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MOPC Workshop Series on Future Markets: Session I August 24, 2010 SPP. org 11 MOPC Workshop Series on Future Markets: Session I August 24, 2010 SPP. org 11

Agenda Ø Introduction Ø The Day Ahead Market Ø Reliability Unit Commitment (RUC) Ø Agenda Ø Introduction Ø The Day Ahead Market Ø Reliability Unit Commitment (RUC) Ø The Real-Time Balancing Market Ø Financial Schedules Ø Virtual Transactions Ø Co-optimization Ø Scarcity Pricing SPP. org 2

Objectives § Describe high level overview of the relationships between the DA Market, RUC, Objectives § Describe high level overview of the relationships between the DA Market, RUC, and RTBM. § Define Demand Bids and Resource Offers in the Day-Ahead Market § Provide examples for Demand Bids and Resource Offers cleared in the DA Market. § Define virtual transactions and financial schedules § Explain examples for virtuals transactions and financial schedules. § Define co-optimization of Energy and Operating Reserves § Understand example of a co-optimized, least-cost solution. § Define scarcity pricing of Operating Reserves § Identify examples of scarcity pricing in the Future Market design SPP. org 3

INTRODUCTION SPP. org 4 INTRODUCTION SPP. org 4

Future Markets Motivation • Increase Market Participant savings by moving from selfcommitment to centralized Future Markets Motivation • Increase Market Participant savings by moving from selfcommitment to centralized unit commitment • Create a Day-Ahead Market so members can get price assurance capability prior to real-time • Market-based Operating Reserves to support the Consolidated Balancing Authority (CBA) SPP. org 5

Future Market Products Ø Energy Ø Operating Reserve § Regulation o Regulation Up o Future Market Products Ø Energy Ø Operating Reserve § Regulation o Regulation Up o Regulation Down § Spinning § Supplemental SPP. org 6

SPP Regulation Reserve Definition Ø Regulation Deployment § Ø Regulation-Down § Ø The utilization SPP Regulation Reserve Definition Ø Regulation Deployment § Ø Regulation-Down § Ø The utilization of Regulation-Up and Regulation-Down through Automatic Generation Control (“AGC”) equipment to automatically and continuously adjust Resource output to balance the SPP Balancing Authority Area in accordance with NERC control performance criteria. Resource capacity that is available for the purpose of providing Regulation Deployment between zero Regulation Deployment and the down direction. Regulation-Up § Resource capacity held in reserve for the purpose of providing Regulation Deployment between zero Regulation Deployment and the up direction. SPP. org 7

SPP Spinning Reserve Definition Ø “The portion of Contingency Reserve consisting of Resources synchronized SPP Spinning Reserve Definition Ø “The portion of Contingency Reserve consisting of Resources synchronized to the system and fully available to serve load within the Contingency Reserve Deployment Period following a contingency event. ” Ø SPP defines contingency deployment period as 10 minute interval SPP. org 8

SPP Supplemental Reserve Definition Ø “The portion of Operating Reserve consisting of on-line or SPP Supplemental Reserve Definition Ø “The portion of Operating Reserve consisting of on-line or off-line Resources capable of being synchronized to the system that is fully available to serve load within the Contingency Reserve Deployment Period following a contingency event. ” Ø SPP defines contingency deployment period as 10 minute interval SPP. org 9

Future Energy and Operating Reserve Market Functions DA Market Offers (Energy and Operating Reserve), Future Energy and Operating Reserve Market Functions DA Market Offers (Energy and Operating Reserve), Bids, Operating Reserve Requirements Day -Ahead Market (DA Market) RTBM Offers, Load Forecast, Operating Reserve Requirements DA Market r Commitment DA Market Commitment, Cleared Energy and Operating Reserve (MW and Price) (hourly) Reliability Unit Commitment (RUC) RTBM Offers, Load Forecast, Operating Reserve Requirements RUC Commitment DA Market & Net RTBM Settlements Resource and Load Meter Data Real -Time Balancing Market (RTBM) Dispatch Instruction, cleared Operating Reserve R (MW and Price) (5 minute) Dispatch Instruction, cleared Operating Reserve (MW) (5 minute) EMS TCR Markets SPP. org 10

Example Conventions Ø To stay consistent with SPP Settlements, all the examples throughout the Example Conventions Ø To stay consistent with SPP Settlements, all the examples throughout the presentation that involve settlement calculations follow the convention below: SPP. org 11

THE DAY-AHEAD MARKET (DA Market) SPP. org 12 THE DAY-AHEAD MARKET (DA Market) SPP. org 12

Understanding The Day Ahead Market Ø The Day Ahead Market provides Market Participants with Understanding The Day Ahead Market Ø The Day Ahead Market provides Market Participants with the ability to submit offers to sell Energy, Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve and/or to submit bids to purchase Energy Ø SPP goal is to create a financially-binding day-ahead schedule for Energy and Operating Reserves Ø SPP will use a “Security-Constrained Unit Commitment” software to derive the day-ahead schedule, based on resource offers and bids submitted by Market Participant at 11 am on the day prior to Operating Day SPP. org 13

Understanding The Day Ahead Market Bid in Load and Operating Reserves cleared in DA Understanding The Day Ahead Market Bid in Load and Operating Reserves cleared in DA Market Megawatts Generation cleared in DA Market Self Committed Resources (Day Ahead Input) 1 Ø 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour Generation committed through the Day-Ahead Market is selected by SPP in a way that results in the lowest total production cost to serve bid in load and to meet Operating Reserve requirements in the Day-Ahead Market. SPP. org 14

Highlights Ø Market Participants submit Offers and Bids by 11: 00 am previous day Highlights Ø Market Participants submit Offers and Bids by 11: 00 am previous day to Operating Day § Suppliers submit MW quantity and price offers for each hour of Operating Day including any Operating Reserve Offers § Loads submit MW requirement bids for each hour of Operating Day including any price sensitive load bids § Includes offers / bids for virtual supply and virtual load Ø Security Constrained Unit Commitment (SCUC) scheduling software co-optimizes Energy and Operating Reserves for least cost solution SPP. org 15

Highlights Ø Locational Marginal Prices (LMPs) and Operating Reserve Market Clearing Prices (MCPs) posted Highlights Ø Locational Marginal Prices (LMPs) and Operating Reserve Market Clearing Prices (MCPs) posted by 4: 00 PM previous day to Operating Day § Cleared Energy supply paid at Settlement Location LMP § Cleared Energy demand charged at Settlement Location LMP § Cleared Operating Reserves paid at the Reserve Zone MCPs Ø SPP guarantees revenue sufficiency of committed resource Offers Ø Supply-Demand deviations settled in Real-Time Market SPP. org 16

