Integrated Marketplace Commission Staff Education March 26, 2012

Common Acronyms ACP - Auction Clearing Price AO - Asset Owner ARR - Auction Revenue Rights BA – Balancing Authority CBA - Consolidated Balancing Authority CBT – Computer Based Training DA - Day-Ahead EIS – Energy Imbalance Service EMS - Energy Management System FERC – Federal Energy Regulatory Commission ISO - Independent System Operator LMP - Locational Marginal Price LMS – SPP Learning Center LSE – Load Serving Entity MCC - Marginal Congestion Component MLC - Marginal Loss Component MEC – Marginal Energy Component MCP - Market Clearing Price MP - Market Participants NERC – North American Electric Reliability Corporation NITS - Network Integrated Transmission Service OATT – Open Access Transmission Tariff OD – Operating Day OR - Operating Reserve RTBM - Real-Time Balancing Market RTO - Regional Transmission Organization RUC - Reliability Unit Commitment SCED - Security-Constrained Economic Dispatch SCUC - Security-Constrained Unit Commitment SPP - Southwest Power Pool TCR - Transmission Congestion Rights VER – Variable Energy Resource

Agenda Morning Introduction Integrated Marketplace Overview Pre Day-Ahead Market Activities Day-Ahead Market Activities Afternoon Operating Day Market Activities Auction Revenue Rights (ARRs) and Transmission Congestion Rights (TCRs) Post Real-Time Market Activities

Section 1 introduction

Map of ISOs and RTOs 6 ISOs in North America: CAISO, NYISO, ERCOT, AEISO, IESO, NBSO 4 RTOs in North America: PJM, MISO, SPP, ISO-NE

Integrated Marketplace Net Benefits Projected savings around $45-$100 Million/Year Reduce total energy costs through centralized unit commitment while maintaining reliable operations Day-Ahead Market allows additional price assurance capability prior to real-time Includes new markets for Operating Reserve to support implementation of Consolidated Balancing Authority (CBA) and facilitate reserve sharing

Today versus Tomorrow’s Market EIS Market Integrated Marketplace Transmission Reservations Energy Bilaterals Real-Time Balancing Market Scheduling (Internal / External) – All Reservations Operating Reserve Regulation and Reserves – Self –Designated Settlements Duration – Hourly Pricing – LIP Unit Commitment Self-Commitment Balancing Authority 16 Individual BAs Auction Revenue Rights (ARRs) Transmission Congestion Rights (TCRs) Day-Ahead Market Virtual Transactions Scheduling (Import/Export/Through) Regulation and Reserves - Market Duration – Hourly (DA); 5 Minutes (RTBM) Pricing – LMP, MCP, and ACP Centralized Commitment 1 SPP BA Here are the key features of EIS Market and Integrated Marketplace. Some of the key differences are: 1) In EIS MPs commit units and in Marketplace SPP will be committing the units. 2) Use Native Load Schedules to hedge congestion in EIS Market and use TCRs for congestion hedging in Marketplace. 3) Added a Day-Ahead Market with Virtual Transactions in Marketplace. 4) Hourly Settlements in EIS and 5-Minute Settlements in Marketplace. 8

Integrated Marketplace Overview Section 2 Integrated Marketplace Overview

Topics Covered SPP Roles and Responsibilities Market Participant Roles and Responsibilities System Models Configuration Roles and responsibilities of Market Monitoring Integrated Marketplace Processes and Products Market Pricing

Integrated Marketplace overview: Evolution of SPP and the Integrated marketplace

Southwest Power Pool Who is SPP? Independent, non-profit, Regional Transmission Organization ~500 employees Membership in 9 states Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas Manages reliability from Little Rock, Arkansas 24 x 7 operations Full redundancy and backup site

Our Major Services Facilitation Reliability Coordination Transmission Service/ Tariff Administration Market Operation Standards Setting Compliance Enforcement Transmission Planning Training Regional Independent Cost-effective Focus on reliability We offer a number of services for our members, including: Facilitating meetings and decision-making processes Monitoring the grid to maintain electric reliability Processing requests for use of the transmission grid under a tariff with consistent rates and terms for all participants Operating a wholesale energy market Ensuring that users, owners, and operators of the bulk transmission system are in compliance with federal reliability standards Creating regional reliability standards Planning for future transmission needs With all of our services, we focus on being regional, independent, and cost-effective. Our overarching goal is maintaining electric reliability.

SPP History and Major Milestones 1941 1968 1991 1994 1997 1998 2001 2004 2007 2010 2014 SPP Formed Founding Member of NERC Regional Council Implemented Operating Reserve Sharing Incorporated as a Non-Profit Implemented Reliability Coordination Implemented Tariff Administration Implemented Regional Scheduling Became FERC-approved RTO EIS Market Launched; Became NERC Regional Entity Integrated Marketplace Approved Integrated Marketplace Goes-Live March 1, 2014 1968: NERC was formed in response to a blackout in the northeast. SPP was a founding member. 1980: SPP’s members implemented a telecommunications network to facilitate information sharing. 1991: Reserve sharing allows all member systems to rely further on each other, reducing the reserves they each have to hold and making more power available for sale. 1997 - 2001: SPP added more services to provide regional benefit: reliability coordination, tariff administration, and scheduling. 2006: SPP began offering services on a contract basis. SPP did not even exist as a legal entity until 1994, and from 1941-1998 the SPP membership agreement was one paragraph. Many of our member companies have been working together for decades; these relationships are SPP’s foundation and why being relationship-based is a key corporate strategy.

SPP Roles and Responsibilities Post implementation of the Integrated Marketplace, SPP is responsible for: Providing all market services for Energy, Operating Reserve, and Transmission Service in accordance with the Open Access Transmission Tariff (OATT) and Market Protocols Managing and administering the Tariff Acting as the centralized SPP Balancing Authority Providing reliable operation of the transmission system Administering the Day-Ahead, Real-Time, Operating Reserve, and Transmission Congestion Rights Markets

(as it exists tomorrow) Balancing Authority With the Integrated Marketplace, SPP will assume the role of the Balancing Authority (BA) Balancing Authority is the responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection Frequency in Real-Time 14 15 13 11 16 Balancing Authorities (as it exists today) SPP – BA (as it exists tomorrow) SPP 12 10 8 9 5 4 7 6 1 2 3

Interactions with the SPP Market Customer Anyone who conducts business within SPP. This is a financial relationship. Market Participant Registration is required if you are acting on behalf of an SPP Customer and require access to the market systems. Member Member status entitles your company to voting privileges and decision making rights as a participant in select organizational groups Stakeholder Any entity (or person) who is interested in activities at SPP. Primarily refers to those who participate in committee meetings.

Interactions with the SPP Market (cont’d) Market Participants will be informed and can encourage changes by getting involved with Committees and Working Groups. SPP Board of Directors Regional State Committee Entity Trustees Membership Market and Operations Policy Committee Regional Tariff WG Change WG System Protection & Control WG Critical Infrastructure Protection WG Generation WG Operations Training WG Operating Reliability WG Seams Steering Committee Transmission WG Consolidated Balancing Authority Steering Committee Model Development WG Business Practices WG Market WG Economic Studies WG Over 500 stakeholders are involved in SPP’s organizational structure of committees, working groups, and ad hoc task forces. This member involvement drives SPP’s decision-making and strategic direction. Any and all opinions are heard loudly and clearly in organizational group meetings. The rosters of our organizational groups match the diverseness of the membership, requiring representatives from across the footprint and recognizing different member types and sizes.

Interactions with the SPP Market (cont’d) Market Participants who wish to participate in the Integrated Marketplace must: Register as a Market Participant with SPP Review and submit required signed legal documents Confirm asset modeling Clear credit requirements (cash collateral, letter of credit, etc.) Participate in Market Trials to ensure connectivity and confirm functionality

Types of Market Participants Key Participants Function Generation Owners An entity that owns or leases facilities for generation that are used to supply energy in SPP’s footprint Transmission Owners An SPP member that owns or leases transmission Load Serving Entity (LSE) An entity that provides electric energy for end use customers load located within or attached to the transmission system Power Marketer An entity that may or may not own assets, who buys and sells generation or participates in the Transmission Congestion Rights (TCR) market

Market Participant Roles and Responsibilities Market Participants are responsible for: Submitting Resource Offers (Energy, Operating Reserves, and Virtual), Demand Bids, Interchange Schedules, and Bilateral Settlement Schedules Own or bid to buy Transmission Congestion Rights (TCRs) Settle transactions through SPP

Integrated Marketplace overview: market monitoring

Market Monitoring Objective - Ensure the integrity of the SPP markets Two Primary Responsibilities Monitoring and prevention abusive practices by Market Participants Market power abuse Market manipulation and gaming Monitoring and improving market efficiency Identify market design flaws and recommend changes Monitor system operators to identify and correct inefficient processes or procedures

Monitoring Reports Annual / Monthly reports Special Studies Required under SPP Tariff Provides overview of market activities and highlights any major developments Special Studies Demand Response Assessment External Generation Access Assessment FERC weekly pricing updates Pricing changes Congestion updates

Integrated Marketplace overview: system models

Network Model Physical representation of the Transmission System Network Model where electrical equipment components (e.g. generators, loads, transmission lines, and transformers) connect Core of transmission grid operations is the physical network model. The Network Model connects Market Participants interactions with the RTO through the Commercial Model. Commercial Model is mapped to the Network Model. Market Participants see the Commercial Model and SPP sees the Network Model.

