settlement Location LMPs are the weighted average of the LMPs at the PNodes that comprise the Load Settlement Location. For WRTBM, the weighting factors are those described under Section 4.1.1.1.5. These weighting factors are applied for calculating the LMP and MCC for the APNode Load Settlement Location.

The LMP for APNodej is:

LMPAPNodej = ∑k (Wk * LMPk )

The MCC for APNodej is:

MCCAPNodej = ∑k (Wk * MCCk )

Where:

1) Wk is the weighting factor for PNode k which is part of APNode j. The sum of the weighting factors for all PNodes k must sum to 1.0;

2) LMPk is the LMP for PNode k which is part of APNode j;

3) MCCk is the Marginal Congestion Component of the LMP for PNode k which is part of APNode j.

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4.5.4.2 CALCULATION OF LMP AT AN EXTERNAL INTERFACE SETTLEMENT LOCATION

SPP calculates an LMP for each External Interface based on the LMPs for the set of PNodes that comprise the External Interface. These External Interface LMPs are the weighted average of the LMPs at the PNodes that comprise the External Interface. The weighting factors are pre-determined by SPP at the time the External Interface is created and are not dependent upon historical injections/withdrawals.. These weighting factors are applied for calculating a LMP and MCC at an External Interface for the WRTBM.

The LMP for External Interfacej is:

LMPEIj = ∑k (Wk * LMPk )

The MCC for External Interface j is:

MCCEIj = ∑k (Wk * MCCk )

Where:

1) Wk is the weighting factor for PNode k which is part of External Interface j. The sum of the weighting factors for all PNodes k must sum to 1.0;

2) LMPk is the LMP for PNode k which is part of External Interface j;

3) MCCk is the Marginal Congestion Components of the LMP for PNode k which is part of External Interface j.

4.5.5 PRECISION AND ROUNDINGExhibit 4-7 documents the input data precision assumptions and the rounding assumptions related to calculated values for each intermediate bill determinant and all charge types. The Unit column corresponds to the Unit column included in the variable description tables included with each charge type. The rounding

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assumptions in Exhibit 4-7 under the Calculated Data are applied to all variable names that begin with a ‘#’.

Exhibit 4-8: Input Data Precision and Rounding Assumptions

Input Data Maximum Allowable Precision

Calculated Data

Unit Precision Unit Rounding$/MW or $/MWh .0001 $ .01

MWh .001 MWh .001MW .001 MW .001

Factor .0001 Factor .0001$ .01 (for cost

data)Rate .0001

Time (minutes) 1 (for Offer parameters)

4.5.6 ENERGY IMBALANCE MARKET SETTLEMENTAn Energy Imbalance Service Market settlement is calculated for each Dispatch Interval per Settlement Location based on the difference between the Market Participant's obligation and supply by Asset Owner within the WEIS Market Footprint. Energy Imbalance Service settlement includes Ancillary Service deployments.

Settlement calculations for the WRTBM are performed on a Dispatch Interval or hourly basis for each Operating Day and are based on the results of the WRTBM process for that Operating Day.

WRTBM results are presented on an hourly basis but Market Participants have access to the 5-minute data for verification purposes.

The following subsections describe the WRTBM settlement charge types in more detail. For each charge type, the initial calculation is performed either at the Dispatch Interval level or hourly level for each Asset Owner at each Settlement Location. In addition to the Dispatch Interval and hourly values, hourly and daily

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values will be accessible on the Settlement Statement for all charge types. Actual settlement examples and detailed calculations can be found in Appendix A of the protocols.

4.5.6.1 ENERGY IMBALANCE SERVICE AMOUNT

Allocation of Energy Imbalance Service (EIS) is calculated through the following steps; 1) Calculate adjusted meter data; 2) Calculate residual amount and calibration to loads within SA; 3) Calculate Billable Meter Data; 4) Calculate Imbalance Energy by Asset Owner for NLH; 5) Calculate Imbalance Energy Unhedged Quantity; and 6) Calculate Energy Imbalance Service Amount.

4.5.6.1.1 CALCULATE ADJUSTED METER DATAFor all Meter Data Submittal Locations, the 5-minute adjusted meter determinant is a hierarchal selection among 1) 5-minute submitted actual meter reading, 2) profiled hourly submitted actual meter reading and 3) default 5-minute state estimator value. Registration records whether 5-minute or hourly meter data submittals are selected. The methodologies are mutually exclusive for any given period. Market Participants who choose to submit their actual hourly meter reading into 5-minute intervals must use a profiling method consistent with the method described below using a data source as described in Appendix C Section C.10. Meter submissions will include transmission losses.

State estimator, 5-minute adjusted meter, and SCADA determinants are expressed in terms of levelized MW and both hourly and 5-minute submitted actual determinants are in terms of MWh. To calculate WRTBM actual Energy in a Dispatch Interval for Market Participants that have not directly submitted 5-minute interval meter data, SPP allocates the submitted hourly meter data for Resources and loads into 5-minute values using 5-minute telemetered or State Estimator profiles for the corresponding hour. The profiling of the hourly meter data maintains the shape of the 5-minute telemetered or State Estimator values even if there are both positive and negative values contained within the 12 intervals. All Dispatch Interval values are expressed in MW, not MWh. Exhibit 4-8 shows an example of how the profiling

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will work for a Resource that submits an actual hourly meter amount of -80 MWh. This process is used to create the adjusted 5-minute meter data.

Exhibit 4-9: Meter Profiling Example

Interval (1)State

Estimator MW

(2)Absolute Value of Column

(1)

(3)Normalize Column (2)

[Col (2) MW / Total Col (2)

MW]

(4)Profiled Hourly

Meter(-80 – (-66.25)) *

12 * Col (3) + Col (1)

1 10 10 0.012 82 5 5 0.006 43 0 0 0.000 04 -50 50 0.061 -605 -60 60 0.073 -726 -70 70 0.085 -847 -80 80 0.097 -968 -90 90 0.109 -1089 -100 100 0.121 -120

10 -110 110 0.133 -13211 -120 120 0.145 -14412 -130 130 0.158 -156

-66.25 MWh 825 (total) 1.000

-80 MWh (Meter)(submitted)

4.5.6.1.2 CALCULATE RESIDUAL AMOUNT AND CALIBRATION TO LOADS WITHIN SA

The hourly adjusted meter determinant is the sum of the 5-minute adjusted meter determinant divided by 12. The hourly adjusted meter determinant is expressed in terms of levelized MW.

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The hourly residual load determinant is the net difference between generation & load (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area), and interchange and losses per Settlement Area. Hourly Net Actual Interchange is derived as the sum of the hourly metering submitted for aggregate ties between interconnected Settlement Areas. Missing tie values are replaced with State Estimator values. The hourly residual determinant is expressed in terms of levelized MW.

The hourly calibration meter determinant is the weighted distribution of Settlement Area residual among load in the Settlement Area (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area). The hourly calibration meter determinant is expressed in terms of levelized MW. WAPA’s transmission capacity and deliveries of Statutory Obligations will be exempted from calibration.

The 5-minute calibration meter determinant is the hourly calibration meter quantity, profiled by State Estimator data into 5-minute intervals. The 5-minute calibration meter determinant is expressed in terms of levelized MW.

4.5.6.1.3 CALCULATE BILLABLE METER DATAThe 5-minute billable meter determinant at the Meter Data Submittal Location level is the sum of the 5-minute adjusted meter determinant and the 5-minute calibration meter determinants at the Meter Data Submittal Location. Both 5-minute determinants are expressed in terms of levelized MW.

The 5-minute billable meter determinant at the Settlement Location level is the sum of the 5-minute billable meter determinants at the Meter Data Submittal Location level. Most Settlement Locations will be comprised of only one Meter Data Submittal Location, but in certain cases a single Settlement Location will represent multiple Meter Data Submittal Locations, each of which is in a separate Settlement Area. Since the calibration function must be performed within Settlement Area boundaries, it is done before summing the data to the Settlement Location level.

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The 5-minute determinants are expressed in terms of levelized MW at both the Settlement Location and Meter Data Submittal Location level

4.5.6.1.4 CALCULATE IMBALANCE ENERGY BY ASSET OWNER FOR NATIVE LOAD HEDGING

The determination of each Market Participant’s Imbalance Energy by Asset Owner will be calculated under the Native Load Hedging (NLH) methodology. In the WEIS Market, native load and Energy Schedules are hedged using lowest priority supply, then least cost supply, before supplying Imbalance Energy. The inputs into the NLH methodology are metered load, metered generation, interchange and energy tags between Asset Owners within a BA. For an export energy tag to be considered a valid input for NLH process, the source must be from a registered Settlement Location. For an import energy tag to be considered a valid input for NLH process, the sink must be for a registered Settlement Location. For an internal energy tag the source and sink of the energy tag that maps to a valid Settlement Location in the Commercial Model will be included in NHL. Energy tags that have a source and sink mapped to Settlement Locations registered to the same Asset Owner will not be considered for purposes of the NLH methodology.

Sources and sinks not included in native load hedging are described in Section 4.5.6.1.5.

The NLH methodology centers upon the difference between supply and obligations for each Market Participant calculated by Asset Owner. The obligations will be determined by summing the metered load at each Settlement Location by Asset Owner over an interval with export energy tags valid for NLH. The supply will be determined by summing the metered generation at each Settlement Location by Asset Owner with import energy tags valid for NLH. If an Asset Owner has more supply than obligations, they will be deemed a net seller of Imbalance Energy. Conversely, if an Asset Owner has less supply than obligations, they will be deemed a net buyer of Imbalance Energy.

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Supply CalculationsThe supply calculations will determine both the total amount of supply available for NLH as well as which portion of the supply is selling Imbalance Energy when the calculated supply is in excess of the calculated obligation. As described above, the total amount of supply available for NLH is the sum of the metered generation at all Settlement Locations added to any energy tags sinking at the same Settlement Location by Asset Owner. Any export tags sourced from that Settlement Location will reduce the amount of supply at that Settlement location based on using lowest priority first and then cost-based for any remaining export obligation. If export tags sourced from that Settlement Location exceed total amount of supply at a Settlement Location, the excess will be considered obligation.The total amount of supply can be grouped into two categories for the purpose of NLH. The first grouping, considered lowest priority, is the sum of the output associated with non-dispatchable generation, and output up to the economic minimum associated with dispatchable generation, the sum of any load Settlement Locations with a net injection after energy tags have been applied, less the amount of any export tags sourced from that Settlement Location. The second grouping, considered cost-based, contains the output associated with dispatchable generation above the economic minimum less the amount of any export tags sourced from that Settlement Location.

Obligation CalculationsThe obligations will be determined by summing the metered load at each Settlement Location, less import tags sinking at the same Settlement Location by Asset Owner over an interval. If energy tags sinking at a Settlement Location exceed the metered load obligation, the excess energy will become lowest priority supply.

Imbalance Energy CalculationImbalance Energy is determined for each Market Participant by comparing the calculated supply to the calculated obligation by Asset Owner.

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1) When the calculated obligation, including the amount of any export energy tags sourced from each Resource Settlement, is greater than the calculated supply, the difference is settled as a purchase from the WEIS Market at the load-weighted average of all load Settlement Locations for that Asset Owner.

2) When the calculated obligation is less than the calculated supply and is also less than the lowest priority supply category described above, the Imbalance Energy is settled as follows:a) The difference between the calculated obligation and the calculated supply

associated with the lowest priority category, and excluding any amount associated with an export energy tag sourcing at that Settlement Location, described above is settled as a sale to the WEIS Market at the generation-weighted average LMP of the Resource Settlement Locations associated with the lowest priority category of supply.

b) The remaining supply, associated with the cost-based category described above, less the amount of any export tags sourced from the same Resource Settlement Location, is settled as a sale to the WEIS Market at the Resource Settlement Location LMP.

3) When the calculated obligation is less than the total calculated supply but is greater than calculated supply associated with the lowest priority region described above, the Imbalance Energy is settled as follows:a) The supply associated with the cost-based category described above is

determined by lining up supply MW in an ascending order, beginning with the lowest cost energy, and excluding any amount associated with an export energy tag sourcing at that Settlement Location. After exhausting the lowest priority category’s supply, this cost-based category’s lowest cost energy is then used to serve the obligation remaining until all calculated obligation has been served.

b) The remaining supply, associated with the cost-based category, less the amount of any export energy tags sourced from each Resource Settlement location associated with the cost-based category, is settled as a sale to the WEIS Market at the Resource Settlement Location LMP.

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4.5.6.1.5 CALCULATE IMBALANCE ENERGY UNHEDGED QUANTITYFor energy tags where the source is in the WEIS Market Footprint and is not a registered Settlement Location, the MP of the source BA will be assigned Imbalance Energy at the load weighted average LMP of the all the loads in the BA containing the point of receipt. For energy tags where the sink is in the WEIS Market Footprint and is not a registered Settlement Location, the MP of the sink BA will be assigned Imbalance Energy at the load weighted average LMP of all the loads in the BA containing the point of delivery. The unregistered source or sink of these energy tags described in this paragraph will not be included in the Supply Calculation or Obligation Calculation described below.

4.5.6.1.6 CALCULATE ENERGY IMBALANCE SERVICE AMOUNTThe Real-Time Energy Imbalance Service Amount can be either a credit or charge to each Market Participant by Asset Owner and is calculated on a net basis at each Settlement Location based on:1) The Energy Imbalance Service MWh quantity calculated at each Settlement

location multiplied by the LMP at that location.

4.5.6.2 REAL-TIME OUT OF MERIT AMOUNT

A WRTBM credit or charge will be made to each Market Participant with a Resource that receives a Setpoint Instruction from a WRTBM OOME that creates a cost to the Market Participant. The amount will be calculated on a Dispatch Interval basis under the following conditions:

1) Each Resource with an OOME instruction that results in an increase in Resource output that creates a sale or an increase in a sale to the WEIS Market will be paid, for its additional output attributable to its response to the OOME Dispatch Instruction (floor or fixed), at the higher of the LMP determined by the security constrained economic dispatch for the Resource Settlement Location or the Resource Energy Offer Curve price at the OOME dispatch point (“OOME Sale Compensation”). If such offer price exceeds the LMP, the difference between the two prices will be multiplied by the minimum of the OOME Dispatch Instruction

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(floor or fixed) and actual output minus the Resource schedule quantity in order to calculate the credit that is recoverable through the revenue neutrality uplift process (Section 4.5.6.5). The OOME Sale Compensation shall be limited to the amount necessary to compensate the Resource for any under-recovery resulting from its response to the OOME Dispatch Instruction (floor or fixed).

2) Each Resource with an OOME instruction that results in a decrease in Resource output that creates a purchase or an increase in a purchase from the WEIS Market will pay, for its WEIS Market purchase attributable to its response to the OOME Dispatch Instruction (cap or fixed), at the lower of the LMP determined by the security constrained economic dispatch for the Resource at the Settlement Location or the Resource Energy Offer Curve price at the OOME dispatch point (“OOME Purchase Compensation”). If the LMP exceeds such offer price, the difference between the two prices will be multiplied by the Resource expected quantity minus the maximum of the OOME Dispatch Instruction (cap or fixed) and the actual output in order to calculate the credit that is recoverable through the revenue neutrality uplift process (Section 4.5.6.5). The OOME Purchase Compensation shall be limited to the amount necessary to compensate the Resource for any under-recovery resulting from its response to the OOME Dispatch Instruction (cap or fixed).

3) To the extent that additional costs are incurred as a direct result of an OOME that are not addressed through the compensation mechanisms described in (1) and (2) above, Market Participants may request additional compensation through submittal of actual cost documentation to SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery.

4.5.6.3 UNINSTRUCTED RESOURCE DEVIATION AMOUNT

In any Dispatch Interval in which the Resource has operated outside of its Operating Tolerance and that Resource has not been exempted from URD per Section 4.4.2.4.1, the incremental Energy MW’s associated between actual Energy output

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and the Resource’s Desired Dispatch will be subject to a charge. The URD charge will be based on the following:

1) A generating unit Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Economic Capacity Operating Limit multiplied by five percent (5%), subject to a minimum of five (5) MW and a maximum of twenty (20) MW.

2) A Dispatchable Demand Response Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Economic Capacity Operating Limit multiplied by five percent (5%), subject to a minimum of five (5) MW and a maximum of twenty (20) MW.

3) The Common Bus Operating Tolerance for each Market Participant registered at a Common Bus is equal to the sum of that Market Participant’s Resources’ Maximum Economic Capacity Operating Limits for Resources that are on-line multiplied by five percent (5%), subject to a minimum of five (5) MW and a maximum of twenty (20) MW.

For the purposes of determining URD exemptions for Resources that are part of a Common Bus as described under Section 4.4.2.4.1, each Resources’ combined average ramped MW Setpoint Instruction and combined actual average MW output at the Common Bus will be used to calculate URD Megawatts at the Common Bus for the Dispatch Interval.

4) If the absolute value of a Resource’s URD is greater than the Resource’s Operating Tolerance in any Dispatch Interval, SPP shall calculate an URD Charge equal to the Resource URD Megawatt multiplied by the Locational Marginal Price for that Settlement Location.

5) A Resource’s Operating Tolerance in each Dispatch Interval is increased by the quantity of Regulation service being maintained on the Resource as indicated in the Ancillary Service Plan (MW) for the Operating Hour and any additional MWh for a Reserve Sharing Group event.

In the event a Resource does not receive a URD exemption in a Dispatch Interval, SPP shall determine through the dispute process, in accordance with the invoice

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dispute process as provided in Attachment A, Section 7.3, of the WEIS Tariff whether an exemption to a URD will be given. The Market Participant may provide SPP with adequate documentation in order for the Market Participant to be eligible to avoid such URD. Adequate documentation may include but is not limited to an audio file documenting a call between the Market Participant and SPP.

4.5.6.4 MISCELLANEOUS AMOUNT

In certain circumstances, it may be necessary to recalculate or make changes to previously billed charges for an Operating Day. In the event these charges cannot be calculated using the defined calculations, SPP will manually calculate the adjustment and post as a manual adjustment to the Settlement Statement regardless of the Operating Day in question. A comment containing the reason for the adjustment(s) will be provided in the Settlement Determinant Report on the Operating Day(s) impacted. SPP will post additional supporting documentation to the Portal when applicable. In some situations, the charge or credit assessed must be excluded from Revenue Neutrality Uplift calculations such that SPP is left with a net receivable or payable amount for the settlement of the Operating Day.

A miscellaneous charge type will be utilized for each distinct charge type and any other charges and credits not specifically accounted for under a distinct charge type.

4.5.6.5 REVENUE NEUTRALITY UPLIFT DISTRIBUTION AMOUNT

A charge or credit will be calculated at each Settlement Location by Asset Owner for each hour in order for SPP to remain revenue neutral. Contributors to revenue non-neutrality include:

1) Rounding errors (related to the calculation of all Charges/Credits);

2) WRTBM residual Energy Imbalance Service Amount;

3) Uninstructed Resource Deviation Credits;

4) Payments for Out-of-Merit Energy; and

5) Miscellaneous Charges/Credits.

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The amount will be determined by multiplying the hourly determinant by a daily Revenue Neutrality Uplift (RNU) rate. The hourly determinant is equal to the sum of that actual generation MWh, actual load MWh, and actual Interchange Transaction (import and exports) MWh, where all of these values are assumed to be positive values.

The calculation of the Revenue Neutrality Uplift (RNU) in the WEIS Market Footprint can result in residual amounts due to rounding as established in Section 4.5.5. The sum of the residual amounts due to rounding for an Operating Day, whether a charge or a credit, are incorporated in the SPP budgeted expenses used to calculate the costs specified under the WEIS Tariff.

4.5.7 SETTLEMENT STATEMENT PROCESS4.5.7.1 METER DATA

All meter data submitted per (1) below will be included in the Settlement(s) scheduled to be executed. Meter updates after the S120 Scheduled Settlement will be limited to disputes submitted and granted per Section 4.5.9.

1) Except in the case of a four day holiday as discussed in Section 4.5.7.8, reported values for an Operating Day must be received by noon according to the following:

a) Day 4 following the Operating Day for inclusion in the S7 Scheduled Settlement Statement. If day 4 falls on a Saturday or Sunday, then data is due on preceding Friday at noon.

b) Day 48 following the Operating Day for inclusion in the S53 Scheduled Settlement Statement.

c) Day 110 following the Operating Day for inclusion in the S120 Scheduled Settlement Statement.

4.5.7.2 DAILY SETTLEMENT STATEMENT

The Settlement Statement(s) will be made available for each Operating Day and will be published for Market Participants and associated Asset Owners electronically

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through the Portal on Business Days. The Market Participant is responsible for accessing the information from the Portal once posted by SPP. In order to issue a Settlement Statement, SPP may use estimated, disputed or calculated meter data. An S7, S53, and S120 Scheduled Settlement Statement will be created for each Operating Day. Resettlement Statements can be created for any given Operating Day as defined in Section 4.5.7.7. When settlement and billing disputes submitted by Market Participants during the validation process have been resolved, SPP shall recalculate the amounts payable and receivable by the affected Market Participant.

For each Market Participant, Settlement Statement(s) will denote:

1) Operating Day;

2) Associated Asset identifier;

3) Market Participant identifier;

4) Type of statement (S7, S53, S120, R<ddd>, where ddd represents the number of days after Operating Day);

5) Statement version number;

6) Unique Statement identification code; and

7) Market services settled.

Settlement Statements will include charges and credits by Asset Owner, appropriate Settlement Interval and Settlement Location.

4.5.7.3 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.

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4.5.7.4 S7 SCHEDULED SETTLEMENT STATEMENTS

SPP will produce the S7 Scheduled Settlement Statements for each Market Participant for each Operating Day. This preliminary Scheduled Settlement Statement is defined as an S7 Scheduled Settlement. For non-holidays as shown in Exhibit 4-9, S7 Scheduled Settlement Statements will be posted at the end of the seventh (7th) Calendar Day following the Operating Day. If the seventh (7th) Calendar Day is not a Business Day, the S7 Scheduled Settlement Statement shall be issued no later than the next Business Day thereafter. For holidays, the S7 Scheduled Settlement Statements will be created as shown in Exhibit 4-10


SPP will produce the S53 Scheduled Settlement Statements for each Market Participant for each Operating Day. This second Scheduled Settlement Statement is defined as an S53 Scheduled Settlement Statement. S53 Scheduled Settlement Statements will be posted at the end of the fifty-third (53rd) Calendar Day following the Operating Day. If the fifty-third (53rd) Calendar Day is not a Business Day, the S53 Scheduled Settlement Statement shall be issued on the next Business Day thereafter. The S53 Scheduled Settlement Statement will reflect the net changes to settlement charges or credits generated on the Operating Day’s S7 Scheduled Settlement Statement. For holidays, S53 Scheduled Settlement Statements will be created as shown in Exhibit 4-10


SPP will produce the S120 Scheduled Settlement Statements for each Market Participant for each Operating Day. This final Scheduled Settlement Statement is defined as an S120 Scheduled Settlement Statement. The S120 Scheduled Settlement Statements will be posted at the end of the one hundred and twentieth (120th) Calendar Day following the Operating Day. If the one hundred and twentieth (120th) Calendar Day is not a Business Day, the S120 Scheduled Settlement Statement shall be issued on the next Business Day thereafter. The S120 Scheduled Settlement Statement will reflect the net changes to settlement charges or credits generated on the Operating Day’s S53 Scheduled Settlement Statement.

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For holidays, S120 Scheduled Settlement Statements will be created as shown in Exhibit 4-10.

4.5.7.7 RESETTLEMENT STATEMENTS

An ad-hoc Settlement Statement produced through the Resettlement of an Operating Day to effect a correction to a previously posted Settlement Statement for an Operating Day:

1) Resettlements will be limited to the following reasons:

a) The correction of data resulting from an SPP Software Error and/or an SPP Data Error per the discretion of SPP in accordance with the rules specified under Section 4.5 of Attachment A to the WEIS Tariff.

b) A granted dispute in accordance with the guidelines in Section 4.5.9.

c) Per court order or FERC order

2) Resettlements are limited to 330 days following the Operating Day, allowing for a dispute period following the relevant Resettlement Statement, prior to reaching the 365 day limit set by the WEIS Tariff.

3) Resettlement Statements shall be referred to according to the number of days following the Operating Day that the results are posted to the Portal, e.g., a Resettlement posted 200 days following the Operating Day would be referenced as the R200 Resettlement.

4) Any settlement and billing dispute for S7 or S53 Scheduled Settlement Statements resolved in accordance with the Dispute Resolution process of the WEIS Tariff will be corrected on the S120 Scheduled Settlement Statement for the Operating Day. In the event that the S120 Scheduled Settlement Statement does not resolve a granted dispute from an S7 or S53 Scheduled Settlement Statement for a given Operating Day, SPP will resolve the dispute on a Resettlement Statement for that Operating Day. Only Disputes for which SPP is

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notified by the end of the time period as defined under Section 4.5.9 will be considered for Resettlement.

5) 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.

4.5.7.8 SETTLEMENT TIMELINE

SPP shall create Settlement Statements and Settlement Determinant Reports daily for each Market Participant and associated Asset Owner, detailing each Market Participant’s cost responsibility. Settlement Statements are published through the Portal on each Business Day. SPP shall prepare a Settlement Invoice each billing cycle for each Market Participant showing the net amount to be paid or received by the Market Participant. Settlement Determinant Reports shall provide sufficient detail to allow verification of the billing amounts and completion of the Market Participant’s internal accounting. SPP’s settlement systems shall allow Market Participants to search for Settlement Statements by issuance date and invoice date and Settlement Determinant Reports by operating date. Settlement Statements shall be issued in accordance with the timelines shown in Exhibits 4-9 and 4-10.

Exhibit 4-10: Settlements Timeline – Non Holiday Example

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Exhibit 4-10 applies to all Thursday through Sunday holidays and similar logic will apply to other 4 day holiday weekend scenarios:

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S7 (Preliminary Scheduled Settlement Statement)

S53 (Second Scheduled Settlement Statement)

S120 (Final Scheduled Settlement Statement)


Exhibit 4-11: Settlements Timeline –Holiday ExampleSunday Monday Tuesday Wednesda

yThursday Friday Saturday

Nov 14 Nov 15Meter DataS7: 11/11S53: 9/21S120: 7/18

StatementsS7: 11/6 – 11/8S53: 9/19 – 9/21S120: 7/16 – 7/18

Nov 16Meter DataS7: 11/12S53: 9/22S120: 7/19

StatementsS7: 11/9S53: 9/21S120: 7/19


Statements S7: 11/10S53: 9/23S120: 7/20


StatementsS7: 11/11S53: 9/24S120: 7/21

Nov 19Meter DataS7: 11/15 – 11/17S53: 9/25 – 9/27S120: 7/22 – 7/24

StatementsS7: 11/12S53: 9/25S120: 7/22

Nov 20

Nov 21 Nov 22Meter DataS7: 11/18S53: 9/28S120: 7/23 – 7/25

Statements

Nov 23Meter DataS7: 11/19 – 11/20*S53: 9/29 – 9/30*S120: 7/26 – 7/27*


Nov 25

Holiday

Nov 26

Holiday

Nov 27

Holiday

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S7: 11/13 – 11/15S53: 9/26 – 9/28S120: 7/23 – 7/25

StatementsS7: 11/16 S53: 9/29S120: 7/26

StatementsS7: 11/17 – 11/19 S53: 9/30 – 10/2S120: 7/27 – 7/29

Nov 28

Holiday

Nov 29 Meter DataS7: 11/23 – 11/24*S53: 10/3 – 10/4*S120: 7/29 – 7/30*

StatementsS7: 11/20 – 11/21S53: 10/3 – 10/4S120: 7/30 – 7/31


StatementsS7: 11/22 – 11/23S53: 10/5 – 10/6S120: 8/1 – 8/2

Meter Data Due by Noon on days indicated*Meter Data due by 3:00 pm instead of normal noon deadlineInitial Settlement Statement (ISS)

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S7 (Preliminary Scheduled Settlement Statement)S53 (Second Scheduled Settlement Statement)S120 (Final Scheduled Settlement Statement)

4.5.8 SETTLEMENT INVOICESPP prepares weekly Settlement Invoices from Settlements Statements. Settlement Invoices will be prepared on a net basis, with payments made to or from SPP.

Invoices will be posted on the Portal by 8:00 a.m. CPT (see Section 4.5.8.3 Holiday Invoice Calendar for exceptions). The Market Participant is responsible for accessing the Settlement Invoice information via the Portal once posted by SPP.

Each Market Participant with a net debit balance will pay any net debit whether or not there is any settlement and billing dispute regarding the amount. Each Market Participant with a net credit balance will receive the balance shown on the Settlement Invoice, adjusted for balances not collected from Market Participants with net debit balances.

4.5.8.1 TIMING AND CONTENT OF INVOICE

SPP will electronically post for each Market Participant, an invoice based on any Scheduled Settlement Statements or Resettlement Statements produced since the prior Settlement Invoice. SPP shall post the Settlement Invoices to the Market Participant in accordance with the Settlement Calendar. The Market Participant is responsible for accessing the information from the Portal once posted by SPP.

Invoices will be issued on a weekly basis as defined in SPP invoice calendars described in Sections 4.5.8.2 and 4.5.8.3. The SPP invoice calendar will be posted monthly on the SPP Portal. Invoice items will be grouped by type of statement (S7, S53, and S120 Scheduled Settlements and Resettlements)and will be sorted by Operating Day within each category. Each Settlement Invoice will contain:

1) Market Participant ID – the name, address and contact information for the Market Participant being invoiced;

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2) Net Amount Due/Payable – the aggregate summary of all charges owed or due by a Market Participant;

3) Amount Due/Payable by Asset Owner, Operating Date and Settlement Date — the aggregate of charges owed or due by a Market Participant by Asset Owner, listed by Operating Day which shall be identified by calendar date;

4) Time Periods – the time period covered for each Settlement Statement run date identified by a range of calendar dates;

5) Run Date – the date in which the invoice was created and published;

6) Invoice Reference Number – a unique number generated by the SPP applications for payment tracking purposes;

7) Settlement Statement ID– an identification code used to reference each Settlement Statement invoiced;

8) Payment Date and Time – the date and time that invoice amounts are to be paid or received;

9) Remittance Information Details – details including the account number, bank name and electronic transfer instructions of the SPP account to which any amounts owed by the Invoice Recipient are to be paid or of the Invoice Recipient’s account to which SPP shall draw payments due;

10) Overdue Terms – the terms that would be applied if payments were received late;

11) Late fees; and

12) Miscellaneous charges from tariff billing not otherwise covered above with details provided or referenced on what the miscellaneous charges include and how they are derived.

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4.5.8.2 INVOICE CALENDAR

Weekly invoices will be distributed every Thursday by no later than 8:00 a.m. CPT with the exceptions described in Section 4.5.8.3 for holidays. Weekly invoices will include the seven (7) daily Settlement Statements (Scheduled Settlements and any Resettlements) produced for the previous Wednesday through Tuesday cycle. Market Participant balances owed to SPP are due by 5:00 p.m. (CPT) of the first (1st) Wednesday following the Thursday invoice date. Balances owed by SPP to Market Participants will be paid on the second (2nd) Friday following the invoice date by 5:00 p.m. (CPT).