DA Market Resource Offers: Energy and OR Cleared Energy & OR Offers DA Market DA Market Resource Offers: Energy and OR Cleared Energy & OR Offers DA Market Demand Bids DA Market Import, Export & Interchange Transactions Cleared Energy Bids: Virtuals & Demand Resource Outage Notifications Cleared Import, Export & Interchange Transactions SPP Operating Reserve Requirements Virtual Energy Offers and Bids [SCUC] SPP. org 17

DA Market Timeline - SPP Publishes Load and Wind Forecast - SPP publishes Operating DA Market Timeline - SPP Publishes Load and Wind Forecast - SPP publishes Operating Reserve requirements 0600 - Submit DA Demand Bids, Unit Offers (Energy & OR), Virtual bids & offers and physical transactions to SPP 1100 - SPP runs SCUC in the dayahead mode 1600 - Submit revised offers and/or self schedules for units that were not selected in DA run 1700 - SPP runs SCUC in RUC mode 1900 - SPP reports DA RUC results to affected market participants 2000 Day Prior to Operating Day SPP. org 18

What Data Will Market Participants Need to Submit to SPP for Resources? Ø 3 What Data Will Market Participants Need to Submit to SPP for Resources? Ø 3 -Part Energy Offers § Ø Operating Reserve Offers Energy Offer Curve ($/MWh as a function of MW) § Startup Offers ($/Start for hot, warm, and cold starts) § § Regulation Up ($/MW) § Regulation Down ($/MW) § Spin ($/MW) § Supplemental ($/MW) No-Load Offers ($/hr) SPP. org 19

What Data Will Market Participants Need to Submit to SPP for Resources? Ø Ø What Data Will Market Participants Need to Submit to SPP for Resources? Ø Ø Operating Parameters and Limits Commit Status § Market § Ramp rates § Reliability § Hourly min and max operation limits § Self § Hourly min and max emergency Ø limits § Outage Energy Dispatch Status § Min and max run time, § Market § Min down time § VER § Etc. § Not Qualified Ø OR Dispatch Status § Market § Fixed § Not Qualified SPP. org 20

Energy 3 -Part Offer The cost that a Market Participant incurs in starting up Energy 3 -Part Offer The cost that a Market Participant incurs in starting up a generating unit The cost for operating a synchronized Resource at zero (0) MW output. A set of price/quantity pairs that represents the offer to provide Energy from a Resource SPP. org 21

Energy 3 -Part Offer Example Consider the following Market Participant Resource: Resource Type 120 Energy 3 -Part 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 Assuming the Market Participant decides to offer this Resource at cost, formulate its 3 -part offer SPP. org 22

Energy 3 -Part Offer Example Consider the following Market Participant Resource: Resource Type 120 Energy 3 -Part Offer Example Consider the following Market Participant Resource: Resource Type 120 MW Gas Unit Fuel Gas Fuel Cost ($/MMBTU) 7 Incremental Heat Rate (MMBTU/MWh) 10 No-Load Heat (MMBTU/Hr) 100 Startup Fuel Requirement (MMBTU) Hot=1000; Warm=2000; Cold=2500 Min Econ. Capacity Limit (MW) 25 Max Econ. Capacity Limit (MW) 120 Startup Offer ($) Hot Warm Cold 7, 000 14, 000 17, 500 No Load Offer ($/h) Incremental Offer MW SPP. org 25 70 120 700 $/MWh 70 23

Operating Reserve Offers Ø An Operating Reserve Offer is an offer to supply Reserve Operating Reserve Offers Ø An Operating Reserve Offer is an offer to supply Reserve Product capacity Ø Impact: § Financial o § Market Participants receive payment for cleared Offers Reliability o Additional capacity offered into the DA Market allows SPP to cover all of its Operating Reserve Requirements SPP. org 24

What Data Will Market Participants Need to Submit to SPP for Loads? Ø Fixed What Data Will Market Participants Need to Submit to SPP for Loads? Ø Fixed Demand Bids § Market Participants specify a MW quantity, load location, and hours and become price takers. The bid will be cleared regardless of the price at the load settlement location. Ø Price-Sensitive Demand Bids § Market Participants specify a MW quantity/price pairs, load location, and hours. A price sensitive demand bid is a bid to buy generation as the price decreases. SPP. org 25

|Example 1| Day Ahead Market: Incremental Energy Offer MP 1 Gen 1 Load 1 |Example 1| Day Ahead Market: Incremental Energy Offer MP 1 Gen 1 Load 1 • MP 1 submits the DA Incremental Offer Curve below for resource Gen 1 for hour 1100. Assuming Gen 1 is online and that DA Market LMP clears at $40/MWh, determine Gen 1’s expected: • DA Energy award • DA Energy credit / charge Gen 1 DA Energy Offer Curve MW $/MWh 25 10 50 25 75 50 DA Energy Award = 65 MWh 120 60 DA Energy Credit/Charge = - DA Award * DA LMP = -65 x 40 = -$2600 (credit) SPP. org 26

|Example 2| Day Ahead Market: Price Sensitive Demand Bid • Assume MP 1 submits |Example 2| Day Ahead Market: Price Sensitive Demand Bid • Assume MP 1 submits the DA Price Sensitive Demand Bid Curve below for resource Load 1 for hour 1100. If DA Market LMP clears at $40/MW, determine Load 1’s expected: • DA Energy award • DA Energy credit / charge MP 1 Gen 1 Load 1 DA Energy Bid Curve MW $/MWh 25 80 50 55 75 30 DA Energy Award = 65 MWh 100 25 DA Energy Credit/Charge = DA Award * DA LMP = 65 x 40 = $2, 600 (charge) SPP. org 27

|Example 3| Day Ahead Market: Operating Reserve Offer MP 1 Gen 1 Load 1 |Example 3| Day Ahead Market: Operating Reserve Offer MP 1 Gen 1 Load 1 • MP 1 submits a $5/MW DA Spin Offer for resource Gen 1 for 1100. Assume Spin clears the DA Market at a 12 $/MW MCP and that Gen 1 cleared 65 MW of Energy. Determine Gen 1’s expected: • DA Spin award • DA Spin credit/charge DA Spin Award = Min [15, 120 – 65] = 15 MW Gen 1 Oper. Cap. Max(MW): 120 Spin Cap. Max (MW): 15 DA Spin Credit/Charge = - DA Award * DA MCP = - 15 x 12 = -$110 (credit) Gen 1 DA Spin Offer Max Spin Cap. (MW) $/MW 15 5 SPP. org 28