Aggregated Pricing Node (APNode) Commercial Model Represents the financial market relationships of the Market Participants and the Asset Owners (AO), and the commercial relationships among the elements of the Network Model Market Participant Asset Owner Settlement Locations Aggregated Pricing Node (APNode) Node (ENode) Pricing Node (PNode) Network Model Commercial Model Market Participant: Entity that is financially obligated to SPP for market settlements Asset Owner: Typically, but not necessarily, represents a company. Asset Owners can own any combination of generation, load, ARR and/or TCR assets within the SPP region Settlement Locations: Energy supply and demand is financially settled at the Settlement Locations Aggregated Pricing Node: Represents an aggregation of two or more PNodes using weighting factors The Commercial Model describes the financial market relationships of the Market Participants and the Asset Owners (AOs), and the commercial relationships among the elements of the Network Model. The Electrical Nodes (Enodes) within the Network Model are mapped to Pricing Nodes (Pnodes) in the Commercial Model. Several Pricing Nodes can be aggregated to represent an Aggregated Pricing Node (APNode). Settlement Locations have a relationship to a single PNode or APNode. Energy supply and demand is financially settled at the Settlement Locations based on the appropriate PNode or APNode LMP and Settlement Location energy injection or withdrawal level. There are four (4) types of Settlement Locations: Resource, Load, Hub and Interface. Pricing Node: Finest level of granularity in the Commercial Model and have a one-to-one relationship with a Node Node: Represents Electrical Nodes (Enode) within the Network Model

Model Updates Reliability-related model changes occur monthly Market Registration related model changes Existing Market Participants: occurs every other month New Market Participants: occurs every 4 months (April, August, December) Model change is required for: Addition, deletion, or change of electric power system components Asset registration changes, additions, or deletions Changes to Pricing Nodes Changes in Market Participant registration Model update cycle details are available in Appendix E of the Integrated Marketplace Protocols

Integrated Marketplace overview: Marketplace Processes, Products AND TIMELINE

Integrated Marketplace: Processes The design relationship between the market processes is illustrated below

Integrated Marketplace: Processes (cont’d) Day-Ahead Market Clears for the next Operating Day Financially binding market whose purpose is to match the set of market supply and market demand made available Reliability Unit Commitment (RUC) Process Exists for the same time period as Day-Ahead Market (Day-Ahead RUC) Exists for the balance of the day (Intra-Day RUC) Operationally binding process whose purpose is to ensure that the supply capacity cleared in the Day-Ahead Market (or for the current Operating for Intra-Day RUC) satisfactorily covers the RTO load and reliability requirement forecasts Real-Time Balancing Market (RTBM) Clears for the next 5-minute period Financially and Operationally binding market whose purpose is to ensure that market resources committed through Day-Ahead Market or lastly approved RUC process are dispatched according to Real-Time load forecast

Integrated Marketplace: Processes (cont’d) Reserve Market Integrated within the Day-Ahead Market, RUC process and the Real-Time Balancing Market through co-optimization Main purpose is to ensure that enough reserve capacity is procured so that the system can smoothly respond to contingencies Auction Revenue Rights Process / Transmission Revenue Rights Market Performed / Clears annually and monthly Provides market participants with a mechanism to be pro-active and hedge against the anticipated Day-Ahead market congestion, or increase their financial benefits Settlement Process Performed on a 5-minute basis Provides market participants with a measure of the financial benefits associated with their participation in the Day-Ahead and Real-Time Balancing Markets

Integrated Marketplace: Products There are five market products, which can be grouped in two categories: Energy - An amount of electricity that is Bid or Offered, produced, consumed, sold or transmitted over a period of time, which is measured or calculated in megawatt hours (MWh). Operating Reserve Regulating Up Reserve – Reserve capacity that is available for the purpose of providing Regulation Deployment in the up direction. Regulating Down Reserve - Reserve capacity that is available for the purpose of providing Regulation Deployment in the down direction. Spinning Reserve – From Resources that are synchronized to the system and fully available to serve load within the Contingency Reserve Deployment Period following a contingency event. Supplemental Reserve – Typically from off-line Resources that are capable of being synchronized to the system and available to serve load within the Contingency Reserve Deployment Period following a contingency event. Could also be provided by online synchronized resources. Applies to: Day-Ahead, RUC, RTBM, ARR/TCR, Settlement Applies to: Day-Ahead, RUC, RTBM, Settlement Regulation Reserve Contingency Reserve

Integrated Marketplace: Products Characteristics Energy Spinning Reserves Regulation UP Reserves Energy capable of being synchronized and deployed in abnormal conditions Energy synchronized and on-line ready to serve load in abnormal conditions Manages the instantaneous difference between net actual and scheduled interchange On-Line; deployed as dispatched — Regulation-Up Regulation-Down On-Line; can respond in 10 minutes Off-Line / On-Line; Can respond in 10 minutes Regulation Down Reserves Supplemental Reserve

Integrated Marketplace Timeline Pre Day-Ahead Market Activities OD -7 Day-Ahead OD -1 OD Real-Time OD 1 – OD 167 Post Process Outage Submittal Multi-Day Reliability Assessment ARR / TCR Registration Settlement Statements Disputes Invoices Metering Demand Bids Interchange Transactions Resource Offers Market Results and Prices Day-Ahead RUC Commitment Period Virtual Bids and Offers Unit Dispatch Supply Offers

Integrated Marketplace overview: MARKET Pricing

Market Pricing Definition Locational Marginal Price (LMP) The LMP at pricing location is defined as the cost to serve the next increment of load at that location (Energy) pricing locations are known as Settlement Locations LMP = Marginal Energy Component(MEC) + Marginal Congestion Component(MCC) + Marginal Loss Component (MLC) Market Clearing Price (MCP) The MCP for an Operating Reserve product at a Reserve Zone is defined as the cost to provide the next capacity increment of that Operating Reserve product at that specific Reserve Zone Auction Clearing Price (ACP) The prices generated at each source and sink Settlement Location in each round of the Annual TCR Auction and Monthly TCR Auction based upon the submitted TCR Offers and Bids

Market Pricing LMP – Key Concepts Locational Marginal Price (LMP) Applies to Energy product only Can be impacted by both Energy and Operating Reserve offers Hourly LMPs are posted for the Day-Ahead Market 5-Minute LMPs are posted for each Settlement Location for the Real-Time Balancing Market Congestion and Loss factors cause price separation

Market Pricing MCP – Key Concepts Market Clearing Price (MCP) Applies to Operating Reserve product only Can be impacted by both Energy and Operating Reserve offers Hourly MCPs posted for the Day-Ahead Market 5-Minute MCPs posted for the Real-Time Balancing Market One MCP per Operating Reserve by Reserve Zone

Market Pricing MCP – Reserve Zone Example

Market Pricing ACP – Key Concepts Auction Clearing Price (ACP) Prices generated at each source and sink Settlement Location in each round of the Annual TCR Auction and Monthly TCR Auction based upon the TCR Offers and Bids submitted The key principle of Auction Clearing algorithm is to maximize the total auction value while holding the flows on the constrained transmission lines to their limit Bids are awarded from highest to lowest and Offers are awarded from lowest to highest until the TCR availability is consumed The auction value is calculated for each TCR based on its clearing price on the path

Pre day-ahead market activities Section 3 Pre day-ahead market activities

Topics Covered Market registration Outage Notification ARRs/TCRs Purposes Multi-Day Reliability Assessment

Pre day-ahead market activities: market registration

Market Registration In order to do business with SPP, you must be a registered Market Participant or be represented by one. Market Participants must register their assets (loads and resources) prior to any market participation: Behind the meter generation less than 10MWs are excluded. Registration data represents a Market Participants physical and financial responsibility. Market Participant Asset Owner Gen PNode Load Pnode Meter Agent

Market Registration Resource Types Resources that are required to register in order to participate in the Integrated Marketplace: Generating Unit Plant Dispatchable Demand Response Block Demand Response Combined Cycle Jointly Owned Unit Dispatchable Variable Energy Non-Dispatchable Variable Energy

Market Registration Characteristics Resource characteristics required for asset registration: Location of Physical Resource Legal Owner Resource Type Non-Price Related Operating Parameters Settlement Location ID Resource Settlement Area ID Real-Time Settlement Meter Data

Market Registration Upcoming Registration Activity Timeline Initial registration will include the following activities: Date Registration Activity SPP Market Participant February 1, 2012 Provide MPs with a blank registration packet Review registration packet, understand the data required, and assess legal agreements April 1, 2012 Provide MPs with a draft of a partially completed registration packet Review registration packet, verify existing data, provide any additional information June 1, 2012 Review and process completed registration packets Return completed registration packets and legal documents to SPP October 1, 2012 Notify MPs of systematic model change completion Test model changes and report any defects

Pre day-ahead market activities: Outage Notification

Outage Notification Market Participants will need to notify SPP when a generation and/or transmission asset needs to deviate from its normal operations Notifications are in the form of an outage submittal through the Outage Scheduler Types of outages include: Unplanned (Deration, Emergency, Forced) Planned (Maintenance, Construction)

Pre day-ahead market activities: Auction Revenue rights / transmission congestion rights (ARR / TCR)

Pre Day-Ahead Market Activities ARRs / TCRs ARRs and TCRs are Congestion Hedging instruments Market Participants use to manage the anticipated Day-Ahead congestion. The allocation of ARRs occurs annually and incrementally (i.e. not systematic every month) , shortly before the TCR auction for the same planning period. The auction of TCRs occurs annually and monthly, in advance of the target Operating Day. Further discussion in the ARRs/TCRs section

Pre day-ahead market activities: multi-day reliability assessment

Pre Day-Ahead Market Activities Multi-Day Reliability Assessment Process that is performed prior to the Operating Day to assess capacity adequacy for the Operating Day (at least three days prior to the Operating Day) Resources with long lead times (“Long-Lead-Time Resource”) that cannot be considered as part of the Day-Ahead Market or Day-Ahead RUC will be considered SPP will issue a commitment order to affected Market Participants Resources committed during the Multi-Day Reliability Assessment process are subject to Day-Ahead Make-Whole Payment given that they meet the eligibility criteria

Pre Day-Ahead Market Activities Multi-Day Reliability Assessment (cont’d) Inputs to Multi-Day Reliability Assessment Process are RTBM Resource Offers Fixed Import and Export Interchange Transactions SPP Operating Reserve Requirements SPP Forecasts (Load and Wind) Transmission System Topology Resource Outages SPP performs analysis and selects Resources for commitment in merit order (least cost Resource based upon the commitment cost) until sufficient capacity is committed RTBM Resource Offers Fixed Interchange Schedules Operating Reserve Requirements SPP Forecasts (Load and Wind) Transmission System Topology Resource Outage Notifications Operating Day -1 OD -3

Day-ahead market activities Section 4 Day-ahead market activities

Topics Covered Day-Ahead Market: Definition and Objective, Resources Offers Day-Ahead Market Clearing Day-Ahead Make-Whole Payment Day-Ahead Market Timeline Day-Ahead RUC: Definition and Objective Day-Ahead RUC Execution Day-Ahead RUC Timeline

Day-Ahead Market What is the Day-Ahead Market? Forward Market that provides Market Participants with the ability to submit: offers to sell Energy and Operating Reserve bids to purchase Energy Simultaneously co-optimizes Energy and Operating Reserve using SCUC and SCED algorithms Ensures that resources are scheduled to be online to meet bid-in load demands and operating reserve obligations for the next Operating Day Financially binding market. Based on clearing market prices: Injection or supply transactions receive credit Withdrawal or demand transactions receive charge

Self Committed Resources Day-Ahead Market What is the Day-Ahead Market? The Day-Ahead Market outcome is a schedule that minimizes SPP total [production offer costs minus demand bid revenues], as determined based on Market Participants Offers and Bids 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Megawatts Generation cleared in DA Market Bid in Load and Operating Reserves cleared in DA Market Hour Self Committed Resources (Day Ahead Input)