4.5.8.3 HOLIDAY INVOICE CALENDAR

The Thursday invoice date and the following Wednesday and Friday payment dates as described in Section 4.5.8.2 will be changed to the next Business Day if the invoice date or payment date fall on a SPP Holiday. In those cases when a payment date falls on a bank holiday but not a SPP holiday, the payment date will be the next Business Day. If there are two (2) consecutive SPP holidays, the following calendar will apply (all invoice dates assume the invoice will be made available to customers by 8:00 a.m. (CPT) on the date shown):

Holiday Invoice Date Customer Pmt Due Date

SPP Pmt Due Date

Mon-Tue Previous Thu Fri Tue

Tue-Wed Following Mon Fri Tue

Wed-Thu Following Mon Fri Tue

Thu-Fri Following Mon Fri Tue

Fri-Mon Normal Sched Fri Tue

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4.5.9 DISPUTESA Market Participant may dispute items set forth in any Settlement Statement. The dispute must be filed using the Request Management System as shown in Exhibit 4-11 with the following minimum content:

1) Request type;

2) Subject;

3) Full Description;

4) Statement Type;

5) Charge Type;

6) Settlement Location;

7) Operating Day;

8) Start interval;

9) End Interval;

10) Dispute Amount; and

11) Proposed Resolution

Exhibit 4-12: Contents of Notice Dispute Form

PLACEHOLDER FOR EXAMPLE ONCE RMS IS SET-UP

4.5.9.1 DISPUTE SUBMISSION TIMELINE

A Market Participant may dispute the settlement of any Operating Day beginning with the posting of the S7 Scheduled Settlement Statement for that Operating Day, and through the 90th Calendar Day after the applicable Operating Day. In the case of the S120 Scheduled Settlement and any Resettlement Statements, a Market Participant may only dispute material incremental changes that occur between the

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posting of: (i) the S53 and S120 Scheduled Settlements; (ii) the S120 Scheduled Settlement and the first Resettlement Statement; or (iii) two consecutive Resettlement Statements. Material for the purpose of this Section 4.5.9.1 is defined as a dispute wherein more than $2,000.00 is at issue for the Market Participant for the impacted Operating Day. The Market Participant must submit documentation supporting the materiality of the dispute for consideration. A dispute relating to an S120 Scheduled Settlement or Resettlement Statement must be filed within 30 Calendar Days following the posting of the applicable Settlement Statement that the Market Participant wishes to dispute.

In the event that the Portal is unavailable on the Business 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 number of sequential Business Days on which the Portal was unavailable.

4.5.9.2 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 A of the WEIS Tariff.

1) SPP shall make reasonable attempts to remedy any informational deficiencies by working with the Market Participant(s);

2) Contents of Notice will be rejected if SPP determines required information is missing. The Dispute will be returned to the Market Participant with an explanation of the missing data no later than 30 days after the receipt of the original or resubmitted dispute. A Market Participant will be able to resubmit the dispute with additional information within 20 Business Days after the Dispute is returned to the Market Participant unless SPP grants an extension of this deadline for good cause. Once the Market Participant sends all required information and SPP determines the settlement and billing dispute is timely and complete, the dispute status will be considered “Open”;

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3) SPP will issue a settlement and billing dispute resolution report containing information related to the disposition of the dispute;

4) 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 available Settlement Statement;

5) For settlement and billing disputes requiring complex research or additional time for resolution, and late disputes that can be reasonably processed, SPP will notify the Market Participant of the length of time expected to research and post those disputes and, if a portion or all of the dispute is granted, SPP will post the necessary adjustments on the next available Settlement Statement or Resettlement for the Operating Day, if any portion or all of the dispute is Granted. Market Participants have the right to proceed to the External Arbitration process in Dispute Resolution of the Tariff for timely filed disputes that cannot be resolved through the settlement and billing dispute process.

4.5.9.2.1 DISPUTE STATUSEach dispute will have a status as defined in the following paragraphs. Valid status designation includes:

1) OPEN & CLOSED: A Dispute will be deemed “Open” when submitted in a timely and complete manner. “Closed” is the final status for all Disputes;

2) DENIED: The Dispute will be “Denied” if SPP concludes that the information used in the Dispute is incorrect. SPP will notify the Market Participant when a Dispute is “Denied”, and will document the supporting research for the denial. If the Market Participant is not satisfied with the outcome of a Denied Settlement and Billing Dispute, the Market Participant may proceed to External Arbitration as described in Dispute Resolution of the Western Energy Imbalance Service Tariff, Dispute Resolution of these Rules. If after 30 Calendar Days from

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receiving notice of a “Denied” dispute, the Market Participant does not begin External Arbitration, the dispute will be “Closed”;

3) GRANTED: SPP may determine a settlement and billing dispute is “Granted”. SPP will notify the Market Participant of the resolution, and will document the basis for resolution. Upon resolution of the issue, the settlement and billing dispute will be processed on the next available Settlement Statement for the Operating Day. Once the necessary adjustments appear on the next available Settlement Statement, the settlement and billing dispute is then “Closed”;

4) GRANTED with EXCEPTIONS: SPP may determine a settlement and billing dispute is “Granted with Exceptions” when the information is partially correct and SPP will provide the exception information to the Market Participant. SPP will require an acknowledgement from the Market Participant of the dispute Granted with Exceptions within twenty Business Days. The acknowledgement must indicate acceptance or rejection of the documented exceptions to the dispute. If accepted, SPP will post the necessary adjustments on the next available 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 available 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 Western Energy Imbalance Service Tariff, Dispute Resolution of these Rules.

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4.5.10 INVOICE PAYMENT PROCESS4.5.10.1 OVERVIEW OF PAYMENT PROCESS

Payments shall be made in a two-step process where:

1) All Settlement Invoices due with net debits owed by Market Participant are paid by 5:00 p.m. (CPT) of the first Wednesday following the Thursday invoice date, and

2) All Settlement Invoices due with net credits owed to Market Participant are paid by 5:00 p.m. (CPT) of the second Friday following the invoice date

Payments due to SPP and payments due to Market Participant will be made by Electronic Funds Transfer (EFT) in U.S. Dollars.

4.5.10.2 INVOICE PAYMENTS DUE TO SPP

Each Market Participant owing monies to SPP shall remit the amount shown on its invoice so SPP receives this amount no later than 5:00 p.m. (CPT) on the first Wednesday following the Thursday invoice date. Payments due will be made by Electronic Funds Transfer (EFT) in U.S. Dollars. Payments will be made regardless of any settlement or invoice dispute regarding the amount of the debit. Payments not received by the due date will be subject to interest charges as approved by the Federal Energy Regulatory Commission.

4.5.10.3 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 5:00 p.m. (CPT) the next day. Once each payout report has been finalized, they will be posted to the Portal by 3:00 p.m. (CPT) on Thursday. At that time, Market Participants will be able to access information regarding their respective Friday payout amounts. The finalized payout calculations will also be provided to the SPP Customer Relations Department on Thursday afternoon by 3:00

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p.m. (CPT) should Market Participants have any questions regarding the payout amounts posted to the Portal.

4.5.11 BILLING DETERMINANT ANOMOLIESCircumstances may occur where billing determinants received from system interfaces contain erroneous data anomalies that would have significant adverse financial impacts on Market Participants if these determinants were used to produce Settlement Statements. In these situations when certain billing determinants deviate beyond prescribed tolerance levels, SPP will work internally and with Meter Agents(s) to resolve the discrepancy and may modify data using actions including, but not limited to substituting meter data with State Estimator when the original data is deemed to be erroneous.

5 WEIS MARKET REGISTRATIONAll Market Participants must register their loads and Resources, excluding Behind-The-Meter Generation less than 10 MW, prior to participation in the WEIS Market. Registration is accomplished by submitting the required information to SPP. In addition, each Market Participant is required to execute the Market Participant Service Agreement specified in Tariff Attachment E. Registration identifies each load and/or Resource to Market Participants by its Asset Owners, Settlement Locations, Meter Agents, and settlement responsibilities. A Market Participant may represent one or more Asset Owners and may appoint a designated agent to perform its functions under these protocols. Resources and loads registered by a Market Participant under the same Asset Owner will count towards supply and obligation for purposes of Native Load Hedging (NLH) described in Section 4.5.6.1.4. Grouping Resources and loads by Asset Owner ensures that assets with the same network service can be hedged through NLH while assets without the same network service must be scheduled to hedge.The participating Balancing Authorities (BA) must register all loads and Resources, excluding Behind-The-Meter Generation less than 10 MW, which are within their BAA but are not registered by another Market Participant that is participating in the WEIS Market. The Market Participant registering Resources and load not directly

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participating in the WEIS Market will be financially responsible for any Imbalance Energy associated with those Resources and load. The Resources registered for the non-participating entity may be identified as Partial Participating Resources. Assets are the registered loads and Resources associated with an Asset Owner at specific Settlement Locations and must have a designated Meter Agent. Market Participants have the legal relationship with SPP. The Market Participants may participate in the WEIS Market representing any combination of Resource entities, load serving entities, Meter Agents, and/or power marketers. The WEIS Market Participant is also responsible for ensuring that SPP receives Settlement Location data from the Meter Agent in a suitable electronic format.

Registration data is used for operation and settlement of the WEIS Market. The registration data is also used in the interaction of SPP Customer Relations personnel with WEIS Market Participants.

All Market assets registered in the WEIS Market must conform to the naming convention requirements described and provided in Section 5.5.

Applications for a WEIS Market Participant to provide services in the WEIS Market must be submitted to SPP prior to the expected date of participation consistent with Section 5.4. New WEIS Market Participants will follow the timeframe as specified in Section 5.4 in addition to the detailed model update timing requirements in Appendix C. Applications and required registration documentation must conform to the procedures and/or requirements specified in this Section. Registration requests initially submitted with incomplete documentation may be rejected and scheduled for implementation during the appropriate Model Update after all completed documentation is received and approved by SPP. Exceptions to this process may be made on a case-by-case basis as determined by SPP.

5.1REGISTRATION OF RESOURCESAny Market Participant operating Resources within the WEIS Market Footprint or representing Resources operated by entities that are not Market Participants that are operating within the WEIS Market Footprint must register with SPP 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

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physical and electrically equivalent injection point to the transmission grid may register at the unit or plant level. In the event an entity within a participating WEIS Balancing Authority chooses not to register its Resources in the WEIS Market, the responsibility for registering those Assets will be with the participating host Balancing Authority. SPP will not be a party to any agreement between the host Balancing Authority and the non-participating entity. Failure or refusal to register a Resource will result in SPP filing an unexecuted version of the Service Agreement as specified in Attachment E to the WEIS Tariff for that Resource with the Commission under the name of the Market Participant representing the participating host Balancing Authority. In the case of a Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its host utility, such registration will not require the Qualifying Facility to participate in the WEIS Market or subject the Qualifying Facility to any charges or payments related to the WEIS Market. Any WEIS Market charges or payments associated with the output of such Qualifying Facility will be allocated to the Market Participant representing the host utility purchasing the output of the Qualifying Facility under PURPA, and the Market Participant will be provided the settlement data required to verify the settlement charges and payments.

Applications and required registration documentation must conform to the procedures and/or requirements specified in this Section 5. Registration requests initially submitted with incomplete documentation may be rejected and scheduled for implementation during the appropriate model update after all completed documentation is received and approved by SPP.

5.1.1 RESPONSIBILITIES OF THE RESOURCE MARKET PARTICIPANT

Each Market Participant shall be responsible for conducting its operations in accordance with all applicable WEIS Market rules and guidelines. Each Market Participant shall supply operating characteristics of its Resource, including, but not limited to: location of physical Resource, Legal owner and Resource type as specified below. Registration shall also include identification of the Settlement

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Location and Settlement Area of the Resource. At the time of registration, SPP will populate the Resource Offer parameters defined in Section 4.2.1. These Resource Offer parameters must be updated by the Market Participant to reflect Resource specific parameters during the 7 days prior to the Resource’s effective date. The Market Participant is responsible for ensuring that real-time settlement meter data is submitted to SPP. Valid Resource Types are:

1) Generating Unit (“Gen”);

2) Plant (“PLT”);

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

4) Dispatchable Variable Energy Resource (“DVER”); and

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

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

5.1.2 COMMON BUSMarket Participants of Resources located at an electrically equivalent bus and registered under the same Asset Owner may elect Common Bus treatment for these Resources. SPP will verify that the specified Resources are located at an electrically equivalent bus prior to creating the Common Bus relationship in the Commercial Model.

5.1.3 DISPATCHABLE DEMAND RESPONSE RESOURCESIn addition to the responsibilities described under Section 5.1.1, Market Participants registering a Dispatchable Demand Response (DDR) Resource must:

1) Identify an associated Demand Response Load Asset;

2) Identify an associated Dispatchable Controllable Load Settlement Location;

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5.1.4 COMBINED CYCLE In addition to the responsibilities described under Section 5.1.1, Market Participants registering a Resource that is a Combined Cycle may use the Generating Unit (“Gen”) or Plant (“PLT”) Resource Types for Commercial Modeling purposes following one of the three options described below.

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

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

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

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

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

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

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

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

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

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

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

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

5.1.5 DISPATCHABLE VARIABLE ENERGY RESOURCEAll Variable Energy Resources in the WEIS Market must be registered as a Dispatchable Variable Energy Resource (DVER) except for (i) a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility or (ii) a Resource having a primary fuel source of run of the river hydro-electric that is incapable of following Dispatch Instructions. A Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility may register as a Dispatchable Variable Energy Resource if it is capable of being incrementally dispatched by SPP and will be subject to the DVER market rules including Uninstructed Resource Deviation Charges.

1) Special dispatch rules for DVERs apply as defined under Section 4.2.3.3.

2) Dispatchable Variable Energy Resource data submittal requirements are defined in Section 4.1.1.

5.1.6 NON-DISPATCHABLE VARIABLE ENERGY RESOURCE

Only a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility or a Resource having a primary fuel source of run of the river hydro-electric that is incapable of following Dispatch Instructions may register as a Non-Dispatchable Variable Energy Resource. Any Resource that has previously registered as a Dispatchable Variable Energy Resource shall not subsequently register as a Non-Dispatchable Variable Energy Resource.

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In the WRTBM, special dispatch rules apply as defined under Section 4.2.3.4. Non-Dispatchable Variable Energy Resource data submittal requirements are defined in Section 4.1.1.

5.1.7 RESOURCES EXTERNAL TO THE WEIS MARKET FOOTPRINT

5.1.7.1 RESOURCE EXTERNAL TO THE WEIS MARKET FOOTPRINT PSEUDO-TYING IN

Market Participants with Resources external to the WEIS Market Footprint wishing to participate in the WEIS Market with those Resources must pseudo-tie those Resources into WEIS Market.

1) The Market Participant representing the Resource will be responsible for registering and performing all responsibilities that are required of any other Resource in the WEIS Market

2) The Market Participant representing the Resource must be the Meter Agent or designate a Meter Agent that will be responsible for submittal of settlement meter data as described under Section C.7.1 of Appendix C.

Market Participants may remove or add pseudo-tied in Resources in accordance with the timelines described under Section 5.4

5.1.8 RESOURCE AUXILIARY LOAD MODELINGIn addition to the responsibilities described under Section 5.1.1, Market Participants registering a Resource shall register its Resource for real-time and settlement metering purposes using one of the two options described below relating to modeling and reporting of auxiliary load.

(1) Gross – Two values shall be reported to SPP via ICCP: gross Resource output (positive value) and auxiliary load consumption (positive value). The gross Resource output does not include reductions for auxiliary load. The Market Participant shall include the auxiliary load of the Resource in the

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instantaneous load reported to SPP through ICCP whether the Resource is online or offline. The Resource’s gross output into the SPP BA will be reported separately through ICCP.

(2) Net with Aux – Two values shall be reported to SPP via ICCP: net Resource output (positive value) and auxiliary load consumption (positive value). The Market Participant shall report the net value of the Resource’s gross output and auxiliary load to SPP through ICCP while the gross output is greater than the auxiliary load. When the Resource’s gross output is less than or equal to the auxiliary load, the Market Participant shall include the auxiliary load less gross output in the instantaneous load that is also reported to SPP through ICCP and report the Resource’s output as zero MWs. When the Resource’s gross output is less than zero MWs, the Market Participant shall include auxiliary load in the instantaneous load that is also reported to SPP through ICCP and report the Resource’s output as the gross quantity.

If the auxiliary load for the Resource is registered by the Market Participant as a separate PNode, and that PNode is part of a larger load Settlement Location, then meter data for the auxiliary load will be included in the meter data for the larger load Settlement Location. However, if the auxiliary load for that Resource is registered by the Market Participant as a separate PNode at a separate Settlement Location, then the auxiliary load must be submitted for that separate Settlement Location and not as a part of a larger load Settlement Location.

5.2REGISTRATION OF LOADAny Market Participant with load within SPP must register with and be capable of performing the functions of load as described herein. Loads are registered at Settlement Locations within Settlement Areas. Loads may choose to be registered at a Settlement Location consisting of either a single Meter Settlement Location (PNode) or multiple Meter Settlement Locations (APNode). For each load registered, the Market Participant must specify whether Settlement Meter Data will be submitted on an hourly basis or on a five (5) minute basis. Naming convention requirements for load assets registered in the WEIS Market are provided in Section

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5.5.3. An APNode load Settlement Location is not limited by Settlement Area boundaries. In the event an entity within a participating WEIS Balancing Authority chooses not to register its load in the WEIS Market, the responsibility for registering those Assets will be with the participating host Balancing Authority. SPP will not be a party to any agreement between the host Balancing Authority and the non-participating entity. Failure or refusal to register a load will result in SPP filing an unexecuted version of the Service Agreement as specified in Attachment E to the WEIS Tariff for that load with the Commission under the name of the Market Participant representing the participating host Balancing Authority.

Applications and required registration documentation must conform to the procedures and/or requirements specified in this Section 5 and may be rejected if it is not complete. Registration requests initially submitted with incomplete documentation may be rejected and scheduled for implementation during the appropriate model update after all completed documentation is received and approved by SPP.

5.2.1 RESPONSIBILITIES OF THE LOADEach Market Participant shall be responsible for conducting its operations in accordance with all applicable SPP market rules and guidelines. The Market Participant is responsible for ensuring that settlement meter data is submitted to SPP.

5.2.2 NON-CONFORMING LOADEach Market Participant must identify any Non-Conforming Load asset, greater than or equal to 25 MW, that the Market Participant specifically forecasts and the PNode or Aggregate PNode (APNode) at which it resides. A Non-Conforming Load may only be represented by an APNode if the load is in the same location (e.g. a single industrial process served by more than one bus).

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5.2.3 DEMAND RESPONSE LOAD ASSETAs part of the registration of a Dispatchable Demand Response Resource, the Market Participant must also identify a corresponding Demand Response Load Asset and its associated PNode or APNode at which the load will be reduced. A Demand Response Load Asset may only be represented by an APNode if the load is in the same location (e.g. a single industrial process served by more than one bus). The PNode or APNode of the Demand Response Load Asset must be contained within the associated Dispatchable Controllable Load Settlement Location definition and have a single Meter Data Submission Location. The Demand Response Load Asset is only used by SPP to identify the actual load reduction to verify DDR compliance with Dispatch.

5.2.4 DISPATCHABLE DEMAND RESPONSE LOAD SETTLEMENT LOCATION

As part of the registration of a Dispatchable Demand Response Resource, the Market Participant must also identify a corresponding load Settlement Location in which the associated Demand Response Load resides. The Dispatchable Demand Response Load is used by SPP for settlements.

5.2.5 LOADS EXTERNAL TO THE WEIS MARKET FOOTPRINT PSEUDO-TYING IN

Market Participants with load external to the BA wishing to participate in the WEIS Market with that load must pseudo-tie that load into the WEIS Market Footprint utilizing an agreement approved by SPP.

1) The Market Participant representing the load will be responsible for registering and performing all responsibilities that are required of any other load in the WEIS Market.

2) The Market Participant representing the load must be the Meter Agent or contract with a Meter Agent that will be responsible for submittal of settlement meter data as described under Section C.7.2 of Appendix C.

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3) Market Participants may remove or add pseudo-tied in load in accordance with the timelines described under Section 5.4.

5.3REGISTRATION OF THE METER AGENTAll Meter Agents (MA) providing meter data under SPP Tariff must register with SPP as a Meter Agent. To become registered, a 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 ensuring that SPP also receives Settlement Location Data from the MA in a suitable electronic format. All Meter Agents must execute the Meter Agent Agreement in Attachment G of the WEIS Tariff.

5.4NETWORK AND COMMERCIAL MODEL UPDATESExhibit 5-1, Model Update Implementation Timelines, illustrates when model changes are implemented. Detailed model update timing requirements for new market data registration and changes to existing market data are included in Appendix C. Network Model changes are implemented on a monthly basis. Commercial Model Updates are completed on a monthly basis. New Market Participant On-boarding Registration related model additions and/or changes are implemented three (3) times per year.

The "Update Duration", as detailed in Appendix C, starts when the completed registration documentation is submitted 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. Registration requests initially submitted with incomplete documentation may be rejected and scheduled for implementation during the appropriate model update after all completed documentation is received and approved by SPP. Changes having an Update Duration of less than thirty (30) days may be implemented incrementally in advance of the next scheduled Model Update as outlined in Appendix C.

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Model changes will be effective on the 1st day of the applicable month. The changes will be available at least seven (7) days prior to the effective date to allow participants to submit necessary market data as applicable in preparation for the effective date. Requests for a new MP with physical assets must be received six (6) months in advance of the effective date desired.

SPP will work to implement each model update as soon as possible and ensure the updates are implemented in a period that is no later/longer than the applicable indicated update duration, unless otherwise noted.

Exhibit 5-13: Model Update Implementation Timeline

Model Upload Production Effective Date

Network Model Changes Effective

*Commercial Model Changes Effective (Existing Market Participants)

New Market Participants Registration Effective

January 1st X X

February 1st X X

March 1st X X

April 1st X X X

May 1st X X

June 1st X X

July 1st X X

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Model Upload Production Effective Date

Network Model Changes Effective

*Commercial Model Changes Effective (Existing Market Participants)

New Market Participants Registration Effective

August 1st X X X

September 1st X X

October 1st X X

November 1st X X

December 1st X X X

5.5NAMING CONVENTIONS FOR WEIS MARKET ASSETS

The SPP naming conventions are established to ensure that the names for all Market assets meet specific criteria so that: 1) the naming structure of Settlement Locations (SLs), Meter Data Submittal Locations (MDSLs), Sources and/or Sinks (Source/Sinks), etc. is consistent and 2) the names of assets are easily identifiable in all SPP Reliability and Market models, systems, etc.. The naming conventions primarily address the naming requirements for SLs and MDSLs, Source/Sinks, and other Market/model data for Market assets registered in the WEIS Market and used in related models and databases. However, SPP will work to ensure that the applicable asset name is consistently used in all pertinent SPP Model data, e.g., EMS

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data (equipment data), Commercial Model data (Settlement Location name), MOS data (PNODENAME), and other applicable model and system data.

The Settlement Location definition in the WEIS Tariff addresses three (3) types of Settlement Locations, which are: Resource (including pseudo-tied Resources), Load (including pseudo-tied loads), and External Interface. Tie Interfaces, including the External Interfaces, are registered and modeled only as Meter Data Submittal Locations instead of as Settlement Locations. The information provided in the following sections address naming conventions developed for naming the five types of Settlement Locations as well as MDSLs and other Market data.

5.5.1 GENERAL REQUIREMENTSThe SPP naming conventions are established to ensure that the names for all Market assets meet specific criteria so that: 1) the naming structure of Settlement Locations (SLs), Meter Data Submittal Locations (MDSLs), Sources and/or Sinks (Source/Sinks), etc. is consistent and 2) the names of assets are easily identifiable in all SPP Reliability and Market models, systems, etc.. The naming conventions primarily address the naming requirements for SLs and MDSLs, Source/Sinks, and other Market/model data for Market assets registered in the WEIS Market and used in related models and databases. However, SPP will work to ensure that the applicable asset name is consistently used in all pertinent SPP Model data, e.g., EMS data (equipment data), Commercial Model data (Settlement Location name), MOS data (PNODENAME), and other applicable model and system data.

The Settlement Location definition in the WEIS Tariff addresses three (3) types of Settlement Locations, which are: Resource (including pseudo-tied Resources), Load (including pseudo-tied loads), and External Interface. Tie Interfaces, including the External Interfaces, are registered and modeled only as Meter Data Submittal Locations instead of as Settlement Locations. The information provided in the following sections address naming conventions developed for naming the five types of Settlement Locations as well as MDSLs and other Market data.

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5.5.2 RESOURCE SETTLEMENT LOCATION/ASSET NAMEThe Resource Settlement Location/Asset name shall be consistent with the name used for the Resource in the latest Planning Model data, EIA-411 data, EIA-860 data, and for Source/Sinks. SPP will work to ensure the applicable Resource name is consistently used in SPP Model data, e.g., EMS Resource data, Commercial Model data (Settlement Location name) and MOS data (PNODENAME), etc. The Resource Settlement Location name shall include appropriate information to uniquely distinguish the Resource from other Resources registered in the WEIS Market. For each option below, the Resource name and Unit name may be combined with no period (.) separating them.

1) The Settlement Location shall include the Settlement Area (SA), MP/Asset Owner name/acronym, Resource name, and Unit name with each separated by a period (.), as applicable.

Example: With Settlement Area for Resource being “AAAA”; MP/Asset Owner name being “MMMM”, Resource name being “BBBB”; unit name being “CCCC”; Settlement Location name = AAAA.MMMM.BBBB.CCCC or AAAA.MMMM.BBBBCCCC.

5.5.3 LOAD SETTLEMENT LOCATION NAME/ASSET NAME

The Load Settlement Location /Asset name shall be consistent with the name used for the load in the latest Planning Model data and/or other applicable load data as well as for Source/Sinks. SPP will work to ensure that the applicable load name is consistently used in SPP Model data, e.g., EMS load data, Commercial Model data (Settlement Location Name) and MOS data (PNODENAME), etc. The Load Settlement Location name shall include the appropriate information, based on the type of load being registered.

1) The name of a BA/Settlement Area MP’s Network Load Settlement Location for loads in the Legacy BA’s Settlement Area shall include the MP’s Settlement Area (SA) listed twice separated by an underscore (_). It is also acceptable to include

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the MP/Asset Owner name/acronym as shown below in (3) for non-BA/non-Settlement Area MP as long as the naming convention character limit is not exceeded (see example for (3) below).

Example: With BA MP’s Settlement Area for load being “AAAA”; Settlement Location name = AAAA_AAAA.

2) The name of a BA/Settlement Area MP’s Load Settlement Location for loads in another Legacy BA’s Settlement Area shall include the MP’s Settlement Area (SA) and the interconnected adjacent Settlement Area separated by an underscore (_). It is also acceptable to include the MP/Asset Owner name/acronym as shown below in (3) for non-Legacy BA/non-Settlement Area MP as long as the naming convention character limit is not exceeded (see example for (3) below).

Example: With BA MP’s Settlement Area being “AAAA”; Adjacent Settlement Area with MP’s load being “BBBB”; Settlement Location name = AAAA_BBBB.

3) The name of a non-BA/non-Settlement Area MP’s Load Settlement Location for loads in a WEIS Market Settlement Area shall include Settlement Area, MP/Asset Owner, and “LOAD” or name of load with each separated by an underscore (_).

Example: With Settlement Area with MP’s load being “AAAA”; MP name being “MMMM”, and load name being “LLLL”; Settlement Location name = AAAA_MMMM_LLLL.

5.5.4 TIE INTERFACE METER DATA SUBMITTAL LOCATION (MDSL) NAME

SPP requires net measurements on the tie interfaces between each Settlement Area and between the Settlement Areas and the external BAs with SPP. Each Market Participant responsible for a residual load of a Settlement Area is required to register an Internal Interface and/or External Interface MDSL(s), as applicable, to assist in the effort to verify the Tie Interfaces and account for net tie-line flows for that Settlement Area. The format for each Tie Interface is AREAX.AREAY. See additional details below:

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1) Internal Interface – The Internal Interface/interchange Meter Data Submittal Location name shall include the registering MP’s responsible Settlement Area name/acronym and the applicable adjacent interconnected SPP Internal Settlement Area name/acronym separated by a period (.).

Example: With the registering MP’s related Settlement Area acronym being “AREA1” and the adjacent interconnected SPP Internal Settlement Area being “AREA2”; the Internal Interface MDSL name = AREA1.AREA2). For each AREA1.AREA2 MDSL combination where both areas are internal WEIS Market Settlement Areas, there will also be a corresponding Reciprocal Internal Interface, AREA2.AREA1. This Reciprocal Internal Interface is registered by the MP responsible for the adjacent Settlement Area and data for this MDSL must be submitted by the designated Meter Agent of the residual load owner of AREA2.

2) External Interface - The External Interface Meter Data Submittal Location name shall include the applicable External Balancing Authority Area name/acronym and the interconnected MP’s responsible Settlement Location name/acronym, with each separated by a period (.).

Example: With External Balancing Authority area being “AREAE” and the interconnected SPP Internal Settlement Area being “AREAI”; MDSL name = AREAE.AREAI). A reciprocal MDSL is not required for External Interface MDSLs.

5.5.5 SOURCE/SINK NAMEEach Settlement Location must have only one Source or Sink mapped to it, which must be registered and activated in the NAESB EIR Source/Sink registry. Multiple Settlement Locations may exist at the same electrically equivalent location. The Source/Sink name must be less than or equal to fourteen (14) characters, and should include the MP acronym and be consistent with/compatible to the related Settlement Location name.

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5.5.6 MARKET AND/OR RELIABILITY DATA DEVELOPED AND NAMED BY SPP

SPP will determine and provide the PNode name (including aggregate level PNode and Elemental PNode names), EMS Station name, and EMS Unit name for all Market assets (Resource, aggregate load, and bus level loads) registered in the WEIS Market by a MP. SPP will also determine and provide the naming of DC Ties, Zones, and other Market data working with MPs, JDTSP, and others as needed. SPP will ensure that names selected and used for each of these data fields are consistent with the names of the related Settlement Location, MDSL, Source/Sink etc. registered and used for the assets in the WEIS Market.

6 MARKET SYSTEM OUTAGE AND ERROR HANDLING

6.1MARKET SYSTEM OUTAGESIn the event that a WEIS Market system is unable to calculate LMPs for use in settlement, SPP will use the following procedures to calculate prices.

Outages of a WEIS Market system can result in the loss of pricing data for use in settlements. The following rules will apply to the calculation of LMPs during WEIS Market system outages:

1) For WEIS Market system outages of twenty-four (24) Dispatch Intervals or less, LMPs and MCCs will be set equal to the set of LMPs and MCCs from the last successful WEIS Market system execution.

2) For WEIS Market system outages of more than twenty-four (24) Dispatch Intervals, SPP will recalculate LMPs and MCCs using the best data available, including but not limited to actual system load, actual system topology, Resource Offers and actual Setpoint Instructions issued to Resources during the system outage, to develop input data for use in an off-line system.

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6.2PROCEDURES FOR CORRECTING LMPS RESULTING FROM MARKET SOFTWARE AND DATA ERRORS

Market software and/or Data Errors may occur in the WEIS Market and result in inaccurate LMPs.

Events that may result in Data Errors include, but are not limited to:

1) Bad or missing SCADA;

2) Load Forecast Error due to bad or missing SCADA;

3) Missing Intervals;

4) Operator/Human Error.

The occurrence of any of these events may result in one or more Data Errors that, in turn, may warrant a revision to LMPs and are flagged by SPP.