Understanding Make Whole Payments Ø SPP Market offers the Make-Whole Payment guarantee: all units Understanding Make Whole Payments Ø SPP Market offers the Make-Whole Payment guarantee: all units that are started by the RTO receive enough DA revenues to cover their 3 part offers (Energy, No. Load, and Startup Offers) and Operating Reserve Offers SPP. org OR Reserve Offer Energy Offer Make-Whole Payment No-Load Offer Startup Offer Market Revenues 29

|Example 4| Day Ahead Market: Understanding Make Whole Payments MP 1 Gen 1 Load |Example 4| Day Ahead Market: Understanding Make Whole Payments MP 1 Gen 1 Load 1 Gen 1 Oper. Cap. Max(MW): 120 Startup Offer ($/start) 17, 500 No-Load ($/hr) 700 Gen 1 DA Energy Offer Curve MW Assume that: • Gen 1 is initially on-line • SPP Commits Gen 1 unit for all 24 hours • DA LMP = 40 $/MWh for all 24 hours • DA Schedule = 65 MWh for all 24 hours Let’s determine: a. DA Revenues b. DA Costs c. DA Make-whole Payment $/MWh 25 10 50 25 75 50 120 60 SPP. org 30

|Example 4| Day Ahead Market: Understanding Make-Whole Payments MP 1 Gen 1 Load 1 |Example 4| Day Ahead Market: Understanding Make-Whole Payments MP 1 Gen 1 Load 1 Gen 1 Oper. Cap. Max(MW): 120 Startup Offer ($/start) 17, 500 No-Load ($/hr) 700 Gen 1 DA Energy Offer Curve MW $/MWh 25 10 50 25 75 Answers: DA Revenues = DA LMP x DA Energy Award x 24 (40 x 65 ) x 24 = $62, 400 DA Costs = (DA Energy Cost + DA No-Load Cost) x 24 = (1, 175 + 700) x 24 =$45, 000 DA Make-Whole Payment = Min{0; DA Rev-DA Cost) 50 120 Assume that: • Gen 1 is initially on-line • ISO Commits Gen 1 unit (cold start) for all 24 hours • DA Schedule = 65 MWh for all 24 hours • DA LMP = 40 $/MWh for all 24 hours 60 = $0 SPP. org 31

|Example 5| Day Ahead Market: Understanding Make-Whole Payments MP 1 Gen 1 Load 1 |Example 5| Day Ahead Market: Understanding Make-Whole Payments MP 1 Gen 1 Load 1 Gen 1 Oper. Cap. Max(MW): 120 Startup Offer ($/start) 17, 500 No-Load ($/hr) 700 Gen 1 DA Energy Offer Curve MW $/MWh 25 25 75 50 120 Let’s determine: a. DA Revenues b. DA Costs c. DA Make-Whole Payment 10 50 Assume that: • Gen 1 is initially off-line • SPP Commits Gen 1 unit (cold start) for all 24 hours • DA Schedule = 65 MWh for all 24 hours • DA LMP = 40 $/MWh for all 24 hours 60 SPP. org 32

|Example 5| Day Ahead Market: Understanding Make-Whole Payments MP 1 Gen 1 Load 1 |Example 5| Day Ahead Market: Understanding Make-Whole Payments MP 1 Gen 1 Load 1 Gen 1 Oper. Cap. Max(MW): 120 Startup Offer ($/start) 17, 500 No-Load ($/hr) 700 Gen 1 DA Energy Offer Curve MW $/MWh 25 10 50 25 75 50 120 Assume that: • Gen 1 is initially off-line • SPP Commits Gen 1 unit (cold start) for all 24 hours • DA Schedule = 65 MWh for all 24 hours • DA LMP = 40 $/MWh for all 24 hours Answers: DA Revenues = DA LMP x Energy Award x 24 (40 x 65 ) x 24 = $62, 400 DA Costs = (Energy Cost + No-Load Cost) x 24 + Startup Cost = (1, 175 + 700)x 24 + 17, 500 = $62, 500 DA Make-Whole Payment = Min{0; DA Rev-DA Cost) 60 = -$100 (credit) SPP. org 33

RELIABILITY UNIT COMMITMENT (RUC) SPP. org 34 RELIABILITY UNIT COMMITMENT (RUC) SPP. org 34

Understanding RUC Ø RUC is required to ensure reliable operating plan during the operating Understanding RUC Ø RUC is required to ensure reliable operating plan during the operating day § Day-Ahead RUC performed following Day-Ahead Market clearing § Intra-Day RUC performed throughout the operating day as needed, at least every 4 hours § RUC process ensures that Market physical commitment produces adequate capacity to meet SPP Load Forecast and Operating Reserve requirements in real-time § Uses SCUC algorithm to commit / de-commit additional resources as needed SPP. org 35

Understanding RUC Bid in Load and Operating Reserve cleared in DA Market Generation committed Understanding RUC Bid in Load and Operating Reserve cleared in DA Market Generation committed in RUC Megawatts SPP Load Forecast and Operating Reserve Requirements (RUC Input) Generation cleared in DA Market Generation de -committed in RUC Self Committed Resources 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour SPP. org 36

Highlights Ø Reliability Unit Commitment (RUC) ensures enough capacity, in addition to Operating Reserve Highlights Ø Reliability Unit Commitment (RUC) ensures enough capacity, in addition to Operating Reserve capacity, is committed to reliably serve the SPP forecasted load for the next operating day Ø All Market Participants need to submit offers for all their registered resources that are not on a planned, forced or otherwise approved outage (Real-Time Balancing Market Resource Offers) Ø RUC will take into consideration the cleared resource commitment schedules from the DA Market or previous RUC clearing process (dependent upon market timeline) Ø Same as in the Day-Ahead Market, Resources committed by the RUC processes are subject to make-whole payments given that they meet the eligibility criteria SPP. org 37