Day-Ahead Market Resource Offers A Resource Offer is a comprehensive set of information that will allow a Market Participant to sell generation into the SPP Integrated Marketplace A Resource Offer consists of the following: Resource Limits Resource Parameters (start-up, no-load) Resource Offer curves Market Participant’s Day-Ahead Resource Offers must offer enough capacity to cover their bid-in loads and Operating Reserve requirements

Day-Ahead Market Resource Offer – Limits and Parameters What are Resource Limits and Parameters? Resource limits and parameters are Resource operational constraints submitted by Market Participants They are taken into consideration by SPP when the Resource is evaluated for commitment and dispatch They can be changed, many of them hourly Resource Limits Resource Parameters Economic Min / Max Normal Min / Max Emergency Min / Max Regulation Min / Max Ramp Rates Min / Max Run Time Minimum Down Time Max Daily / Weekly Starts Start-Up Times Start-Up Costs No-Load Costs

Day-Ahead Market Resource Offer – Resource Limits Off-Line Maximum Emergency Capacity Operating Limit Minimum Emergency Minimum Economic Minimum Regulation Maximum Economic Maximum Regulation Resource Limits Emergency Economic Regulation VALIDATION RULES Min. Economic ≥ Min. Emergency Min. Regulation ≥ Min. Economic Max. Regulation ≥ Min. Regulation Max. Economic ≥ Max. Regulation Min. Emergency ≥ Max. Economic

Day-Ahead Market Resource Offer – Resource Limits (cont’d) Ramp Rates How fast a Resource can increase or decrease production Submitted as a curve in MW / Minutes for: Energy Regulation Contingency Reserve MW MW/Min 50 5 100 8 150 15 200 23 250 29 300 33 350 36

Day-Ahead Market Resource Offer - Commitment Status Commitment status indicates to SPP how the Resource should be considered for unit commitment Commitment Status may be specified separately for use in the Day-Ahead Market, RUC or Real-Time Balancing Market Market – Resource is available for SPP economic commitment Self – Market Participant is committing the Resource Reliability – Resource is off-line and is only available for commitment by SPP if there is an anticipated reliability issue Outage – Resource is unavailable due to a planned, forced, maintenance or other approved outage Not Participating – The Resource is otherwise available but has elected not to participate in the Day Ahead Market.

Day-Ahead Market Resource Offer - Dispatch Status Dispatch Status indicates to SPP how the Resource should be considered for dispatch once it is committed Dispatch Status is submitted for each product (Energy, Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve) Product Dispatch Status Description Energy Market Available for economic dispatch if committed Not Qualified Not qualified to provide Energy Operating Reserve (OR) Available to clear the Operating Reserve product based on submitted OR Offers Fixed MP is fixing the OR product clearing at the specified MW level Not qualified to supply ORs because of physical restrictions

Day-Ahead Market Resource Offer – Resource Parameters Start-Up Costs Cost to bring a resource on-line and to its Minimum Economic Capacity Operating Limit Start-up costs of the resource is based on the unit status (cold, intermediate or hot) and the commitment start time No-Load Costs Cost to operate a resource at zero MW output Hot Start Intermediate Start Cold $$$ $$ $

Day-Ahead Market Resource Offer – Resource Parameters (cont’d) An Resource Offer Curve represents an offer to provide Energy from a Resource Two types of Curves – Slope or Block Monotonically non-decreasing Submission can begin seven days prior to the Operating Day and updated up to 1100 CPT Day-Ahead Offers can vary hourly Can submit up to 10 price/quantity pairs Submitted Resource Offers roll forward hour to hour until changed within each respective market

Day-Ahead Market Resource Offer – Resource Parameters (cont’d) Run and Start Times Resource Parameter Description Maximum Daily Starts Maximum number of times a Resource can be started within a 24-hour period. Maximum Weekly Starts Maximum number of times a Resource can be started within a rolling 7-day period. Maximum Daily Energy Maximum amount of Energy, in MWh, that is available to be produced in an Operating Day from a particular Resource. Minimum Run Time Minimum number of hours a Resource must run from the time the Resource is put online to the time the Resource is shut down. Maximum Run Time Maximum number of hours a Resource must run from the time the Resource is synchronized to the time the Resource is off-line. Minimum Down Time Minimum number of hours required following desynchronization that a Resource must remain off-line prior to a subsequent synchronization.

Day-Ahead Market Resource Offer – Resource Parameters (cont’d) Start Times Maximum Weekly Starts is the maximum number of times a unit can be started within a rolling 7- day period Maximum Daily Starts is the maximum number of times that a unit can be started in a 24-hour period Maximum Daily Starts <= Maximum Weekly Starts # of Starts Max Daily 2 Max Weekly 6

Day-Ahead Market Resource Offer – Example Consider the following Market Participant’s Resource: Resource Type 120 MW Gas Unit Fuel Gas Fuel Cost ($/MMBTU) 7 Incremental Heat Rate (MMBTU/MWh) 10 No-Load Heat (MMBTU/Hr) 100 Startup Fuel Requirement (MMBTU) Hot=1000;Warm=2000;Cold=2500 Min Econ. Capacity Limit (MW) 25 Max Econ. Capacity Limit (MW) 120 Assuming the Market Participant decides to offer this Resource at cost except for the energy cost curve being offered 20% above cost between 80 MW and 120 MW: formulate its 3-part offer.

Energy Offer Curve (Block) Startup Offer ($/start): Day-Ahead Market Resource Offer – Example Consider the following Market Participant Resource: Resource Type 120 MW Gas Unit Fuel Gas Fuel Cost ($/MMBTU) 7 Incremental Heat Rate (MMBTU/MWh) 10 No-Load Heat (MMBTU/Hr) 100 Startup Fuel Requirement (MMBTU) Hot=1000;Warm=2000;Cold=2500 Min Econ. Capacity Limit (MW) 25 Max Econ. Capacity Limit (MW) 120 Energy Offer Curve (Block) MW $/MWh 25 70 80 84 120 No Load Offer ($/h): Startup Offer ($/start): 700 Hot Warm Cold 7,000 14,000 17,500

Day-Ahead Market Resource Offer – Resource Parameters (cont’d) Run Times Minimum Run Time is the minimum consecutive number of hours a Resource should remain online from the time it was synchronized, before being considered for shutdown. Maximum Run Time is the maximum number of consecutive hours a Resource should remain online from the time it was synchronized. HE 0200 Available for commitment HE 2300 Offline Available for shutdown Min Run (Hrs) 16 3 Min Down (Hrs) Max Run (Hrs) 144 Day 1 2 4 5 6 7 0001 Online 2400 Off-Line HE 0700 Online

Resource Offer Types (cont’d) Jointly Owned Units (JOUs) A unit with multiple owners that can elect whether to submit individual or combined resource options Individual Resource Option Combined Each ownership share is committed independently for commitment and dispatch status Each ownership share is committed separately for dispatch status only Each ownership share ≥ Minimum physical capacity operating limit All ownership shares must be committed or none at all

Resource Offers (cont’d) Combined Cycle Resource Consists of combustion turbines and steam turbines The exhaust of one heat engine is used as a heat source for the other 3 Options for submitting Combined Cycle Resource Offers: Option Configuration Implementation Single Aggregate Combustion and Steam Turbines Committed, dispatched, and settled as any other resource Separate Component All Combustion or all Steam Turbines Committed and dispatched independently; settled as any other resource Pseudo Combined Cycle Resource 1 Combustion turbine and a portion of the steam turbine Committed and dispatched independently; settled as any other resource

Resource Offers (cont’d) Demand Response (DDR) Resource Dispatchable Demand Response (DDR) Resource A Resource created to model demand reduction associated with controllable load and/or a behind-the-meter generator that is dispatchable on a 5- minute basis Reporting Options for actual DDR Resource Output: Block Demand Response Resource A Resource created to model demand reduction that is not dispatchable on a 5-minute basis but can be committed and dispatched in hourly blocks Uses Calculated Response Production Option to determine the amount of Real-Time resource production and actual resource production Submitted Resource Production Option Calculated Resource MPs submit amount of response provided via ICCP and will represent the Real-Time resource production SPP calculates the Real-Time resource output for operational dispatch and actual resource output for settlements

Day-Ahead Market Resource Offer – Example MP1 submits the DA Incremental Offer Curve below for resource Gen1 for hour 1100. Assuming Gen1 is online and that DA Market LMP clears at $40/MWh, determine Gen1’s expected: DA Energy award DA Energy credit / charge MP1 Gen1 Load1 Gen1 DA Energy Offer Curve MW $/MWh 25 10 50 75 120 60 DA Energy Award = 65 MWh DA Energy Credit/Charge = - DA Award * DA LMP = -65 x 40 = -$2600 (credit)

Day-Ahead Market Demand Bids A demand bid is a proposal to purchase Energy at a specified location and period of time in the Day-Ahead Market Only Market Participants with registered load may submit demand bids at the registered load settlement location Load may submit fixed and/or price-sensitive demand bids Demand bids have same timeline as supply offers Can vary hourly by location Bid submittal other than for a fixed Export Interchange Transaction Bid does not apply to any of the RUC processes or RTBM Submitted Bids do not roll forward hour to hour Bid submittal for use in the Day-Ahead Market is voluntary

Day-Ahead Market Demand Bids – Fixed Demand Bids A fixed demand bid is a bid to buy generation in the Day-Ahead market, regardless of price (price- taker) Bids must specify MW Quantity Settlement Load location Hour (s)

Day-Ahead Market Demand Bids – Price Sensitive Demand Bids A price sensitive demand bid is a bid to buy more generation as the price decreases Bids must specify MW Quantity (up to 10 price/quantity pairs, slope or block option) Settlement Load location Hour (s)

Day-Ahead Market Demand Bids – Example Assume MP1 submits the DA Price Sensitive Demand Bid Curve below for resource Load1 for hour 1100. If DA Market LMP clears at $40/MW, determine Load1’s expected: DA Energy award DA Energy credit / charge MP1 Gen1 Load1 Load1 DA Energy Bid Curve MW $/MWh 25 80 50 55 75 30 100 DA Energy Award = 65 MWh DA Energy Credit/Charge = DA Award * DA LMP = 65 x 40 = $2,600 (charge)

Day-Ahead Market Interchange Schedules Contract for transfer of Energy between seller and buyer Interchange Schedules (Physical) Transactions that crosses the boundary of the SPP Balancing Authority Area and transfers physical energy Classified as Import, Export, or Through transactions

Day-Ahead Market Interchange Schedules Three types of Interchange Schedules Import Interchange Schedule Offer - MPs offer to purchase Energy for delivery into the SPP Balancing Authority Export Interchange Schedule Bids - MPs offer to purchase Energy for delivery outside the SPP Balancing Authority Through Interchange Schedules - MP schedule submitted between two external interfaces for moving Energy through the SPP Balancing Authority Import Export Through Interchange Schedule SPP