6.2.1 PROCEDURES FOR REVISING PRICES IN RESPONSE TO MARKET SOFWARE AND DATA ERRORS

In accordance with the process set forth in the Tariff at Attachment A, Section 4.5, SPP, in its sole discretion, may perform LMP corrections. Price corrections may only be performed pursuant to Section 4.5 of Attachment A in the Tariff and only if the error results in a significant WRTBM impact. In the exercise of its discretion pursuant to Section 4.5 of Attachment A in the Tariff, SPP may consider all relevant facts, including, but not limited to, the degree of the economic impact to the market results in terms of production cost or otherwise. For purposes of this section, “production cost” is defined as the settlement cost for the market and can be calculated as the sum of the cleared MW * LMP for all Resources.

6.2.1.1 NOTICE TO MARKET PARTICIPANTS AND THE PUBLIC

If SPP determines per Section 6.2.1 that a market software and/or Data Error has occurred that requires a correction of one or more LMPs, SPP shall notify Market Participants of the contemplated price correction. If SPP provides notification of the

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contemplated price correction later than 1700 hours five (5) Calendar Days following the Operating Day in which the LMPs would be affected by the contemplated price correction, SPP shall request Commission approval prior to making the price correction. SPP shall review with the appropriate SPP organizational group the proposal for the price correction and the schedule for remediating the market software and/or Data Error causing the need for price correction.

6.2.1.2 PROCESS FOR RECALCULATING WEIS MARKET PRICES

SPP shall recalculate LMPs and shall perform a Resettlement using these recalculated values, if required. Such recalculated LMPs shall be provided to Market Participants in the same manner as LMPs determined in the ordinary course of business (i.e. in a programmatically downloadable file).

6.2.1.3 COMPENSATORY PAYMENTS TO MARKET PARTICIPANTS

For cases in which WEIS Market prices have been recalculated, compensation to Market Participants shall be as follows:

1) For instances where the recalculated WEIS Market LMP is less than a Resource’s Energy Offer Curve price, compensation shall be as described under Section 4.5.6.2.

6.2.2 DISPUTES AND RESETTLEMENT PROVISIONSIf a Market Participant does not agree with a price correction made by SPP, the Market Participant may use the dispute and Resettlement mechanism provided in Section 4.5.9 to resolve such disagreement.

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7 MARKET MONITORING AND MITIGATION

Market monitoring and mitigation is intended to provide for the monitoring by the Market Monitor of the WEIS Market and other services required for that market to function and mitigation by SPP of the potential exercise of horizontal and vertical market power by Market Participants. Market monitoring and mitigation are essential functions for wholesale electricity markets.

7.1MARKET MONITORING PLAN7.1.1 PURPOSE AND OBJECTIVEThe objective of the Market Monitoring Plan is to provide for the independent, impartial, and effective monitoring of (a) the WEIS Market for abuses of horizontal and vertical market power and (b) the efficiency and implementation of the WEIS Market. The Market Monitor will work to ensure that their functions and activities are implemented fairly and consistently, and that they protect and foster competition while minimizing interference with open and competitive markets. Correcting market inefficiencies and preventing the exercise of market power in advance rather than punishing offenders afterward shall be the preferred approach.

The Market Monitor will evaluate existing and proposed market rules, Tariff provisions, and market design elements and recommend proposed rules and tariff changes to SPP, the Commission’s Office of Energy Market Regulation (or its successor organization) staff, and other interested entities such as state commissions and Market Participants. The Market Monitor will limit distribution of its identifications and recommendations to SPP and the Commission’s Office of Energy Market Regulations (or its successor organization) staff in the event that the Market Monitor believes that broader dissemination could lead to exploitation, with an explanation of why further dissemination should be avoided.

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The Market Monitor will review the performance of the wholesale market and provide an annual report on the state of the market as provided in Section 7 of Attachment C of the of the WEIS Tariff.

7.1.2 RESOLUTION OF CONFLICTSIn the event there is a conflict between this Section 7 of the WEIS Market Protocols and Attachment B of the Tariff or any other provision of the Tariff, the Tariff will control.

7.1.3 INDEPENDENT MARKET MONITORThe 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 Tariff and these Protocols.

7.1.3.1 STAFFING AND RESOURCES

The Market Monitor shall be comprised of employees of SPP with the necessary experience and qualifications to perform the duties of the Market Monitor.

The SPP Market Monitoring Unit (MMU) is responsible for all market monitoring functions and shall be an independent organization within SPP reporting to the Board of Directors, excluding any SPP management representatives serving on the Board of Directors.

7.1.3.2 RELATIONSHIPS AND NOTIFICATIONS

As a general principle, the Market Monitor may obtain input from WEIS Market committees and working groups, FERC Staff, SPP Staff, and affected state regulatory authorities for the purpose of executing its duties. The Market Monitor shall bring any instances of market behavior that may require investigation (including, but not limited to, suspected Tariff violations, suspected violations of Commission-approved

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rules and regulations, suspected market manipulation, and inappropriate dispatch) to the attention of the Board, the officers of SPP, FERC’s Office of Enforcement (or its successor organization) staff, and other affected state regulatory authorities, as the Market Monitor may deem necessary or appropriate. After any initial inquiry, the Market Monitor shall also provide notification to the Board of Directors, FERC’s Office of Enforcement (or its successor organization) staff, and other interested entities such as relevant state regulatory commissions and Market Participants, as soon as practicable in the event it identifies a significant market problem that may require (a) further review, (b) a change in Tariff or market rules, or (c) referral to FERC. In the event the Market Monitor believes broader dissemination could lead to exploitation, it may limit distribution of its identifications and recommendations to the Board of Directors and FERC Staff with an explanation of why further dissemination should be avoided at that time.

The MMU shall also interface with FERC Staff and other market monitors in adjacent regions as needed for the purpose of addressing electricity market issues in a comprehensive manner.

7.1.3.3 STANDARDS OF CONDUCT

The MMU shall abide by SPP’s Standards of Conduct, which shall be appropriate for establishing the professional and financial independence of the MMU. The MMU shall certify compliance with such policies to the Board. Consistent with Order No. 719 requirements for MMU ethics standards, the Market Monitor and its employees shall comply with those standards outlined in Section 3.3 of Attachment C of the WEIS Tariff.

7.1.4 MARKET MONITORINGThe primary purposes of market monitoring are to obtain objective information about the WEIS Market, assess the behavior of Market Participants, and assess the behavior of other markets and services that impact the performance of the WEIS Market. Key aspects of such market monitoring are assessing the design and structure of the WEIS Market to ensure market efficiency, determining Market Participants’ compliance with market rules and preventing the exercise of horizontal

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and/or vertical market power, which includes whether a Market Participant is affecting SPP’s ability to provide reliable and non-discriminatory service.

7.1.4.1 MARKETS TO BE MONITORED

The Market Monitor will monitor the WEIS Market. The Market Monitor will not monitor bilateral energy, transmission or capacity markets and services not administered, coordinated or facilitated by SPP, except to assess the effect of these markets and services on the WEIS Market, or the effects of the WEIS Market on these unmonitored markets. Similarly, the Market Monitor will not monitor the energy, transmission or capacity markets and services in regions adjacent to the WEIS Region except to assess the effect of these markets and services on the WEIS Market, or the effects of the WEIS Market on these adjacent markets.

7.1.4.2 MONITORING ACTIVITIES

The Market Monitor will implement the market monitoring protocols and will monitor the WEIS Market by reviewing and analyzing market data and information including, but not limited to:

1) Resource registration data;

2) Resource Offer data and other Resource offer parameters required for use in the WEIS Market;

3) Interchange Transactions;

4) Actual commitment and dispatch of Resources, including but not limited to Resource MW capability and output, MVAR capability and output, status, and outages;

5) Additional generation and transmission facility outage data not otherwise provided for in (4) above;

6) Locational Marginal Prices at all nodes and designated Settlement Areas in or affecting any of the WEIS Market;

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7) Balancing Authority Area data, including but not limited to demand, area control error, Net Scheduled Interchange (NSI), actual total net interchange, and forecasts of operating and contingency reserves and peak demand;

8) Conditions or events both inside and outside the Balancing Authority Area affecting the supply and demand for, and the quantity and price of, products or services sold or to be sold in the WEIS Market;

9) Information regarding transmission services and rights, administration of the WEIS Tariff, the operation and maintenance of the transmission system, and the reservation and scheduling of transmission service;

10) Information regarding the nature and extent of transmission congestion in the region and, to the extent practicable, transmission congestion on any other system that affects the WEIS Market, including but not limited to causes of, costs of and charges for transmission congestion, transmission facility loading, MVAR capability, line status and outages;

11) Settlement data for the WEIS Market;

12) Any information regarding collusive or other anticompetitive or inefficient behavior in or affecting the WEIS Market;

13) 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;

14) Logs of Transmission Service requests along with the disposition of the request and the explanation of any refused requests;

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.

7.1.4.3 INSTANCES OF MARKET POWER

The Market Monitor will analyze market data with regard to instances of market power and refer possible cases to FERC when there is sufficient credible information

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to warrant such action. When the case is referred to FERC, the Market Monitor is required to desist from any further action independent of FERC’s investigation into the case.

The Market Monitor will keep SPP and interested government agencies apprised of the potential for and the implications of abusive market power behavior, and make recommendations as to how to remove the potential for and ability to exercise market power.

Specific monitoring activities regarding physical and economic withholding shall include but not be limited to assessment on (a) availability of Resources, (b) artificial barriers to entry, (c) impact of the use of Resources for reliability versus energy purposes, (d) market response to price spikes, and (e) analysis of offer patterns. On an ongoing basis, the Market Monitor will consult with SPP on examining other areas for instances of market power.

7.1.4.4 MARKET PARTICIPANT BEHAVIOR WARRANTING POSSIBLE MITIGATION

The Market Monitor shall monitor the WEIS Market for potential abuse associated with the following categories of Market Participant behavior:

1) Economic Withholding;

2) Uneconomic Production;

3) Physical Withholding;

The mitigation measures and monitoring metrics for each of the Market Participant behaviors identified above are fully developed in Section 7.2. When the Market Monitor determines there is sufficient credible information about a specific abusive practice, the issue will be referred to the Commission’s Office of Enforcement for further review. Nothing in this section shall limit the Market Monitor’s obligation to refer other suspected market violations to the Commission’s Office of Enforcement, even where suspected behavior does not fall explicitly within the abovementioned categories or descriptions.

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7.1.5 INQUIRIES7.1.5.1 REQUESTS

Any Market Participant or interested government agency may submit in writing a complaint or request for inquiry to the Market Monitor. Upon receipt of such complaint or request, the Market Monitor will decide whether an inquiry should be conducted. As an initial screen, the Market Monitor should not pursue any complaint pertaining to issues not related to the WEIS Market or monitored and overseen by the Market Monitor. An inquiry will be conducted if the 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 the WEIS Market that is part of their market monitoring or market power mitigation obligation.

7.1.5.2 CONDUCTING INQUIRIES

Market Participants shall cooperate fully with the Market Monitor during any inquiry.

7.1.5.3 REPORTING

The Market Monitor must follow the confidentiality provisions established by the Commission. The Market Monitor is responsible for notifying the requesting party that the inquiry is completed. The Market Monitor will coordinate reporting of the results of inquiry to the Board, FERC and appropriate state authorities, where appropriate, typically when issues with market rules arise.

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7.1.6 COMPLIANCE AND CORRECTIVE ACTIONS7.1.6.1 COMPLIANCE

The Market Monitor shall administer the Market Monitoring Plan as described in Attachment C of the WEIS Tariff and report any actual or potential abuse of market power or market design inefficiencies as part of its monitoring process. However, such enforcement is limited to matters that (i) are expressly set forth in the WEIS Tariff; (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 WEIS Tariff. Other enforcement matters shall be subject to Commission determination in the first instance. As part of the inquiry process, the Market Monitor may issue a demand letter requesting Market Participants causing the issue to arise to change actions as the Market Monitor deem proper to achieve compliance.

The Market Monitor may also engage in discussions with persons or entities other than Market Participants that they deem may have information that may be helpful to any investigatory or compliance process.

7.1.6.2 CORRECTIVE ACTIONS FOR MARKET DESIGNS

If the Market Monitor discerns any weaknesses or failures in market design and protocols, including the determination that the WEIS Market is 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 advise the appropriate Organizational Group of SPP, the President of SPP, the regional state committee, appropriate state authorities, FERC Staff, and relevant Market Participants.. In the event the Market Monitor believes providing such information could lead to exploitation, it will restrict such notification to the President of SPP, the Chairman of the SPP Oversight Committee, and FERC Staff, and will provide a justification for such limited notification. Should the responsible party not respond within 60 days, the Market Monitor may recommend

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changes in market design and protocols to the Board, FERC and the appropriate state authorities as needed. If the responsible party responds, but does not recommend changes to market design and market rules that are acceptable to the Market Monitor, the Market Monitor shall report to the Board, and the appropriate regulatory body or bodies as needed, and then SPP or the Market Monitor 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 WEIS Tariff and Protocols as necessary to correct weaknesses or failures in the WEIS Market.

In the event that any weaknesses or failures in market design require immediate corrective action to ensure just and reasonable prices, the Market Monitor may request the SPP President to authorize an immediate FERC filing requesting implementation of a corrective action while SPP responds to the Market Monitor’s notification as described above. The requested immediate corrective action should be the method least intrusive or disruptive to the WEIS Market 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 affected interested government agencies the market weakness or failure potentially requiring immediate corrective action, unless the Market Monitor determines that such discussion would lead to exploitation.

7.1.7 REPORTINGThe Market Monitor is responsible for producing (a) an Annual State of the Market Report and (b) Quarterly and Annual Reports for assessing the efficiency, effectiveness and competitiveness of the WEIS Market as requested by the SPP Board of Directors or required by FERC. The Market Monitor shall have complete independence in developing and producing reports, and no person or entity may screen, alter, delete or delay the Market Monitor’s findings, conclusions and recommendations. SPP and Market Participants may comment on any report made pursuant to this section, through the appropriate stakeholder process. The Market Monitor shall be free to disregard suggestions with which it disagrees.

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7.1.7.1 ANNUAL STATE OF THE MARKET REPORT

The Annual State of the Market Report shall assess the performance of the WEIS Market as discussed in Section 7.1.1. Such report will include any recommendations of the Market Monitor for the improvement of the WEIS Market, or of the monitoring, reporting and other functions undertaken pursuant to these 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, SPP, Market Participants, and other interested entities. The report shall be submitted to FERC. Copies of the report shall be provided to appropriate state regulatory authorities on request and made publicly available by SPP through a posting of the document on the SPP website. Confidential information will be subject to redaction or other measures necessary for the protection of Confidential Information.

7.1.7.2 MONTHLY, QUARTERLY AND ANNUAL REPORTS

The Market Monitor will prepare Monthly, Quarterly and Annual Reports. The purpose of these metrics is to provide transparency of the WEIS Market and to provide a standardized basis to evaluate the performance of the market structure and market power mitigation over time. This information will also be used to compare the performance of the WEIS Market with that of other markets. Copies of the reports shall be made publicly available by SPP through posting on the SPP website, subject to redaction or other measures necessary for the protection of Confidential Information.

7.1.7.3 COMMUNICATION OF MARKET MONITORING REPORTS

Conference calls related to the Market Monitor reports may be attended by SPP, the Board of Directors, FERC Staff and other affected regulatory authorities, state authorities, and Market Participants regardless of which party initiates the conference call. The Market Monitor shall make one or more of its staff members available for regular conference calls.

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7.1.7.4 OTHER REPORTS

The Market Monitor shall prepare other reports or briefings on matters within their responsibility as may be requested by the Board or FERC, or as they deem necessary.

7.1.8 PERFORMANCE INDICES, METRICS AND SCREENSPerformance indices, metrics and screens form the necessary objective basis for observing the functioning of the WEIS Market, including the conduct of Market Participants in such markets, and for providing reports and market analyses.

7.1.8.1 DEVELOPMENT

The Market Monitor, will develop performance indices, metrics and screens for reviewing market data and other information collected. Consideration should be given to the metrics in use by SPP and other RTOs, ISOs and the FERC during such development.

7.1.9 REFERRALS TO THE COMMISSIONThe Market Monitor shall report suspected Market Violations, as defined in 18 CFR 35.28(b)(8), to FERC’s Office of Enforcement (or its successor organization) staff in accordance with the FERC’s reporting protocols for referral by market monitors as specified in 18 CFR 35.28(g)(3)(iv) in a timely manner. Any such reports by the Market Monitor to FERC Staff shall be on a confidential basis, and all information and documents included in such reports will not be released to any other party except to the extent FERC directs or authorizes such release, unless such information and documents are already in the public domain.

7.1.10 MARKET MANIPULATIONThe Market Monitor will monitor the WEIS Market for potential instances of market manipulation. Such actions or transactions that are without a legitimate business purpose and that are intended to or foreseeably 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)

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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 WEIS Market in a timely manner when there is sufficient credible information to warrant such action.

7.1.11 MONITORING FOR POTENTIAL TRANSMISSION MARKET POWER ACTIVITIES

The Market Monitor shall monitor the WEIS Market for suspected exercise of transmission market power by reviewing and analyzing data and information related to the availability of transmission facilities that impact access particularly with respect to the withholding of transmission facilities or transmission capacity, including activities such as but not limited to, the following:

1) Physical withholding by Joint Dispatch Transmission Service Provider(s) by providing improper information related to the availability of transmission, such as information related to the capability or other modeling data used by SPP for use in system operations;

2) Economic withholding by Joint Dispatch Transmission Service Provider(s) through the use of methods and data for estimating costs of interconnection and system upgrades that is not comparable for Affiliates and non-Affiliates;

3) Unavailability of transmission facilities through planned and unplanned maintenance outages that routinely exceed historical baselines;

4) Withholding of transmission capacity by Joint Dispatch Transmission Service Customer through excess reservations that are not actually used.

The Market Monitor shall refer any instance(s) of perceived market design flaws and recommend WEIS Tariff language changes to the Commission’s Office of Energy Market Regulation (or its successor office/organization). Additionally, the Market Monitor shall refer any instance(s) of suspected exercise of transmission market power directly to the Commission’s Office of Enforcement (or its successor organization) utilizing the protocols for referral to the Commission for suspect potential instances of the exercise of market violations (such as manipulation) as found in 18 CFR 35.28(g)(3)(iv), when there is sufficient credible information to

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warrant such action. Where appropriate, the Market Monitor shall also provide the FERC with an estimate of damages equal to (i) the effect on prices multiplied by (ii) the affected energy produced by the Joint Dispatch Transmission Service Provider(s) or Market Participant. All such referrals by the Market Monitor to FERC will be on a confidential basis, and all information and documents included in such reports will not be released to any other party except to the extent FERC directs or authorizes such release.

7.1.12 DATA ACCESS, COLLECTION AND RETENTIONSPP shall regularly collect and maintain Data and Information necessary for monitoring the WEIS Market and implementing mitigation protocols.

7.1.12.1 CONFIDENTIALITY

The Market Monitor is subject to and will abide by the confidential rules as delineated in the WEIS Tariff.

7.1.12.2 ACCESS TO SPP DATA AND INFORMATION

The Market Monitor shall have access to all Data and Information gathered or generated by SPP in the course of its operations. This Data and Information shall include, but not be limited to, that listed in Section 7.1.4 of these Protocols. All Data and Information listed in Section 7.1.4 shall be retained by SPP for a minimum period of three years.

7.1.12.3 ACCESS TO MARKET PARTICIPANT DATA AND INFORMATION

Market Participants shall retain all Data and Information listed below, and in Section 7.1.4 of the Market Monitoring Plan as applicable, that is in the custody and control of Market Participants, for a minimum of three years and will promptly provide any such Data and Information to the Market Monitor upon request. Market Participants shall be capable, upon request, of providing the Data in native format and a description of the format used by the Market Participant. If necessary, due to

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proprietary format restrictions, the MP shall be capable of providing the data in a non-proprietary format, such as CSV or XML format.

Data and Information to be retained by Market Participants and provided to the Market Monitor upon request:

1) All Data and Information relating to the costs of operating a Resource, including but not limited to, heat rates, start-up fuel requirements, fuel purchase costs, environmental costs, and operating and maintenance expenses;

2) All Data and Information regarding opportunity costs of a Resource, including but not limited to, regulatory, environmental, technical, or other restrictions that limit the run-time or other Resource operating characteristics;

3) All Data and Information relating to the operating status of a Resource, including Resource logs showing the generating status of a specified unit, including information relating to a forced outage, planned outage or derating of a Resource;

4) All Data and Information relating to the operating status of a transmission facility, a contingency, or other operating consideration, including forced outages, planned outages or derating of a transmission system component;

5) All Data and Information relating to transmission system planning, including studies, reports, plans, models, analyses, and filings with FERC or any state regulatory commission;

6) All Data and Information relating to the ability of a Market Participant or its Affiliate to determine the pricing or output level of generating capacity owned by another entity, including but not limited to any document setting forth the terms or conditions of such ability.

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

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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) the dispute resolution procedures under the WEIS Tariff or (b) a filing with the appropriate regulatory or enforcement agency to compel the production of the requested information.

7.1.12.4 DATA CREATED BY THE MARKET MONITOR

Any data created by the Market Monitor, including any reconfiguration of data and information obtained from SPP or Market Participants, will remain within the Market Monitor’s exclusive control. Such data may be shared with SPP and Market Participants at the Market Monitor’s sole discretion and on a non-discriminatory basis, subject to the confidentiality provisions specified in the Attachment C and Attachment A to the WEIS Tariff.

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7.1.13 MISCELLANEOUS PROVISIONS7.1.13.1 RIGHTS AND REMEDIES

This Plan does not restrict SPP and Market Participants from asserting any rights they may have under state and federal regulation and laws, including initiating proceedings before the FERC regarding any matter which is subject to this Plan.

7.1.13.2 DISPUTES

Disputes as to the implementation of, or compliance with, this Plan shall be subject to the dispute resolution procedures under the WEIS Tariff or subject to review by FERC.

7.1.13.3 REVIEW OF MARKET MONITOR

The activities of the Market Monitor shall be reviewed from time to time by the Board of Directors.

7.2MARKET POWER MITIGATION AND MONITORING7.2.1 PURPOSE AND OBJECTIVESSPP shall implement these Market Mitigation Protocols in conjunction with the Market Mitigation Plan in Attachment B of the WEIS Tariff.

There are two basic themes with regard to market power mitigation. First, mitigation measures must offer the opportunity for extensive intervention in energy markets, if necessary, to suppress price spikes resulting from the exercise of market power. Mitigation measures are meant to block generators with the potential for market power abuse from bidding above the price level that would otherwise prevail in a competitive market. Second, that intervention must explicitly be balanced with the goal of assuring system reliability in the long term.

7.2.2 ECONOMIC WITHOLDINGThis section develops the market power mitigation measures that are applied to the WEIS Market.

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7.2.2.1 MITIGATE ONLY IN THE PRESENCE OF LOCAL MARKET POWER

The electricity marketplace in the WEIS region is workably competitive, with an adequate supply of electricity and diversity of suppliers, absent reliability conditions or congestion on the transmission system that create the potential for abuse of local market power. Therefore, mitigation will be applied only at the time of, and in places with, a congested transmission element or facility, or a Local Reliability Issue not represented by a flowgate constraint.

7.2.2.2 MITIGATION MEASURES

The Energy Offer Curves are subject to mitigation measures in the WEIS Market. A determination of Resources that have local market power is described in Section 7.2.2.4 A Resource with mitigation measures applied to its Energy Offer Curve shall have an effective energy offer no higher than the Resource’s Mitigated Energy Offer Curve. The effective Energy Offer Curves are used by the Market Operating System to determine prices and Dispatch Instructions. Whenever a Market Participant has a Resource(s) where a mitigation measure has been applied to the Market Participant’s offer(s), the SPP shall identify the market offer(s) that have been mitigated in SCED. SPP will supply the Market Participant with the reason for mitigation, (local market power failure test, FCA failure test, or other test failures) where a mitigation measure has been applied. If the mitigation is associated with the Local Market Power Test, SPP shall also provide the Market Participant, when applicable, with the binding transmission constraint and Resource-to-Load Distribution factor.

7.2.2.3 MITIGATION MEASURES FOR ENERGY OFFER CURVES

1) Mitigated energy offer curves shall be submitted on a daily basis by the Market Participant in accordance with the Mitigated Offer Development Guidelines. PPRs are not obligated to submit mitigated Energy Offer Curves and are not subject to mitigation measures. The mitigated Energy Offer Curve may be updated by the same schedule as the real-time Energy Offer.

2) The Energy Offer Curve conduct thresholds are as follows:

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a) For Resources located in a Frequently Constrained Area, the threshold is a 17.5% increase above the Mitigated Energy Offer Curve.

b) For all other Resources the threshold is a 25% increase above the Mitigated Energy Offer Curve.

3) SPP shall apply mitigation measures by replacing the Energy Offer Curve with the Mitigated Energy Offer Curve if:a) The Resource’s Energy Offer Curve exceeds the Mitigated Energy Offer Curve

by the applicable conduct threshold; andb) The Resource has local market power as determined in Section 7.2.2.4; andc) The Resource fails the Market Impact Test as described in Section 7.2.2.6.

An Energy Offer Curve below $25/MWh will not be subject to mitigation measures for economic withholding.

4) The Mitigated Energy Offer Curve shall be the Resource’s short-run marginal cost of producing energy as determined by the unit’s heat rate, fuel costs and the costs related to fuel usage, such as transportation and emissions costs (“total fuel related costs”), and variable operation and maintenance costs (VOM) as detailed in the Mitigated Offer Development Guidelines. The formula for Mitigated Energy Offer Curves can be found in Appendix D.

5) Opportunity costs may be reflected in the total fuel related costs and/or the VOM under the following circumstances:a) Externally imposed environmental run-hour restrictions; orb) Physical equipment limitations on the number of starts or run-hours; orc) Fuel supply limitations.

6) The Market Participant shall submit heat rates and the methods for determining fuel costs, fuel related costs including emissions costs, opportunity costs, and variable operation and maintenance costs to the Market Monitoring Unit. The information will be sufficient for replication of the Mitigated Energy Offer Curve and shall include, among other data, the following information:a) For fuel costs, Market Participants shall provide the Market Monitoring Unit

with an explanation of the Market Participants’ fuel cost policy, indicating whether fuel purchases are subject to a fixed contract price and/or spot

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pricing and specifying the contract price and/or referenced spot market prices. Any included fuel transportation and handling costs must be short-run marginal costs only, exclusive of fixed costs.

b) For emissions costs, Market Participants shall report the emissions rate of each of their units and indicate the applicable emissions allowance cost.

c) For VOM costs, Market Participants shall submit VOM costs, calculated in adherence with the Appendix D of the WEIS Market Protocols, reflecting short-run marginal costs, exclusive of fixed costs.

Further details associated with the development and validation of these costs are included in the Mitigated Offer Development Guidelines.

7) For Demand Response Resources with Behind-The-Meter Generation the Mitigated Energy Offer Curve shall be developed in the same manner, described above, as any other generating Resource. For load response Demand Response Resources, the mitigated Energy Offer Curve shall reflect the quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage.

8) For Variable Energy Resources, the mitigated Energy Offer Curve may include, but shall not exceed, any quantifiable costs that vary by MWh output, including short-run incremental VOM.

9) Intra-day changes to the mitigated Energy Offer Curve are allowed under the following conditions:

a) The Market Participant incurs higher fuel procurement costs due to a request by the Joint Dispatch Transmission Service Provider(s), for a Resource to remain online past the scheduled commitment provided in the Resource Plan; or

b) A Resource must switch fuels or pipelines due to unforeseen operating conditions;

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Intra-day changes to the mitigated Energy Offer Curve must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.

10) Market Participants that have Resources with short-run marginal costs greater than the Safety-Net Energy Offer Cap specified in Section 7.2.4 may submit an Energy Offer Curve using the same guidelines for development of the Resource’s Mitigated Energy Offer Curve established in Appendix D, Section D.2.5. The Energy Offer Curve above $1,000/MWh must be equal to the Mitigated Energy Offer Curve, and may also include an adder with a maximum of $100/MWh due to the uncertainty of expected costs. For purposes of LMP calculation, the Energy Offer Curve will be limited to a maximum of $2,000/MWh and will have to be verified by the Market Monitor prior to the start of the applicable market clearing process. If the Energy Offer Curve cannot be verified prior to the start of the applicable market clearing process, then the Resource may be eligible to receive Real-Time Out-of-Merit Energy payments for its actual costs after verification by the Market Monitor. The default value is $1,000/MWh for any offer above $1,000/MWh until the offer can be verified. If the verified Energy Offer Curve is greater than $2,000/MWh, the Energy Offer Curve will be capped at $2,000/MWh in the applicable market clearing process, and the Resource may be eligible for Real-Time Out-of-Merit Energy payments for actual costs exceeding $2,000/MWh. Market Participants must submit evidence of actual costs to the Market Monitor. The Market Monitor shall verify the actual costs for use in Real-Time Out-of-Merit Energy payments. In order to include the costs in the Real-Time Out-of-Merit Energy payments of the final Settlement Statement, the submission must occur within 35 Calendar Days after the Operating Day and the verification must be complete no later than noon on the Business Day prior to 45 Calendar Days after the Operating Day.

11) In all cases under this Section 7.2.2.3, cost data submitted for the development of mitigated offers, including opportunity cost data, shall be subject to the confidentiality provisions set forth in Section 8 of Attachment A to the WEIS Tariff.

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7.2.2.4 LOCAL MARKET POWER TEST

A Resource satisfying at least one of the following conditions is determined to have local market power:

1) The Resource is located in a Frequently Constrained Area, as described in Section 7.2.2.4.1, and one or more of the transmission constraints that define the Frequently Constrained Area is binding;

2) The Resource is not in a Frequently Constrained Area and has a Resource-to-Load-Distribution factor less than or equal to negative five percent (-5%) relative to a binding transmission constraint.

7.2.2.4.1 FREQUENTLY CONSTRAINED AREASA Frequently Constrained Area is an electrical area identified by the Market Monitor that is defined by one or more binding transmission constraints that are expected to be binding for at least five-hundred (500) hours during a given twelve (12)-month period and within which one (1) or more suppliers are pivotal.

A supplier is pivotal when the energy output by any of its Resources, or some of its Resources jointly, must be increased or decreased to resolve the binding transmission constraint during some or all hours. This will be determined utilizing transmission load flow cases or WRTBM market cases reflecting a variety of market conditions.

These load flow or market cases will be used to estimate: (i) the Generation Shift Factors for all WEIS and relevant non-WEIS Resources relative to each potentially constrained flowgate; (ii) the base loadings of Resources; (iii) the base allocation of Ancillary Services on Resources; and (iv) the base flows on each flowgate. A supplier is pivotal when a binding transmission constraint cannot be relieved by changing the base loadings for other suppliers’ Resources.

The Frequently Constrained Areas will be defined prior to the start of the WEIS Market and will be reevaluated annually. A reevaluation may be performed more frequently if the Market Monitor determines that conditions have changed with respect to the binding transmission constraints that define a Frequently Constrained

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Area, or if congestion on constraints that are not designated as a Frequently Constrained Area warrant a new analysis. SPP may also propose an area be designated or undesignated as a Frequently Constrained Area to the Market Monitor.

The Market Monitor will post the updated Frequently Constrained Area information along with the associated analysis on the SPP website at least 14 Calendar Days prior to the Frequently Constrained Area updates becoming effective and will notify Market Participants of the posting. Market Participants may contact the MMU within the 14 day posting period if there are concerns with the Market Monitor’s proposed updates. The Market Monitor will consider and respond to Market Participant concerns and will make updates if needed. The Market Monitor will notify Market Participants when updates become effective.

The Frequently Constrained Area conduct test thresholds are set forth in Section 7.2.2.3(2).