Highlights Ø A Security Constrained Unit Commitment (SCUC) program is used in order to Highlights Ø A Security Constrained Unit Commitment (SCUC) program is used in order to commit (decommit) and dispatch committed resources based on submitted 3 -Part Energy Offers and Operating Reserve Offers in order to meet SPP Load Forecast and Operating Reserve Requirements, respecting transmission system operating constraints Ø RUC clearing is performed for Energy and Operating Reserve products on a least cost, co-optimized basis accounting for Resource marginal impacts on the transmission network (marginal system losses and congestion) SPP. org 38

Resource Commit / De-commit Schedules RTBM Resource Offers DA Confirmed Import, Export & Interchange Resource Commit / De-commit Schedules RTBM Resource Offers DA Confirmed Import, Export & Interchange Transactions Resource Dispatch and AGC Notifications DA Resource Commit Schedules Resource Outage Notifications Fixed Interchange Transaction Curtailment Notification SPP Operating Reserve Requirements SPP Forecasts (Load & Wind) [SCUC] SPP. org 39

Day-Ahead RUC vs. Intra-Day RUC Ø Both RUC processes share the same purpose: ensure Day-Ahead RUC vs. Intra-Day RUC Ø Both RUC processes share the same purpose: ensure a reliable operating plan during the operating day Ø Both processes use similar input data: § Day-Ahead RUC uses outputs from Day-Ahead Market clearing process and the SPP available forecasts in the Day-Ahead period. § Intra-day RUC uses outputs from the Day-Ahead Market, Day-Ahead RUC and previously run Intra-day RUC processes within the operating day § Intra-day RUC uses more up to date forecast data and state estimator data closer to the operating hour SPP. org 40

Day-Ahead RUC Timeline - Submit revised offers and/or self schedules for units that were Day-Ahead RUC Timeline - Submit revised offers and/or self schedules for units that were not selected in DA run 1700 - SPP runs SCUC in RUC mode - SPP reports DA RUC results to affected Market Participants 1900 2000 Day Prior to Operating Day SPP. org 41

Intra-Day RUC Timeline Intra-Day RUC Process 0000 Intra-Day RUC Process 0400 Intra-Day RUC Process Intra-Day RUC Timeline Intra-Day RUC Process 0000 Intra-Day RUC Process 0400 Intra-Day RUC Process 0800 - Submit revised offers and/or self schedules for units that were not selected in previous DA, DA RUC, Intra-Day RUC = Intra-Day RUC Process 1200 1600 Intra-Day RUC Process - SPP runs SCUC in RUC mode - SPP reports RUC results to affected Market Participants Intra-Day RUC Process 2000 2400 Operating Day SPP. org 42

THE REAL-TIME BALANCING MARKET (RTBM) SPP. org 43 THE REAL-TIME BALANCING MARKET (RTBM) SPP. org 43

Understanding the Real-Time Balancing Market Ø The Real-Time Balancing Market (RTBM) serves as the Understanding the Real-Time Balancing Market Ø The Real-Time Balancing Market (RTBM) serves as the mechanism through which SPP balances real-time load and generation. § Resources are selected to be increased (incremented) or decreased (decremented) in order to maintain system balance Generation SPP. org Load 44

Highlights Ø Uses Security Constrained Economic Dispatch (SCED) to ensure results are physically feasible. Highlights Ø Uses Security Constrained Economic Dispatch (SCED) to ensure results are physically feasible. Ø Operates on a continuous 5 -minute basis; calculates Dispatch Instructions for Energy and clears Operating Reserve by resource. Ø Energy and Operating Reserve are co-optimized. Ø Settlements are based on the difference between the results of the RTBM process and the DA Market clearing. Ø Charges are imposed on Market Participants for failure to deploy Energy and Operating Reserve as instructed. SPP. org 45

Highlights Ø 1 -part offer: Energy Offer Curve Ø Operating Reserve Offers § Regulation-up Highlights Ø 1 -part offer: Energy Offer Curve Ø Operating Reserve Offers § Regulation-up and Regulation-down § Spinning Reserve and Supplemental Reserves Ø Accommodates participation of supply and demand external to SPP § Imports, exports and through transactions and external resources SPP. org 46

|Example 6| Real-Time Balancing Market Energy Offer Curve MP 1 Gen 1 Load 1 |Example 6| Real-Time Balancing Market Energy Offer Curve MP 1 Gen 1 Load 1 • MP 1 clears DA as shown in Example 1 and then submits the following Incremental Offer Curve for Resource Gen 1 for hour 1100 in Real-Time. Assuming Gen 1 is online and that RT Market LMP is $40/MWh, Gen 1’s dispatch instruction is 60 MW for each interval of the hour. • What will be settlement for this scenario? Gen 1 RT Energy Offer Curve MW $/MWh 25 10 50 25 75 60 RT Energy Actual= 60 MWh 120 65 RT Energy Settlement = (RT Actual -DA Award) x RT LMP = (-60 + 65) x 40 = $200. 00 (charge) SPP. org 47

|Example 7| Real Time Balancing Market Incremental Energy Offer • MP 1 clears DA |Example 7| Real Time Balancing Market Incremental Energy Offer • MP 1 clears DA as shown in Example 1. Assuming Gen 1 is metered at 70 MWh at hour 1100 and that RT Market LMP clears at $40/MWh, determine Gen 1’s: • RT Energy award • RT Energy settlement MP 1 Gen 1 Load 1 Gen 1 RT Energy Offer Curve MW $/MWh 25 10 50 25 75 50 120 60 RT Energy Award = 70 MWh RT Energy Settlement = (RT Actual -DA Award) x RT LMP = (-70+65) x 40 = -$200 (credit) SPP. org 48

FINANCIAL SCHEDULES SPP. org 49 FINANCIAL SCHEDULES SPP. org 49

Understanding Financial Schedules Ø Bilateral Transactions that transfer financial responsibility within the SPP Market Understanding Financial Schedules Ø Bilateral Transactions that transfer financial responsibility within the SPP Market Footprint § Energy § Operating Reserve § May be entered up to 4 days after Operating Day SPP. org 50

Understanding Financial Schedules Ø Energy Financial Schedules § Must specify o Settlement Location o Understanding Financial Schedules Ø Energy Financial Schedules § Must specify o Settlement Location o MW amount o Buyer o Seller o Pricing (Day-Ahead or Real-Time Balancing Market) o Seller and Buyer confirmation of the transaction SPP. org 51