Day-Ahead Market Virtual Transactions Virtual Transactions are Day-Ahead Energy market instruments A Virtual Transaction can either be: Virtual Energy Offer: a proposal by a Market Participant to sell Energy at a specified price, Settlement Location and period of time in the Day-Ahead Market that is not associated with a physical Resource. Virtual Energy Bid: a proposal by a Market Participant to purchase Energy at a specified price, Settlement Location and period of time in the Day-Ahead Market that is not associated with a physical Load. When cleared by the Day-Ahead Market, a Virtual transaction will be settled at the price difference between the Day-Ahead LMP and the Real-Time LMP

Day-Ahead Market Virtual Transactions In general, the net effect of Virtual Transactions is to cause the Day-Ahead LMPs and RTBM LMPs to converge: If a Settlement Location is expected to be priced higher in day-ahead than in real-time, market participants may be incented to submit Virtual offers until, overtime, the two markets equalize in price Mechanics of a Virtual Offer Offer Quantity/Price into DA Market If DA LMP >= Offer Price, then transaction clears DA Market If cleared, market participant must buy Energy back at real-time LMP: Profit if DA LMP >= RTBM LMP, Loss otherwise Mechanics of a Virtual Bid Bid Quantity/Price into DA Market If DA LMP <= Bid Price, then transaction clears DA Market If cleared, market participant must sell Energy back at real-time LMP: Profit if DA LMP <= RTBM LMP, Loss otherwise

Day-Ahead Market Virtual Transaction - Rules Virtual Energy Offers and Bids are subject to a transaction fee Virtual Energy Offers and Bids can be submitted by a Market Participant at any Settlement Location, subject to meeting credit requirements A Market Participant may submit a single Virtual Energy Bid and a single Virtual Energy Offer for each Asset Owners at any Settlement Location for a particular Hour Each Virtual Energy Offer and Bid must specify a start and stop Hour within the applicable Operating Day

Virtual DA Energy Offer Curve Day-Ahead Market Virtual Transactions - Example MP1 submits a Virtual Energy Offer at Load1 settlement location for hour 1100 in Day-Ahead. Assuming the DA LMP and RTBM LMPs at Load1’s settlement location are $ 40/MWH and $55/MWH respectively, determine the transaction’s hourly: Expected DA Energy award and Net Energy Settlement MP1 Gen1 Load1 Virtual DA Energy Offer Curve MW $/MWh 25 10 50 75 60 120 65 DA Energy Award= 60 MW Net Energy Settlement = - DA Award * (DA LMP – RTBM LMP) = -60 x (40 – 55) = $900 (charge)

Day-Ahead Market Bilateral Settlement Schedules Bilateral Settlement Schedules (Financial) Transactions that transfer financial responsibility for market product between 2 participating entities within SPP. SPP Confirmation by both parties is required. Can be defined for: Energy: Day-Ahead or Real-Time Balancing Market Transaction must specify: buyer, seller, MW amount and Settlement Location Operating Reserve: Day-Ahead Market only Transaction must specify: buyer, seller, obligation percentage and Reserve Zone for settlement pricing Purely a settlement activity: does NOT impact market clearing

DA Market Clearing (Supply) DA Market Clearing (Load) Day-Ahead Market Bilateral Settlement Schedule - Example DA Market Clearing (Supply) Energy Award(MW): 100 DA LMP ($/MWH): 40 MP1 MP2 Gen1 Load2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 Assume the Day-Ahead Market clears as shown above. MP2 purchases 100 MW from MP1 at 45 $/MWH by entering into an Energy financial schedule. The parties agree to submit an 100 MW Energy Bilateral Settlement Schedule that is settled at MP1 Settlement Location. Determine MP1 and MP2 hourly DA impacts if: - Both Market Participants confirm the financial schedule with SPP

DA Market Clearing (Supply) DA Market Clearing (Load) Day-Ahead Market Bilateral Settlement Schedule - Example DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP1 MP2 Gen1 Load2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP1 SPP Settlement Gen1 DA Settlement = -DA Award x DA LMP = -100 x 40 = -$4,000 (credit) DA Bilateral Schedule Settlement = Sched x DA LMP = 100 x 40 = $4,000 (charge) DA Net Settlement =- 4,000 + 4,000 = $0 MP1 Books (this transaction occurs outside SPP) MP1 gets paid by MP2 an amount equal to $4,500 (=100 x 45) In total, the impact on MP1 is a total credit of $4,500 since the Bilateral Schedule was confirmed with SPP

DA Market Clearing (Supply) DA Market Clearing (Load) Day-Ahead Market Bilateral Settlement Schedule - Example DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP1 MP2 Gen1 Load2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP2 SPP Settlement Load2 DA Settlement = DA Award x DA LMP = 100 x 50 = $5,000 (charge) DA Bilateral Schedule Settlement = -Sched x DA LMP = -100 x 40 = $4,000 (credit) DA Net Settlement = 5,000 – 4,000 = $1,000 (charge) MP2 Books (this transaction occurs outside SPP) MP2 pays MP1 an amount equal to $4,500 ( = 100 x 45) In total, the impact on MP2 is a total charge of $5,500 since the Bilateral Schedule was confirmed with SPP

day-ahead market activities: Day-ahead market clearing

Day-Ahead Market Activities Day-Ahead Market Clearing and Results SPP clears the Day-Ahead Market between 1100 and 1600 Day-Ahead for the entire next Operating Day Day-Ahead Market Clearing requires the following algorithms: Security-Constrained Unit Commitment (SCUC) Security-Constrained Economic Dispatch (SCED) Simultaneous Feasibility Test (SFT) Results of the Day-Ahead Market include hourly: Market product awards for each market instrument LMP for each Settlement Location MCP for each Operating Reserve product per Reserve Zone

Day-Ahead Market Activities: Clearing RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements DA Market Co-optimized SCUC and SCED Cleared Energy & OR Offers Cleared Energy Bids: Virtuals & Demand Cleared Import, Export & Interchange Transactions DA Market Resource Offers: Energy and OR RTBM Resource Offers DA Resource Commit Schedules DA Confirmed Import, Export & Interchange Transactions Resource Outage Notifications SPP Operating Reserve Requirements SPP Forecasts (Load & Wind) RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements DA Market Demand Bids DA Market Import, Export & Interchange Transactions Resource Outage Notifications SPP Operating Reserve Requirements Virtual Energy Offers and Bids

Day-Ahead Market Activities Timeline By 7:00AM: SPP publishes load and wind Forecast, provides Market Participants with their Operating Reserve Requirement By 11:00AM: Market Participants submit their Day-Ahead Demand bids, Resource Offers and outage notification, Virtual, Bilateral and Physical Transactions information to SPP Between 11:00AM and 4:00PM: SPP clears Day-Ahead Market By 4:00PM: SPP publishes the results of Day-Ahead Market

Day-Ahead Market Activities Make-Whole Payment Resources committed by the Day-Ahead Market should be financially made whole. The Make-Whole Payment guarantees that they receive enough revenues to cover their 3-part offer and Operating Reserve offer, for the Operating Day Generation resources that self-commit or self-schedule into the market are not eligible for: Startup cost recovery if the resource self-commits No-load cost if the resource self-commit or self-schedules Energy cost for the self-schedule amount Operating Reserve cost for the self-schedule amount Daily Op. Reserve Cost Make-Whole Payment Daily Energy Cost Daily No-Load Cost Daily Market Revenues Daily Startup Cost

Gen1 DA Energy Offer Curve Day-Ahead Market Activities Make-Whole Payment – Example 1 Consider Market participant MP1: Gen1 is initially off-line Gen1 commitment status is Self-Commit for the entire day Day-Ahead ISO awards Gen1 65MW for each hour Day-Ahead LMP at Gen1 pricing location is 40 $/MWH for all hours Day-Ahead Is Gen1 eligible for Make-Whole payment? DA Revenues = Sum of hourly [DA LMP x DA Energy Award] = (40 x 65) x 24 = $62,400 DA Costs = Startup Cost + Sum of hourly [DA energy Cost + DA No-Load cost] = 0 DA Make-Whole Payment = Min [ 0 ; DA Revenues – DA Costs] = $ 0 MP1 Gen1 Load1 Gen 1 Oper. Cap. Max(MW): 120 Startup Offer ($/start) 17,500 No-Load ($/hr) 700 Gen1 DA Energy Offer Curve MW $/MWh 25 10 50 75 120 60

Gen1 DA Energy Offer Curve Day-Ahead Market Activities Make-Whole Payment – Example 2 Consider Market participant MP1 Gen1 is initially off-line Gen1 commitment status is Market for the entire day Day-Ahead ISO awards Gen1 65MW for each hour Day-Ahead LMP at Gen1 pricing location is 40 $/MWH for all hours Day-Ahead Is Gen1 eligible for Make-Whole payment? DA Revenues = Sum of hourly [DA LMP x DA Energy Award] = (40 x 65) x 24 = $62,400 DA Costs = Startup Cost + Sum of hourly [DA energy Cost + DA No-Load cost] = 17,500 + (1,175 + 700) x 24 = $62,500 DA Make-Whole Payment = Min [ 0 ; DA Revenues – DA Costs] = -$100 (credit) MP1 Gen1 Load1 Gen 1 Oper. Cap. Max(MW): 120 Startup Offer ($/start) 17,500 No-Load ($/hr) 700 Gen1 DA Energy Offer Curve MW $/MWh 25 10 50 75 120 60

Day-Ahead Market Co-optimization - Example Balancing Authority Spin Requirement (MW): 10 Balancing Authority Spin Requirement (MW): 10 Gen MP1 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): 30 Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 5 Gen MP2 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 10 MP1 MP2 Load MP2 Energy Fixed Bid (MW): 90 Load MP1 Energy Fixed Bid (MW): 100 Load MP1@2 Energy Fixed Bid (MW): 10 Balancing Authority 1 Balancing Authority 2 Consider 2 Market Participants MP1 and MP2 above, each with generation resources (assume these resources have 1.5 MW/Min Energy and CR ramp rates, no startup or no-load cost, and operate in a lossless network), load to serve and reliability requirement in the form of Spinning Reserve. Note how part of MP1’s load is in MP2’s service territory. How will these Market Participants benefit most from SPP future market operations?