7.2.2.5 ADDITIONAL MITIGATION MEASURES FOR RESOURCE OFFER PARAMETERS

Competitive outcomes can also be distorted by submitting offers that do not reflect the physical capabilities of Resources. The mitigation measures in this section are intended to provide SPP with the means to mitigate the effects of physical parameter offers that are inconsistent with competitive conduct. The mitigation measures in this section apply to all Offer parameters in Section 4.2.1 expressed in units other than dollars.

A reference level for each Offer parameter that reflects the physical capability of the Resource shall be determined prior to the start of the Market by one or a combination of the following methods: (i) the reference levels will be determined through consultation with the Market Participant and the Market Monitor; (ii) the reference levels will be based on averages of Offer parameters from similar Resources. This methodology for setting reference levels for Offer parameters shall apply to all Resources at the start of the market and to all new Resources that join the Market subsequent to the start of the Market. The SPP output forecast for a

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wind-powered Variable Energy Resource shall be used as the reference maximum output limit for the wind-powered Variable Energy Resource.

The following thresholds shall be used by the SPP to identify Resource Offers that may warrant mitigation and shall be determined with respect to the corresponding reference level:

Time-based Offer parameters: An increase of three (3) hours, or an increase of six (6) hours in total for multiple time-based Offer parameters.

Offer parameters expressed in units other than time or dollars: A 100 percent increase for Offer parameters that are minimum values, or a 50 percent decrease for Offer parameters that are maximum values.

Minimum Economic Capacity Operating Limit threshold for Resources committed to address a Local Reliability Issue: a 25 percent increase.

In the case that a Resource Offer fails the thresholds described above, the Market Monitor shall determine the impact on prices. If an impact exceeds the LMP threshold in Section 7.2.2.6, the Market Monitor will initiate a discussion with the Market Participant concerning an explanation of the parameter changes. The Market Monitor will inform SPP of any potential issue. If SPP, in consultation with the Market Monitor, concludes that the Market Participant has demonstrated the validity of the submitted Resource Offer parameter, no further action will be taken. If not, SPP shall replace the Resource Offer parameter with the corresponding reference level. Mitigation measures will remain in place until such time that the Market Participant demonstrates the validity of the Resource Offer parameter or the Market Participant notifies the Market Monitor that the Resource Offer parameter has been changed to a value that is within the applicable threshold range, and the Market Monitor has verified that this change has occurred. In the event that the Market Participant submits a dispute, the mitigation measure will remain in place until the resolution of the dispute.

7.2.2.6 MARKET IMPACT TEST

SPP will apply a market impact test to determine if offers should be mitigated. The following market impact test will be applied in WRTBM:

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During times of congestion, a market solution with no mitigation in place is compared to a market solution with the appropriate mitigation applied. If a Settlement Location LMP without mitigation exceeds the corresponding price from the mitigated solution by at least the applicable impact test threshold, then the mitigated solution is used for dispatch.

The LMP impact threshold is $25/MWh.

7.2.2.7 MITIGATED OFFER DEVELOPMENT GUIDELINES

The Market Monitor, in coordination with SPP, shall develop and maintain Mitigated Offer Development Guidelines in Appendix D, describing the standards for determining cost components for products and services provided to the WEIS Market that are subject to mitigation. The Mitigated Resource Offer Parameters, as defined in Section 7.2.2.3, are intended to capture the short-run marginal cost, including the appropriate application of opportunity costs, of providing service to the WEIS Market. The Mitigated Offer Development Guidelines shall describe all relevant cost components for defining mitigated Energy Offer Curves by Resource-type.

Exceptions to the Mitigated Offer Development Guidelines may be submitted to the Market Monitor. The Market Monitor shall respond with a resolution to such a request within 15 Calendar Days of receipt.

The Market Monitor shall review the costs included in the Mitigated Resource Offer Parameters on an ex-post basis relative to the relevant Operating Day in order to ensure that the Market Participant has correctly applied the formulas and definitions in Section 7.2.2.3, the Mitigated Offer Development Guidelines, and in Attachment B of the WEIS Tariff and that the level of the mitigated offer is otherwise acceptable. If the mitigated offer determined by the Market Monitor and the Market Participant differ, the Market Participant shall use the mitigated offer calculated by the Market Monitor going forward. If a Market Participant submits a dispute over its mitigated offer, the previously approved mitigated offer shall be used from the time the dispute is submitted until the dispute is resolved. SPP shall remedy mitigated offer disputes resolved in favor of the Market Participant by providing an Out-of-Merit

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Energy payment, as necessary, to the Market Participant whose mitigated offer was improperly determined by the Market Monitor.

The Market Monitor shall gather and keep confidential detailed data on the costs of generation of electric power transmitted in the WEIS Region in order to assist the performance of its duties under the WEIS Tariff. To achieve this objective, the Market Monitoring Unit shall maintain on its website a mechanism that allows Market Participants to conveniently and confidentially submit such data. In addition the Market Monitoring Unit shall develop a manual in consultation with stakeholders that describes the nature of and procedure for data collection. Market Participants registering a Resource or otherwise subject to a commitment to provide service to the WEIS Market shall provide data to the Market Monitoring Unit.

7.2.3 UNECONOMIC PRODUCTIONThe Market Monitor will monitor for cases where uneconomic production by a Market Participant’s Resources causes congestion on transmission facilities that is not justified by reliability concerns. The provisions of this Section 7.2.3 will not apply to Demand Response Resources.

1) Potential uneconomic production will be indicated, and subject to further analysis as described in Section 7.2.3(2), when the Resource has a positive Resource-to-Load Distribution Factor and any of the following conditions are met:a) A Resource is identified with an incremental energy offer price less than 50

percent of the applicable reference level; orb) A Resource is determined to be generating outside of its Operating

Tolerance; orc) Time-based or other (non-time and non-dollar) offer parameters contribute to

congestion on transmission facilities.2) For any Resource meeting the conditions described in Section 7.2.3(1), the

Market Monitor shall determine whether: (i) the MW impact from uneconomic production associated with such Resource is exacerbating the transmission congestion; and (ii) the uneconomic production is not obviously justified by reliability or other operational concerns.

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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.

7.2.4 OFFER CAPS AND FLOORSSubmission of Energy Offer Curves by Market Participants for use in the WRTBM will be limited by the following offer caps and floors.

1) Safety-Net Energy Offer Cap = $1000/MWh; Energy Offers greater than $1,000/MWh are subject to Section 7.2.2.3(9);

2) Energy Offer Floor = Negative $500/MWh;

7.2.5 PHYSICAL WITHHOLDING1) The Market Monitor will monitor for physical withholding of capacity and

unavailability of transmission facilities. Physical withholding may include,

a) Declaring that a Resource has been derated, forced out of service or otherwise been made unavailable for technical reasons that are untrue or that cannot be verified;

b) Refusing to provide offers or schedules for a Resource when it would otherwise have been in the economic interest to do so without market power;

c) Operating a Resource in real-time to produce an output level that is less than the Dispatch Instruction minus the Resource’s Operating Tolerance defined in Section 4.4.2.4 and the Resource is not exempt from URD under Section 4.4.2.4.1;

d) Derating a transmission facility for technical reasons that are not true or verifiable; and

e) Operating a transmission facility in a manner that is not economic and that causes a binding transmission constraint or reliability issue.

f) Declaring that the magnitude of the capability of a Resource is reduced for reasons that are not true or verifiable.

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2) A Market Participant will not be deemed to be physically withholding if;

a) They are following the directions of SPP, or a reliability coordinator, or applicable reliability standards.

b) They are selling into another market at a higher price;

7.2.5.1 THRESHOLDS FOR IDENTIFYING PHYSICAL WITHHOLDING OF RESOURCE CAPACITY

A Market Participant is deemed to be physically withholding capacity in a Frequently Constrained Area if the following conditions hold:

1) One or more of the transmission constraints that define the Frequently Constrained Area are binding;

2) The Market Participant controls or owns a Resource that satisfies condition Sections 7.2.5(1), or 7.2.5(2) and is located in the Frequently Constrained Area identified in 7.2.2.4.1;

A Market Participant is deemed to be physically withholding capacity in an area not designated as a Frequently Constrained Area if the following conditions hold:

1) One or more transmission constraints are binding; and

2) The Market Participant owns or controls one or more Resources that has local market power as defined in Section 7.2.2.4; and

3) Either of (a) or (b) hold;

a) The total capacity withheld, by Resources identified in (2) that satisfy condition 7.2.5(1), or 7.2.5(2) exceeds the lower of 5 percent of the total capability owned or controlled by the Market Participant or 200 MW;

b) The real-time output of a Resource identified in (2) is less than the Dispatch Instruction minus the Resource’s Operating Tolerance defined in Section 4.4.2.4 and the Resource is not exempt from URD under Section 4.4.2.4.1;

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7.2.5.2 THRESHOLDS FOR IDENTIFYING PHYSICAL WITHHOLDING OF TRANSMISSION FACILITIES

Physical withholding of a transmission facility occurs when:

a) The Market Monitor identifies a pattern of scheduling outages resulting in increased market costs compared to an alternative and lower cost impact outage schedule; or

b) The transmission facility satisfies a condition in Section 7.2.5(1), or 7.2.5(2)

7.2.5.3 SANCTIONS FOR PHYSICAL WITHHOLDING

The Market Monitor will record instances where Market Participants have failed the physical withholding screens in Sections 7.2.5.1 and 7.2.5.2. The Market Monitor will notify the Commission’s Office of Enforcement, or successor organization, of suspected physical withholding behavior. In the event the Market Monitor determines there is credible evidence of a market violation, the Market Monitor shall make a referral to the Commission as described in Section 7.1.9.

7.2.6 MAINTENANCE AND IMPLEMENTATION OF THE MITIGATION PROTOCOLS

SPP is responsible for implementing the market power mitigation measures as approved by FERC. SPP is also responsible for periodically reviewing and recommending revisions to the mitigation protocols and seeking approval from FERC for any such updates with input and support from the appropriate WEIS Market stakeholder group.

8 WEIS MARKET PROCESS AND SYSTEM CHANGE PROCESS

This section outlines the methods that govern SPP System changes that directly impact SPP Western RC Services Customers’ and/or SPP Western Markets Market

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Participants’ processes, systems, or interfaces with SPP systems, referred to as “member-facing changes” or “member-impacting changes”. The intent of this section is to ensure there is transparency when member-impacting changes occur to SPP processes and/or systems.

Once a WRR has been approved through the stakeholder process, the SPP Change Working Group (“CWG”) will serve as the forum for coordinating the implementation of member-facing and member-impacting efforts for process and/or system changes affecting SPP administered markets and reliability functions.

A project is considered member-facing if:

• There are no changes required to systems owned by SPP Western RC Services Customers and/or SPP Western Markets Market Participants needed to allow for SPP’s change, but the change will be noticeable.

A project is considered member-impacting if:

• The change in the project will require changes to SPP Western RC Services Customers’ and/or SPP Western Markets Market Participants’ system(s) or processes; and/or

• There are required system modifications or testing to be accomplished by SPP Western RC Services Customers and/or SPP Western Markets Market Participants, without which their current systems will no longer work with this particular process.

The CWG will be responsible for monitoring and coordinating all planned member-impacting system or process changes that meet one or more of the following criteria:

(1) The change will result in SPP Western RC Services Customers and/or SPP Western Markets Participants having to make changes to their internal systems or interfaces;

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(2) The change will require SPP Western RC Services Customers and/or SPP Western Markets Participants to coordinate testing with SPP prior to the change being released to Production systems;

(3) The change will cause SPP Western RC Services Customers and/or SPP Western Markets Participants to change their internal processes;

(4) The change modifies or creates a system interface between SPP and its SPP Western RC Services Customers and/or SPP Western Markets Participants;

(5) The risk associated with the change justifies inclusion as a member-impacting change.

(2) 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 WRR ranking process conducted by the SPP Western Reliability Working Group (“WRWG”) or the SPP Western Market Working Group (“WMWG”), whichever is applicable, 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 WRWG or WMWG, after coordination with the CWG. The plan will include, at a minimum, the following:

a) Listing and description of planned member-impacting projects;

b) Updated current status of planned member-impacting projects;

c) Identifiable milestones of planned member-impacting projects, including, but not limited to:

i) Requirements Signoff;

ii) Schedule of Testing and Training;

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iii) Communication of Expectations / Specifications;

iv) Release of Required Documentation;

v) System Release Dates.

(3) 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 CWG and alternative timelines may 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.

(a) Minor Change – a change to an SPP system that corrects or changes existing functionality but does not require SPP Western RC Services Customers and/or SPP Western Markets Market Participants to make any changes to their systems, nor test the new functionality in a coordinated fashion with SPP. An example of a minor member-impacting change would be an enhancement to SPP Western RC Services Customers and/or SPP Western Markets Market Participants accessible web page that includes adding newly available options or functionality. For minor member-impacting changes, SPP staff is required to notify the SPP Western RC Services Customers and/or SPP Western Markets Market Participants at least two (2) weeks prior to implementation in production.

(b) Medium Change - a change to an SPP system that involves changes to system interfaces between SPP and its SPP Western RC Services Customers and/or SPP Western Markets Market Participants, such as changes to XML file specifications or Application Programmable Interfaces (API). The process for interface changes must allow sufficient time for SPP Western RC Services Customers and/or SPP Western Markets Market Participants 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 SPP

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Western RC Services Customers and/or SPP Western Markets Market Participants at least six (6) weeks prior to implementation in production, or as defined and agreed to by the CWG.

(c) Major Change - a change to an SPP system that introduces a new member-facing application, major system functionality or wholesale process changes. These changes will always be managed by SPP as projects, with milestones defined on the plan that is updated quarterly, and will include SPP Western RC Services Customers and/or SPP Western Markets Market Participants participation, coordination, and testing throughout the project phases. For major changes that require the development of new applications or interfaces by SPP Western RC Services Customers and/or SPP Western Markets Market Participants, SPP staff is required to coordinate the project schedule by means of the CWG to determine the appropriate lead times for documentation, testing, and implementation.

(d) Emergency Change - a member-impacting change to an SPP system that is required to immediately restore or correct existing functionality. If changes to SPP Western RC Services Customers’ and/or SPP Western Markets Market Participants’ systems or processes are required as a result of an Emergency Change, SPP staff will make the necessary changes and send the notification of the change as soon as practicable following the resolution of the emergency change.

If the WRR has no member-facing or member-impacting efforts or Tariff impacts, the WRR will be implemented in the latest version of the applicable governing document(s) following all necessary stakeholder approvals.

Appendix A Settlement Calculations and ExamplesSPP Staff will provide Settlement calculations and examples to match the WEIS Tariff and Protocol language

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A.1 IntroductionA.1.1 PurposeThe purpose of this document is to add context to the settlement formulae from the WEIS Market Protocols by providing transactional examples of the settlement charge types and intermediate calculations. Where practical the examples are presented with illustrations which show how different types of market instruments interact in achieving settlement results. In the interest of brevity and clarity the example calculations evaluate results in a single interval, be it 5-minute, hourly, daily or even monthly/yearly.

A.1.2 Definitions of TermsAcrony

m Term Definition

AO Asset Owner The middle tier of financial entities in the CM, used for Settlement Statements.

BA Balancing Authority

A boundary defined by internal generation control to an instantaneous NAI signal

CC Combined Cycle (Resource)

An electric generating technology in which electricity is generated by both a combustion turbine Resource (the Brayton Cycle) and a steam turbine Resource (the Rankine Cycle) hence the name Combined Cycle. The CT exhaust heat flows to a conventional boiler or to a heat recovery steam Resource (HRSG) to produce steam for use by a steam turbine Resource in the production of electricity.

CM Commercial Model

The financial entities, network elements and relationships between them constructing the backbone of the market

COSCommercial Operations Systems

A suite of market applications including settlements, customer service and the portal

DDRDispatchable Demand Response

Load reduction which can be metered

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Acronym Term Definition

DRL Demand Response Load

A meter location discretely representing the load behind which a demand response Resource is located. A DRL is not necessarily associated with a SL which will be settled, its primary function is for acceptance of metering which supports DDRs

DRRDemand Response Resource

DDR

EMSEnergy Management System

SPP repository and dashboard for MP SCADA data

JOU Joint Owned Unit Ownership of a physical Resource shared among multiple financial entities

LRS Load Ratio Share The % of load at a single SL relative to the SPP total

MA Meter AgentEntity responsible for submittal of revenue quality interchange, Resource and load meter data to settlements via the market portal

MDSLMeter Data Submittal Location

A child of SL – the level at which meter data is submitted. It is usually 1:1 with SL, but in certain cases multiple MDSLs may relate to a single SL. MDSLs are confined to a single SA (necessary for the purpose of calibration calculation) while a SL may span multiple SAs.

MP Market Participant

The highest tier of financial entities in the CM, used for invoicing and credit.

MS Market Settlements

The system built to implement new WEIS Market Protocols

MTR Meter Revenue Quality

NAI Net Actual Interchange The actual net flow into or out of BA or SA

NSI Net Scheduled Interchange The scheduled net flow into or out of BA or SA

OD Operating Day The day boundary for a single settlement period

POP Post Operations Processor

A rudimentary system which consists primarily of a market system database dump, and bridges the gap between RT Operations and MS

WRTBMWestern Real-Time Balancing Market

Future market for dispatch of energy and operating reserves to meet current demand

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Acronym Term Definition

RNU Revenue Neutrality Uplift Market charge type for balancing daily settlement

SA Settlement AreaA boundary within the WEIS Market Footprint which defines the load balance equation to determine the calibration quantity

SCADASupervisory Control And Data Acquisition

4 second Resource and load bus signals from MP equipment sent to SPP

SE State EstimatorAn operations system which smooths, replaces and repairs SCADA data to create complete snapshots of the transmission system every 5 minutes

SL Settlement Location

Pricing points in the footprint: Resource, Load, Interface & Resource Hub types

UOM Unit of Measure MW or MWh data submitted in 5-minute intervals

URDUninstructed Resource Deviation

Performance outside of a tolerance band from the dispatch setpoint

A.2 WEIS Market ModelA.2.1 Commercial ModelThe settlement examples are based on a miniature model of the WEIS Market Footprint, but one which provides substantial diversity in the different organizational structures or transactional scenarios found in actual market operations.

A.2.1.1 Financial Entities and RelationshipsThree tiers of financial entities comprise the backbone of settlements.

1) MP: the top level for invoicing and credit exposure calculations.2) AO: an organizational or accounting sub-group used to compartmentalize market

activity, Settlement Statements are presented at this level.3) Asset: a Resource or load owned by and Market Participant, exclusive use of a SL

for certain charge types.

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Each of the settlement examples will provide a dialogue that associates the transactional activity to a single AO. The calculations themselves occur at various levels, primarily per SL, but in cases where SL granularity is not practical the results are at a zonal level or are summed to the AO.

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A.2.1.2 Network Entities and RelationshipsThe relationships among MLs, SLs, SAs, and Common Bus described in the WEIS Market Protocols are not always important to settlement calculations; however, there are exceptions where an understanding of the underlying framework is essential.

Settlement formulae use the billable metering determinant as the point of entry for calculations which require revenue quality injection and withdrawal data, but it is in fact an intermediate determinant derived from a chain of other raw data elements.

Actual submittals must be at a location, the MDSL, confined to a single SA for the purpose of calculating unaccounted for Energy. Where an SL consists of multiple MDSLs in different SAs the billable meter determinant is an aggregation of the submitted values.

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Calibration of SA unaccounted for Energy is included with MDSL values in the roll-up to the SL level.

Metered load represents net withdrawal of energy plus transmission losses.

Demand response will be treated as a generation within the BA and settled as part of the EIS calculation.

Absent any submittal the settlement system substitutes SE values.

Hourly meter submittals are profiled into 5 minute intervals.

The Common Bus object is used as a tool to prevent charges for URD where a group of Resources measured in aggregate pass the performance threshold.

A.3 Settlement CalculationsA.3.1 Energy Imbalance Service AmountThe net amount for each Asset Owner (AO) for each Settlement Location in a Dispatch Interval is calculated as follows:

# EISRtEnergy5minAmt a, s, i = (EISRtLmp5minPrc s, i

* EISRtEnergy5minQty a, s, i ) / 12

Where,

1) The real-time Energy Imbalance Service quantity combining supply and withdrawal obligations for an AO at a Settlement Location in a Dispatch Interval is calculated by the follow formula: #EISRtEnergy5minQty a, s, i = EISRtUnH5minQty a, s, i + EISRtNLH5minQty

a, s, i 2) In the event that an AO has a market position which is not eligible for inclusion in

Native Load Hedging, these market positions will be included outside the Native Load Hedging process. Excluded tagged transactions may cause such a market

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position which is calculated as follows: #EISRtUnH5minQty a, s, i = t

EISRtUnHEnTag5minQty a, s, i, t 3) The AO’s Imbalance Energy quantity per Settlement Location in a Dispatch

Interval is based on using the Native Load Heading process as described in Section 4.5.6.1.4. This process centers on determining the difference between supply and obligation for each Market Participant calculated by Asset Owner and applied across Settlement Locations. In order to determine the Imbalance Energy quantity, the supplied MW must be grouped and sorted.

The total amount of supply can be grouped into two categories for the purpose of NLH. The first grouping, considered lowest priority supply, is the sum of the output associated with non-dispatchable generation; output up to the economic minimum associated with dispatchable generation; the sum of any load Settlement Locations with a net injection after energy tags have been applied; less the amount of any export tags sourced from that Settlement Location. The second grouping, considered cost-based, contains the output associated with dispatchable generation above the economic minimum up to the billable meter amount, sorted by mitigated cost offer per KW, less the amount of any export tags sourced from that Settlement Location greater than the lowest priority supply available.

Based on amount of obligation and applying the energy tags to Resources and loads, the results will fall in one of the following conditions:a) If the AO is consuming, the AO’s Native Load Hedging net obligaton is

allocated to Settlement locations with Native Load Hedging obligaton.b) If the AO is supplying and the AO’s net Native Load Hedging energy quantity

(quantity of excess supply) equals or exceeds the AO’s Native Load Hedging cost-based energy available, the AO’s Native Load Hedging net supply is comprised of all cost-based energy at its Settlement Location and the remainder allocated to Settlement locations with Native Load Hedging lowest priority supply

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c) If the AO is supplying and the net quantity sold is less than the AO’s Native Load Hedging cost-based MWs, the AO’s Native Load Hedging net supply is based on the Settlement Locations with the highest priced cost-based energy blocks representing the cost-based MWs.#EISRtNLH5minQty a, s, i =IF { EISRtNLHBase5minAoQty a, i >= 0 } THEN

EISRtNLHBase5minAoQty a, i *[EISRtNLH5minLPWdlQty a, s, i / EISRtNLH5minLPWdlAoQty a, i ]

ELSE IF { EISRtNLHBase5minAoQty a, i <= EISRtNLH5minCBInjAoQty a,

i }

THEN{[ EISRtNLHBase5minAoQty a, i - EISRtNLH5minCBInjAoQty a, i ] * [EISRtNLH5minLPInjQty a, s, i / EISRtNLH5minLPInjAoQty a, i ]} + EISRtNLH5minCBInjQty a, s, i

ELSEEISRtNLH5minCBEISQty a, s, i

d) Each AO’s Native Load Hedging net energy in a Settlement Interval is calculated as follows:

#EISRtNLHBase5minAoQty a, i = s EISRtNLHBase5minQty a, s, i

e) Each AO’s Native Load Hedging total withdrawal from Settlement Locations with net energy withdrawal in a Settlement Interval is calculated as follows:

#EISRtNLH5minLPWdlAoQty a, i = s EISRtNLH5minLPWdlQty a, s, i

f) Each AO’s Native Load Hedging total calculated cost-based supply from Settlement Locations with net energy supply in a Settlement Interval is calculated as follows:

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#EISRtNLH5minCBInjAoQty a, i = s EISRtNLH5minCBInjQty a, s, i

g) Each AO’s Native Load Hedging total lowest priority supply from Settlement Locations with net energy supply in a Settlement Interval is calculated as follows:

#EISRtNLH5minLPInjAoQty a, i = s EISRtNLH5minLPInjQty a, s, i

h) The Settlement Locations with a net Native Load Hedging energy withdrawal for an AO in a Dispatch Interval are defined to have a lowest priority withdrawal energy amount defined by the following:EISRtNLH5minLPWdlQty a, s, i =

Max(0, EISRtNLHBase5minQty a, s, i )

i) The Settlement Locations with a net Native Load Hedging energy supply for an AO in a Dispatch Interval have the supply divided between lowest priority supply energy and cost-based energy defined by the following where cost-based energy represents the Dispatchable Resource range at the Settlement Location which is not consumed by load or transaction obligations at the Settlement Location:i) #EISRtNLH5minLPInjQty a, s, i = IF EISRtNLHBase5minQty a, s, i < 0

THEN EISRtNLHBase5minQty a, s, i - EISRtNLH5minCBInjQty a, s, i ELSE 0

ii) #EISRtNLH5minCBInjQty a, s, i = IF EISRtNLHBase5minQty a, s, i < 0 and EISRtBillMtr5minQty a, s, i < 0 and EISRtMktDisp5minFlg a, s, i = 1THENmin [ 0 , max ( EISRtNLHBase5minQty a, s, i , EISRtBillMtr5minQty a, s, i - (EISRtEffMin5minQty a, s, i * -1))] ELSE 0

iii) EISRtEffMin5minQty a, s, i = Min (EISRtDispMinEconCapOL5minQty a,

s, i , Max (0, (-1) * EISRtBillMtr5minQtya, s, i ))

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j) The base Native Load Hedging energy before hedging across Settlement Locations for an AO at the Settlement Location level in a Dispatch Interval combines the 5-minute billable meter determinant and the sum of the individual tagged transactions for the Native Load Hedging calculation at the Settlement Location:

#EISRtNLHBase5minQty a, s, i = EISRtBillMtr5minQty a, s, i + t

EISRtNLHEnTag5minQty a, s, i, t k) The 5-minute billable meter determinant at the Settlement Location level is

the sum of the 5-minute billable meter determinants at the Meter Data Submittal Location level as shown in the formula below. Most Settlement Locations will be comprised of only one Meter Data Submittal Location, but in certain cases a single Settlement Location will represent multiple Meter Data Submittal Locations, each of which is in a separate Settlement Area. Since the calibration function must be performed within Settlement Area boundaries, it is done before summing the data to the Settlement Location level. The 5-minute determinants are expressed in terms of levelized MW at both the Settlement Location and Meter Data Submittal Location level.

EISRtBillMtr5minQty a, s, i = ml EISRtMlBillMtr5minQty a, ml, i

l) The 5-minute billable meter determinant at the Meter Data Submittal Location level is the sum of the 5-minute adjusted meter determinant and the 5-minute calibration meter determinants at the Meter Data Submittal Location level as shown in the formula below. Both 5-minute determinants are expressed in terms of levelized MW.EISRtMlBillMtr5minQty a, ml, i = EISRtAdjMtr5minQty a, ml, i + EISRtCalMtr5minQty a, ml, i

m) For Resource (including Demand Response Resources) and load assets, the 5-minute adjusted meter determinant is a hierarchal selection among 1) 5-minute submitted actual meter reading, 2) profiled hourly submitted actual meter reading and 3) default 5-minute state estimator value. Registration

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records whether 5-minute or hourly meter data submittals are selected. The methodologies are mutually exclusive for any given period. Market Participants who choose to submit their actual hourly meter reading into 5-minute intervals must use a profiling method consistent with the method described in Section 4.5.6.1.1.The 5-minute adjusted meter, state estimator, and SCADA determinants are expressed in terms of levelized MW and both hourly and 5-minute submitted actual determinants are in terms of MWh. The formula for the 5-minute adjusted meter determinant is shown below.IF EXISTS { EISRtActMtr5minQty a, ml, i } THEN

# EISRtAdjMtr5minQty a, ml, i =

EISRtActMtr5minQty a, ml, i * 12

ELSEIF EXISTS { EISRtActMtrHrlyQty a, ml, h } THEN# EISRtAdjMtr5minQty a, ml, i = EISRtSE5minQty a, ml, i

+ { ( EISRtActMtrHrlyQty a, ml, h -i EISRtSE5minQty a, ml, i / 12)

* {IF (i ABS (EISRtSE5minQtya, ml, i ) > 0 THEN [ABS

(EISRtSE5minQtya, ml, i) / i ABS ( EISRtSE5minQty a, ml, i ) ], ELSE 1 /12

} * 12 }ELSE# EISRtAdjMtr5minQty a, ml, i = EISRtSE5minQty a, ml, i

n) The 5-minute calibration meter determinant is the hourly quantity, profiled by State Estimator data into 5-minute intervals as shown in the formula below.

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The 5-minute calibration meter determinant is expressed in terms of levelized MW. The formula for the 5-minute calibration meter determinant is shown below.# EISRtCalMtr5minQty a, ml, i = If EISRtCalMtrHrlyQty a, ml, h = 0THEN 0ELSEEISRtSE5minQty a, ml, i

+ { (EISRtCalMtrHrlyQty a, ml, h - i EISRtSE5minQty a, ml, i / 12)

* {IF i ABS(EISRtSE5minQty a, ml, i > 0 THEN [ ABS(EISRtSE5minQty

a, ml, i ) / i ABS(EISRtSE5minQty a, ml, i ) ] , ELSE 1/12} * 12 }

o) The hourly calibration meter determinant is the weighted distribution of Settlement Area unaccounted for Energy among load in the Settlement Area (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area). The hourly calibration meter determinant is expressed in terms of levelized MW. WAPA’s transmission capacity and deliveries of Statutory Obligations will be exempted from calibration. The formula for the hourly calibration meter determinant is shown below.IF EISIsPsgiPsli (ml) THEN # EISRtCalMtrHrlyQty a, ml, h = 0ELSE# EISRtCalMtrHrlyQty a, ml, h = EISRtResMtrHrlyQty sa, h

* [ MAX ( ( ( 1 – EISAoIsExemptLoadDlyFlg a, ml, d ) * EISRtAdjMtrHrlyQty sa, a, ml, h ) , 0 )

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/ ml MAX ( ( ( 1 - EISAoIsExemptLoadDlyFlg a, ml, d ) *

EISRtAdjMtrHrlyQty sa, a, ml, h ) , 0 ) ]

p) The hourly adjusted meter determinant is the sum of the 5-minute adjusted meter determinant divided by 12. The hourly adjusted meter determinant is expressed in terms of levelized MW. The formula for the hourly adjusted meter determinant is shown below.

# EISRtAdjMtrHrlyQty a, ml, h = i EISRtAdjMtr5minQty a, ml, i / 12

q) The unaccounted for Energy determinant is the net difference between generation, load (excluding Demand Response Resources, and Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area) and tie-line flows per Settlement Area. Hourly Net Actual Interchange is derived as the sum of the hourly adjusted meter values for aggregate ties between interconnected Settlement Areas. To the extent that adjusted meter values for aggregate ties are submitted on a 5-minute basis, SPP will integrate those values to an hourly value. Missing tie values are replaced with State Estimator values. The unaccounted for Energy determinant is expressed in terms of levelized MW. The formula for the hourly unaccounted for Energy determinant is shown below.