Understanding Financial Schedules Ø Operating Reserve Financial Schedules § Must specify o Reserve Zone Understanding Financial Schedules Ø Operating Reserve Financial Schedules § Must specify o Reserve Zone o Operating Reserve Product o MW amount o Buyer o Seller o Pricing o Seller and Buyer confirmation of the transaction SPP. org 52

|Example 8| Understanding Financial Schedules: Energy Bilateral DA Market Clearing (Supply) Energy Award(MW): 100 |Example 8| Understanding Financial Schedules: Energy Bilateral DA Market Clearing (Supply) Energy Award(MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 Assume DA Market clears as shown above. MP 2 purchases 100 MW from MP 1 @ 45 $/MWH by entering into a bilateral transaction. The parties agree to submit an 100 MW Financial Schedule that is settled at MP 1 Settlement Location. Determine MP 1 and MP 2 DA impacts if: a) One of the Market Participants fails to confirm the above financial schedule with SPP b) Both Market Participants confirm the financial schedule with SPP. org 53

|Example 8| Understanding Financial Schedules: Energy Bilateral a) Financial Schedule not confirmed by Market |Example 8| Understanding Financial Schedules: Energy Bilateral a) Financial Schedule not confirmed by Market Participants with SPP DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP 1 SPP Settlement DA Market Settlement = - DA Award x DA LMP = 100 x 40 = -$4, 000 (credit) MP 1 Books (this bilateral transaction occurs outside SPP) MP 1 gets paid by MP 2 an amount equal to $4, 500 (=100 x 45) In total, the impact on MP 1 is a total credit of $8, 500 since the Financial Schedule was not confirmed with SPP. org 54

|Example 8| Understanding Financial Schedules: Energy Bilateral a) Financial Schedule not confirmed by Market |Example 8| Understanding Financial Schedules: Energy Bilateral a) Financial Schedule not confirmed by Market Participants with SPP DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP 2 SPP Settlement DA Market Settlement = DA Award x DA LMP = 100 x 50= $5, 000 (charge) MP 2 Books (this bilateral transaction occurs outside SPP) MP 2 pays MP 1 an amount equal to $4, 500 (= 100 x 45) In total, the impact on MP 2 is a total charge of $9, 500 since the Financial Schedule was not confirmed with SPP. org 55

|Example 8| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants |Example 8| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants to SPP DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP 1 SPP Settlement Gen 1 DA Settlement = -DA Award x DA LMP = -100 x 40 = -$4, 000 (credit) DA Financial Schedule Settlement = Fin Sched x DA LMP = 100 x 40 = $4, 000 (charge) DA Net Settlement =- 4, 000 + 4, 000 = $0 MP 1 Books (this bilateral transaction occurs outside SPP) MP 1 gets paid by MP 2 an amount equal to $4, 500 (=100 x 45) In total, the impact on MP 1 is a total credit of $4, 500 since the Financial Schedule was confirmed with SPP. org 56

|Example 8| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants |Example 8| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants to SPP DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP 2 SPP Settlement Load 2 DA Settlement = DA Award x DA LMP = 100 x 50 = $5, 000 (charge) DA Financial Schedule Settlement = -Fin Sched x DA LMP = -100 x 40 = $4, 000 (credit) DA Net Settlement = 5, 000 – 4, 000 = $1, 000 (charge) MP 2 Books (this bilateral transaction occurs outside SPP) MP 2 pays MP 1 an amount equal to $4, 500 ( = 100 x 45) In total, the impact on MP 2 is a total charge of $5, 500 since the Financial Schedule was confirmed with SPP. org 57

|Example 9| Understanding Financial Schedules: Energy Bilateral DA Market Clearing (Supply) Energy Award (MW): |Example 9| Understanding Financial Schedules: Energy Bilateral DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 Assume DA Market clears as shown above. MP 2 purchases 100 MW from MP 1 @ 45 $/MWH by entering into a bilateral transaction. The parties agree to submit an 100 MW Financial Schedule that is settled at MP 2 Settlement Location. Determine MP 1 and MP 2 DA impacts if both Market Participants confirm the financial schedule with SPP. org 58

|Example 9| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants |Example 9| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants to SPP DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP 1 SPP Settlement Gen 1 DA Settlement = -DA Award x DA LMP = -100 x 40 = -$4, 000 (credit) DA Financial Schedule Settlement = Fin Sched x DA LMP =100 x 50 = $5, 000 (charge) DA Net Settlement = - 4, 000 + 5, 000= $1, 000 (charge) MP 1 Books (this bilateral transaction occurs outside SPP) MP 1 gets paid by MP 2 an amount equal to $4, 500 ( = 100 x 45) In total, the impact on MP 1 is a total credit of $3500 since the Financial Schedule was confirmed with SPP. org 59

|Example 9| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants |Example 9| Understanding Financial Schedules: Energy Bilateral b) Financial Schedule confirmed by Market Participants to SPP DA Market Clearing (Supply) Energy Award (MW): 100 DA LMP ($/MWH): 40 MP 1 MP 2 Gen 1 Load 2 DA Market Clearing (Load) Energy Award (MW): 100 DA LMP ($/MWH): 50 MP 2 SPP Settlement Load 2 DA Settlement = DA Award x DA LMP = 100 x 50 = $5, 000 (charge) DA Financial Schedule Settlement = - Fin Sched x DA LMP = 100 x 50 = -$5, 000 (credit) DA Net Settlement = 5, 000 – 5, 000 = $0 MP 2 Books (this bilateral transaction occurs outside SPP) MP 2 pays MP 1 an amount equal to $4, 500 ( = 100 x 45) In total, the impact on MP 2 is a total charge of $4500 since the Financial Schedule was confirmed with SPP. org 60

VIRTUAL TRANSACTIONS SPP. org 61 VIRTUAL TRANSACTIONS SPP. org 61

Understanding Virtual Transactions Ø What is a Virtual Transaction? § Virtual Energy Bids and Understanding Virtual Transactions Ø What is a Virtual Transaction? § Virtual Energy Bids and Offers allow any Market Participant to bid or offer at any Settlement Location in the SPP Day-Ahead Market. § If a virtual transaction is cleared, the Market Participant will settle the Bid or Offer at the difference between the Day-Ahead Market LMP and the Real-Time Balancing Market (RTBM) LMP for the full amount of the Day-Ahead award. § The net effect of Virtual Energy Bids and Offers is to cause the Day. Ahead LMP and RTBM LMP to converge. o If there is a location that is expected to be more expensive in the DA Market than in the RTBM, participants may be incented to submit Virtual Energy Offers until, over time, the two markets equalize in price. SPP. org 62