Consolidated Balancing Authority Day-Ahead Market Co-optimization - Example Gen MP1 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): 30 Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 5 Gen MP2 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 10 Reserve Zone Spin Requirement (MW): 20 MP1 MP2 Load MP2 Energy Fixed Bid (MW): 90 Load MP1 Energy Fixed Bid (MW): 100 Load MP1@2 Energy Fixed Bid (MW): 10 Consolidated Balancing Authority In SPP future market operations, there will be only one Consolidated Balancing Authority, responsible for establishing reliability requirements throughout SPP network footprint. In the following case studies, we assume that: Both Market Participants belong to the same Reserve Zone and offer their generation at cost, The network has no congestion and no losses.

Day-Ahead Market Co-optimization - Example Market Participants self-schedule their participation in the market (Fixed Spin: 11 MW for MP1 and 9 MW for MP2) Gen MP1 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): 30 Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 5 Fixed Spin (MW): 11 Gen MP2 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 10 Fixed Spin (MW): 9 Reserve Zone Spin Requirement (MW): 20 MP1 MP2 Load MP2 Energy Fixed Bid (MW): 90 Load MP1 Energy Fixed Bid (MW): 100 Load MP1@2 Energy Fixed Bid (MW): 10 Let’s determine for the Hour: Each Market Participant awards (Energy and Spin), operational cost and LMP, The Spinning Reserve Zone MCP, SPP DA total production cost

Day-Ahead Market Co-optimization - Example Market Participants self-schedule their participation in the market (Fixed Spin: 11 MW for MP1 and 9 MW for MP2) Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 91 Spin Award (MW): 9 Gen MP1 Energy Award (MW): 109 Spin Award (MW): 11 10 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 LMP = 50 $/MWH LMP = 50 $/MWH Spin MCP = 10 $/MW MP1 Gen. Award (MW) Operational Cost ($) Margin Analysis ($/MW) Energy 109 3,270 20 Spin 11 55 5 Total - 3,325 MP2 Gen. Award (MW) Operational Cost ($) Margin Analysis ($/MW) Energy 91 4,550 Spin 9 90 Total - 4,640 DA Total System Operational Cost = $ 7,965

Consolidated Balancing Authority Day-Ahead Market Co-optimization - Example Market Participants let SPP fully co-optimize the market Gen MP1 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): 30 Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 5 Gen MP2 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 10 Reserve Zone Spin Requirement (MW): 20 MP1 MP2 Load MP2 Energy Fixed Bid (MW): 90 Load MP1 Energy Fixed Bid (MW): 100 Load MP1@2 Energy Fixed Bid (MW): 10 Consolidated Balancing Authority Let’s now determine for the Hour: Each Market Participant awards (Energy and Spin), operational cost and LMP, The Reserve Zone Spin MCP, SPP total production cost

Day-Ahead Market Co-optimization - Example Market Participants let SPP fully co-optimize the market Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 85 Spin Award (MW): 15 Gen MP1 Energy Award (MW): 115 Spin Award (MW): 5 15 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 LMP = 50 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW MP1 Gen. Award (MW) Operational Cost ($) Margin Analysis ($/MW) Energy 115 3,450 20 Spin 5 25 Total - 3,475 MP2 Gen. Award (MW) Operational Cost ($) Margin Analysis ($/MW) Energy 85 4,250 Spin 15 150 Total - 4,400 DA Total System Operational Cost = $ 7,875 (vs. $ 7,965 previously)

Day-Ahead Market Co-optimization - Example Market Participants let SPP fully co-optimize the market Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 85 Spin Award (MW): 15 Gen MP1 Energy Award (MW): 115 Spin Award (MW): 5 15 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 LMP = 50 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW Explaining Spin MCP By definition, the Spinning Reserve MCP represents the cost of procuring an additional increment of Spinning Reserve from the Reserve Zone. That value could be extracted through sensitivity analysis.

Day-Ahead Market Co-optimization - Example Base Case Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 85 Spin Award (MW): 15 Gen MP1 Energy Award (MW): 115 Spin Award (MW): 5 15 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 DA Total System Operational Cost = $ 7,875 Sensitivity analysis: Adding 0.1 MW of Spin Requirement Reserve Zone Spin Requirement (MW): 20.1 Gen MP2 Energy Award (MW): 85.1 Spin Award (MW): 15 Gen MP1 Energy Award (MW): 114.9 Spin Award (MW): 5.1 14.9 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 DA Total System Operational Cost = $ 7,877.5

DA Total System Operational Cost = $ 7,877.5 Day-Ahead Market Co-optimization - Example Market Participants let SPP fully co-optimize the market Sensitivity analysis: Adding 0.1 MW of Spin Requirement Reserve Zone Spin Requirement (MW): 20.1 Gen MP2 Energy Award (MW): 85.1 Spin Award (MW): 15 Gen MP1 Energy Award (MW): 114.9 Spin Award (MW): 5.1 14.9 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 DA Total System Operational Cost = $ 7,877.5 Explaining Spin MCP Given the base solution, the most economical way to provide an additional increment of Spinning Reserve requires: - Decreasing Gen MP1 Energy award by 0.1 MW (from 115 to 114.9) - Increasing Gen MP2 Energy award by 0.1 MW (from 85 to 85.1) - Increasing Gen MP1 Spinning Reserve Award by 0.1 MW (from 5 to 5.1) Production Cost Impact = (7,877.5 – 7,875) / 0.1 = 25 $/MW

day-ahead activities: RUC Commitment period

Day-Ahead Activities Reliability Unit Commitment (RUC) The Reliability Unit Commitment (RUC) process is a market mechanism that ensures there is enough capacity committed in order to cover the system load and Operating Reserve requirement forecasts, as determined by the RTO. Purpose of running a Day-Ahead RUC process is to ensure a reliable operating plan for the next Operating Day. The Day-Ahead RUC is executed shortly after the Day-Ahead Market completes. The clearing in the RUC process is performed via a Security-Constrained Unit Commitment (SCUC) algorithm.

Day-Ahead Activities Reliability Unit Commitment (RUC): Objective The Day-Ahead RUC process outcome is a schedule that minimizes SPP total commitment costs, as determined based on generation resources (real-time) offers and system load and Operating Reserve requirement forecasts. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Megawatts Generation cleared in DA Market Bid in Load and Operating Reserve cleared in DA Market Self Committed Resources Generation committed in RUC Generation de-committed in RUC SPP Load Forecast and Operating Reserve Requirements (RUC Input)

Day-Ahead Activities Reliability Unit Commitment (RUC) - Execution RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements Co-optimized SCUC Resource Commit / De-commit Schedules Resource Commitment/ Regulation Notifications Fixed Interchange Transaction Curtailment Notification RTBM Resource Offers RTBM Resource Offers DA Resource Commit Schedules DA Confirmed Import, Export & Interchange Transactions Resource Outage Notifications SPP Operating Reserve Requirements SPP Forecasts (Load & Wind) Ruc PROCeS S RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements DA Confirmed Import, Export & Interchange Transactions DA Resource Commit Schedules Resource Outage Notifications SPP Operating Reserve Requirements SPP Forecasts (Load & Wind)

Day-Ahead Activities Reliability Unit Commitment (RUC) (cont’d) All Market Participants need to submit (Real-Time) offers for all their registered resources that are not on planned, forced or otherwise approved outage The RUC process will take into consideration the cleared resource commitment schedules from the Day-Ahead Market and updated Current Operating Plan (which could have been modified as a result of a previously cleared RUC process) Resources committed by any RUC (Day-Ahead or Intra-Day) or Reliability Assessment processes are subject to Make-Whole Payment given that they meet the eligibility criterion

Day-Ahead Market vs. Day-Ahead RUC Differences Uses Day-Ahead Offer data MPs must offer enough capacity to cover load Clears by matching Resource Offers to Load Bids Accepts Virtual Bids and Offers Day-Ahead RUC: Uses Real-Time Offer data MPs must submit offers for ALL resources not on outage Uses SPP Load Forecast to make commitment decisions Does NOT evaluate Virtual Bids and Offers

Day-Ahead Activities Reliability Unit Commitment (RUC) - Timeline Between 4:00 PM and 5:00PM: Market Participants can update RTBM Resources Offers and outage notification, including Resources that were not selected by Day-Ahead Market Between 5:00PM and 8:00PM: SPP execute Day-Ahead RUC By 8:00PM: SPP notifies Market Participants affected by Day-Ahead RUC results

Section 5 Operating Day market activities: intra-day reliability unit commitment (Intra-day ruc)

Topics Covered Intra-Day RUC: Definition and Timeline RTBM: Definition and Objective, Resource Offers RTBM Clearing

Operating Day Market Activities Intra-Day Reliability Unit Commitment (Intra-Day RUC) Purpose of running the Intra-Day RUC process is to ensure Resource and Operating Reserve adequacy for the Operating Day Process performed by SPP at least every four hours throughout the Operating Day, for the balance of the day All Market Participants need to submit (Real-Time) offers for all their registered resources that are not on planned, forced or otherwise approved outage Affected Market Participants are notified by SPP Resources committed by RUC or Reliability Assessment processes are subject to Make-Whole Payment given that they meet the eligibility criteria.

Operating day market activities: Real-Time Balancing Market (RTBM)

Real-Time Balancing Market (RTBM) What is the RTBM? The Real-Time Balancing Market (RTBM) is the financially driven mechanism by which SPP balances real-time load and generation committed by the Day-Ahead Market and RUC processes. Its objective is to minimize the total RTO production cost based on the online resources Real-Time Offers and statuses, short-term load forecast and Operating Reserve requirements. Generation Load

Operating Day Activities Real-Time Balancing Market (RTBM) The RTBM is executed every 5-minutes for the next Dispatch Interval Resources receive dispatch amount for Energy and Operating Reserve every 5-minutes Setpoint Instructions are issued every 4-seconds to represent the sum of Energy and Operating Reserve deployment for a Resource Deviations from Setpoint Instructions result in additional charges

Operating Day Activities Real-Time Balancing Market (RTBM) SPP may issue a reliability directive in the form of a Manual Dispatch to resolve emergency condition (Referred to as OOME, Out-of-Merit Energy) The clearing of Energy and Operating Reserves is co-optimized using a SCED algorithm The difference in Day-Ahead cleared and RTBM dispatch amounts are settled based on RTBM prices Prices are posted every 5-minutes

Real-Time Balancing Market (RTBM) Resource Offers A Resource Offer is a comprehensive set of information that will allow a Market Participant to sell generation into the SPP Integrated Marketplace All Market Participants must submit RTBM offers for all their registered Resources that are not on planned, forced or otherwise approved outage Market Participants are required to keep their Resource Offer operating parameters up-to-date during the Operating Day

Real-Time Balancing Market (RTBM) Resource Offers – RTBM Commitment Status “Not Participating” status is not available for RTBM Offers Dispatch Status Resource Limits Economic Min/ Max Emergency Min/ Max Ramp Rates Energy Offer Curve Operating Reserve Offer