EISRtResMtrHrlyQty sa, h = (a

ml { IF EISIsPsgiPsli (ml) THEN 0 ELSE

EISRtAdjMtrHrlyQty sa ,a, ml, h }

+ EISRtSaNetActIchngHrlyQty sa, h + i * (-1)

r) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:

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EISRtEnergyHrlyAmt a, s, h = i EISRtEnergy5minAmt a, s, i

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

EISRtEnergyDlyAmt a, s, d = h EISRtEnergyHrlyAmt a, s, h

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

EISRtEnergyAoAmt a, m, d = s EISRtEnergyDlyAmt a, s, d

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

EISRtEnergyMpAmt m, d = a EISRtEnergyAoAmt a, m, d

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The above variables are defined as follows: Variable Unit Settleme

ntInterval

Definition

EISRtEnergy5minAmt a, s, i $ Dispatch Interval

Real-Time Energy Imbalance Service Amount per AO per Settlement Location per Dispatch Interval - The amount for AO a for Energy Imbalance Service between an Asset Owner obligation and supply energy amounts at Settlement Location s for the Dispatch Interval i.

EISRtLmp5minPrc s, i $/MW

Dispatch Interval

Real-Time LMP - The LMP at Settlement Location s for Dispatch Interval i.

EISRtEnergy5minQty a, s, i MW Dispatch Interval

Real-Time Energy Imbalance Service Quantity per AO per Settlement Location per Dispatch Interval – The quantity for Energy Imbalance Service for AO a at Settlement Location s for Dispatch Interval i.

EISRtUnH5minQty a, s, i MW Dispatch Interval

Real-Time Unhedged Quantity per AO per Settlement Location per Dispatch Interval - The total net quantity of energy for AO a at Settlement Location s, for the Dispatch Interval i which is not participating in Native Load Hedging at Settlement Location s.

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Variable Unit SettlementInterval

Definition

EISRtUnHEnTag5minQty a, s, i, t MW Dispatch Interval

Real-Time Unhedged Energy Tag Quantity per AO per Settlement Location per Dispatch Interval - The quantity of energy represented by one of AO a’s actual tagged energy transactions t not participating in Native Load Hedging at Settlement Location s, for the Dispatch Interval i. The Dispatch Interval value of the transaction will be equal to the scheduled MW within the scheduled start-time and stop-time of the transaction. Transaction ramping will be ignored. When the AO is associated with the source end of the tagged transaction at the Settlement Location, the quantity is treated as an obligation. When the AO is associated with the sink end of the tagged transaction at the Settlement Location, the quantity is treated as supply.

EISRtNLH5minQty a, s, i MW Dispatch Interval

Real-Time Native Load Hedging Quantity per AO per Settlement Location per Dispatch Interval – The total net quantity of energy participating in Native Load Hedging for AO a at Settlement Location s for the Dispatch Interval i. Indicates if the SL is a net supplier or consumer.

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Definition

EISRtNLHBase5minAoQty a, i MW Dispatch Interval

Real-Time Native Load Hedging Base Quantity per AO per Dispatch Interval – The total net quantity of energy participating in Native Load Hedging for AO a for the Dispatch Interval i. Indicates if the AO is a net supplier or consumer.

EISRtNLH5minLPWdlAoQty a, i MW Dispatch Interval

Real-Time Native Load Hedging Net Withdrawal Location Total Quantity per AO per Dispatch Interval – The total net withdrawals from Settlement Locations with net withdrawals participating in Native Load Hedging for AO a for the Dispatch Interval i.

EISRtNLH5minCBInjAoQty a, i MW Dispatch Interval

Real-Time Native Load Hedging Calculated Cost-Base Supply Quantity per AO per Dispatch Interval – The total net cost-based supply from Settlement Locations calculated to participate in Native Load Hedging for AO a for the Dispatch Interval i.

EISRtNLH5minLPInjAoQty a, i MW Dispatch Interval

Real-Time Native Load Hedging Calculated Lowest Priority Supply Quantity per AO per Dispatch Interval – The total net lowest cost supply from Settlement Locations calculated to participate in Native Load Hedging for AO a for the Dispatch Interval i.

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Definition

EISRtNLH5minLPWdlQty a, s, i MW Dispatch Interval

Real-Time Base Native Load Hedging Net Lowest Priority Withdrawal Quantity per AO per Settlement Location per Dispatch Interval – When the total base net quantity of energy participating in Native Load Hedging (prior to hedging across Settlement Locations) for AO a at Settlement Location s for the Dispatch Interval i is a withdrawal, this value is the total base net energy, else 0.

EISRtNLH5minCBInjQty a, s, i MW Dispatch Interval

Real-Time Base Native Load Hedging Net Cost-Based Supply Quantity per AO per Settlement Location per Dispatch Interval – The Native Load Hedging cost-based supply quantity (prior to hedging across Settlement Locations) for AO a at Settlement Location s for the Dispatch Interval i is the cost-based dispatchable range of Resources at the Settlement Location which is not consumed by net load/transactions obligations at this Settlement Location.

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Definition

EISRtNLH5minCBEISQty a, s, i MW Dispatch Interval

Real-Time Base Native Load Hedging Cost-Based EIS Quantity per AO per Settlement Location per Dispatch Interval – The Native Load Hedging cost-based supply quantity remaining (after hedging across Settlement Locations) for AO a at Settlement Location s for the Dispatch Interval i is the cost-based dispatchable range of Resources at the Settlement Location which is not consumed by NLH and considered EIS at this Settlement Location based on:Select quantity of NLH available cost-based blocks at Settlement Location i selected as AO’s highest priced cost-based blocks totaling EISRtNLHBase5minAoQty a, i

from all offer cost blocks at all Settlement Locations for capacity representing EISRtNLH5minCBInjQty a, s, i

EISRtMktDisp5minFlg a, s, i none Dispatch Interval

Real-Time Resource Market Dispatchable Flag per AO per Resource per Dispatch Interval – A flag indicating the availability of AO a’s eligible Resource at Settlement Location s for WRTBM dispatch in Dispatch Interval i.

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Definition

EISRtEffMin5minQty a, s, i MW Dispatch Interval

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

EISRtDispMinEconCapOL5minQty a, s, i

MW Dispatch Interval

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

EISRtNLH5minLPInjQty a, s, i MW Dispatch Interval

Real-Time Base Native Load Hedging Net Lowest Priority Supply Quantity per AO per Settlement Location per Dispatch Interval – When the total base net quantity of energy participating in Native Load Hedging (prior to hedging across Settlement Locations) for AO a at Settlement Location s for the Dispatch Interval i is a supply, this value is the difference between the total base net energy and cost-based supply energy, else 0.

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Definition

EISRtNLHBase5minQty a, s, i MW Dispatch Interval

Real-Time Base Native Load Hedging Quantity per AO per Settlement Location per Dispatch Interval – The total base net quantity of energy participating in Native Load Hedging (prior to hedging across Settlement Locations) for AO a at Settlement Location s, for the Dispatch Interval i combining physical assets and tagged transactions.

EISRtNLHEnTag5minQty a, s, i, t MW Dispatch Interval

Real-Time Energy Tag Quantity per AO per Settlement Location per Dispatch Interval - The quantity of energy represented by one of AO a’s actual tagged energy transactions t participating in Native Load Hedging at Settlement Location s, for the Dispatch Interval i. The Dispatch Interval value of the transaction will be equal to the scheduled MW within the scheduled start-time and stop-time of the transaction. Transaction ramping will be ignored. When the AO is associated with the source end of the tagged transaction at the Settlement Location, the quantity is treated as an obligation. When the AO is associated with the sink end of the tagged transaction at the Settlement Location, the quantity is treated as supply.

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Definition

EISRtBillMtr5minQty a, s, i MW Dispatch Interval

Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The Dispatch Interval metered quantities for AO a Resources and load at Settlement Location s in Dispatch Interval i used by SPP for settlement purposes.

EISRtActMtr5minQty a, ml, i MWh Dispatch Interval

Real-Time Actual Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval metered quantity, in MWh, for AO a’s Resources and load directly submitted by Market Participant.

EISRtActMtrHrlyQty a, ml, h MWh Hour Real-Time Actual Meter Quantity per AO per Meter Data Submittal Location per Hour - The hourly metered quantity, in MWh, for AO a’s Resources and load directly submitted by the Market Participant.

EISRtMlBillMtr5minQty a, ml, i MW Dispatch Interval

Real-Time Billing Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval RtAdjMtr5minQty a, ml, i quantities adjusted to account for calibration Energy for AO a load at Meter Location ml in Dispatch Interval i.

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Definition

EISRtCalMtr5minQty a, ml, i MW Dispatch Interval

Real-Time Calibration Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval calibration quantities calculated by SPP for AO a at load at Meter Data Submittal Location ml in Dispatch Interval i.

EISRtCalMtrHrlyQty a, ml, h MWh Hour Real-Time Calibration Meter Quantity per AO per Meter Settlement Location per Hour- The Dispatch Interval calibration Energy quantities calculated by SPP for AO a at load at Meter Data Submittal Location ml in Hour h.

EISAoIsExemptLoadDlyFlg a, ml, d None None Asset Owner Load is Exempt from Calibration Flag per AO per MDSL per Operating Day. – This flag is set to 1 when the Asset Owner has Load that is exempt from Calibration.

EISRtSE5minQty a, ml, i MW Dispatch Interval

Real-Time State Estimator Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval State Estimator value for AO a at Meter Data Submittal Location ml in Dispatch Interval i.

EISRtResMtrHrlyQty sa, h MWh Hour Real-Time unaccounted for Energy per Settlement Area per Hour - The unaccounted for Energy for Settlement Area sa in Hour h.

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Definition

EISIsPsgiPsli (ml) None None A Logical operation of the Meter Data Submittal Location to determine if it is of type PSGI or PSLI – a Resource or load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area

EISRtSaNetActIchngHrlyQty sa,

h

MWh Hour Real-Time Net Actual Interchange per Settlement Area per Hour - The sum of Adjusted Meter Data values submitted for tie-line Meter Data Submittal Locations within Settlement Area sa in Hour h.

EISRtAdjMtr5minQty a, ml, i MW Dispatch Interval

Real-Time Adjusted Actual Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval metered quantity, in MW, for AO a’s Resources and load calculated by SPP to account for load adjustments related to Demand Response Resources and to calculate a default value if EISRtActMtrHrlyQty a, ml, h or EISRtActMtr5minQty a,

ml, i is not submitted.

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Definition

EISRtAdjMtrHrlyQty sa, a, ml, h MWh Hour Real-Time Adjusted Actual Meter Quantity per AO per Meter Data Submittal Location per Hour - The hourly metered quantity, in MWh, for AO a’s Resources and load calculated by SPP to account for load adjustments related to Demand Response Resources and to calculate a default value if EISRtActMtrHrlyQty a, ml, h or EISRtActMtr5minQty a, ml, i is not submitted for AO a at Meter Data Submittal Location ml in Settlement Area sa in Hour h.

EISRtEnergyHrlyAmt a, s, h $ Hour Real-Time Energy Imbalance Service Amount per AO per Settlement Location per Hour - The amount for AO a for Energy Imbalance Service between an Asset Owner obligation and supply energy at Settlement Location s for the Hour.

EISRtEnergyDlyAmt a, s, d $ Operating Day

Real-Time Energy Imbalance Service Amount per AO per Settlement Location per Operating Day - The amount for AO a for Energy Imbalance Service between an Asset Owner obligation and supply energy at Settlement Location s for the Operating Day.

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Definition

EISRtEnergyAoAmt a, m, d $ Operating Day

Real-Time Energy Imbalance Service Amount per AO per Operating Day - The amount for AO a associated with Market Participant m for Energy Imbalance Service between an Asset Owner obligation and supply energy for the Operating Day.

EISRtEnergyMpAmt m, d $ Operating Day

Real-Time Energy Amount per MP per Operating Day - The amount to MP m for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids for the Operating Day.

A none none An Asset Owner.H none none An Hour.I none none A Dispatch Interval.S none none A Settlement Location.T none none A single tagged Interchange Transaction or a single

Reserve Sharing Event transaction.Sa none none A Settlement Area.Ml none none A Meter Data Submittal Location.D none none An Operating Day.M none none A Market Participant.

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A.3.2 Real-Time Out-Of-Merit AmountThe amount for each Asset Owner (AO) for each eligible Resource Settlement Location for each Dispatch Interval is calculated as follows:

IF EISRtOom5minFlg a, s, i = 1 OR EISRtReprice5minFlg a, s, i = 1

THEN

# EISRtOom5minAmt a, s, i = (EISRtOomeIncr5minAmt a, s, i + EISRtOomeDecr5minAmt a, s, i ) * (-1)

Where,

(a) IF Min (Min (0, EISRtBillMtr5minQty a, s, i) * (-1), EISRtAvgSetpoint5minQty a, s, i )

> EISRtOomeDesiredEn5minQty a, s, i

And EISRtEnergy5minQty a, s, i < 0

Then

#EISRtOomeIncr5minAmt a, s, i =

Max ( 0, Max ( 0, EISRtOomeIncrEn5minAmt a, s, i – EISRtOomeDesiredEn5minAmt a, s, i ) -

Max (0, Min (Min (0, EISRtBillMtr5minQty a, s, i ) * (-1),

Min (EISRtOomeDesiredEn5minQty a, s, i - EISRtEnergy5minQty a, s,

i , ,EISRtOomeFloor5minQty a, s, i , EISRtAvgSetpoint5minQty a,

s, i ) ) - EISRtOomeDesiredEn5minQty a, s, i )

* EISRtLmp5minPrc s, i ) / 12

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(a.1) #EISRtOomeIncrEn5minAmt a, s, i =

∫x

y

RTBM As Dispatched Energy Offer Curve

Where:

X = 0

Y = Min ( Min ( 0, EISRtBillMtr5minQty a, s, i ) * (-1), Min (EISRtOomeDesiredEn5minQty a, s, i - EISRtEnergy5minQty a, s, i ,

EISRtOomeFloor5minQty a, s, i , EISRtAvgSetpoint5minQty a, s,

i ) )

(a.2) # EISRtOomeDesiredEn5minAmt a, s, i =

∫x

y

RTBM As Dispatched Energy Offer Curve

Where:

X = 0

Y = EISRtOomeDesiredEn5minQtya, s, i

(b) IF Min (Min (0, EISRtBillMtr5minQty a, s, i ) * (-1), EISRtAvgSetpoint5minQty a, s, i ) <= EISRtOomeDesiredEn5minQty a, s, i

And EISRtEnergy5minQty a, s, i > 0

Then

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#EISRtOomeDecr5minAmt a, s, i =

(EISRtOomeDesiredEn5minQty a, s, i -

Max (Min ( 0, EISRtBillMtr5minQty a, s, i )

* (-1), EISRtAvgSetpoint5minQty a, s, i ,EISRtOomeCap5minQty a,

s, i ,(EISRtOomeDesiredEn5minQty a, s, i - EISRtEnergy5minQty a, s,

i )

* Max ( 0, EISRtLmp5minPrc s, i - EISRtOom5minPrc s, i )) / 12

(1) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The hourly amount is calculated as follows:

EISRtOomHrlyAmt a, s, h = ∑i EISRtOom5minAmt a, s, i

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

EISRtOomDlyAmt a, s, d = ∑h EISRtOomHrlyAmt a, s, h

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

EISRtOomAoAmt a, m, d = ∑s EISRtOomDlyAmt a, s, d

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

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EISRtOomMpAmt m, d = ∑a EISRtOomAoAmt a, m, d

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The above variables are defined as follows:

Variable Unit Settlement

Interval

Definition

EISRtOom5minAmt a, s, i $ Dispatch Interval

Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The amount for AO a for eligible Resource Settlement Location s in Dispatch Interval i for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

EISRtOomeIncr5minAmt a,

s, i

$ Dispatch Interval

Real-Time Out-Of-Merit Incremental Energy Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i amount for eligible Resource Settlement Location s in Dispatch Interval i for Out-of-Merit Energy resulting from an OOME in the up direction.

EISRtOomeDecr5minAmt a, s, i

$ Dispatch Interval

Real-Time Out-Of-Merit Decremental Energy Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i amount for eligible Resource Settlement Location s in Dispatch Interval i for Out-of-Merit Energy resulting from an OOME in the down direction.

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Interval

Definition

EISRtOomeDesiredEn5minQty a, s, i


Real-Time OOME Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval – The Desired Dispatch MW for AO a’s eligible Resource for Dispatch Interval i at EISRtLmp5minPrc s, i as calculated from the Resource’s latest verified As Dispatched Energy Offer Curveusing the As-Dispatched Minimum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the OOME as an output floor and the As-Dispatched Maximum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the OOME as an output ceiling.

EISRtOomeIncrEn5minAmt a, s, i

$ Dispatch Interval

Real-Time OOME Incremental Energy Cost Amount per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as calculated from the Resource’s latest verified As Dispatched Energy Offer Curve from 0 MW to the lesser of the EISRtBillMtr5minQty a, s, i , (EISRtEnergy5minQty a, s, i – EISRtEnergy5minQty a, s, i), EISRtOomeFloor5minQty a, s, i, or EISRtAvgSetpoint5minQty a, s, i.

EISRtOomeDesiredEn5minAmt a, s, i

$ Dispatch Interval

Real-Time OOME Energy Cost at Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as calculated from the Resource’s As Dispatched Energy Offer Curve from 0 MW to RtOomeDesiredEn5minQty a, s, i. , using the latest verified As Dispatched Energy Offer Curve.

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Interval

Definition

EISRtAvgSetPoint5minQty a,

s, i


Real-Time Average Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The value described under Section A.3.3 except that when EISRtOom5minFlg a, s, i is set to 1, EISRtAvgSetPoint5minQty a, s, i is set equal to the OOME MW.


Real-Time Actual Meter Quantity per AO per Location per Dispatch Interval - The value defined under Section A.3.1 for Dispatch Interval i.

EISRtOomeFloor5minQty a, s, i


Real-Time OOME Floor MW per AO per Settlement Location per Dispatch Interval – The MW floor for an out-of-merit Dispatch Instruction as defined in Section 4.4.1.4.2.

EISRtOomeCap5minQty a, s, i


Real-Time OOME Cap MW per AO per Settlement Location per Dispatch Interval – The MW cap for an out-of-merit dispatch instruction as defined in Section 4.4.1.4.2.

EISRtLmp5minPrc s, i $/MW Dispatch Interval

Real-Time LMP - The value defined under Section A.3.1 at Settlement Location s for Dispatch Interval i.

EISRtOom5minPrc s, i $/MW Dispatch Interval

Real-Time OOME Energy Offer Curve at the Dispatch Quantity per AO per Settlement Location per Dispatch Interval – The LMP for AO a’s eligible OOME for Dispatch Interval i as calculated from the Resource’s latest verified As Dispatched Energy Offer Curve based on quantity of y where:

y = Max (Min ( 0, EISRtBillMtr5minQty a, s, i ) * (-1), EISRtAvgSetpoint5minQty a, s,

i ,EISRtOomeCap5minQty a, s, i ,(EISRtOomeDesiredEn5minQty a, s, i - EISRtEnergy5minQty

a, s, i )

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Interval

Definition

EISRtOom5minFlg a, s, i None Dispatch Interval

Real-Time Out-of-Merit Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 when the BA issued a Manual Dispatch Instruction otherwise, this flag is set equal to zero.

EISRtReprice5minFlg a, s, i None Dispatch Interval

Real-Time Repricing Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever there is a price correction event as described under Section 6.2, otherwise, this flag is set equal to zero.

EISRtOomHrlyAmt a, s, h $ Hour Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Settlement Location per Hour - The amount for AO a for eligible Resource Settlement Location s in Hour h for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

EISRtOomDlyAmt a, s, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Settlement Location per Operating Day - The amount for AO a for eligible Resource Settlement Location s in Operating Day d for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

EISRtOomAoAmt a, m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Operating Day - The amount for AO a associated with Market Participant m in Operating Day d for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

EISRtOomMpAmt m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per MP per Operating Day - The amount to MP m in Operating Day d for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

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Interval

Definition

EISRtEnergy5minQty a, s, i MW Dispatch Interval

Real-Time Energy Imbalance Service Quantity per AO per Settlement Location per Dispatch Interval – The quantity for Energy Imbalance Service for AO a at Settlement Location s for Dispatch Interval i.

A none none An Asset Owner.S none none A Settlement Location.I none none A Dispatch Interval.H none none An Hour.D none none An Operating Day.M none none A Market Participant.T none none A single tagged Interchange Transaction, Reserve Sharing

Event.

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A.3.3 Uninstructed Resource Deviation AmountIn any Dispatch Interval in which the Resource has operated outside of its Operating Tolerance and that Resource has not been exempted from URD per Section 4.4.2.4.1, an incremental Energy adjustment associated with difference between actual Energy output and the Resource’s Desired Dispatch . The URD adjustment is calculated as follows:

IF (EISURD5minQty a, s, i > EISResOpHiTol5minQty a, s, i

OR EISURD5minQty a, s, i < EISResOpLoTol5minQty a, s, I )

AND ( EISXmptDev5minFlg a, s, i = 0 )

THEN

#EISRtURD5minAmt a, s, i =

(ABS(EISURD5minQty a, s, i ) * EISRtLmp5minPrc s, i) / 12

ELSE

EISRtURD5minAmt a, s, i = 0

(A.3.3.1) #EISURD5minQty a, s, i =

Max ( EISRtBillMtr5minQty a, s, i * (-1), 0 ) - EISRtAvgSetPoint5minQty a, s, i

(A.3.3.2) #EISResOpHiTol5minQty a, s, i =

Min ( EISURDMaxTol5minQty i , Max (EISURDMinTol5minQty i ,

EISURDTol5minPct i * EISRtDispMaxEmerCapOL5minQty a, s, i ) ) + EISRtRegUp5minQty a, s, i + EISRtSpin5minQty a, s, i + EISRtSupp5minQty a, s, i

(A.3.3.3) #EISResOpLoTol5minQty a, s, i =

Min ( EISURDMaxTol5minQty i , Max (EISURDMinTol5minQty i ,

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EISURDTol5minPct i * EISRtDispMaxEconCapOL5minQty a, s, i ) ) - EISRtRegDn5minQty a, s, i

1) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The hourly amount is calculated as follows:

EISRtURDHrlyAmt a, s, h = ∑i EISRtURD5minAmt a, s, i

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

EISRtURDDlyAmt a, s, d = ∑h EISRtURDHrlyAmt a, s, h

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

EISRtURDAoAmt a, m, d = ∑s EISRtURDDlyAmt a, s, d

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

EISRtURDMpAmt m, d = ∑a EISRtURDAoAmt a, m, d

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The above variable is defined as follows:


Interval

Definition

EISRtURD5minAmt a, s, i $ Dispatch Interval

URD Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i when the Resource’s EISURD5minQty a, s, i is outside of the Resource’s EISResOpTol5minQty a, s, i.

EISURD5minQty a, s, i MW Dispatch Interval

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

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Interval

Definition

EISResOpHiTol5minQty a, s, i MW Dispatch Interval

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

EISResOpLoTol5minQty a, s, i MW Dispatch Interval

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

EISURDMaxTol5minQty i MW Dispatch Interval

Uninstructed Resource Deviation Maximum Tolerance per Dispatch Interval – The maximum value of EISResOpTol5minQty a, s,

i that is currently set at 20 MW.

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Interval

Definition

EISURDMinTol5minQty i MW Dispatch Interval

Uninstructed Resource Deviation Minimum Tolerance per Dispatch Interval – The minimum value of EISResOpTol5minQty a, s, i

that is currently set at 5 MW.

EISURDTol5minPct i Percent Dispatch Interval

Uninstructed Resource Deviation Tolerance Percentage per Dispatch Interval – The percentage used to calculate the value of EISResOpTol5minQty a, s, i that is currently set at 5%.

EISRtAvgSetPoint5minQty a, s, i MW Dispatch Interval

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

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Interval

Definition

EISXmptDev5minFlg a, s, i none Dispatch Interval

URD Exemption Flag per AO per Resource Settlement Location per Dispatch Interval – A flag associated with AO a’s eligible Resource at Settlement Location s indicating that a Resource that has operated outside of its Operating Tolerance is or is not exempt from any associated penalty charges in Dispatch Interval i. If the flag is equal to zero, the Resource is not exempt. Otherwise, the flag will be set to a positive integer number which will indicate the reason of the exemption as specified under Section 4.4.2.4.1.

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Interval

Definition

EISRtDispMaxEconCapOL5minQty a, s, i


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

EISRtLmp5minPrc s, i $/MWh Dispatch

IntervalReal-Time LMP - The value defined under Section A.3.1 at Settlement Location s for Dispatch Interval i.


Real-Time Actual Meter Quantity per AO per Location per Dispatch Interval - The value defined under Section A.3.1 for Dispatch Interval i.

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Interval

Definition

EISRtRegUp5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Regulation-Up Service MW represented by AO a’s cleared Regulation-Up Service Offers in WRTBM that includes Resource Settlement Location s, for Dispatch Interval i, as described under Section 4.4.2.4(2)(d)

EISRtSpin5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Operational Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval - The total amount of spinning reserve MW represented by AO a’s cleared spinning reserve Offers in WRTBM that includes Resource Settlement Location s, for Dispatch Interval i, as described under Section 4.4.2.4(2)(d)

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Interval

Definition

EISRtSupp5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Operational Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval - The total amount of supplemental reserve MW represented by AO a’s cleared supplemental reserve Offers in WRTBM that includes Resource Settlement Location s, for Dispatch Interval i, as described under Section 4.4.2.4(2)(d)

EISRtRegDn5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Regulation-Down Quantity per AO per Settlement Location per Dispatch Interval - The total amount of regulation-down represented by AO a’s cleared regulation-down Offers in the WRTBM that includes Resource Settlement Location s, for Dispatch Interval i.

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Interval

Definition

EISRtURDHrlyAmt a, s, h $ Hour Real-Time Uninstructed Resource Deviation Amount per AO per Settlement Location per Hour - The amount for AO a for an eligible Resource Settlement Location s in Hour h for an Uninstructed Resource Deviation Amount resulting from an URD adjustment.

EISRtURDDlyAmt a, s, d $ Operating Day

Real-Time Uninstructed Resource Deviation Amount per AO per Settlement Location per Operating Day - The amount for AO a for eligible Resource Settlement Location s in Operating Day d for an Uninstructed Resource Deviation Amount resulting from an URD adjustment.

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Interval

Definition

EISRtURDAoAmt a, m, d $ Operating Day

Real-Time Uninstructed Resource Deviation Amount per AO per Operating Day - The amount for AO a associated with Market Participant m in Operating Day d for an Uninstructed Resource Deviation Amount resulting from an URD adjustment.

EISRtURDMpAmt m, d $ Operating Day

Real-Time Uninstructed Resource Deviation Amount per MP per Operating Day - The amount to MP m in Operating Day d for an Uninstructed Resource Deviation Amount resulting from an URD adjustment.

a none none An Asset Owner.

I none none A Dispatch Interval.

h none none An Hour.

d None none An Operating Day.

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Interval

Definition

s none none A Settlement Location.

m none none A Market Participant.

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A.3.4 Miscellaneous Amount1) Miscellaneous charges and credits to the affected Asset Owners are represented

for each Operating Day as follows:

EISMiscDlyAmt a, ct, s, rnu, d

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

EISMiscAoAmt a, m, d = ∑ct

∑s∑rnu EISMiscDlyAmt a, ct, s, rnu, d


EISMiscMpAmt m, d = ∑a EISMiscAoAmt a, m, d

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Interval

Definition

EISMiscDlyAmt a, ct, s, rnu, d $ Operating Day

Western EIS Miscellaneous Amount per AO per Settlement Location per Settlement Location per Operating Day – The miscellaneous amount for AO a for charge type ct at Settlement Location s in Operating Day d.

EISMiscAoAmt a, m, d $ Operating Day

Western EIS Miscellaneous Amount per AO per Operating Day – The total miscellaneous amount for AO a in Operating Day d.

EISMiscMpAmt m, d $ Operating Day

Western EIS Miscellaneous Amount per MP per Operating Day – The total miscellaneous amount to MP m in Operating Day d.

a none none An Asset Owner.ct none none Any charge type specified under Section 4.5.6 or any other

miscellaneous charges not specifically accounted for under a distinct charge type.

s none none A Settlement Location.rnu none none A flag which instructs the settlement system to include the

amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N).

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Interval

Definition

d none none An Operating Day.

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A.3.5 Revenue Neutrality Uplift Distribution AmountThe amount for each applicable Asset Owner is calculated as follows.

#EISRtRnuHrlyAmt a, s, h = (EISRtRnuSppDistRate d * EISRtRnuDistHrlyQty a, s, h ) * (-1)

Where,

(a) #EISRtRnuDistHrlyQty a, s, h =

(∑i ABS (EISRtBillMtr5minQty a, s, i ) / 12) +

(∑i∑t [ (ABS (EISRtExtEnTag5minQty a, s, i, t )/12) ]

(b) #EISRtRnuSppDistRated = EISRtRnuSppDlyAmt spp, d / EISRtRnuDistSppQty spp, d

(b.1) EISRtRnuDistSppQty spp, d =∑a∑s∑h

EISRtRnuDistHrlyQty a, s, h

(c) #EISRtRnuSppDlyAmt spp, d =

(EISRtRevInadqcSppAmt spp, d

+ EISRtOomSppAmt spp, d

+ EISRtURDSppAmt spp, d

+ EISRtMiscSppAmt spp, d )

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(c.1) EISRtRevInadqcSppAmt spp, d =

∑m ( EISRtEnergyMpAmt m, d )

(c.2) EISRtOomSppAmt spp, d = ∑m EISRtOomMpAmt m, d

(c.3) EISRtURDSppAmt spp, d = ∑m ( EISRtURDMpAmt m, d )

(c.4) EISRtMiscSppAmt spp, d =

∑a∑c∑s { IF rnu = 1, THEN EISMiscDlyAmt a, c, s, rnu, d , ELSE 0

}

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

EISRtRnuDlyAmt a, s, d = ∑h EISRtRnuHrlyAmt a, s, h

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

EISRtRnuAoAmt a, m, d = ∑s EISRtRnuDlyAmt a, s, d


EISRtRnuMpAmt m, d = ∑a EISRtRnuAoAmt a, m, d

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Interval

Definition

EISRtRnuHrlyAmt a, s, h $ Hour Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Hour – The amount for revenue neutrality for AO a at Settlement Location s in Hour h.

EISRtRnuSppDistRate d $/MW Operating Day

Real-Time Revenue Neutrality Uplift SPP Distribution Rate per Operating Day – The rate applied for AO a’s EISRtRnuDistHrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d.

EISRtRnuSppDlyAmt spp, d $ Operating Day

Real-Time Revenue Neutrality Uplift SPP Daily Amount – The total amount SPP is not revenue neutral, through all other charge types, in an Operating Day. The amount that is to be uplifted to the WEIS Market for Operating Day d.

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Interval

Definition

EISRtRnuDistHrlyQty a, s, h MWh Hour Real-Time Revenue Neutrality Uplift Quantity per AO per Hour per Settlement Location – The total MWh RNU allocation determinant for AO a at Settlement Location s for Hour h.

EISRtRnuDistSppQty spp, d MWh Operating Day

Real-Time Revenue Neutrality Uplift Quantity for SPP per Operating Day – The total MWh RNU allocation determinant for SPP on a system-wide basis.

EISRtOomSppAmt spp, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section A.3.2.

EISRtURDSppAmt spp, d $ Operating Day

Real-Time Uninstructed Resource Deviation Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section A.3.3

EISRtMiscSppAmt spp, d $ Operating Day

Real-Time Miscellaneous Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section A.3.4

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Interval

Definition

EISRtRevInadqcSppAmt spp, d $ Operating Day

Real-Time Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total WRTBM charges and WRTBM credits.


Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section A.3.1.

EISRtExtEnTag5minQty a, s, i, t MW Dispatch Interval

Real-Time External Energy Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The quantity of energy represented by AO a’s external (both import and export) tagged energy transactions t at Settlement Location s, for the Dispatch Interval i. The Dispatch Interval value of the transaction will be equal to the scheduled MW within the scheduled start-time and stop-time of the transaction. Transaction ramping will be ignored.