Understanding Virtual Transactions: Settlement Ø Virtual Offer § § If DA LMP > Offer Understanding Virtual Transactions: Settlement Ø Virtual Offer § § If DA LMP > Offer Price, Offer is cleared in Day-Ahead for Offer Quantity § If cleared, Market Participant must buy back Energy awarded from SPP at the Real. Time price § If DA LMP > RT LMP Market Participant realizes a profit § Ø Offer Quantity (MW) into DA Market at an Offer Price ($/MWh) If DA LMP < RT LMP Market Participant incurs losses Virtual Bid § Bid Quantity (MW) into DA Market at Bid Price ($/MWh) § If DA LMP < Bid Price, bid is cleared in day-ahead for Bid Quantity § If cleared, Market Participant must sell back Energy awarded to SPP at the Real. Time price § If DA LMP < RT LMP Market Participant realizes a profit § If DA LMP > RT LMP Market Participant incurs losses SPP. org 63

|Example 10| Understanding Virtual Transactions: Virtual Offer • MP 1 submits a Virtual Energy |Example 10| Understanding Virtual Transactions: Virtual Offer • MP 1 submits a Virtual Energy Offer Curve for hour 1100 in Day-Ahead. Assuming the DA LMP clears at $40/MWh and the RT LMP clears at $35/MWh, determine the virtual’s: • DA Energy award • Net Energy Settlement of the Virtual financial position MP 1 Gen 1 Load 1 MP 1 DA Virtual Offer Curve MW $/MWh 5 25 10 35 DA Energy Award = 12. 5 MWh 15 45 Net Energy Settlement = - DA Award x (DA LMP – RT LMP) = -12. 5 x (40 -35) = - $62. 5 (credit) SPP. org 64

|Example 11| Understanding Virtual Transactions: Virtual Offer • MP 1 submits a Virtual Energy |Example 11| Understanding Virtual Transactions: Virtual Offer • MP 1 submits a Virtual Energy Offer Curve for hour 1100 in Day-Ahead. Assuming the DA LMP clears at $40/MWh and the RT LMP clears at $45/MWh, determine the virtual’s: • DA Energy award • Net Energy Settlement of the Virtual financial position MP 1 Gen 1 Load 1 MP 1 DA Virtual Offer Curve MW $/MWh 5 25 10 35 DA Energy Award = 12. 5 MWh 15 45 Net Energy Settlement = - DA Award x (DA LMP – RT LMP) = -12. 5 x (40 -45) = $62. 5 (charge) SPP. org 65

|Example 12| Understanding Virtual Transactions: Virtual Bid • MP 1 submits a Virtual Energy |Example 12| Understanding Virtual Transactions: Virtual Bid • MP 1 submits a Virtual Energy Bid Curve for hour 1100 in Day-Ahead. Assuming that the DA LMP clears at $40/MWh and the RT LMP clears at $35/MWh, determine the virtual’s: • DA Energy award • Net Energy Settlement of the Virtual financial position MP 1 Gen 1 Load 1 MP 1 DA Virtual Bid Curve MW $/MWh 5 45 10 20 DA Energy Award = 6 MWh 15 5 Net Energy Settlement = DA Award x (DA LMP – RT LMP) = 6 x (40 -35) = $30 (charge) SPP. org 66

|Example 13| Understanding Virtual Transactions: Virtual Bid • MP 1 submits a Virtual Energy |Example 13| Understanding Virtual Transactions: Virtual Bid • MP 1 submits a Virtual Energy Bid Curve for hour 1100 in Day-Ahead. Assuming that the DA LMP clears at $40/MWh and the RT LMP clears at $45/MWh, determine the virtual’s: • DA Energy award • Net Energy Settlement of the Virtual financial position MP 1 Gen 1 Load 1 MP 1 DA Virtual Bid Curve MW $/MWh 5 45 10 20 DA Energy Award = 6 MWh 15 5 Net Energy Settlement = DA Award x (DA LMP – RT LMP) = 6 x (40 -45) = - $30 (credit) SPP. org 67

CO-OPTIMIZATION SPP. org 68 CO-OPTIMIZATION SPP. org 68

Understanding Co-optimization Why co-optimize? Ø There is a strong interaction between the supply of Understanding Co-optimization Why co-optimize? Ø There is a strong interaction between the supply of Energy and the provision of Operating Reserve § Energy and Operating Reserve compete for same resource capacity § Co-optimization evaluates the lost opportunity costs trade-offs when allocating products (Energy, Operating Reserve) SPP. org 69

Understanding Co-optimization Ø When clearing the market (Day-Ahead and Real-Time), SPP must determine an Understanding Co-optimization Ø When clearing the market (Day-Ahead and Real-Time), SPP must determine an operating schedule that: Ø Ø Maximizes Market Participants benefits for all the market products that they have submitted Bids and Offers on, Ø Ø Minimizes the SPP total production costs, based on Offers and Bids of Market Participants and , Ensures that all reliability and transmission constraints are met. The market clearing optimization engine proposed by SPP is a cooptimization engine, which takes Bids and Offers of all market products (Energy, Spinning Reserve, Regulation-Up, Regulation-Down, Supplemental Reserve) for all Market Participants and simultaneously determine the market products allocation amongst Market Participants that achieves the above mentioned objectives. SPP. org 70

Understanding Co-optimization Ø Does co-optimization produce a schedule that minimizes the total production cost Understanding Co-optimization Ø Does co-optimization produce a schedule that minimizes the total production cost for SPP? Ø Does co-optimization produce a schedule that maximizes operating profits for Market Participants? Ø Can we explain Operating Reserve prices calculated by the optimization engine? SPP. org 71

Understanding Co-optimization: Examples Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max Understanding Co-optimization: Examples Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 50 120 8 15 2 MP 1 Load 1 Energy Forecast (MW): End User Rate ($/MWH): Spin Requirement (MW): 50 120 10 15 3 MP 2 Load 2 Energy Forecast (MW): End User Rate ($/MWH): Spin Requirement (MW): 100 40 10 Balancing Authority 1 100 45 10 Balancing Authority 2 Ø Consider 2 Market Participants MP 1 and MP 2 as above, each with generation resources and load to serve with a reliability requirement in the form of Spinning Reserve. Ø How can these Market Participants benefit most from SPP future market operations? SPP. org 72