Real-Time Balancing Market: Timeline Up until 20min prior to Operating Hour: Market Participants can update the RTBM Resource Offers to be considered for the next Operating Hour For each of twelve 5-min intervals of the Operating Hour: At the beginning of each interval: SPP will clear RTBM based on short-term load forecast and Operating reserve requirement, and known Market Participants online resources statuses and offers At the end of each interval: SPP will publish the results of the RTBM and send Market Participants resources their dispatch instructions

Real-Time Balancing Market (RTBM) Resource Offers – Example MP1 clears DA as shown earlier and then submits the following Incremental Offer Curve for Resource Gen1 for hour 1100 in Real-Time. Assuming Gen1 is online and that RT Market LMP is $40/MWh, Gen1’s dispatch instruction is 60MW for each interval of the hour. What will be settlement for this scenario? MP1 Gen1 Load1 Gen1 RT Energy Offer Curve MW $/MWh 25 10 50 75 60 120 65 RT Energy Actual= 60MWh RT Energy Settlement = (DA Award - RT Actual ) x RT LMP = (65-60) x 40 = $200.00 (charge)

Section 6 AUCTION REVENUE RIGHTS (ARRs) AND Transmission congestion rights (TCRs)

Topics Covered Understanding Congestion ARRs/TCRs Processes Interaction: Overview and Timeline ARRs: Definition and Allocation Objective ARR Allocation: Process TCRs: Definition and Auction Objective TCR Auction: Process TCRs Secondary Market ARRs and TCRs Settlement Valuation

Understanding Congestion About Congestion Congestion occurs when the desired amount of electricity is unable to flow due to limitations on the transmission grid The transmission grid limitations could be intrinsic to the grid itself or further exacerbated by planned (e.g. transmission line maintenance) or unforeseen events (e.g. transmission line damage caused by extreme weather) However, one can hedge to manage the uncertainty of congestion Electricity Congestion – ARRs/TCRs

Understanding Congestion Day-Ahead - Example Market Participants let SPP fully co-optimize the market Gen MP1 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): 30 Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 5 Gen MP2 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 10 Reserve Zone Spin Requirement (MW): 20 MP1 MP2 Load MP2 Energy Fixed Bid (MW): 90 Load MP1 Energy Fixed Bid (MW): 100 Load MP1@2 Energy Fixed Bid (MW): 10 Flowgate Limit = 12 MW Considering the Day-Ahead co-optimization example presented earlier, let’s determine how a flowgate constraint of 12 MW on the interconnection affects: Each Market Participant awards (Energy and Spin), operational cost and LMP, The Reserve Zone Spin MCP, SPP Day-Ahead total production cost

Understanding Congestion Day-Ahead - Example Market Participants let SPP fully co-optimize the market Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 88 Spin Award (MW): 12 Gen MP1 Energy Award (MW): 112 Spin Award (MW): 8 12 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 LMP = 35 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW MP1 Gen. Award (MW) Operational Cost ($) Margin Analysis ($/MW) Energy 112 3,360 5 Spin 8 40 20 Total - 3,400 MP2 Gen. Award (MW) Operational Cost ($) Margin Analysis ($/MW) Energy 88 4,400 Spin 12 120 15 Total - 4,520 DA Total System Operational Cost = $ 7,920

Understanding Congestion Day-Ahead - Example Market Participants let SPP fully co-optimize the market Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 88 Spin Award (MW): 12 Gen MP1 Energy Award (MW): 112 Spin Award (MW): 8 12 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 LMP = 35 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW MP1 is net Energy provider in the system since its total cleared Energy generation (112 MW) is greater than its total cleared Energy demand (110 MW). However, part of MP1 load (Load MP1@2) is charged at a much higher LMP than is credited the Market Participant’s generation. As such, one can conclude that: Day-Ahead Hourly Congestion Exposure for MP1 = 10 x (50 – 35) = $ 150 To the extent it is possible, MP1 will likely try to hedge that congestion exposure.

Understanding Congestion Differences from SPP’s current EIS Market TCRs replace the use of Energy Schedules and Native Load Schedules as congestion hedges. Pre-DA activity – Congestion hedging process occurs prior to Real-Time and Day-Ahead operations. Financial Players – External participants and those without assets in market footprint can participate.

ARR/TCR Process Overview

ARR/TCR PROCESS: TIMELINE: ANNUAL AND MONTHLY

Timeline: Annual ARR Allocation/TCR Auction X – 2/13 Prepare for ARR Nominations Annual ARR Allocation Process Annual TCR Auction 2/14 – 3/15 4/5 – 4/23 5/3 – 5/23 Analyze Historical Data Transmission Service Verification Submit Nominations Perform SFT Award Annual ARRs (Round 1) Assign Candidate ARRs Submit Bid to Purchase and Self-Convert Run Annual TCR Auction Clear Annual TCR Auction / Perform SFT Post TCR Awards Check Auction Results (Round 3) (Round 2) Annual TCR in effect June - May MP Activity SPP Staff Activity

Incremental ARR Allocation / Monthly TCR Auction Process The Monthly TCR Auction process is the mechanism through which MPs may: Purchase TCRs over and above those obtained in the Annual TCR Auction process Offer for sale any TCRs awarded in the Annual TCR Auction process Self-Convert available Incremental ARRs to TCRs The Monthly TCR Auction has Single round for the months of July, August, and September Two rounds for the months of October-May (all the months in the Season periods) Monthly TCR Auction Submit TCR Bids, Offers and Self-Converts Run Monthly TCR Auction Clear Monthly TCR Auction / Perform SFT Post Monthly TCR Awards Check Auction Results Analyze Historical Data Verify Incremental Transmission Service Assign Incremental Candidate ARRs Request Incremental Transmission Service (optional) MP Activity SPP Staff Activity

ARR/TCR Process: Auction Revenue rights (ARRs) overview

Understanding Auction Revenue Rights Transmission service customers typically pay the embedded cost of the transmission system Transmission service customers (i.e. with firm transmission service) can request and expect contract path rights on the transmission system. These path rights are nominated by: MW amount Point of Receipt Point of Delivery Once awarded (allocated), such path right becomes a financial right entitling the owner to either: A portion of auction revenues or, Possibly turning it into financial instrument to use towards Day- Ahead congestion exposure hedging

ARRs: Definition In Integrated Marketplace, such path right is known as Auction Revenue Right (ARR) and defined as: A financial right, awarded during the annual/incremental ARR allocation process, that entitles the holder to a share of the auction revenues generated in the applicable TCR auction(s) and/or entitles the holder to self-convert the ARRs into TCRs Nomination Parameters: MW Amount Source Settlement Location Sink Settlement Location Could be Network Type or PTP type Time of Use (Period, On/Off-Peak) Candidate nominated ARRs are subject to a cap, which is a function of: Historical peak load or, Incremental candidate ARR allocation Financial Obligation Will be either a credit or a liability to Market Participant in TCR auction settlement Valuation based on the full MW allocation

ARRs: Definition In Integrated Marketplace, candidate ARRs do not have to be necessarily submitted in the ARR Allocation process Possible use of candidate ARR: Do nothing or, Nominate for ARR Allocation Process and: Self-convert Allocated ARR to TCR Bid, or Retain Allocated ARR for settlement based on the TCR Auction The ARR allocation process is conducted: Annually Incrementally (i.e. monthly if there is new transmission service reservation for that month or existing reservation that could not be accounted for in the annual process)

ARR Allocation: Objective The objective of the ARR Allocation Process is to grant as much ARR MWs as possible (or minimize the total curtailment amount, if needed) , while ensuring that the transmission network security is maintained: that allocation algorithm is referred to as ARR Simultaneous Feasibility Test (ARR SFT) The results of the ARR Allocation Process will include: The awarded (allocated) MW amount for each nominated candidate ARR The total system awarded ARR MW amount

Auction Revenue Rights How are Candidate ARRs allocated? Based on following Confirmed Firm Transmission Rights Network Integrated Transmission Service Agreement Point to Point Firm Transmission Service Request Grandfathered Agreements Nominate Candidate ARRs to become ARRs Allocated Annually - Period and Class June, July, August, September (On/Off Peak) Fall, Winter, Spring (On/Off Peak) Allocated in three rounds Allocated Monthly - Class Monthly single round (On/Off Peak) – as needed basis

ARR Allocation: Process In Integrated Marketplace, the ARR Allocation process is structured through 2 sequential timeline processes: The Annual ARR Allocation Process Is triggered once a year, in April Covers a planning horizon of 1 year The planning horizon is further segmented in the following periods: Will be divided in 2 process runs for each period: an Off-Peak process run and an On-Peak process run Period Months Covered 1 June 2 July 3 August 4 September 5 October - November 6 December - January - February - March 7 April - May Season: Fall Season: Winter Season: Spring

ARR Allocation: Process The Annual ARR Allocation Process (continued) Each process run will be executed in 3 sequential rounds, to allow Market Participants to adjust their strategy Round Additional Considerations System Transmission Cumulative Capacity Availability 1 Parallel flows 100% 2 ARRs awarded in Round 1 of ARR Annual allocation 3 ARRs awarded in Round 2 of ARR Annual allocation

ARR Allocation: Process The Incremental (Monthly) ARR Allocation Process Is triggered once a month Covers a planning horizon of 1 Month The following Incremental ARR periods are proposed: Will be divided in 2 process runs for each process: an Off-Peak process run and an On-Peak process run Acknowledges the allocation from any previous ARR processes for the covered planning horizon Period Month Covered June July August September October November December Period Month Covered December January February March April May

ARR Allocation: Process The Incremental (monthly) ARR Allocation Process (continued) Each process run will be executed in 1 round Round Additional Considerations System Transmission Cumulative Capacity Availability 1 Parallel flows TCRs awarded from TCR Annual auction Non-settled ARRs from TCR Annual auction 100%

Auction Revenue Rights (ARR) Characteristics: Summary Economic value based on ACPs from the TCR Auctions SPP issues obligation type ARRs to MPs Defined from source to sink Source point – Settlement Location where a ARR originates Sink point – Settlement Location where a ARR ends Defined by MW Quantity, ARR Period (month/season), and ARR Class (on/off-peak) Financial entitlement, not physical right 100 MWs A B Source Sink

Annual ARR Allocation Process SFT – Example with no curtailment B 100 MW line limit Feasible as Bid If all the nominated candidate ARRs are confirmed feasible, all nominated candidate ARRs are awarded

Annual ARR Allocation Process SFT – Curtailment Example B 100 MW line limit If the nominated candidate ARRs are not feasible, the amount to be awarded will be reduced using a weighted least squares method The SFT will assign a higher percentage ARR reduction for those nominations having the greatest impact on constraints ARR nominations with an equal impact on constraints will have an equal reduction