EISRtEnergyMpAmt m, d $ Operating Day

Real-Time Energy Amount per MP per Operating Day – The value described under Section A.3.1.

EISRtOomMpAmt m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per MP per Operating Day - The value described under Section A.3.4.

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Interval

Definition

EISRtURDMpAmt m, d $ Operating Day

Real-Time Uninstructed Resource Deviation Amount per MP per Operating Day - The amount to MP m in Operating Day d for an Uninstructed Resource Deviation Amount resulting from an URD adjustment.

EISMiscDlyAmt a, c, d $ Operating Day

Real-Time Miscellaneous Amount per AO per Charge Type per Operating Day – The miscellaneous amount for AO a for charge type c in Operating Day d as described under Section A.3.4.

EISRtRnuDlyAmt a, s, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Operating Day– The amount for revenue neutrality for AO a at Settlement Location s in Operating Day d.

EISRtRnuAoAmt a, m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per AO per Operating Day – The amount for revenue neutrality for AO a associated with Market Participant m in Operating Day d.

EISRtRnuMpAmt m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per MP per Operating Day – The amount for revenue neutrality to MP m in Operating Day d.

A none none An Asset Owner.

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Interval

Definition

S none none A Resource Settlement Location.h none none An Hour.i none none A Dispatch Interval.t none none A single tagged Interchange Transaction, a single

Reserve Sharing Event transaction.d none none An Operating Day.rnu none none A flag which instructs the settlement system to

include the amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N).

m none none A Market Participant.rsg none none An import or export resulting from a schedule

created by a Reserve Sharing Event.

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Appendix B Network and Commercial Model Update TimingAnticipated types of SPP System Changes with Typical Durations for Related Updates

New WEIS Market Registration Changes

System Update Type

Update Duration

Comments

New Market

Participant (MP) with physical assets

6 Months This will include adding all associated Asset Owners, Resource and/or Load assets. This change is implemented

following the New MP On-boarding process.

New Asset Owner

(Existing MP)

45 Days This is a 45-Day change for adding a new AO to an existing MP. Adding New AO with New MP will follow the New MP

duration.

New Meter Agent (MA)

4 Months Adding a new Meter Agent requires testing to prove the entity is capable of supplying meter data to SPP. This change is implemented following the New MP On-boarding process as

outlined in Section 5.

New Resource

Asset (Unit,

Plant, etc.) – Includes

Settlement Location,

Meter Data Submittal Location,

Source/Sink, and Pnode

Information

45 Days / 6 months

This is a 45-Day change for limited scope additions to existing asset owning MP. It can take up to 6 months for

moderate to large scope additions, or when new ICCP connection is required.

New Load 45 Days / 6 This is a 45 -Day change for limited scope additions to

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Asset (Load

Aggregate, DRL, etc.) –

Includes Settlement Location,

Meter Data Submittal Location,

Source/Sink, and Pnode

Information

Months existing asset owning MP. It can take up to 6 months for moderate to large scope additions, or when new ICCP

connection is required.

New Settlement

Area

6 Months This is a 6-month change. Duration applies for areas within SPP BA and areas outside of the SPP BA.

New Meter Data

Submittal Location (MDSL)

45 Days Adding an MDSL can be implemented in advance of the next scheduled model update if deemed necessary by MP and

approved my SPP Management.

New Source, Sink, or

Source/Sink

2 Weeks (Incrementa

l)

Adding a new source, sink, or source/sink can be implemented incrementally in advance of the next scheduled model update if deemed necessary by MP and approved by

SPP Management.

System Update Type

Update Duration

Comments

Terminating Market

Participant

6 Months / 1+ Years

This change is implemented following the timeline outlined in Section 5. Depending on the complexity, this change could

take longer than a year.

MarketParticipant Name

Change (Long

45 Days This is a 45-Day change for limited scope.

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Name)

Market Participant

Name Change (Short

Name/Acronym)

6 Months This change is implemented following the timeline outlined in Section 5.

Asset Owner Name

Change (Long Name)

45 Days This is a 45-Day change for limited scope.

Asset Owner Name

Change (Short

Name/Acronym)


Move Asset Owner

from one MP to

another


Terminating an Asset

Owner


Terminating a

Resource due to

Deactivation,

Retirement, or

Mothball

6 Months Deactivated, retired or mothballed Resources could have reliability and/or economic impacts on the SPP footprint.

Market Participants must provide a 6 month notification prior to planned Resource deactivation, retirement, or mothball in

order for SPP to have sufficient time to study possible impacts.

Contact Information Changes

2 Weeks Change will be implemented with the next scheduled model update.

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Modify/Terminate Resource

Asset Configurati

on – Includes

aggregating to a

plant, de-aggregating a plant, breaking

out individual units from

a plant, etc.

45 Days / 4 Months

This is a 45-Day change for limited scope additions for current MP. It can take up to 4 months for moderate to large scope additions. This includes changes to related Settlement

Location, Meter Data Submittal Location, and Source/Sink Information.

Modify/Terminate Load Asset Configurati

on – Includes

adding and removing bus level

loads

45 Days / 4 Months

This is a 45-Day change for limited scope additions for current MP. It can take up to 4 months for moderate to large scope additions. This includes changes to related Settlement

Location, Meter Data Submittal Location, and Source/Sink Information.

Modify/Terminate Settlement

Location

45 Days / 6 Months

This is a 45-Day change for limited scope. It could take up to 6 months for moderate to large scope. This change is

implemented following the timeline outlined in Section 5.

Modify/Terminate Meter Data Submittal Location (MDSL)

45 Days Changing an MDSL can be implemented in advance of the next scheduled model update if deemed necessary by MP

and approved by SPP Management.

Modify/Terminate

Source, Sink, or

Source/Sin

2 Weeks (Incrementa

l)

Changing a source, sink, or source/sink can be implemented incrementally in advance of the next scheduled model

update if deemed necessary by MP and approved by SPP Management.

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k

Modify/Terminate

Meter Agent (MA)

6 Months This is a 6-Month change.

Settlement Area

Change / Terminatio

n

4 Months / 6 Months

This is 4 months for limited scope changes. It could take up to 6 Months for moderate to large scope changes.

Resource Reasonable Limit MW

Value Changes

2 Weeks (Incrementa

l)

Changing Reasonable Limit MW value can be implemented incrementally in advance of the next scheduled model

update if deemed necessary by MP and approved by SPP Management.

1st Tier BA/External Aggregate

45 Days / 4 months

This is a 45-Day change for limited scope changes. It could take up to 4 months for moderate to large scope changes.

WEIS Market

Footprint Changes – Includes moving

Footprint SA to 1st Tier and

moving 1st Tier BA to Footprint.

6 Months Implement in applicable scheduled seasonal/periodic update.

System Update Type

Update Duration

Comments

Asset Owner

Company

4 months / 6 Months

4 Months for limited scope changes. 6 Months for Moderate to large scope changes. This change will also impact commercial reliability and other models. (Include in

applicable periodic Update)

Units 45 Days / 4 months


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Loads 45 Days / 4 months



Other EquipmentND, LD, LN, CAP, XFMR, ZBR, DCLN, CB, DSC, LS

45 Days / 4 months



All Changes

45 Days / 4 months

4 Months for limited scope changes. 6 Months for Moderate to large scope changes. This change will also impact commercial reliability and other models. (Include in applicable periodic Update) (Same as note above.)

System Update Type

Update Duration

Comments

Asset Owner

Company

45 Days / 4 months

45 Days for limited scope changes. 4 Months for Moderate to large scope changes. (Include in periodic Update)






45 Days / 4 months


All Other Changes

45 Days / 4 months


System Update Type

Update Duration

Comments

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Asset Owner

Company

45 Days / 4 months







45 Days / 4 months


EMS Company

45 Days / 4 months





45 Days / 4 months


Beyond 1st Tier

45 Days / 4 months


Add or Remove EMS Contingency

System Update Type

Update Duration

Comments

Both inside and

outside of WEIS

Market Footprint

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.)

System Update

Update Comments

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Type Duration

Temporary On the fly Implement this type change as needed.

Coordinated

45 Days Implement in applicable periodic update.

System Update Type

Update Duration

Comments

In WEIS Market

Footprint

1 Week / 6 Months

1 Week for basic ICCP/SCADA Ref. additions. 6 Months for Generation and load related changes

In Reliability

Area

1 Week / 6 Months


PNODE 1 Week / 6 Months


EMS Equipment or Station

Name

1 Week / 6 Months


ECC Bus or Machine ID

1 Week / 6 Months

1 Week for basic ICCP//SCADA Ref. additions. 6 Months for Generation and load related changes

System Update Type

Update Duration

Comments

(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.

System Update Type

Update Duration

Comments

In WEIS Market

Footprint

1 Week / 6 Months

1 Week for basic ICCP/SCADARef. additions.

6 Months for Generation and load related changes.

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In Reliability

Area

1 Week / 6 Months

1 Week for basic ICCP/SCADA Ref. additions.


PNODE 1 Week / 6 Months



EMS Equipment or Station

Name

1 Week / 6 Months



ECC Bus or Machine ID

1 Week / 6 Months



System Update Type

Update Duration

Comments

(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.

System Update Type

Update Duration

Comments

Plant 4 Months Implement in applicable periodic update.

Unit 4 Months Implement in applicable periodic update.

Other 4 Months Implement in applicable periodic update.

Plant 4 Months Implement in applicable periodic update.

Unit 4 Months Implement in applicable periodic update.

Other 4 Months Implement in applicable periodic update.

System Update Type

Update Duration

Comments

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ECC Bus Name or

Machine ID Change

45 Days Changes are incorporated during periodic Model Updates. Machine ID 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)

ECC Mapping Changes

45 Days Changes are incorporated during periodic Model Updates. Machine ID 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)

System Update Type

Update Duration

Comments

Add New Resources

1 Week Change to External RSS Table only. (This type change may need to be implemented prior to the next scheduled periodic

Model Update.)

Change Resource

Information

1 Week (Same as note above.)

Delete Resource

Information

1 Week (Same as note above.)

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Appendix C Settlement Metering Data Management ProtocolsC.1 ScopeThis document will serve as a definitive Resource concerning the expected responsibilities, duties, standards, processes, and liabilities with regard to the Market Participants for the Western Energy Imbalance Service settlement Meter Data.

C.2 PurposeThis document will provide the standards by which the Meter Agent, on behalf of the Market Participants, consistent with other sections of the WEIS Market Protocols and the WEIS Tariff will collect, calculate, document, and report settlement Meter Data for the Western Energy Imbalance Service.

C.3 DefinitionsThis appendix uses the terms as defined in Section 1.

C.4 Market ParticipantsThis document will define what is expected of the Market Participant with regards to their Meter Data Submittal Locations.

C.4.1 ResponsibilitiesThe Market Participant is responsible for the quality, accuracy and timeliness of Meter Data submitted to SPP for the purposes of, and use in, the execution of the Western Energy Imbalance Service settlements. At all times, SPP maintains a financial, legal and operational relationship with the Market Participant, and not the Meter Agent.

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C.4.2 Meter Agent(s) DesignationThe Market Participant must designate a Meter Agent for each of its Meter Data Submittal Locations (MDSLs). The Market Participant will be responsible for any and all data supplied by its designated Meter Agent. The Market Participant can have more than one Meter Agent, but only one designated Meter Agent per Meter Data Submittal Location.

SPP will at all times use the data provided by the Meter Agent until such time as the Market Participant revokes the designation of an entity as its Meter Agent and replaces that entity with a substitute entity.

Any dispute between the Meter Agent and the Market Participant concerning the accuracy of values reported to SPP shall be resolved between the two parties absent the involvement of SPP.

C.5 Meter AgentThe Meter Agent is expected to fulfill the Market Participant’s responsibility for submitting Meter Data Submittal Location data for which it is responsible and registered.

The Meter Agent will adhere to the standards for calculating and reporting settlement data as defined in this Appendix.

The Meter Agent will act on behalf of the Market Participant to provide settlement Meter Data to SPP, the Market Participant, and the entity responsible for Residual Load.

C.6 Data FormatThe settlement data must be submitted according to the following conventions.

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C.6.1 Unit of MeasureThe following rules apply to the submittal of Meter Data:

1) Settlement Meter Data must be submitted in 5-minute or hourly intervals for Resources, load and/or Settlement Area tie-lines as specified by the market registration;

2) 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; and

3) Settlement Meter Data can be submitted in fractional MWhs.

C.6.2 Sign Convention of DataMeter Data Submittal Locations:

Net Injection into the WEIS Market Footprint will be negative [-].

Net Withdraws out of the WEIS Market Footprint will be positive [+].

Meter Data Submittal Location between Settlement Areas:

Metered Settlement Area tie-line flows will be reported based on the Settlement Area perspective.

Into the Settlement Area will be reported as negative [-].

Out of the Settlement Area will be reported as positive [+].

C.6.3 Meter Technical StandardsAny data supplied to SPP from existing metering or other equipment must comply with the meter data technical standards specified under Appendix C. The metering used for data submission must meet all SPP interconnection guidelines.

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C.6.4 Data Submission StandardsSettlement Data must be communicated to SPP in electronic format in order to ensure timely settlement as defined in Section 4.5.7.

C.7 Settlement Meter Data TypesThere are three basic types of interval settlement data required for the Western Energy Imbalance Service.

Meter Data Submittal Locations:

1) Resources (generation)

2) Loads

3) Settlement Area tie-lines: (Metered tie-line flows between Settlement Areas, and between Settlement Areas including pseudo-ties)

Additional meter data types include:

1) Block Demand Response Resource

2) Demand Response Load

3) Dispatchable Demand Response Resource

4) Pseudo-Tie Generation In

5) Pseudo-Tie Load In

C.7.1 Resource MeteringResource data must be submitted in either 5-minute or hourly intervals as indicated by the market registration and must be consistent with the Resource’s registration as described in protocol Section 5.1.

If a Resource is registered with either the Gross option or the Net with Aux option selected, as described in protocol Section 5.1.8, then the Resource meter value will always be negative [-] indicating an injection.

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C.7.1.1 Generation Loss CompensationMeter Data for a Resource must be loss compensated, when the meter is not at the SPP Node. Please reference to Section C.9 of this Appendix for the complete loss compensation requirements.

C.7.2 Load MeteringC.7.2.1 GeneralMetering Equipment sufficient to meet the requirements set forth in Section C.7 of this Appendix, shall be installed for the settlement of Reported Load in accordance with the terms of the applicable Interconnection Agreement or Network Operating Agreement. Meter Data supplied to SPP should be consistent with the registered load as described in protocol Section 5.2.

Load data must be submitted in either 5-minute or hourly intervals according to the sign convention. All Loads should be reported as a positive [+] value to indicate a withdrawal at the SPP Node.

C.7.2.2 Load Loss AdjustmentMetering for a Load must be adjusted up to account for any distribution losses up to the point of interconnection and transmission losses within the WEIS Market Footprint.

C.7.2.3 Residual LoadResidual Load in a Settlement Area is the sum of the metered tie-line flows adjusted for pseudo-ties out of the Settlement Area, plus the sum of all Resource Meter Data Submittal Locations less all other load Meter Data Submittal Location as reported separately under Section C.7.2.2 for that Settlement Area. Residual Load is submitted by the Meter Agent representing the Market Participant responsible for Residual Load in the same manner as other Meter Data Submittal Locations for loads.

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C.7.3 Settlement Area Tie-LinesEach Meter Agent that is responsible for the calculation of total Settlement Area load shall report metered tie-line flows between each Settlement Area with which its Settlement Area is interconnected and pseudo-tie out interchange associated with each Settlement Area. This meter data must be submitted in either 5-minute intervals or hourly intervals, as specified by the market registration, according to the sign convention. Metered tie-line flows are reported based on the Settlement Area’s prospective. See Section C.6 Data Format for sign convention. The metered tie-line flows are needed for the calibration function of settlements (See protocol Section 4.5.6.1.1 for a description of the calibration calculation).

C.7.3.1 Substitution for Missing DataIn the event that a Meter Agent fails to submit Settlement Area tie-line flow data or pseudo-tie interchange data, SPP will initially use the value calculated by the State Estimator until the actual value is submitted prior to the S120 meter submittal window closing.C.8 Settlement Location AnatomyC.8.1 GeneralThese sections describe standards for providing meter data under the following conditions:

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1) The actual meter location can be on a distribution voltage system or transmission voltage system.

2) The physical meter is not at the defined Meter Location.

3) Aggregation of multiple Meter Settlement Locations for reporting a Meter Data Submittal Locations.

4) Each physical meter value will need to have applicable losses applied to the meter data to determine Meter Settlement Location. The applicable losses only include losses up to a single SPP Meter Settlement Location.

5) A Node will be at the point of interchange with the facilities under the Western Energy Imbalance Service.

6) A Meter Data Submittal Location includes one or more Meter Settlement Locations. A Settlement Location includes one or more Meter Data Submittal Locations which may be located in multiple Settlement Areas. A Settlement Area includes one or more Meter Data Submittal Location(s). Meter Data Submittal Location(s) meter data is a component of the settlement billing process.

Meter Data Submittal Location meter data reported is effectively at a Resource bus (including transmission losses).

C.8.2 Making of a Settlement LocationThe WRTBM is all settled at a Settlement Location granularity. A Settlement Location is made up of one or more Meter Data Submittal Locations. A Meter Data Submittal Location is made up of one or more Meter Settlement Locations. A Meter Settlement Location is made of only one Node. A Node is made up of only one meter. A Settlement Area is a collection of generation, interchange, and load Settlement Locations within a metered geographic area, as defined under Attachment AE to the WEIS Tariff, used in Settlements for balancing purposes. A Meter Settlement Location is simply a single meter compensated for losses, if applicable. Loss compensation methods are detailed in Section C.9 of this Appendix.

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C.8.2.1 Resource and Load Settlement Locations The following diagram illustrates the components of the Settlement Location for either a Resource or load. Each component is manipulated to achieve the next value. It is very important that each step of this methodology is completed in order in your calculations.

Meter A Meter B Meter n Actual Load or Resource meter interval data

Increase (load) or decrease (generation) for losses as needed to represent the point of interface with the SPP Transmission System and should coorespond to a pricing point (LMP)

SPP node SPP node SPP nodeSPP Transmission System Point of Interchange SPP Market pricing point (LMP)

Meter Settlement Location (MSL)

A


B


n

Meter Data Submittal Location (MDSL)

MSL represents the settlement value for a single meter in the SPP Market

The sum of one or many MSLs that will be reported for a single MDSL. If Truncate and Carry is required apply after aggregation and before submittal at the MDSL

Settlement Location (SL)Settlement Location is the point of entry for Market Settlement charge type calculations, based on whole or fractional MWhs. Aggregation of multiple MDSLs to a single SL occurs within SPP systems.

Meter Data Submittal Location (MDSL)

Note that generators may only be aggregated within a single substation voltage level

C.8.2.2 Overview of Settlement Area Load Settlement LocationsMultiple Meter Agents may use a single Meter as part of their calculations of a Meter Data Submittal Location. This requires coordination and method agreement

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between all Metering Parties and Market Participants involved with the shared Meter. The following diagram illustrates all Load Settlement Locations within a Settlement Area. Load D is the Residual Load.

Table 1 – Load Inclusion and Coordination

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3

2

41

A

C

D

E

F

B

Load C MDSL

Load BMDSL

Load AMDSL

Settlement Area ZLoad D MDSL (Residual)


Load Actual # of Meters

Meters included in Settlement Location

Coordination on Methods used with all entities for Load x for meter x

A 4 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

Residual

Load

8 A, B, E, F,

1, 2, 3, 4

Load A Meter A and B

Load B Meter F

Load C Meter E

Others (Tie-lines) Meters 1, 2, 3, 4

Others: defined as another Load Settlement Location and seam with another Balancing Authority or other Settlement Areas.

Settlement Area Boundary would be equal to the sum of meters 1, 2, 3, and 4.

Load D (Residual) accounts for any unaccounted for energy within the Settlement Area Z.

C.9 Loss CompensationC.9.1 GeneralThe Meter Agent will submit Meter Data Submittal Location data for Resources and Loads with the applicable loss compensations for the Meter Settlement Location.

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Load Meter Settlement Locations may have line losses, transformer step-downs, shared metering, etc. Resource Meter Settlement Locations may have transformer losses, auxiliary Loads, shared metering between units, commercial Load off generation bus, etc. These sections cannot cover all possible situations; therefore, common electric utility business practices with the Metering Parties will apply. The Market Participants along with their Meter Agent will be responsible for appropriate meter data adjustments and submissions.

C.9.2 Node Loss Compensation ExamplesThere are several elements that can require loss compensation prior to the Meter Settlement Location. A couple of examples of this are: 1) Meter is located on the distribution system and needs to be adjusted to the Node and 2) Meter is located on the transmission system not at the Node and needs to be adjusted to the Node.

Formula for calculation of Meter Settlement Location will be taking known actual meter value divided by (1- Loss %). This formula will be used for all calculations of the Meter Settlement Location. Actual meter value divided by (1-Loss %).

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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 between the meter and the Generation Node Point.1) Transformer No-Load Loss2) Transformer Full Load Losses;

3) Distribution Losses;

4) Transmission losses before WEIS Market Footprint Losses

Calculating Aggregation of Meter Settlement Locations to report Meter Data Submittal Location:

1) A Meter Agent can combine two or more Meter Settlement Locations for Loads within a Settlement Area to report the registered Meter Data Submittal Location.

2) A Meter Agent may combine two or more Meter Settlement Locations to report a Resource Meter Data Submittal Location as long as all the combined Meter Settlement Locations are electrically equivalent.

C.9.2.1 Loss Compensation to Node when Meter is on Distribution SystemLoss Compensation to Node – Example 1 Assumptions:

1) Meter is on distribution system @ 12 kV

2) Transformer between distribution and transmission system requires compensation for a transmission voltage at SPP Node.

3) Actual meter reads 20000 kWh.

4) Transformer loss is 5%.

5) Transmission owner has modeled their network with transmission voltage at 69kV.

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Calculating from Meter to Node:

1) Actual meter reads 20000 kWh divided by (1- 5%). 20000/(1–0.05) or 20000/0.9500

2) SPP Node Value = 21052.631 kWh

3) All resolution below kWh of 21052 is dropped

4) This rule can be applied when distribution line losses are required along with transformer losses.

5) The Market Participant can apply the compensation process separately for each loss percentage or sum percentages together and then apply the process for the sum of losses to calculate the Node value.

Calculating Aggregation of Meter Settlement Locations to report Meter Data Submittal Location



C.9.2.2 Methods for CompensationThere are three methods for compensation:

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.

2) Engineered Adjustment with Assumptions – This type of adjustment is made on the meter quantities received by the external system.

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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.

Transmission and secondary line losses are referenced in Section C.9.2.5.

C.9.2.3 Loss Compensation to Node when Meter at Different Location

C.9.2.4 Loss Compensation to Node – Example 2 Assumptions1) Meter is on transmission system @ 69kV2) The Node is not at the same location as the meter. (i.e. losses on line between

meter and Node will be applied to provide the correct value at the Node) 3) Actual meter reads 20000 kWh.4) Line losses between meter and SPP Node is 2%5) This 69kV line starting at the Node is under the WEIS Tariff.Calculating from the Meter to the SPP Node value:

1) Actual meter reads 20000 kWh divided by (1- 2%)

2) 20000 / (1 – 0.02) or 20000 / 0.9800

3) SPP Node value = 20408.163 kWh

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Line Losses of 2%

SPP Node

69kV*

LoadMete


4) All resolution below kWh of 20408 is dropped

Calculating Aggregation of Meter Settlement Locations to report Meter Data Submittal Location



C.9.2.5 Transmission and Secondary Line LossesTransmission and secondary line losses are the result of series resistance, inductance, and shunt capacitance. The following items are required to calculate these values.

Transmission Line Loss Components

Units

Series resistance (rTL) Ohms / mile

The effective series reactance(xTL)

Ohms / mile

The length of the line (LTL) mile

Secondary Line Loss Components

Units

Series resistance (rSL) Ohms / mile

The effective series reactance(xSL)

Ohms / mile

The length of the line (LSL) mile

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C.9.3 Meter Data Exchange and SubmissionSettlement Location meter data shall be entered, modified and retrieved solely via the XML specification for submission of interval Settlement Data.

The Settlement Location meter data will be available via the Portal and include the files uploaded from the Meter Agent. There will also be the capability of reviewing any rejected values with the specific errors associated with the attempt to process the rejected values. Values successfully processed shall also be available via the Portal for that Market Participant.

Other parties may have access to Settlement Location data, as allowed by SPP.

C.9.3.1 Alternate Settlement Meter DataUnder circumstances where one or more Meter Agents fails to submit Settlement Location meter data in accordance with the timelines set forth for Settlement Statements, SPP will substitute missing Settlement Location meter data with the State Estimator data for that Settlement Location until Settlement Location meter data is provided. SPP will notify all MPs and Meter Agents when a Meter Agent fails to submit Settlement Location meter data. Refer to WEIS Market Protocols Section 4.5.6.1.1 for treatment of substitution data for calibration purposes.

C.10 Verification Meter SL ValuesVerification of Meter Data used as a component of Settlement Location value calculations shall be performed. Verification of Meter Data would be performed by the party responsible for the operations of that meter. The Market Participant is responsible for the data verification process for all meters that are used in calculation of Settlement Location values. Methods of verification should be based on the type of data and communication technology used.

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C.11 Real-Time Data Reporting to SPPIn addition to the data reporting requirements specified under the SPP Criteria, all Resources, other than Demand Response Resources, are to submit the following data via ICCP to SPP.

1) Unit power output (MW);

2) Unit MVar output;

3) Current on/off line status;

Current AGC status (on/off).

C.12 Record RetentionThe Market Participant must maintain the following additional documentation of the meter process and values in order to verify the integrity and accuracy of the reported data.

1) Raw Meter values;

2) Meter Settlement Location values;

3) Settlement Location values.

The records must be retained for a period of six (6) years.

Appendix D Mitigated Offer Development GuidelinesD.1 IntroductionD.1.1 About these GuidelinesThe Mitigated Offer Development Guidelines manual comprises Appendix D of SPP’s WEIS Market Protocols. This manual is maintained by the appropriate WEIS stakeholder group with the advice of the Market Monitoring Unit.

To use this manual, read sections one and two then go to the section for a particular Resource type for possible additional information.

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All capitalized terms shall have the same meaning as they are defined in the WEIS Market Protocols and/or the WEIS Tariff.

In the event of a conflict between the WEIS Tariff and Appendix G, the most recent approved version of the WEIS Tariff will govern.

D.1.2 Intended Audience Market Participants

SPP Staff

Market Monitoring Unit

Regulators

D.1.3 What is in this ManualSections containing the specific guidelines, requirements, or procedures including SPP actions and Market Participants actions.

D.1.4 PurposeAs described in Section 7.2 of the WEIS Market Protocols, each Market Participant shall submit mitigated offer parameters along with each market offer. The mitigated offers reflect the cost of providing the offered product or service. SPP will use the mitigated offers as the cost based offer used in the Native Load Hedging described in section 4.5.6.1.4, screen for market offers that adversely impact the market, and as replacement offers in the case that those offers are mitigated. The purpose of this Manual is to define the mitigated offers to ensure that each Market Participant's mitigated offer is developed to represent the short-run marginal cost of production, ensuring that the Market Participants who own or control Resources with market power cannot exercise it.

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D.1.5 Mitigated Offer Methodology Approval ProcessFor all new Resources, Market Participants shall submit the initial cost data and supporting documentation thirty days prior to submitting their first offer to the market, and the SPP MMU shall respond within fifteen Calendar Days.

The SPP MMU shall maintain on its website a mechanism that allows Market Participants to conveniently and confidentially submit and update such data as required or as needed. The website shall also contain instructions and examples of required documentation.

A Market Participant who seeks to obtain an exemption, exception or change to any time frame, process, methodology, calculation or policy set forth in these guidelines, or the approval of any mitigated offer that is not specifically permitted by these guidelines, shall submit a request to the SPP MMU for consideration and determination, except as otherwise specified herein.

The SPP MMU shall approve or disapprove such a request based on the following criteria:

The cost components included in all mitigated offers should reflect the short-run marginal cost of generation;

The formulas used to calculate mitigated offers and the components of cost included in mitigated offers do not deviate from those specified in the WEIS Tariff; and

The documentation and data validation provided by the Market Participant are sufficient for the SPP MMU to verify mitigated offers on an ongoing basis.

After receipt of such a request, the SPP MMU shall notify the Market Participant of its decision regarding the request no later than fifteen (15) Calendar Days after the submission of the request. If the Market Participant agrees with the SPP MMU’s decision, the request shall be deemed to be approved. In the event that the Market Participant disagrees with the SPP MMU’s decision and submits a dispute following the procedures described in Section 7 of the WEIS Tariff, the previously approved

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time frame, process, methodology, calculation or policy shall remain in place until the resolution of the dispute.

D.2 Policies for all Resource TypesThis section contains information that is relevant for the development of a mitigated offer for all types of Resources.

D.2.1 Heat RateHeat Rate equals the mmBtu content of the heat input divided by the MWh of power output. The smaller the heat rate value the greater the efficiency. The heat rate can also be referred to as the input-output function. The term “mmBtu” is defined as millions of British Thermal Units. The following equation defines average heat rate over an amount of energy production or at a given net power output:

Total Heat Rate=mmBtuMWh

=Heat InputNet MW

Incremental heat rate is the relationship between an additional MW of output and the additional heat input necessary to produce it. Graphically, the incremental heat rate can be determined from the ratio of the change in fuel input to the change in Resource MW output; which is the slope of the input/output curve. An input/output curve shows the net MW output on the “x” axis and the heat input on the “y” axis. Mathematically, the incremental heat rate curve can be expressed as the first derivative of the input/output curve (input heat versus MW output).

IncrementalHeat Rate=∆mmBtu∆MWh

=Change∈Heat Going∈ ¿Change∈EnergyComingOut

=∂ y∂ x

Total Heat Rate ¿

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D.2.1.1 Heat Content of Fuel

Heat Content of Fuel is the energy content of a given fuel, expressed in mmBtu per unit of fuel. Heat content of fuel may be based on one of the following:

As burned test

In stock test

As received test

As shipped test

Contract value

Seller's invoice

Seller's quote

Nominal value based on Industry Standard

D.2.1.2 Heat Rate Curve

All Market Participants shall develop heat rate curves for thermal units, which they must submit to the SPP MMU pursuant to the Mitigated Offer Methodology Approval Process (Section D.1.5).

These curves show input heat from burning fuel for each level of MW output for each of their Resources. The curves serve as the basis for the theoretical incremental heat rate curves for fuel consumption and performance factor development.

Heat rate curves submitted to SPP should be calculated on a net MW basis.

Heat rate curves (one curve per fuel type of operating mode, such as combustion turbine or Combined Cycles) will be based on design and/or comparable Resource data modified by actual Resource test data (when available), and/or actual Resource operations data.

Data for the heat rate curve development should include normal minimum and normal maximum MW points. The heat rate curve for emergency ranges may be extrapolated from available data by the Market Participant.

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This heat rate curve (or curves) will be used as the basis for incremental heat rate curves, incremental costs, and performance factor calculations.

Heat rate and heat input data used in Offer Curve and no-load cost development should be submitted to the Market Monitor using the confidential web portal.

D.2.2 Performance FactorsPerformance Factor is the calculated ratio of actual fuel burn to either theoretical fuel use (design heat input) or the most recent heat rate performance test. Actual burn may vary from theoretical or test fuel use due to factors such as Resource age or modification, changes in fuel properties, seasonal ambient conditions, etc.