Understanding Co-optimization: Examples Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max Understanding Co-optimization: Examples Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 50 120 8 15 2 Reserve Zone Spin Requirement (MW): 20 MP 1 Load 1 Energy Forecast (MW): End User Rate ($/MWH): Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 50 120 10 15 3 MP 2 Load 2 Energy Forecast (MW): End User Rate ($/MWH): 100 40 100 45 Consolidated Balancing Authority Ø In SPP future market operations, there will be only one Consolidated Balancing Authority, responsible for establishing reliability requirements throughout SPP network footprint. Ø In the following case studies, we assume that: Ø Both Market Participants belong to the same Reserve Zone and offer their generation at cost, Ø The network has no congestion and no losses. SPP. org 73

|Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market |Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 50 120 8 15 2 Reserve Zone Spin Requirement (MW): MP 1 Load 1 Energy Forecast (MW): End User Rate ($/MWH): Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 20 50 120 10 15 3 MP 2 Load 2 Energy Forecast (MW): End User Rate ($/MWH): 100 40 Ø Let’s determine: Ø Each Market Participant awards (Energy and Spin), operational cost and LMP, Ø The Reserve Zone Spin MCP, Ø SPP total production cost, Ø 100 45 Each Market Participant profit margin. SPP. org 74

|Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market |Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 50 120 8 15 2 Reserve Zone Spin Requirement (MW): MP 1 Load 1 Energy Forecast (MW): End User Rate ($/MWH): Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 20 50 120 10 15 3 MP 2 Load 2 Energy Forecast (MW): End User Rate ($/MWH): 100 40 Ø Let’s determine: Ø Each Market Participant awards (Energy and Spin), operational cost and LMP, Ø The Reserve Zone Spin MCP, Ø SPP total production cost, Ø 100 45 Each Market Participant profit margin. SPP. org 75

|Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market |Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) Reserve Zone Spin Requirement (MW): Gen 1 Energy Award (MW): Spin Award (MW): 100 10 Load 2 Energy Forecast (MW): 100 10 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 0 MW >> MP 2 100 LMP = 8 $/MWH Spin Market Clearing Price = 2 $/MW MP 1 Gen. Schedule (MW) Operational Cost ($) Energy 100 800 Spin 10 Total - MP 2 Gen. Schedule (MW) Operational Cost ($) Energy 100 1, 000 20 Spin 10 30 820 Total - 1, 030 Total System Operational Cost = $ 1, 850 SPP. org 76

|Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market |Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 100 10 Load 2 Energy Forecast (MW): 100 10 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 0 MW >> MP 2 100 LMP = 8 $/MWH Spin Market Clearing Price = 2 $/MW Explaining LMPs: Why is LMP = 8 $/MWH at MP 1’s price node? Answer: if we increase the load at MP 1’s price node by 1 MW, that increase would be most economically met by: - increasing Gen 1’s energy schedule by 1 MW → production cost impact = (101 -100) x 8 = $ 8 SPP. org 77

|Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market |Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 100 10 Load 2 Energy Forecast (MW): 100 10 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 0 MW >> MP 2 100 LMP = 8 $/MWH Spin Market Clearing Price = 2 $/MW Explaining MCPs : Why is Spin Clearing Price = 2 $/MW? Answer: if we increase the Spinning Reserve system requirement by 1 MW, that need would be most economically met by: - increasing Gen 1’s Spinning Reserve schedule by 1 MW → production cost impact = (11 -10) x 2 = $ 2 SPP. org 78

|Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market |Example 14| Understanding Co-optimization: Non-Co-optimized case Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 100 10 Load 2 Energy Forecast (MW): 100 10 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 0 MW >> MP 2 100 LMP = 8 $/MWH Spin Market Clearing Price = 2 $/MW Operating Profit Revenues ($) Generation MP 1: 820. 00 Demand MP 1: Charges ($) 820. 00 Costs ($) 820. 00 Net Profit ($) 0. 00 Generation MP 2: Revenues ($) Net Profit ($) 4, 000. 00 3, 180. 00 Demand MP 2: MP 1 Profit = $ 3, 180 Revenues ($) 820. 00 Charges ($) 820. 00 Costs ($) 1, 030. 00 Net Profit ($) -210. 00 Revenues ($) Net Profit ($) 4, 500. 00 3, 680. 00 MP 2 Profit = $ 3, 470 SPP. org 79

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 50 120 8 15 2 Reserve Zone Spin Requirement (MW): MP 1 Load 1 Energy Forecast (MW): End User Rate ($/MWH): Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): 20 50 120 10 15 3 MP 2 Load 2 Energy Forecast (MW): End User Rate ($/MWH): 100 40 100 45 Consolidated Balancing Authority Ø Let’s determine: Ø Each Market Participant awards (Energy and Spin), operational cost and LMP, Ø The Reserve Zone Spin MCP, Ø SPP total production cost, Ø Each Market Participant profit margin. SPP. org 80

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Reserve Zone Spin Requirement (MW): Gen 1 Energy Award (MW): Spin Award (MW): 15 MW >> 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 100 MP 2 100 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW MP 1 Gen. Schedule (MW) Operational Cost ($) 115 920 Spin 5 Total - Energy MP 2 Gen. Schedule (MW) Operational Cost ($) Energy 85 850 10 Spin 15 45 930 Total - 895 Total System Operational Cost = $ 1, 825 SPP. org (vs. $ 1, 850 in Example 14) 81

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 15 MW >> 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 100 MP 2 100 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW Explaining LMPs : Why is LMP = 10 $/MWH at MP 1’s price node? Answer: if we increase the load at MP 1’s price node by 1 MW, that increase would be most economically met by: - increasing Gen 2’s energy schedule by 1 MW → production cost impact = (86 -85) x 10 = $ 10 SPP. org 82

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 15 MW >> 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 100 MP 2 100 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW Explaining LMPs : Why is LMP = 10 $/MWH at MP 1’s price node? Answer: if we increase the load at MP 1’s price node by 1 MW, that increase would be most economically met by: - increasing Gen 2’s energy schedule by 1 MW → production cost impact = (86 -85) x 10 = $ 10 SPP. org 83