ARR/TCR Process: TRANSMISSION CONGESTION rights (TCRs) overview

Understanding Transmission Congestion Rights In addition to providing ARRs for Market Participants who are entitled to, there is also the possibility of purchasing or selling (financial) transmission rights. Once granted, these rights are then used to mitigate the Market Participant congestion exposure to the Day-Ahead Market The MW amount of purchase or sale in these transmission rights is determined through an centralized auction process whose objective is to maximize the auction value These financial rights are submitted with the following characteristics: MW amount Point of Receipt Point of Delivery Incremental Offer/Bid Price

TCRs: Definition In Integrated Marketplace, such financial right is known as Transmission Congestion Right (TCR) and defined as: A financial right that entitles the holder to a share of the congestion revenue collected in the Day-Ahead Market Submittal Parameters: Max MW Amount Incremental Offer/Bid Price Source Settlement Location Sink Settlement Location Time of Use (Period, On/Off-Peak) Credit Check: MP TCR Bids/Offers can be limited or cancelled in case of inadequate MP Market Credit Financial Obligation: Will be either a credit or a liability in DA Settlement valuation Valuation based on the full MW award

TCR Auction: Objective The objective of the TCR Auction Process is to maximize the auction value based on the TCR bids and offers, while ensuring that the transmission network security is maintained: that auction algorithm is known to as TCR Simultaneous Feasibility Test (TCR SFT) The results of the TCR Auction Process will include: The awarded MW amount for each submitted TCR Bid/Offer The Auction Clearing Price (ACP) at each system Pricing Location The total auction value

TCRs: How can one obtain TCRs from SPP? Annual TCR auction Multi-period (months/seasons) Multi-Class (On Peak/Off Peak) Based on reduced system capability Monthly TCR auction Single or two rounds Based on residual capability that was not purchased TCR secondary market Bilateral trading

December - January - February - March TCR Auction: Process In Integrated Marketplace, the TCR auction process is structured through 2 sequential timeline processes (similar to ARR Allocation process): The Annual TCR Auction Process (subsequent to ARR Annual Allocation) Is triggered once a year, in May Covers a planning horizon of 1 Year The planning horizon is further segmented in the following periods: Will be divided in 2 process runs for each period: an Off-Peak process run and an On-Peak process run Acknowledges the allocation from the Annual ARR process for the covered planning horizon Period Months Covered 1 June 2 July 3 August 4 September 5 October - November 6 December - January - February - March 7 April - May Season: Fall Season: Winter Season: Spring

TCR Auction: Process The Annual TCR Allocation Process (continued) Each process run will be executed in 1 round System Transmission Capacity Made Available Round Additional Considerations 1 a) Parallel flows Period Months Covered System Transmission Cumulative Capacity Availability 1 June 100% 2 July 90% 3 August 4 September 5 October - November 60% 6 December - January - February - March 7 April - May

TCR Auction: Process The monthly TCR Auction Process (subsequent to ARR Monthly Allocation) Is triggered once a month Covers a planning horizon of 1 month The following monthly TCR periods are proposed: Will be divided in 2 process runs for each process: an Off-Peak process run and an On-Peak process run Acknowledges the allocation from any previous ARR/TCR processes for the covered planning horizon Period Month Covered June July August September October November December Period Month Covered December January February March April May

TCR Auction: Process The monthly TCR Auction Process (subsequent to ARR Monthly Allocation) Each process run will be executed in up to 2 rounds, depending on the covered month Covered Month: July, August or September Round Additional Considerations System Transmission Cumulative Capacity Availability 1 Parallel flows TCRs awarded in Round 1 of TCR Annual allocation 100% Covered Month: October, November, December, January, February, March, April or May Round Additional Considerations System Transmission Cumulative Capacity Availability 1 Parallel flows TCRs awarded in Round 1 of TCR Annual allocation 80% 2 TCRs awarded in Round 1 of TCR Monthly allocation 100%

Annual TCR Auction Process Submit Bid to Purchase and Self-Convert Run Annual TCR Auction Clear Annual TCR Auction / Perform SFT Post TCR Awards Check Auction Results The mechanism through which MPs may obtain TCRs through the submission of bid to purchase TCRs and/or through self-conversion of ARRs into TCRs Different percentages of the grid capacity are made available during the TCR periods included in the Annual TCR Auction TCRs in the annual auction are auctioned in a single round process for all months and seasons MP Activity SPP Staff Activity

Annual TCR Auction Process Auction Bidding – Self-Convert If an MP elects to purchase the TCR corresponding to an ARR he holds, he will submit the ARR as a “self-convert” bid type during the Annual TCR Auction Only MPs holding ARRs may submit a Self-Convert TCR bid The Self-Convert bid must contain the same source and sink as the associated ARR The Self-Convert MW must be less than or equal to the associated ARR MW The MP will technically pay for the TCR, but as holder of the corresponding Auction Revenue Rights they will in effect be funding their own portion of the ARR fund, typically resulting in a net $0 transaction during ARR Settlements

Annual TCR Auction Process Auction Bidding – Bid to Purchase An MP may elect to submit bids to purchase TCRs instead of or in addition to self-converting ARR MWs Sources and Sinks for TCR bids may be any valid Settlement Location The number of TCR MW an MP may bid to purchase is limited by the amount of credit they have established in the TCR System

Monthly TCR Auction Process Monthly Auction Bidding The TCR offer and bid submittal process allows for the following submittal types: Self-Convert: When a Market Participant elects to purchase the TCR corresponding to an ARR that it holds Bids to Purchase: Sources and Sinks for bids to purchase TCRs may be any valid Settlement Location Offers to Sell: In the Monthly TCR Auction an MP may also offer for sale any TCR that was acquired during the Annual TCR Auction. Self-conversions, bids to purchase, and offers to sell TCRs in the Monthly TCR Auction process follow the same procedures and have the same restrictions as in the Annual TCR Auction

TCR Secondary Market SPP will facilitate a secondary market for TCRs TCR for sale! TCR! T C R Buy 1 Get 1 Free! Act now! Lonely TCR seeks companion Secondary TCR Market Details Bilateral trading of existing TCRs is facilitated through a bulletin board system TCRs may be broken down into small MW increments that total the original TCR TCRs may be traded daily, for On-Peak and/or Off-Peak periods Secondary TCR restrictions TCRs may not be reconfigured (path remains the same) TCRs must span a minimum of 1 day and a maximum of the month for which they’re offered

TCR Secondary Market Market Participants contact each other directly to negotiate terms of sale The TCR purchaser pays TCR seller directly SPP accounts for transfer of TCR ownership Purchaser must meet applicable credit requirements

TCR Characteristics: Summary Economic value based on Day-Ahead Congestion Prices TCRs are an instrument of obligation type Defined from source to sink Source point – Pnode where a TCR originates Sink point – Pnode where a TCR ends Financial entitlement, not physical right Independent of energy delivery MW Quantity TCR period: Season or Month TCR class: On-Peak or Off-Peak 100 MWs A B Source Sink

Annual TCR Auction Process Auction Clearing and SFT – Example B 100 MW line limit

ARR/TCR PROCESS: Auction Revenue rights AND TRANSMISSION CONGESTION RIGHTS SETTLEMENT VALUATION

Auction Revenue Rights (ARR) Settlement Valuation The value of an ARR is determined based on the difference in TCR Auction Clearing Prices (ACP) between the source and the sink Auction Clearing Price (ACP) is based on the sum of the nodal clearing prices for each auction, over an Auction Period and Class (e.g. seasonal on-peak, monthly off-peak, etc) ARRs can be a benefit or a liability ARR Value = (ARR MW) * (ACPARR Source – ACPARR Sink)

Transmission Congestion Rights (TCR) Settlement Valuation TCRs have a monetary value which will result in a credit or debit to be paid to (or owed by) the TCR holder TCR values are based on the difference between the Marginal Congestion Component (MCC) of the Day-Ahead LMP from the TCR source point to the TCR sink point TCR Value = (TCR MW) * (Congestion Price TCR Source – Congestion Price TCR Sink) LMP LMP = MEC + MCC + MLC Marginal Loss Component (MLC) Marginal Congestion Component (MCC) Marginal Energy Component (MEC)

Settlement Valuation - Example ARR / TCR Settlement Valuation - Example MP1 has 10 MW of Firm Transmission Service between its generation and MP2 service territory Gen MP1 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): 30 Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 5 Gen MP2 Econ. Oper. Cap. Min (MW): 50 Econ. Oper. Cap. Max (MW): 120 Energy Offer Cost ($/MWH): Spin Cap. Max (MW): 15 Spin Offer Cost ($/MW): 10 Reserve Zone Spin Requirement (MW): 20 MP1 MP2 Load MP2 Energy Fixed Bid (MW): 90 Load MP1 Energy Fixed Bid (MW): 100 Load MP1@2 Energy Fixed Bid (MW): 10 Flowgate Limit = 12 MW Based on historical congestion analysis, MP1 has decided to participate in the ARR/TCR Process for the upcoming Off-Peak Period (assume 8 Hours/day, 30 days) as follows: Nominate up to 10MW of transmission service into a candidate ARR (source: Gen MP1 Settlement Location, sink: LoadMP1@2 Settlement Location): - The ARR Allocation process has resulted in MP1 receiving 8 MW worth of ARRs With the 8MW of allocated ARRs: - Self-convert 6MW for the TCR Auction: all were awarded

Settlement Valuation - Example ARR / TCR Settlement Valuation - Example MP1 has 10 MW of Firm Transmission Service between its generation and MP2 service territory Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 88 Spin Award (MW): 12 Gen MP1 Energy Award (MW): 112 Spin Award (MW): 8 12 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 MEC ($/MWH): 42.5 MCC ($/MWH): -7.5 MLC ($/MWH): MEC ($/MWH): 42.5 MCC ($/MWH): 7.5 MLC ($/MWH): LMP = 35 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW TCR Auction Clearing Prices for that Off-Peak Period are: ACP (Gen MP1 Settlement Location) = $Period/MW -800 ACP (Load MP1@2 Settlement Location) = $Period/MW 1600 Assuming that the Day-Ahead Market clears as illustrated above for each hour of that Off-Peak Period, let’s determine: - The impact of these market instruments on MP1’s net congestion exposure

Settlement Valuation - Example ARR / TCR Settlement Valuation - Example MP1 has 10 MW of Firm Transmission Service between its generation and MP2 service territory Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 88 Spin Award (MW): 12 Gen MP1 Energy Award (MW): 112 Spin Award (MW): 8 12 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 MEC ($/MWH): 42.5 MCC ($/MWH): -7.5 MLC ($/MWH): MEC ($/MWH): 42.5 MCC ($/MWH): 7.5 MLC ($/MWH): LMP = 35 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW ARR Allocation: ARR Value (based on TCR Process) = 8 x (- 800 – 1600) = $Period/MW -19,200 = $Day/MW -600 (credit) TCR Auction: ARR Self-Converting Value (from TCR Auction) = 6 x (1600 + 800) = $Period/MW 14,400 = $Day/ 480 (charge) TCR Value (based on Day-Ahead Market) = 6 x (-7.5 – 7.5) = $/MWH -90 = - $Day/MW 720 (credit)