Performance Factor= Total Actual FuelConsumed (mmBtu)Total Theoretical Fuel Consumed (mmBtu)

The performance factor shall be calculated on either the total fuel consumed over a specific calibration period or a monthly spot check test basis. Market Participants are required to update their Resources’ Performance Factors(s) annually; however, Market Participants may update these performance factors more frequently to reflect seasonal variations and/or other operational changes.

Those Market Participants lacking the “Total Theoretical Fuel Consumed” value may designate a performance factor of 1; these Market Participants must notify the SPP MMU prior to the start of the WEIS Market. These Market Participants shall use fuel consumed during the first time that Resource(s) is committed for operation as the “Total Theoretical Fuel Consumed” value and report such value to SPP MMU. These Market Participants will also submit the fuel consumption data from a subsequent window of operation to update its Performance Factor.

Requests for exemptions from the annual update should first be submitted to the SPP MMU for evaluation pursuant to the Mitigated Offer Methodology Approval

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Process. The overall performance factor can be modified by a seasonal performance factor to reflect ambient conditions or equipment conditions.

D.2.2.1 Engineering Judgment in Performance Factors

The calculated performance factor may be superseded by estimates based on sound engineering judgment. If the period during which estimated performance factors are used exceeds three months, documentation concerning reasons for the override must be maintained and available for review upon request.

D.2.2.2 Current Methods of Performance Factors

There are three options available for use in determining a Resource’s performance factor:

1) Total Fuel approach

2) Separate performance factors

3) Fixed start approach

Performance factors are used in calculating start fuel as well as operating fuel.

When the total fuel approach is used, the performance factor represents the ratio:

Performance Factor= Total Actual FuelConsumed (mmBtu)Total TheoreticalFuel Consumed (mmBtu)

With the total fuel approach, fuel quantities measured during start tests should be modified by the performance factor in effect at the time of the test so that theoretical or standard start fuel quantities will be on the same basis as the standard operating fuel quantity.

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Conditions encountered during the start of certain Resources may make it preferable to assign separate performance factors for start and operating fuel (no-load fuel and fuel used for any energy production).

If separate performance factors are calculated for start fuel prior to calculating the “operating fuel” performance factor, the operating fuel performance factor represents the ratio:

OperatingFuel Performance Factor

¿Total Actual FuelConsumed (mmBtu)−Actual Start FuelConsumed (mmBtu)

TotalTheoretical FuelConsumed (mmBtu)−Theoretical Start FuelConsumed (mmBtu)

Due to the variability and difficulty in measuring actual start fuel, a Market Participant may choose to set a fixed start performance factor of one, implicitly assigning all performance variations to no-load and incremental loading costs. In order to account for all fuel actually consumed, the operating fuel performance factor represents the ratio:

OperatingFuel Performance Factor

¿Total Acutal FuelConsumed (mmBtu)−Theoretical Start Fuel Consumed (mmBtu)

TotalTheoretical FuelConsumed (mmBtu)−Theoretical Start FuelConsumed (mmBtu)

where Total Theoretical Start Fuel Consumed is the fuel quantity used in the start cost calculation.

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D.2.2.3 “Like” Resources for Performance Factors

An average performance factor may be calculated and applied for groups of like Resources burning the same type of fuel. Please see the Resource Type sections for further detail of “like” Resources.

D.2.3 Fuel Cost Policies

Market Participants must submit a fuel cost policy for each Resource describing its method of calculation of fuel costs to the SPP MMU pursuant to the Mitigated Offer Methodology Approval Process. Such fuel cost policies shall include the following information:

1) For the component of cost indicating daily delivered fuel cost, please include, for each fuel type:

Resources using this fuel

Source of fuel cost, for each Resource. For example; specified NYMEX index, forward contract.

Source of fuel basis cost (e.g. Henry Hub)

Methodology for converting fuel basis cost to $/mmBtu.

Average BTU content of fuel (as fuel prices must be converted to $/mmBtu), if source does not describe a fixed BTU content.

Any additional information regarding pricing fuel cost including;

i) Fuel cost uncertainty

ii) When prices are revised

iii) All additional charges

2) Please include, for each fuel, any additional costs related to fuel or fuel handling. Such costs may include railroad delivery, pipeline charges, etc.

3) For SO2 / NOx / CO2 Emission Allowance Costs, please include:

Units with emission allowance costs

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How emission data is collected

How emission allowance is calculated in $/mmBtu

Source of emission costs

When costs are updated

D.2.3.1 Modifications to Fuel Cost Policies

A request to change the method of calculation of fuel cost shall be submitted to the SPP MMU for evaluation pursuant to the Mitigated Offer Methodology Approval Process in advance of the proposed change (this is referred to below as “the proposal”).

The Market Participant and the SPP MMU shall discuss the proposal and the Market Participant will provide documentation supporting its request to the SPP MMU. The SPP MMU shall provide an initial response to the Market Participant in writing within 15 days of the Market Participant’s submission of the request to the SPP MMU, indicating its agreement with the request or areas of concern pursuant to the Mitigated Offer Methodology Approval Process. The changed method of calculation may be implemented immediately upon final approval pursuant to the Mitigated Offer Methodology Approval Process.

D.2.3.2 Fuel Cost Calculation

The method of calculation of fuel cost may include the use of actual fuel prices paid, e.g., the contract price paid for fuel, or the spot price for fuel. The fuel cost may also include a fuel cost uncertainty amount based on historical variance between actual fuel cost and estimated fuel cost at the time the offers were submitted. The contract price for fuel must include the locational cost of fuel for the generating Resource. The source used for spot price for fuel must be publicly available and reflect the locational cost of fuel for the generating Resource. The locational cost of fuel shall include specification of any additional incremental costs of delivery for the generating Resource.

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Each Market Participant will be responsible for establishing its own method of calculating delivered fossil fuel cost, limited to inventoried cost, replacement cost or a combination there of, that reflects the way fuel is purchased or scheduled for purchase.

The Market Participant shall submit any changes to the method of calculation to the SPP MMU with supporting documentation. The SPP MMU shall review the changes. If SPP MMU has concern over any such proposed changes, it will hold discussions with the Market Participant to address concerns. The method of calculation may only be changed by receipt of final approval pursuant to the Mitigated Offer Methodology Approval Process in advance of the proposed change.

Fossil fuel cost adjustments compensating for previous estimate inaccuracies should not be considered when determining the basic fuel cost component of Total Fuel Related Cost described under Section D.2.3.3.

Each Market Participant must review and document their historical fuel costs at least once per month (12 times per year). Additionally, each review must occur within sixty-five (65) days of the end of the reporting month. The results of this review will be used to determine whether a fuel cost update is necessary. The documentation of fuel costs must be filed via the Market Monitoring Unit website.

D.2.3.3 Total Fuel Related Costs

Total Fuel Related Cost (“TFRC”) is the sum of basic fuel cost, other fuel related cost, emission allowance cost, and variable operation and maintenance (VOM) cost.

Total Fuel RelatedCosts ($ /mmBtu)=¿

basic fuel costs($ /mmBtu)+other fuel related costs($ /mmBtu)+SO2 Allowance cost ($/mmBtu)+CO2 Allowance cost ($ /mmBtu)+NOX Allowance cost ($ /mmBtu)+TFRCVOM ($ /mmBtu)

Total Fuel Related Costs may vary between different fuel types to the extent that the differences can be quantified and demonstrated.

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D.2.3.4 Types of Fuel Costs

Basic fuel cost is the commodity cost of fuel calculated as stated in the company’s fuel cost policy.

NOTE: Basic Fuel Cost for each Resource type will be addressed in subsequent sections.

Other fuel related cost includes the additional incremental components of fuel cost required to operate a generating Resource, such as transportation fees, taxes on fuel and water injection.

D.2.3.5 Variable Fuel Transportation Equipment

When calculating the Total Fuel Related Costs, fixed charges for transportation equipment (e.g. pipelines, train cars, and barges) should be excluded. Dollars that represent lease charges are considered fixed charges if the total amount to be paid over a period is fixed regardless of the amount of fuel transported. Should the terms of the lease or transportation agreement be such that there is a fixed charge plus a charge for the amount of fuel delivered, the “charge per unit of fuel delivered” should be included in the Fuel on Board (FOB) delivered cost or in the calculation of the “other fuel related costs” as per the documented fuel pricing policy.

The above guideline applies when a Resource, plant, or system is served totally by leased fuel transportation equipment or fuel transportation contracts. When fuel is supplied by both leased and common carrier fuel transportation systems, the common carrier rate should be included in the FOB delivered cost or included in the calculation of the “other fuel related costs” as per the documented fuel pricing policy of each Market Participant.

The other fuel-related cost components of TFRC may be calculated based on an average of short-run variable costs for each such component for a period of one year or less, reviewed and updated annually, or based on a rolling twelve month average, reviewed and updated monthly. These costs typically include delivery

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fees, railroad charges, pipeline fees denominated in $/MMBTU or %, and costs incurred in fuel storage that vary based on the amount of fuel stored. Both the term and the frequency of the other fuel-related costs calculation shall be included in the Market Participant’s fuel cost policy.

Demurrage and other avoided variable costs may occasionally result in a reduction in the Total Related Costs.

D.2.3.6 Emission Allowances

Market Participants with Resources that require SO2, CO2, NOX, or other types of emission allowances (EAs) , as dictated by regulatory bodies, to operate may include in the Resource’s TFRC the cost ($/mmBtu) of the EAs as determined in the Market Participant’s allowance cost policy.

If a Market Participant includes Emission Allowances as components of TFRC, the Market Participant must submit with their cost policy its method of determining the cost of SO2, CO2, NOX, or other type of EA for evaluation pursuant to the Mitigated Offer Methodology Approval Process. An example of the calculation method must be included in the policy. Any changes to the method of calculation may be changed only after approval pursuant to the Mitigated Offer Methodology Approval Process.

The period used for determining the projected SO2, CO2, NOX, or other type of emission discharge and the MMBTUs burned must be included in the Market Participant’s allowance cost policy and may be based on historical or projected data.

For Resources that have dual fuel firing capability, a Market Participant should use different EA factors based on the SO2, CO2, NOX, or other type of emission emitted for each particular fuel or fuel mix.

Emissions costs will be included in TFRC only during the emission compliance period and only by Resources subject to compliance requirements. Details of the cost calculation methodology and example calculations will be contained in each Market

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Participant’s allowance cost policy. Compliance requirements and dates may vary by geographic region. Those Market Participants not incorporating emissions costs in their TFRC will be exempt from the requirements of this Section D.2.3.6.

D.2.3.7 Total Fuel Related Cost Variable Operations and Maintenance

The TFRC VOM is calculated using an allocated portion of the total VOM calculated under Section D.2.4. Note that the sum of total allocated $ used to calculate TFRC VOM included here and the allocated VOM $ used to calculate Energy Offer Curve VOM under Section D.2.5 must not exceed the total VOM $ calculated under Section D.2.4.

D.2.4 Total Variable Operation and Maintenance CostsTotal Variable Operation and Maintenance (VOM) costs are the parts and labor expenses of maintaining equipment and facilities in satisfactory operating condition. A Resource should reflect its short-run incremental VOM costs by using the most current data available. This could include the previous maintenance cycle period cost or actual short-run incremental cost where available.

TotalVOM❑ ($ ) =

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The SPP MMU will review the development of the total maintenance costs for all Resources pursuant to the Mitigated Offer Methodology Approval Process.

The total VOM cost as calculated above is based on available maintenance expense history for the defined Maintenance Period (See Section D.2.4.2) regardless of Market Participant. Only expenses incurred as a result of short-run incremental electric production (short-run marginal costs) qualify for inclusion. Major maintenance costs are excluded from VOM.

D.2.4.1 Escalation Index

The Bureau of Labor Statistics Producer Price Index Series ID PCU3331203331208, Construction Machinery Manufacturing, Other Construction Machinery and Equipment shall be used for the Escalation Index as shown below.

Appendix D Section D.2.4.1 will be updated by SPP as necessary.

Bureau of Labor Statistics Producer Price Index

2008: Index 124.8 - Escalation Factor 1.247










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D.2.4.2 Maintenance Period

The period of years between major overhauls or such other period as used in the calculation of total VOM under Section D.2.4, not to exceed 10 years.

If a Resource experiences a significant configuration change, the Resource may submit to the SPP MMU its changed VOM cost methodology.

Examples of a significant Resource configuration change may include but are not limited to:

Flue Gas Desulfurization (FGD or scrubber)

Activated Carbon Injection (ACI)

Selective Catalytic NOX Reduction (SCR)

Selective Non-Catalytic NOX Reduction (SNCR)

Low-NOX burners

Bag House addition

Long-term Fuel change (greater than 10 years)

Water injection for NOX control

Gas Turbine Inlet Air Cooling

Dry Sorbent Injection (DSI)

D.2.4.3 Average VOM Cost

Average VOM Cost is the average VOM cost $/mmBtu, $/MWh or $/hour. This is defined as allocated VOM cost in the historical Maintenance Period divided by total MWhs, total fuel or total on-line hours associated with the historical Maintenance Period, depending on VOM cost type.

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EnergyOfferCurve (EOC)VOMCost ($ /MWh )

¿ Allocated EOC portionof TotalVOM Dollars¿ Section2.4 ¿Total Mwhs∈Maintenance Period

TFRC VOMCost ($ /mmBtu )

¿ AllocatedTFRC portionof Total VOM Dollars ¿Section2.4 ¿Total Fuel (mmBtu )∈Maintenance Period

The VOM costs should be reviewed and updated at least once every twelve months or once in the maintenance cycle, whichever is shorter.

If a Market Participant feels that a Resource modification or required change in operating procedures will affect the Resource's VOM costs, the revised VOM costs must be submitted to the SPP MMU for review and approval pursuant to the Mitigated Offer Methodology Approval Process.

D.2.5 Mitigated Energy Offer CurveThe Mitigated Energy Offer Curve is a set of up to ten price/quantity pairs (measured in $/MWh and MW) describing the short-run marginal cost of providing energy based on the heat rate curve, fuel cost, and variable operations and maintenance costs. For thermal Resources,

Mitigated EnergyOffer ($ /MWh ) =

HeatRate (mmBtu/MWh )∗Performance Factor∗Total Fuel RelatedCosts ($ /mmBtu )+EOC VOM ($/MWh )

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For renewable Resources:

Mitigated Energy Offer ($/MWh) = -Foregone credits ($/MWh) + EOC VOM ($/MWh) + Opportunity costs ($/MWh) where EOC VOM is defined in Section D.2.4.3, the heat rate is as defined in Section D.2.1, the performance factor is as defined in Section D.2.2, and the Total Fuel Related Cost is as defined in Section D.2.3. The EOC VOM is calculated using an allocated portion of the total VOM calculated under Section D.2.4.

Note that the sum of total allocated $ used to calculate EOC VOM included here and the allocated VOM $ used to calculate TFRC VOM under Section D.2.3, must not exceed the total VOM $ calculated under Section D.2.4.

Additional detail on calculating the Mitigated Energy Offer is given in individual unit types.

Resources with run hour limitations may have Opportunity Costs as described in Section D.11.

D.3 Nuclear Unit GuidelinesThis section presents information relevant for mitigated offer development for nuclear units.

Nuclear Plant – A facility that is licensed to produce commercial power from controlled nuclear reactions to heat water to produce steam that drives steam turbines Resources.

D.3.1 Nuclear Heat Rate Note: The information in Section D.2.1 contains basic Heat Rate information relevant for all unit types including nuclear units.

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D.3.2 Performance Factor Note: The information in Section D.2.2 contains basic Performance Factor information relevant for all unit types including nuclear units.

D.3.3 Fuel Cost Note: The information in Section D.2.3 contains basic Fuel Cost information relevant for all unit types. The following information only pertains to nuclear units.

D.3.3.1 Basic Nuclear Fuel Cost

Basic Nuclear Fuel Cost - Basic nuclear fuel cost shall be based on the dollars in FERC Account 518, less in-service interest charges (whether related to fuel that is leased or capitalized). This quantity shall be calculated in units of dollars per mmBtu, as forecast for the applicable fuel cycle.

Basic Nuclear FuelCost ($ /mmBtu )=¿

Dollars∈FERC Account 518($/mmBtu)−Interest Cost ($ /mmBtu)

D.3.3.2 Total Fuel Related Costs for Nuclear Units

Total Fuel RelatedCosts for Nuclear Units($ /mmBtu)=¿

Basic Nuclear FuelCost ( $mmBtu )+TFRC VOMCost ($ /mmBtu)

D.3.4 VOM CostVOM Cost

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Note: The information in Section D.2.4 contains basic VOM Cost information relevant for all unit types including nuclear units.

Nuclear VOM Cost - The historical dollars per unit of fuel (or heat) as derived from FERC Accounts 530 and 531 for nuclear steam units.

D.3.4.1 Configuration Addition VOM Cost

For units undergoing a significant system or unit Configuration Addition the use of an additional “Configuration Addition VOM Cost” may be included in the determination of the total VOM cost. It is not intended to be used for upgrades to existing equipment.

Examples of significant system or unit Configuration Additions may include but are not limited to:

Conversion from open loop to closed loop circulation water systems

The specific system or unit configuration system change must be reviewed by the MMU for evaluation pursuant to the Mitigated Offer Methodology Approval Process prior to approving the use of a Configuration Addition VOM cost.

D.3.4.2 Calculation of the Configuration Addition VOM Cost:

The Configuration Addition VOM Cost (“CAVC”) is to be calculated in the same manner as the VOM cost described in this section with the exception that the Configuration Addition VOM cost are only the incremental additional costs incurred because of the system or unit configuration change.

As with the current VOM cost calculation, the cost for year (Y) uses the actual costs beginning with year (Y-1). Therefore, the first year of actual incremental additional expenses will be captured by the CAVC in the second year.

Following the initial year of use of the CAVC, each additional year’s Configuration Addition VOM cost will be incorporated into the Configuration Addition VOM Cost until the end of the historical maintenance cost period selected for the unit.

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To calculate the Configuration Addition VOM Cost, calculate the solely incremental VOM Cost for the Configuration Change. Please note these expenses are purely incremental.

D.3.4.3 Reductions in Total VOM Costs

While it is expected that the Configuration Addition VOM Cost will most often be used to cover step increases in VOM costs, it is also to be used to capture step decreases in VOM costs resulting from a significant system or unit configuration change that results in a significant reduction in VOM costs. Any equipment that falls into disuse or is retired because of the configuration change must have its VOM expenses removed from the historical record used to develop the VOM cost. An example of a significant system or unit configuration change that may result in a step decrease in qualified VOM costs includes, but is not limited to, conversion from open loop to closed loop circulation water systems.

D.4 Fossil Steam Unit GuidelinesThis section contains information pertaining to Fossil Steam Unit mitigated offer development.Fossil Steam Turbine plants use combusted fossil fuels to heat water and create steam that generates the dynamic pressure to turn the blades of a steam turbine Resource.

D.4.1 Heat RateNote: The information in Section D.2.1 contains basic Heat Rate information relevant for all unit types including fossil steam units.

D.4.2 Performance FactorNote: The information in Section D.2.2 contains basic Performance Factor information relevant for all unit types. The following information only pertains to fossil steam units.

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D.4.3 Fuel CostsNote: The information in Section D.2.3 contains basic Fuel information relevant for all unit types. The following information only pertains to fossil steam units.

Fossil fuel cost adjustments compensating for previous estimate inaccuracies should not be considered when determining the basic fossil cost component of Total Fuel Related Cost .

Fossil Other Fuel-Related Costs - the dollars in FERC Account 501 Fuel plus incremental expenses for fuel treatment and pollution control (excluding SO2 and NOX emission allowance costs) that were not included in Account 501; minus the fuel expenses from FERC Account 151 that were charged into Account 501, all divided by the fuel (heat content or quantity) shifted from Account 151 into Account 501.

D.4.4 VOM CostNote: The information in Section D.2.4 contains basic VOM Cost information relevant for all unit types. The following information only pertains to fossil steam units.

Fossil Steam - VOM Cost - is the historical VOM cost as derived from FERC Accounts 512 and 513 for fossil steam units.

D.4.4.1 Configuration Addition VOM Cost

For units undergoing a significant system or unit Configuration Addition the use of an additional “Configuration Addition VOM Cost” may be included in the determination of the total VOM cost. It is not intended to be used for upgrades to existing equipment (i.e. : replacement of a standard burner with a low NOX burner).

Examples of significant system or unit Configuration Additions may include but are not limited to:

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Installation of Flue Gas Desulfurization (FGD or scrubber) systems

Activated Carbon Injection (ACI) or other sorbent injection systems

Installation of SCR or SNCR NOX removal systems

Conversion from open loop to closed loop circulation water systems

Bag House addition

Water injection for NOX control

Gas Turbine Inlet Air Cooling

Dry Sorbent Injection (DSI)

The specific system or unit configuration system change needs to be reviewed by the MMU pursuant to the Mitigated Offer Methodology Approval Process and receive final approval thereof prior to the use of a Configuration Addition VOM Cost.

D.4.4.2 Calculation of the Configuration Addition VOM Cost

The Configuration Addition VOM Cost (CAVC) is to be calculated in the same manner as the VOM cost described in this section with the exception that the CAVC dollars are only the incremental additional costs incurred because of the system or unit configuration change.

As with the current VOM cost calculation under Section D.2.4, the cost for year (Y) uses the actual costs beginning with year (Y-1). Therefore, the first year of actual incremental additional expenses will be captured by the CAVC in the second year.

Following the initial year of use of the CAVC, each additional year‘s CAVC will be incorporated into the total until the end of the historical Maintenance Period selected for the unit.

D.4.4.3 Reductions in Total VOM Costs

While it is expected that the CAVC will most often be used to cover step increases in VOM costs, it is also to be used to capture step decreases in VOM costs resulting from a significant system or unit configuration change that results in a significant reduction in VOM costs. Any equipment that falls into disuse or is retired because of

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the configuration change must have its VOM expenses removed from the historical record used to develop the VOM cost. An example of a significant system or unit configuration change that may result in a step decrease in qualified VOM costs includes, but is not limited to, a fuel change from coal to gas fuel.

D.5 Combined Cycle (CC) GuidelinesThis section contains information pertaining to Combined Cycle Cost development.

Combined Cycle - An electric generating technology in which electricity is generated by both a combustion turbine Resource (the Brayton Cycle) and a steam turbine Resource (the Rankine Cycle) hence the name Combined Cycle. The CT exhaust heat flows to a conventional boiler or to a heat recovery steam Resource (HRSG) to produce steam for use by a steam turbine Resource in the production of electricity.

Heat recovery steam Resource (HRSG) – A CT exhaust feeds hot gas into a heat to steam exchanger installed on combined-cycle power plants designed to utilize the heat in the combustion turbine exhaust to produce steam to drive a conventional steam turbine Resource. The HRSG may or may not also include a supplemental source of heat, e.g. duct firing.

D.5.1 Heat RateNote: The information in Section D.2.1 contains basic Heat Rate information relevant for all unit types including Combined Cycle Resources.

D.5.2 Performance FactorsNote: The information in Section D.2.2 contains basic Performance Factor information relevant for all unit types including Combined Cycle Resources.

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D.5.3 Fuel CostNote: The information in Section D.2.3 contains basic Fuel Cost information relevant for all unit types including Combined Cycle Resources.

D.5.4 VOM CostNote: The information in Section D.2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to Combined Cycle Resources.

Combined Cycle VOM Cost – the historical VOM dollars as derived from FERC Accounts 512, 513, and 553. If submitting as a simple cycle combustion turbine, use total dollars from FERC Account 553.

D.6 Combustion Turbine (CT) and Reciprocating Engine GuidelinesThis section details specific information for the mitigated offer development for units that are Combustion turbine or reciprocating engine Resources.

Combustion Turbine Resource – A generating unit in which a natural gas or oil fired combustion turbine engine is the prime mover for an electrical Resource.

Reciprocating Engine Resource – A generating unit in which a reciprocating engine is the prime mover for an electrical Resource.

D.6.1 Combustion Turbine and Reciprocating Engine Heat RateNote: The information in Section D.2.1 contains basic Heat Rate information relevant for all unit types, including CTs and Reciprocating Engines.

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D.6.2 Performance FactorsNote: The information in Section D.2.2 contains basic Performance Factor information relevant for all unit types. The following additional information only pertains to CT, diesel and reciprocating engine units.

D.6.3 Fuel CostNote: The information in Section D.2.3 contains basic Fuel Cost information relevant for all unit types including CTs, and reciprocating diesel engine units.

D.6.3.1 Combustion Turbine other Fuel-Related CostsThe dollars in FERC Account 547, plus incremental expenses for fuel treatment and pollution control excluding SO2 and NOX emission allowance costs that were not included in Account 547; minus the fuel expenses from FERC Account 151 that were charged into Account 547, all divided by the fuel (heat content or quantity) shifted from Account 151 into Account 547.

D.6.4 VOM CostsNote: The information in Section D.2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to CT and diesel engine units.

Combustion Turbine - VOM Cost – The historical total dollars from FERC Account 553 should be used to calculate the VOM $ specified under Section D.2.4.

D.7 Hydro GuidelinesThis section contains information for the development of Hydro or Hydro Pumped Storage cost offers.

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Hydro Unit – Generating unit in which the energy of flowing water drives the turbine Resource to produce electricity. This classification includes pumped and run-of-river hydro.Pumped Hydro Unit – Hydroelectric power generation that stores energy in the form of water by pumping from a lower elevation source to a higher elevation reservoir, then allowing the upper reservoir to drain turning the turbines to produce power.

D.7.1 Pumping Efficiency (Pumped Hydro Only)Pumping Efficiency is the Pumped Hydro Unit’s version of a heat rate. It measures the ratio of generation produced to the amount of generation used as fuel.

Pumping Efficiency (PE) is calculated by dividing the MWh of generation produced while operating in generation mode by the MWh required to pump the water needed to produce the generation MWh.

PumpingEfficiency= MWhGenerationProducedMWhGenerationPumped as Fuel

For example, it requires 1,000 ft3 to produce one MWh of generation as water flows from the pond to the sink and it requires two MWh of pumping load to pump 1,000 ft3 of water from the sink to the pond. The resultant efficiency is:

Pumping Efficiency= MWhGeneration ProducedMWhGenerationPumped as Fuel

=3.5 MWh(generated)

5 MWh( pumped )=0. 70

In order to account for environmental and physical factors associated with the characteristics of the pond and pumping operations that limit the accuracy of calculating short term pumping efficiency, a seven day rolling total of pumping and generation MWh are utilized for pumping efficiency calculations.

PE can be calculated by one of three methods as specified in the submitted Mitigated Offer Methodology.

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Option 1: Twelve month calendar actual Pumping Efficiency.

o The previous 12-month calendar year average Pumping Efficiency based on actual pumping operations.

Option 2: Three month rolling Pumping Efficiency.

o The previous three months rolling actual efficiency where the average monthly availability is 50% or greater. The calculation must be updated after each month.

Option 3: The previous month actual Pumping Efficiency.

The previous month actual efficiency where the availability is 50% or greater. The calculation must be updated monthly.

D.7.2 Performance FactorNote: The information in Section D.2.2 contains basic Performance Factor information relevant for all unit types. The following additional information only pertains to hydro units.

D.7.3 Fuel CostTo be consistent with other SPP units within this manual the term fuel cost is used to account for the energy necessary to pump from the lower reservoir to the upper reservoir.

Note: The information in Section D.2.3 contains basic Fuel Cost information relevant for all unit types. The following additional information only pertains to pumped hydro units.

If, a Market Participant wishes to change its method of calculation of pumped storage TFRC, the Market Participant shall notify the SPP MMU in writing, to be evaluated pursuant to the Mitigated Offer Methodology Approval Process. Pumped Storage Fuel Cost – Pumped storage fuel cost shall be calculated on a seven (7) day rolling basis, or other period as specified in the Mitigated Offer Development

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Methodology, by multiplying the Real-Time bus LMP at the plant node by the actual power consumed when pumping. The following equations govern pumping storage fuel cost:

PumpingPowerCost ($ /MWh ) =

∑ Real−Time LMP($ /MWh)∗PumpingPower (MWh)Total Pumping Power (MWh )∗PumpingEfficency

D.7.3.1 Total Energy Input Related Costs for Pumped Storage Hydro Plant GenerationTotal energy input-related costs for all pumped storage hydro units shall be defined as follows:

Pumped Storage HydroTotal Energy Input RelatedCost ($/MWh)

¿ PumpingPowerCost ($/MWh)+EOC VOMCost ($ /MWh )

D.7.4 VOM CostNote: The information in Section D.2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to hydro units.

The historical total dollars from the FERC accounts 543, 544 and the part of account 545 related to account 335.

D.8 Demand Response GuidelinesA Demand Response Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind-the-meter Resource that is dispatchable either on a 5-minute basis or an hourly basis;

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D.8.1 Demand Response (DDR) Cost for Behind-The-Meter GenerationMarket Participants using behind-the-meter Resource as a DDR Resource should refer to the appropriate unit type defined in this manual to develop incremental cost.

D.8.2 Dispatchable Demand Response Cost for Demand ReductionDemand Reduction is the actual reduction of load at the direction of SPP through the dispatch of an associated DRR. This could include the cycling of air conditioners or the shutdown of an industrial production process in order to reduce the load at a site. Incremental costs can include quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage.

D.9 Wind GuidelinesWind Units- Generating unit in which wind spins the turbine Resource to produce electricity.

Mitigated Energy Offer ($/MWh) = - Foregone credits ($/MWh) + EOC VOM ($/MWh)

D.9.1 Foregone CreditsWind Units may include as a negative value foregone federal and state production tax credits, grossed up for federal and state taxes. Additionally, wind Resources may include as a negative value the foregone renewable energy credits applicable costs that vary by MWh output. Foregone credits ($/MWh) = Federal PTC($/MWh)/(1-Fed tax rate) + State PTC($/MWh)/(1- State tax rate) + Renewable Energy Credits ($/MWh)State tax rates and credits vary by state and may need to be included in the gross-up. Renewable Energy Credits may be based on exchange or public price indices.D.9.2 VOMWind units should reflect their short-run incremental VOM costs by using the most current data available. This could include the previous actual short-run incremental

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cost where available. For wind units, VOM dollars from the previous years should be divided by MWh generated in the same period.

EOCVOM Adder ($ /MWh)=VOM Dollars($ )

MWhGenerationProduced

D.10 Solar GuidelinesSolar photovoltaic - Generating unit in which light from the sun is converted into electricity through solar cells.

Solar thermal – Generating unit in which heat from the sun is used to create steam that spins a turbine to generate electricity.

Mitigated Energy Offer ($/MWh) = -Foregone credits ($/MWh) + EOC VOM ($/MWh)

D.10.1 Foregone CreditsSolar Units may include applicable costs that vary by MWh output.

Foregone credits ($/MWh) = State PTC($/MWh)(1- state tax rate) + Renewable Energy Credits ($/MWh)

Most solar installations fall under the federal investment tax credit which is a fixed amount based on the installation price. This amount is not includable.

D.10.2 VOMSolar units should reflect their short-run incremental VOM costs by using the most current data available. This could include the previous actual short-run incremental cost where available. For solar units, VOM dollars from the previous years should be divided by MWh generated in the same period.

EOCVOM Adder ($ /MWh)= VOM Dollars($ )MWhGenerationProduced

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D.11 Energy Market Opportunity Cost GuidelinesD.11.1 Basis for Opportunity Cost to be included in Mitigated OffersOpportunity Cost may be a component of mitigated offers under certain circumstances. There are three reasons for application of Opportunity Costs as contained in this section.

D.11.1.1 Environmental Run-Hour RestrictionOpportunity costs associated with an externally imposed environmental run-hour restriction on a generation unit. Examples would include a limit on emissions for the unit imposed by a regulatory agency or legislation, a direct run hour restriction in the operating permit, or a heat input limitation defined by a regulatory decision or operating permit. Environmental run-hour restrictions must have suitable supporting documentation.

D.11.1.2 Physical Equipment LimitationsPhysical equipment limitations that cause the unit to experience a restriction in the number of starts or run hours would be eligible for opportunity cost. Physical equipment limitations must have supporting evidence submitted by the Market Participant. Documentation such as an OEM recommendation or bulletin and/or insurance carrier restrictions would meet this criterion.

D.11.1.3 Non-Regulatory Opportunity Cost: Fuel LimitationsFuel Limitations are eligible for Non-Regulatory Opportunity Costs for a fuel supply limitation, for up to one year, resulting from an event of force majeure.

Force Majeure is defined as: Any cause beyond the control of the affected Interconnection Party or Construction Party, including but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of

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the foregoing cases, by exercise of due diligence such party could not reasonably have been expected to avoid, and which, by the exercise of due diligence, it has been unable to overcome. Force Majeure does not include (i) a failure of performance that is due to an affected party’s own negligence or intentional wrongdoing; (ii) any removable or remediable causes (other than settlement of a strike or labor dispute) which an affected party fails to remove or remedy within a reasonable time; or (iii) economic hardship of an affected party.

D.11.2 Calculation MethodMarket Participants may opt to follow the method proposed here, or they may develop alternative methods specific to their Resources and submit those methods to the SPP MMU for approval. Requests for inclusion of opportunity costs in offers using other methods not defined in the Mitigated Offer Development Guidelines should be initially submitted to the SPP MMU for evaluation under the Mitigated Offer Methodology Approval Process.

Opportunity costs are a distinct component of the mitigated offer. As is the case with any computation of the mitigated offer, Market Participants may elect to enter their mitigated offer at a value less than the computed mitigated offer. However, they may not exceed the computed value.

D.11.2.1 Overview of the Opportunity Cost CalculationWhen added to the marginal cost of production in the Energy Offer Curve, the opportunity cost raises the offer to a level where the market dispatches the Resource up to, but not in excess of the run-time restriction. This is accomplished by:

1) Forecasting LMPs and production costs for the Resource,

2) Determining the market value of each potential run hour, revenue minus costs,

3) Ranking potential run hours (or blocks of run hours) during the restricted time frame by market value,

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4) Identifying the opportunity cost adder as the market value of the lowest ranked hour (or block of hours),

5) Adding the opportunity cost adder to the Mitigated Energy Offer Curve.

Opportunity cost calculations are based on daily, monthly, or annual run-time restrictions as applicable to the Resource. The run-time restriction parameters and supporting documentation must be submitted to the SPP MMU pursuant to the Mitigated Offer Methodology Approval Process (Section D.1.5).

D.11.2.2 Daily Opportunity Cost CalculationThe daily opportunity cost calculation is used for Resources with a daily run-time restriction. This would include pumped storage hydro Resources with externally imposed environmental restrictions on daily water levels. The daily calculation would typically be performed on Operating Day minus two (OD – 2).

D.11.2.2.1 Step 1: Forecast Hourly Resource LMPsInputs required for STEP 1:

Previous four weeks of hourly average LMPs at the Resource Settlement Location

To create a forecast for the Resource LMP, take the average LMP for the same hour of the day and day of the week for the last four weeks. (NERC holidays may be excluded from the four week history, and weekend days may be substituted for the same day of the week if the Operating Day is a NERC holiday.)

ForecastResourceLMPfd , h=(ResourceLMP fd−7 ,h+ResourceLMPfd−14 , h+ResourceLMP fd−21, h+ResourceLMPfd−28 ,h ) /4

For example,

ForecastResourceLMPNovember5 , 2013 HE9 :00=(ResourceLMPOctober 29 ,2013 HE9 : 00+ResourceLMPOctober22 ,2013 HE9 : 00+ResourceLMPOctober 15 ,2013 HE9 : 00+ResourceLMPOctober8 , 2013 HE9 :00 )/ 4

Output for STEP 1:

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Hourly forecast Resource LMPs for the Operating Day

D.11.2.2.2 Step 2: Calculate the Price-Cost Margin for each Hour of the DayInputs required for STEP 2:

Output from Step 1

Expected future full load seasonal (May-September/October-April) heat rate for the compliance period

Total Fuel related costs as defined in Section D.2

VOM as defined in Section D.2

The hourly margin is the hourly price minus hourly production cost.

Margin fd ,h=ForecastResourceLMP fd ,h−HourlyProductionCost fd ,h ,

where HourlyProductionCost fd , h=HeatRate (MBtu /MWh) X TotalFuelRelated Cost fd , h ( $ /MBtu )+VOM .

Output for STEP 2:

24 hourly forecast profit margins for the Operating Day

D.11.2.2.3 Step 3: Determine the Opportunity Cost ComponentThe opportunity cost component for the Mitigated Energy Offer Curve is determined for Resources with a one hour or less minimum run time by ranking each potential run hour by its hourly margin, with the highest value hour ranked 1. The

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opportunity cost component is the hourly margin for the hour with rank equal to the run hour limit.

For units exceeding a one hour minimum run time, blocks should be formed using contiguous hours, with the highest block margin being in block 1. The opportunity cost component is the hourly margin for the block with the hour equal to the run hour limit.

D.11.2.3 Long Term Opportunity Cost CalculationThe long term calculation applies to run-time restrictions that exceed 30 days. This method uses monthly forward prices as the basis for forecasts of fuel and electricity costs in the future. Opportunity costs calculated with this method will change frequently. The confidential market monitoring portal provides input space and outputs for this model. Given that fuel futures can change daily, the opportunity costs computed can likewise change daily. Market Participants who include opportunity costs in their mitigated offers must recalculate their long term opportunity cost no less frequently than once per every 7 days. If the 7th day falls on a holiday, then the calculation can be delayed until the next Business Day. In the event of a technical failure in the calculation, the previous value should be used.

D.11.2.3.1 Step 1: Forecast SPP System Monthly On-Peak/Off-Peak Average LMPs

Inputs required for STEP 1:

Natural Gas futures prices for Henry Hub and

A random number generator

The forecast of the average WEIS LMP is obtained by simulating from the model below or an update to the model provided by the SPP Market Monitoring Unit and may include third party models such as Platts. The first equation describes the relationship between the monthly average WEIS LMP and the price of natural gas.

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The second equation describes random daily deviations in price that are persistent over time.

Forecasted SPP LMPfy ,m, don− peak=8.2429+6.1039∗FutureHenryHubfy ,m

❑ +v fy ,m, don−peak

❑

v fy , m ,don−peak=0.5097∗v fy ,m , d−1

on− peak +e fy , m ,don−peak

e fy ,m, don− peak Normal(0,29.5)

Forecasted SPP LMPfy ,m , doff− peak=9.3146+3.4827∗FutureHenryHub fy , m

❑ +v fy ,m ,doff−peak

❑

v fy , m,doff−peak=0.4942∗v fy , m,d−1

off−peak +e fy , m,doff− peak

e fy ,m , doff−peak Normal(0,19.12)

To simulate the model, use a random number generator to obtain values for e fy ,m, 0on−peak

and e fy ,m , 0off− peak, the day prior to the first day in the forecast period. For example,

e2012 , August 13off−peak = 4.1278

is a single draw from the Normal distribution with a mean of zero and a variance of 19.12. Only one random number each is needed to simulate v0

on−peak and v0off−peak. All

other values for v fy , m,don−peak and v f , m ,d

off−peak are calculated from the previous realizations of

v fy , m,don−peak and v fy , m,d

off−peak, and e fy ,m , don− peak and e fy ,m , d

off−peakare zero on average. If the actual realizations of v0

on−peak and v0off−peakare known from the forecast model estimation, they

may be used in place of the random draw.

For example,

v2012 , August 13off−peak =e2012 , August13

off−peak =4.1278

v2012, August 13off−peak =0.4942∗4.1278=2.039

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Henry Hub natural gas monthly futures prices may be obtained daily from the CME Group website.1 Using these natural gas futures prices and the computed realizations of v fy , m,d

on−peak and v fy , m,doff−peak, the first equation above is applied to obtain

Forecasted SPP LMPfy ,m , don− peak and Forecasted SPP LMPfy ,m , d

off− peak. For example,

FutureHenryHubAugust 2012❑ =3.534

Forecasted SPP LMP2012 , August 13off− peak =9.3146+(3.4827∗3.534)+2.039❑= $23.66.

To obtain a monthly forecast of the average SPP LMP for on-peak and off-peak, average the computed values of Forecasted SPP LMPfy ,m, d

on−peak and

Forecasted SPP LMPfy ,m , doff−peak for each future month in the period for which the run-time

restriction applies.

Forecasted SPP LMPfy ,mon− peak= 1

N d∑

d∈ fy ,mForecasted SPPLMP fy , m,d

on−peak

Forecasted SPP LMPfy ,moff− peak= 1

N d∑

d∈ fy , mForecasted SPPLMP fy , m,d

off−peak

where Nd is the number of days in the month.

Outputs for STEP 1:

Forecasted On-Peak and Off-Peak SPP Monthly Average LMP

D.11.2.3.2 Step 2: Derive Historical Monthly LMP Basis Differential between the Resource Settlement Location and the SPP Real-Time Marginal Energy Component of LMP

Inputs required for STEP 2:

1 As of November 5, 2013, these could be found at http://www.cmegroup.com/trading/energy/natural-gas/natural-gas.html.

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http://www.cmegroup.com/trading/energy/natural-gas/natural-gas.html

http://www.cmegroup.com/trading/energy/natural-gas/natural-gas.html


Output from Step 1,

Three years of historical hourly real-time LMPs at the Resource Settlement Location, and

Three years of historical hourly average SPP LMPs

The difference between the WRTBM average LMP (SPP LMP below) and the LMP at the relevant Resource Settlement Location can be accounted for in the historic, monthly average basis differential for both peak and off-peak hours. This basis differential can be expressed as the average, over all peak or off-peak hours in a month, of the ratio of the hourly Resource Settlement Location LMP to the hourly average SPP LMP. If this ratio is greater than one, it means the Resource LMP is greater than the SPP LMP on average. If this ratio is less than one, it means the Resource LMP is less than the SPP LMP on average.

The forecast average SPP LMP multiplied by a historical basis adjustment ratio to the Resource Settlement Location creates monthly Resource LMPs. The three prior calendar year’s historical data is used to make this calculation. For example, when calculating opportunity costs for July 2, 2012 for a unit with a calendar year compliance period, use historical LMP data from July 2nd (2009, 2010, 2011) to December 31st (2009, 2010, 2011). For units with a 12 month rolling compliance period, use LMP data from the previous three years, beginning on the date calculated and ending two days previous. For example, when a unit is calculating opportunity cost for July 2nd, 2012 with a rolling 12 month compliance period, use historical LMP data from July 2nd (2009, 2010, 2011) to June 30th (2009, 2010, 2011). Begin by taking the hourly LMPs for the three prior calendar years at the Resource Settlement Location, and for every hour, divide that hour’s LMP by the corresponding forecast average SPP LMP. The historic hourly basis differential in hour h, day d, month m, and year y is

HourlyBasisDifferentialRatio y ,m, d ,h=Resource LMPy , m,d ,h

Av . SPPLMP y, m,d ,h

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Note: When the average SPP LMP is zero and the Resource LMP is zero, then the ratio value is one. If the average SPP LMP is zero and the Resource LMP is not zero, then the value is null, and it is not included in the average.

For example,

HourlyBasisDifferentialRatioAugust 13, 2012H 16=Resource LMPAugust 13 ,2012 H 16

Av .SPP LMPAugust 13 ,2012H 16

HourlyBasisDifferentialRatioAugust 13, 2011H 16=ResourceLMP August13 ,2011H 16

Av .SPPLMP August 13 ,2011H 16

HourlyBasisDifferentialRatioAugust 13, 2010H16=Resource LMPAugust13 ,2010H 16

Av .SPP LMPAugust 13 , 2010H 16

Exhibit 1: Three hourly basis differential ratio values for the same hour in each of three historical years

Once the hourly basis ratios are calculated for every hour during the three-year history, for each historic month take the sum of the on-peak hourly basis differentials in the month, and divide by the number of peak hours in the month (observations). Similarly, for every month, sum the off-peak hourly basis ratios, and then divide by the number of off-peak hours within that month. When calculating the monthly peak basis ratio, all days in the month will be used for the average. These monthly basis differentials adjust the average SPP LMP monthly peak and off-peak forecasts to expected peak and off-peak monthly forward Resource LMPs.

MonthlyPeakBasisDifferentialRatio y, m❑ =

∑peak hours

HourlyBasisDifferentialRatios y ,m, d ,hpeak

Number of Peak Hours∈monthm

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MonthlyOffPeakBasisDifferentialRatio y ,m❑ =

∑off - peak hours

HourlyBasisDifferentialRatios y , m,d ,hoff− peak

Number of Off -Peak Hours∈monthm

For example,

MonthlyPeakBasisDifferentialRatio June2009❑ =

∑peak hours

(Hourly Basis DifferentialRatios June2009 )

Number of Peak Hours∈June2009


∑peak hours

(Hourly Basis DifferentialRatios June2010 )

Number of Peak Hours∈June2010


∑peakhours

(Hourly BasisDifferentialRatios June2011)

Number of Peak Hours∈June 2011

Exhibit 2: Monthly Peak Basis Differentials for the three historical periods

Multiply monthly peak and off-peak basis differential ratios by the respective monthly peak and off-peak SPP average LMPs to derive forecasted monthly peak and off-peak Resource LMPs from the historical year. When calculating the monthly peak basis differential ratio, all days in the month will be used for the average.

ForecastedMonthly Resource LMPfy ,mpeak=Forecasted SPP LMPfy ,m

peak∗MonthlyPeakBasisRatio y ,mpeak

For example,

ForecastedMonthly Resource LMPJune 2012base 2009off - peak =(Forecasted SPPLMP for deliveryJune 2012

off - peak )∗(MonthlyOffPeakBasisDifferentialRatioJune2009off - peak )

ForecastedMonthly Resource LMPJune 2012 ,base 2010off - peak =(Forecasted SPP LMPfor delivery June2012

off - peak )∗(MonthlyOffPeakBasisDifferentialRatioJune 2010off - peak )

Forecasted Monthly Resource LMPJune 2012 ,base 2011off - peak

¿ (Forecasted SPP LMP fordelivery June2012off - peak )∗(MonthlyOffPeakBasisDifferentialRatioJune2011

off - peak )

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Exhibit 3: Forecasted monthly Resource Settlement Location prices for three historical periods

Outputs from STEP 2:

Three peak and off-peak monthly Resource LMP forecasts for each month remaining in the compliance period

D.11.2.3.3 Step 3: Derive Hourly Volatility Scalars to Incorporate Hourly Volatility into the LMP Forecast

Inputs for STEP 3:

Three years historical hourly real-time LMPs at the Resource Settlement Location

The monthly LMP forecasts only consider the average peak and off-peak prices for the month and do not consider hourly LMP volatility. Step 3 derives an hourly volatility scalar. This scalar will later be multiplied against the forecast in Step 2 to derive an hourly Resource LMP forecast that incorporates historic hourly peak and off-peak LMP volatility as well as monthly peak and off-peak basis differentials from the historical year.

First, for each historic month, compute the average peak and off-peak price at the Resource Settlement Location for each remaining month in the compliance period. When calculating the monthly average Resource LMP all days in the month will be used for the average.

MonthlyAverageResourceLMP y ,mpeak=

∑peak hours

HourlyResourceLMP y, m,d ,hpeak

Number of Peak Hours∈monthm

MonthlyAverageResourceLMP y ,moff - peak=

∑peakhours

HourlyResourceLMP y ,m, d , hoff - peak

Number of Off -Peak Hours∈monthm

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Next, for every hour, take the hourly Resource LMP divided by the relevant monthly average peak or off-peak Resource LMP computed above. If the hour is an on-peak hour, divide by the average peak LMP for the month.

HourlyVolatilityScalar y, m,d ,hpeak =

ResourceLMP y ,m, d , hpeak

MonthlyAverageResourceLMP y ,mpeak

If the hour is off-peak, divide that hour by the monthly off-peak average price for the corresponding month.

HourlyVolatilityScalar y, m,d ,hoff - peak=

Resource LMP y ,m, d ,hoff - peak

MonthlyAverageResourceLMP y ,moff - peak

For example,

HourlyVolatilityScalarAugust 13,2009H 23❑ =

Resource LMPAugust 13,2009 H 23❑

AverageOff -Peak August 2009ResourceLMP

HourlyVolatilityScalar August 13,2010H 23❑ =


Average Off -Peak August 2010 ResourceLMP

HourlyVolatilityScalarAugust 13,2011H 23❑ =


AverageOff -Peak August 2011ResourceLMP

Exhibit 4: Volatility scalar for the each of the three historical years

Output from STEP 3:

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Three ratio values per hour for each of the historical years used for volatility

D.11.2.3.4 Step 4: Create Three Sets of Hourly Forecasted Resource Settlement Location Values

Inputs to STEP 4:

Output from STEP 2: On-peak/off-peak monthly Resource Settlement Location LMP Forecast

Output from STEP 3: Hourly volatility scalars

Step 4 creates three hourly forecasts from the volatility scalars developed in Step 3 and the monthly Resource LMP forecasts developed in Step 2. Multiply the hourly volatility scalars developed in Step 3 by the corresponding peak or off-peak from the historical year forecasted monthly Resource LMP calculated in Step 2.

The expected or forecasted LMP for hour h, day d, month m, based on year y that is a peak hour is

ForecastedResourceLMP y , m,d ,hpeak =HourlyVolatilityScalar y ,m, d , h

peak ∗ForecastedMonthlyResourceLMPfy ,mpeak

The expected or forecasted LMP for hour h, day d, month m, based on year y that is an off-peak hour is

ForecastedResourceLMP y , m,d ,hoff - peak=HourlyVolatilityScalar y ,m, d , h

off - peak∗ForecastedMonthlyResourcePricefy ,moff - peak

For example, assume that it is July 15, 2012. To create the set of three forecasted prices for each hour of August 13, 2012:

ForecastedResourceLMPAugust 13,2012 H 23, base2009❑ =HourlyVolatilityScalar August 13,2009 H23

❑ ∗ForecastedMonthlyResourceLMP August 2012off - peak

ForecastedResourceLMPAugust 13,2012 H 23, base2010❑ =HourlyVolatilityScalar August 13,2010 H 23

❑ ∗ForecastedMonthlyResourceLMPAugust 2012off - peak

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ForecastedResourceLMPAugust 13,2012 H 23, base2011❑ =HourlyVolatilityScalarAugust 13,2011 H 23

❑ ∗ForecastedMonthlyResourceLMPAugust 2012off - peak


Three hourly Resource LMP forecasts for each hour remaining in the compliance period

D.11.2.3.5 Step 5: Create a Daily Fuel Volatility ScalarInputs to STEP 5:

Three years historical delivered daily fuel prices at the Resource Settlement Location ($/MMBTU)

Fuel Weights if dual fuel

Step 4 creates a daily fuel volatility scalar using historic daily delivered fuel prices (as used to develop a unit’s Total Fuel Related Cost (“TFRC”)) from the previous three calendar years. Take each daily Resource-delivered fuel price and divide it by the monthly average Resource-delivered fuel price to create a ratio for every day in the three-year history. In calculating monthly average Resource prices, all days in the month will be used for the average. For units that have dual fuels, the daily delivered fuel prices need to be multiplied by their respective weights and then added together. Nm is the number of days in month m.

Units with a single fuel type:

DailyFuelVolatilityScalar y ,m, d=DeliveredFuelPrice y ,m, d

(∑n=1

Nm

DeliveredFuelPricey , m

N m)

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Exhibit 5: Forecasted Resource Settlement Location LMPs for one hour for each of the three historical base years


Units with dual fuel:

DailyFuelVolatilityScalar y ,m, d=( DeliveredFuelPriceA y, m,d∗WeightFuelTypeA )+(DeliveredFuelPriceTypeB y , m,d∗WeightFuelTypeB )

(∑n=1

Nm

( (DeliveredFuelPriceA y ,m∗WeightFuelTypeA )+(DeliveredFuelPriceTypeB y ,m∗WeightFuelTypeB ))Nm

)For example,

DailyFuelVolatilityScalar August 13,2009=DeliveredFuelPrice August 13,2009

Average August 2009 Delivered Fuel Price

DailyFuelVolatilityScalar August13,2010=DeliveredFuelPrice August 13,2010

Average August 2010 Delivered Fuel Price

DailyFuelVolatilityScalar August 13,2011=DeliveredFuelPriceAugust 13,2011

Average August 2011Delivered Fuel Price

Exhibit 6: Three daily fuel volatility scalars values developed for August 13 in each of three historic years for a unit with a single fuel

If there is no fuel cost record for a given date, use the previous available value.

Output from STEP 5:

Three years of historic daily scalars for fuel volatility

D.11.2.3.6 Step 6: Create Three Daily Delivered Fuel ForecastsInputs for STEP 6:

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CME Forward curve for Fuels from the most recent trading day, for delivery in the compliance period ($/MMBTU) with a daily delivery charge adjustment

Fuel Weights if dual fuel

Fuel contract monthly prices if applicable

Output from STEP 5: Three years historic daily scalars for fuel volatility

Step 6 takes fuel futures and/or contract prices and the daily delivered fuel scalars from Step 5 and multiplies them together to create a fuel forecast that corresponds on an average monthly basis to the fuel futures, yet maintains historical volatility. For Resources that have dual fuels: the fuel forwards for the two fuels will be multiplied by their respective weights (derived from expected use of each fuel), added together, and then multiplied by the daily fuel volatility scalar. For Resources with some or all of their fuel procured by contract, the contract and fuel forwards are multiplied by their respective weights (derived from expected use of each fuel) and added together and then multiplied by the daily fuel volatility scalar. The current daily delivery charge adjustment will be applied through the compliance period.

Resources with a single fuel:

DailyDeliveredFuel fy , m,d=¿

DailyFuelVolatilityScalar y ,m , d∗¿

[ (WeightSpotm∗FuelForward fy , m )+ (WeightContractm∗ContractPrice fy ,m ) ],

where WeightSpotm + WeightContractm = 1.

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Resource with dual fuel:

(Permits the use of dual fuels for Resources that may burn multiple fuels or source fuels from different areas at different prices. For Resources with restrictions on consumption of specific fuels, this method allows accounting for both fuels in the same calculation.)

DailyDeliveredFuel fy , m,d=DailyFuelVolatilityScalar y ,m , d∗[WeightFuelTypeAm∗( WeightContractTypeAm∗ContractPriceTypeA fy ,m

+WeightSpotFuelTypeAm∗(DeliveryAdjustmentFuelTypeA+FuelForwardTypeA fy ,m ))+WeightFuelTypeBm∗( WeightContractTypeBm∗ContractPriceTypeB fy ,m

+WeightSpotFueTypelBm∗(DeliveryAdjustmentFuelTypeB+FuelForwardTypeB fy , m ))],

where WeightContractFuelTypeAm + WeightSpotFuelTypeAm = 1 and WeightContractFuelTypeBm + WeightSpotFuelTypeBm = 1.

For example, for a unit with a single fuel,

DailyDeliveredFuelForecast August 13 , 2012base2009 =DailyFuelVolatilityScalar August 13 ,2009∗FuelForward August 2012

DailyDeliveredFuelForecast August 13 , 2012base2010 =DailyFuelVolatilityScalar August 13 ,2010∗FuelForwardAugust 2012

DailyDeliveredFuelForecast August 13 , 2012base 2011 =DailyFuelVolatilityScalar August 13 ,2011∗FuelForward August 2012

Exhibit 7: Create three daily delivered fuel forecasts from the volatilities of three historic years


Daily Resource delivered fuel forecast

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D.11.2.3.7 Step 7: Create Resource(s) Cost for each of the Three ForecastsInputs for STEP 7:

Expected future full load seasonal (May-September/ October – April) heat rate for the compliance period

Fuel Prices output from Step 6

Unit SO2, CO2, and NOX Emission Rates (lbs/MMBTU)

(Note that the CO2 adder is in effect only for incurring carbon emission charges)Futures prices for SO2, CO2

and NOX from Evolution Markets ($/ton) modified to $/lb

Energy Offer Curve VOM as defined in Section D.2

In Step 7, take the Resource characteristics, future emission allowance prices, the three daily fuel forecasts and create a daily Resource cost for the three forecasts using the appropriate heat rate for the forecast day. Resource costs do not include start costs. They will be added later in the calculation of Resource Dispatch Cost. For each day in the three fuel forecasts, a Resource dispatch cost is calculated as follows:

ResourceCost fy ,m, dbase year=[HeatRate (MBtu

MWh )∗DailyDeliveredFuelForecast y, m ,dbase year( $

MBtu )]+[HeatRate( MBtuMWh )∗NOX EmissionRate( lbs

MBtu )∗Cost of NOX ( $lb )]+[HeatRate (MBtuMWh )∗SO2EmissionRate( lbs

MBtu )∗Cost of SO2( $lb )]+[HeatRate (MBtuMWh )∗CO2 EmissionRate( lbs

MBtu )∗Cost of CO2( $lb )]+EOC VOM

For example,

Heat rate=10.35 MMBTU/MWh

NOX emission rate =0.328 lbs/MMBTU

SO2 emission rate=1.2 lbs/MMBTU

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CO2 emission rate=117 lbs/MMBTU

DailyDeliveredFuelForecast=$5.56/MMBTU

Combined NOX Allowance cost=$1375/ton

SO2 Allowance cost=$200/ton

CO2 emission cost = $8/ton

EOC VOM = $2.22/MWh

ResourceCost=[( 10.35 MBtuMWh )∗( $5.56

MBtu )]+[( 10.35 MBtuMWh )∗(0.328 lbs

MBtu )∗( $1,375ton )∗( ton

2,000 lbs )]+[(10.35 MBtuMWh )∗( 1.2lbs

MBtu )∗( $200ton )∗( ton

2,000 lbs )]+[( 10.35MBtuMWh )∗( 117 lbs

MBtu )∗( $ 8ton )∗( ton

2,000lbs )]+( $2.22MWh )

¿( $57.58MWh )+( $2.33

MWh )+( $ 1.24MWh )+( $ 4.84

MWh )+( $2.22MWh )=$ 68.18/MWh

Exhibit 8: Daily Resource Cost

Outputs for Step 7:

Three forecasts based on historic year factors for daily Resource cost

D.11.2.3.8 Step 8: Calculate the Margin for every Hour in the Three Hourly Forecasts

Inputs for Step 8:

Daily Resource Cost from Step 7

Hourly Resource Settlement Location LMP forecast from Step 4

All future maintenance outage information

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Resource-specific minimum runtime parameter restriction

Resource-specific start-up costs (cold start-up costs for Combined Cycle and combustion turbine units and hot startup costs for steam units)

Resource Economic Maximum Operating Limit

Step 8 calculates the hourly margin the generator would receive by comparing the cost offer developed in Step 7 against the hourly forecasted Resource LMPs developed in Step 4. To remove planned outages, for any future date that the unit will be offline, set the outage hours to unavailable for all three forecasts.

For Resources with minimum run time restrictions, this step calculates the total margins in blocks of adjacent hours, based on the sum of the margins of each block and the minimum runtime parameter restriction of the Resource. Blocks may include additional incremental hours, if these hours are found to be more valuable than the additional block, up to double the Resource’s minimum runtime. Adjacent hour blocks with equal or greater number of hours than double a Resource’s minimum run time will be split into multiple blocks (however, adjacent blocks do not use an additional startup cost). For Resources with start-up costs, the value of the Resource’s start-up cost divided by Economic Maximum Operating Limit will be subtracted from the total margin of each block that contains a new start, but not from each subsequent incremental hour added to the block, in order to correctly value hours that do not incur start costs. Calculate the total margins for all blocks of hours in the three forecasts.

TotalMarginBlockblockbase year=¿

∑t=block

T

(ForecastedResourceLMP y (t ) ,m ( t ), d (t ) , h(t )base year −ResourceDispatchCost future y ,m, d

base year ),

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where T = block + MRT – 1 and MRT = minimum run time. When applicable, ResourceDispatchCost includes start-up costs. The block ranges from 1 to Total Number of Hours – MRT + 1 and y(t), m(t), d(t), h(t) are the year, month, day and hour corresponding to the tth overall hour of the time period spanning from the date calculated to the end of the compliance period forecasted.

The Total Number of Hours variable represents the number of hours left in the compliance period to be forecasted, and is based on the date calculated and whether or not the Resource has a rolling 12 month run-hour restriction.

For example,

TotalMarginBlockblock37882009

¿ ∑t=3788

T=3788+1−1

(ForecastedResourceLMP y ,m, d ,h ( t )2009 −ResourceDispatchCost y, m,d ,h (t )

2009 )

¿ (ForecastedResourceLMPAugust 13, 2012H 162009 −ResourceDispatchCost August 13 ,2012

2009 )

¿ $78.27−¿$68.18 = $10.09


¿ ∑t=3788

T=3788+1−1


2010 )


2010 )

¿ $58.00−¿$52.41 = $5.59

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¿ ∑t=3788

T=3788+1−1


2011 )


2011 )

¿ $63.78−¿$76.72 = -$12.94

At this point, the blocks of hours would be ranked according to the value of their total margins.

Exhibit 9: Calculating total margins with a minimum runtime of one hour (i.e. no minimum runtime restriction), using historical data from the past three calendar years

Output from Step 8:

Three sets of ranked blocks of total margin forecasts including each hour in the compliance period, adjusted to include start-up costs for each block that contains a new start, with all future outage hours removed

D.11.2.3.9 Step 9: Determine the Opportunity Cost ComponentInput to Step 9:

Three sets of ranked blocks of total margin forecasts

For each of the three years, the opportunity cost component for that year will be the total margin per hour of the lowest value block added before the run hour limit was reached. The three opportunity costs will then be averaged to get the opportunity cost component available to the Resource. If the final opportunity cost component is less than zero then the opportunity cost component will be set to zero.

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For example,

The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎𝟎9 = $𝟕.𝟗𝟗/𝐌𝐖𝐡.

The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎10 = -$𝟐.𝟓𝟒/𝐌𝐖𝐡.

The hourly value of the block which includes the 𝟕𝟎𝟎𝐭𝐡 𝐡𝐨𝐮𝐫𝐛𝐚𝐬𝐞 𝟐𝟎11 = $𝟏𝟎.𝟓𝟗/𝐌𝐖𝐡.

700 thhour opportunity cost component=$7.99+(−$2.54 )+$10.593

=$5.33/MWh

Exhibit 10: A unit with 700 run hours

Output from step 9:

Maximum Opportunity Cost Component that can be included in a run-limited Resource’s Mitigated Energy Offer Curve.

D.11.2.4 Short Term Opportunity Cost CalculationShort Term Opportunity Costs are of limited duration where the event lasts 30 days or less. The Short Term Method modifies the method in Section D.11.2.3 to capture daily price movements -in the monthly fuel forwards. For best results, Resources should recalculate opportunity costs every Business Day during the short-term episode. The confidential, market monitoring portal can also be used for short term opportunity cost calculations, which are performed each Calendar Day. In the event of a technical failure in the calculation, the previous value should be used.

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