Settlement Valuation - Example ARR / TCR Settlement Valuation - Example MP1 has 10 MW of Firm Transmission Service between its generation and MP2 service territory Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 88 Spin Award (MW): 12 Gen MP1 Energy Award (MW): 112 Spin Award (MW): 8 12 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 MEC ($/MWH): 42.5 MCC ($/MWH): -7.5 MLC ($/MWH): MEC ($/MWH): 42.5 MCC ($/MWH): 7.5 MLC ($/MWH): LMP = 35 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW Without Congestion Hedging: MP1 Day-Ahead Congestion Exposure = 10 x (50 – 35) = $/MWH 150 = $Day/MW 1,200 (=150 x 8 Hours) With Congestion Hedging: MP1 Day-Ahead Congestion Exposure = 1200 (DA congestion)- 720 (TCR) + 480 (TCR conversion) – 600 (ARR revenue) = $Day/MW 360 = $/MW 45 (= 360 /8 Hours)

Settlement Valuation - Example ARR / TCR Settlement Valuation - Example MP1 has 10 MW of Firm Transmission Service between its generation and MP2 service territory Reserve Zone Spin Requirement (MW): 20 Gen MP2 Energy Award (MW): 88 Spin Award (MW): 12 Gen MP1 Energy Award (MW): 112 Spin Award (MW): 8 12 MW >> MP1 MP2 Load MP2 Energy Award (MW): 90 Load MP1 Energy Award (MW): 100 Load MP1@2 Energy Award (MW): 10 MEC ($/MWH): 42.5 MCC ($/MWH): -7.5 MLC ($/MWH): MEC ($/MWH): 42.5 MCC ($/MWH): 7.5 MLC ($/MWH): LMP = 35 $/MWH LMP = 50 $/MWH Spin MCP = 25 $/MW MP1’s decision to participate in the ARRs/TCRs Process has indeed reduced its overall congestion exposure for the Off-Peak Period from $1,200 to $360 on a daily basis.

TCR Market: Financial Reconciliation TCRs are fully funded on a daily basis from the congestion revenue collected Any revenue deficiencies will be handled through the TCR Daily Uplift on a pro-rata share Monthly Payback will attempt to pay back deficiencies collected within that month Annual Payback will attempt to pay back deficiencies collected throughout the year To the extent that there is an excess amount of net charges collected for the year and all deficiencies have been fully reimbursed, the excess is distributed to ARR holders in proportion to their ARR Nomination Caps

Post real-time Market activities Section 7 Post real-time Market activities

Topics Covered Market Settlements: Definition Meter Data Submission Responsibilities Settlement Statements vs. Resettlement Statements Settlement Invoice: Content and Deadlines Charge Type: Definition Dispute Process

Post Real-Time Market Activities Market Settlements Market Settlements represent the financial settling of market activities between Market Participants in the SPP footprint SPP will issue an Initial and Final settlement statement for each Operating Day that will include: Day-Ahead Market Activity Real-Time Market Activity Transmission Congestion Rights (TCR) Activity Settlement Statements will be issued at the Market Participant (MP) and Asset Owner (AO) level Meter Data will be used to settle Real-Time charges

Post Real-Time Market Activities Meter Data Market Participant is responsible for the quality, accuracy and timeliness of meter data Market Participants must designate a Meter Agent for each of its Meter Data Submittal Location Market Participants (not Meter Agent) is responsible for any and all data submitted; SPP maintains relationship with the Market Participant (not Meter Agent) Settlement meter data must be submitted in either 5-minute or hourly intervals as indicated during market registration Can submit estimates if not available for Operating Day Must submit actual values when available, prior to the next scheduled settlement If not submitted, SPP will use State Estimator Data

Post Real-Time Market Activities Metering / Settlement Relationship Demand Response Load Meter Data Submittal Locations Settlement Locations (pricing / settlement) Gen Settlement Areas (residual / calibration) MDSL Intf Hub Reserve Zones Common Bus RZN SA DRL DDR BDR Tie Line Node Pnode Meter Settlement Locations Network Model Link – Commercial Model

Post Real-Time Market Activities Meter Data Submittal Timelines Meter data values submitted by NOON on the previous business day will be included in the Settlement Statement(s) to be executed Day 5 calendar day for Initial Settlement Statement Day 45 calendar day for Final Settlement Statement For meter data submittal after Day 44 at NOON, there must be an associated dispute Day 75 calendar day for Resettlement 1 Statement +30 calendar days for Resettlement 2-11 Statement Meter Data Submittal Example for Initial Settlement Statement Operating Day Day 1 Day 2 Day 3 Day 4 Day 5 Day 6 Day 7 March 3, 2014 MP’s Meter Agent submits Meter Data by NOON SPP performs data validations and prepares Initial Settlement Statement SPP publishes Initial Settlement Statement

Post Real-Time Market Activities Settlement Statements Settlement Statement is a detailing of the charges and credits by charge type and Operating Day Generated for each Market Participant and associated Asset Owner Contains data for all of the Operating Days settled Available electronically through the Portal on Business Days SPP Market Participant Asset Owner Asset Initial Final Resettlement

Post Real-Time Market Activities Settlement Statement - Timeline One Settlement Statement will be published for each Operating Day Initial Settlement Statement – 7 calendar days following the Operating Day Final Settlement Statement – 47 calendar days following the Operating Day If the publishing date is not a business day, Settlement Statements will be published no later than the next Business Day OD OD+7 OD+47 47 calendar days 7 calendar days March 1st Operating Day *March 10th Initial Settlement Statement April 17th Final Settlement Statement *March 8th is not a business day

Post Real-Time Market Activities Resettlement Statement - Timeline Resettlement Statements will be produced using corrected settlement data due to resolution of disputes, or correction of data SPP will produce up to 12 Resettlement Statement (on an as needed basis) Resettlement 1 – 77 calendar days after the Operating Day** Resettlement 2 – 107 calendar days after the Operating Day* Resettlement 3 – 137 calendar days after the Operating Day** Resettlement 4 – 167 calendar days after the Operating Day* Resettlement 5 through 9 – incremental 30 days from last Resettlement date** Resettlement 10 through 12 – ad hoc (not scheduled for a specific date) *Resettlement 2 and Resettlement 4 are produced as a result of dispute resolution **Resettlement 1 and 3 will be produced and published if the financial change is greater than 25% for a single Market Participant

Post Real-Time Market Activities Settlement / Resettlement Statement Publishing Schedule OD OD+7 OD+47 OD+77 OD+107 OD+137 OD+167 7 CD March 1st Operating Day *March 10th Initial Statement 47 calendar days 77 calendar days 107 calendar days 137 calendar days 167 calendar days April 17th Final Statement June 16th Resettlement Statement 2 August 15th Resettlement Statement 4 *May 19th **Resettlement Statement 1 July 16th **Resettlement Statement 3 *Non-business day **Produced ‘as required’ 184

Post Real-Time Market Activities Charge Types Charge Types represent the various market activities Each Charge Type uses different Billing Determinants and a different calculation formula There are a total of 51 Charge Types that represent the following: Day-Ahead Market Settlement Real-Time Market Settlement ARR/TCR Auction Settlement Miscellaneous Amount Revenue Neutrality Uplift Distribution Amount The complete list of Charge Types and Billing Determinants can be found in the Market Protocols for SPP Integrated Marketplace

Post Real-Time Market Activities Charge Type - Components Charge Type Settlement Formula Billing Determinants Billing Determinants Charge Type is the end result of Settlement calculations which describes the type of activity being settled (e.g. “TCR Auction Charge”) Charge Type Settlement Formula is the equation that is used to settle the charge type Billing Determinants are data inputs and intermediate calculations used to calculate the final result to be output on the settlement

Post Real-Time Market Activities Charge Type – Sign Convention Activity (+) (-) *Energy Transactions Withdrawal Injection Bilateral Settlement Schedules Buyer Seller Transmission Congestion Rights Charges Credits Settlement Statements / Invoices Payment due SPP Payment due MP *Generation, Load, Imports, Exports, and Virtuals

Post Real-Time Market Activities Settlement Invoices Settlement Invoice is a weekly summary of the net daily charges and credits by Market Participants and associated Asset Owner and Operating Day Contains all data for all Operating Days settled during the invoice period Net amounts for each Operating Day contribute to invoice amounts Market Participant is the financially responsible entity SPP Market Participant Asset Owner

Post Real-Time Market Activities Settlement Invoices (cont’d) Market Participants $ Market Participants are responsible for paying invoices Payments due to SPP must be made in full (regardless of any billing dispute) Payments for market settlements flow through SPP Market Participants with a net credit balance will receive that balance - adjusted for balances not collected

Post Real-Time Market Activities Disputes A dispute is a discrepancy Market Participants uncover when reviewing their Settlement Statement Market Participants may dispute items set forth in any Settlement Statement (initial, final, resettlement) NOTE: In case of a resettlement, only incremental differences can be disputed Dispute Submission Timeline Market Participants can begin submission immediately after the receipt of their initial settlement statement Market Participants have up to 90 calendar days after the final settlement statement to file a dispute for that Operating Day Any adjustments from a resolved dispute will be posted to a subsequent settlement statement

Post Real-Time Market Activities Disputes (cont’d) OD +7 OD+47 OD+77 OD+107 OD+137 OD+167 SPP publishes Initial Settlement Statement SPP publishes Final Settlement Statement Resettlements R1 (OD+77) and R3 (OD+137) will be utilized if the dispute resolution results in at least a 25% financial change in a Market Participant’s Settlement Statement Dispute Filing Period for Initial and Final Settlement Statements Resettlements R2 (OD+107) and R4 (OD+167) require a dispute regardless of financial impact

Post Real-Time Market Activities Disputes (cont’d) Disputes must be filed on the Request Management System using the Contents of Notice dispute form Each dispute is tracked throughout the process and assigned the following statuses: Open Closed Denied Granted Granted with Exceptions Withdrawn

Market Participant Milestones TCR Market Trials Begins

Carrie Simpson Lead Analyst, Market Design 501-688-1757 csimpson@spp Carrie Simpson Lead Analyst, Market Design 501-688-1757 csimpson@spp.org Heather Starnes Manager, Regulatory Policy 501-516-0041 hstarnes@spp.org Debbie James Manager, Market Design 501-614-3577 djames@spp.org