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 15 MW >> 100 MP 2 100 LMP = 10 $/MWH 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW Explaining MCPs: Why is Spin Clearing Price = 4 $/MW? Answer: if we increase the Spinning Reserve system requirement by 1 MW, that need would be most economically met by: - decreasing Gen 1’s energy schedule by 1 MW → production cost impact = (114 – 115) x 8 = - $ 8 - increasing Gen 2’s energy schedule by 1 MW → production cost impact = (86 -85) x 10 = $ 10 - increasing Gen 1’s Spinning Reserve schedule by 1 MW → production cost impact = (6 -5) x 2 = $ 2 SPP. org 84

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 15 MW >> 100 MP 2 100 LMP = 10 $/MWH 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW Operating Profit Revenues ($) Generation MP 1: 1, 170. 00 Demand MP 1: Charges ($) 1, 040. 00 MP 1 Profit = $ 3, 200 Costs ($) 930. 00 Net Profit ($) 240. 00 Generation MP 2: Revenues ($) Net Profit ($) 4, 000. 00 2, 960. 00 Demand MP 2: (vs. $ 3, 180 in Example 14) Revenues ($) 910. 00 Charges ($) 1, 040. 00 Costs ($) 895. 00 Net Profit ($) 15. 00 Revenues ($) Net Profit ($) 4, 500. 00 3, 460. 00 MP 2 Profit = $ 3, 475 (vs. $ 3, 470 in Example 14) SPP. org 85

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 15 MW >> 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 100 MP 2 100 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW Explaining Profit Maximization: Is MP 2 Profit maximized? Answer: Yes, since MP 2 is being awarded as much spinning reserve (its most profitable product) first followed by energy next (less profitable product). Offer ($/MW) Market Price ($/MW) Profit Margin ($/MW) Energy: 10 10 10 – 10 = 0 Spin: 3 4 4– 3=1 SPP. org 86

|Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market Gen 1 Energy Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): 15 MW >> 85 15 Load 2 Energy Forecast (MW): 115 5 MP 1 Load 1 Energy Forecast (MW): Gen 2 Energy Award (MW): Spin Award (MW): 20 100 MP 2 100 LMP = 10 $/MWH Spin Market Clearing Price = 4 $/MW Explaining Profit Maximization: Is MP 1 Profit maximized? Answer: Yes, since MP 1 is being awarded as much energy first, followed by Spinning Reserve. Note that both products are equally profitable for this Market Participant. Offer ($/MW) Market Price ($/MW) Profit Margin ($/MW) Energy: 8 10 10 – 8 = 2 Spin: 2 4 4– 2=2 SPP. org 87

Understanding Co-optimization: Conclusion Ø Does co-optimization produce a schedule that minimizes the total production Understanding Co-optimization: Conclusion Ø Does co-optimization produce a schedule that minimizes the total production cost for SPP? Ø Answer: YES No Cooptimization System Cost ($): Ø With Cooptimization 1, 850 1, 825 Does co-optimization produce a schedule that maximizes operating profits for Market Participants? Ø Answer: YES No Cooptimization With Cooptimization MP 1 Profit ($): 3, 180 3, 200 MP 2 Profit ($): 3, 470 3, 475 Total MPs Profits ($): 6, 650 6, 675 SPP. org 88

Understanding Co-optimization: Conclusion Ø Can we explain Operating Reserve prices calculated by the optimization Understanding Co-optimization: Conclusion Ø Can we explain Operating Reserve prices calculated by the optimization engine? Ø Answer: YES Ø Operating Reserve Clearing Price = Lost Opportunity Cost + Operating Reserve Offer Price for marginal unit (which provides the next MW for the Operating Reserve product) Co-optimized Scenario (Example 9): MCP for Spinning Reserve Decreasing Gen 1’s energy schedule by 1 MW: production cost impact = (114 – 115) x 8 = - $ 8 Lost Opportunity Cost = 2 $ + Increasing Gen 2’s energy schedule by 1 MW: production cost impact = (86 – 85) x 10 = $ 10 Marginal Unit Offer Price = 2 $ Increasing Gen 1’s Spinning Reserve schedule by 1 MW: production cost impact = (6 -5) x 2 = $ 2 SPP. org 89

SCARCITY PRICING SPP. org 90 SCARCITY PRICING SPP. org 90

Understanding Scarcity Pricing Ø Scarcity Pricing is a market mechanism that allows prices to Understanding Scarcity Pricing Ø Scarcity Pricing is a market mechanism that allows prices to rise automatically when there is a shortage of supply in the market § Prices set by scarcity pricing should reflect the level of shortage in supply § Scarcity prices enhance market efficiency and reliability o May stimulate demand response o Draw supply from outside the SPP Balancing Authority o Incentivizes generation availability during peak loads o Promotes long-term contracting SPP. org 91

Understanding Scarcity Pricing Ø SPP has implemented Scarcity Pricing in its Future Market Protocols Understanding Scarcity Pricing Ø SPP has implemented Scarcity Pricing in its Future Market Protocols through a set of Demand Curves for Operating Reserve Ø Demand Curves: Set pre-determined prices at different levels of shortages for each of the reserve products: o Operating Reserve o Regulation – Up o Regulation - Down SPP. org 92

Understanding Scarcity Pricing: Examples Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Understanding Scarcity Pricing: Examples Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Reg. Up Cap. Max (MW): Reg. Up Offer Cost ($/MW): Load 1 Energy Forecast (MW): End User Rate ($/MW) 50 120 8 15 2 4. 5 6 Reserve Zone Spin Requirement (MW): Reg Up Requirement (MW): MP 1 - MP 2 Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Reg. Up Cap. Max (MW): Reg. Up Offer Cost (MW): Load 2 Energy Forecast (MW): End User Rate ($/MW) 100 40 50 120 10 15 3 4. 5 4 100 45 Consolidated Balancing Authority Ø In the following case studies, we assume that: Ø Both Market Participants belong to the same Reserve Zone and offer their generation at cost as well as their true economic limits, Ø Reliability requirements are in the form of Regulation-Up and Spinning Reserve, with demand curves set to $200/MW and $75/MW respectively, Ø The network has no congestion and no losses. SPP. org 93

|Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Gen 1 Econ. Oper. Cap. |Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Reg. Up Cap. Max (MW): Reg. Up Offer Cost ($/MW): Load 1 Energy Forecast (MW): End User Rate ($/MW) 50 120 8 15 2 4. 5 6 Reserve Zone Spin Requirement (MW): Reg Up Requirement (MW): MP 1 20 8 MP 2 Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Reg. Up Cap. Max (MW): Reg. Up Offer Cost (MW): Load 2 Energy Forecast (MW): End User Rate ($/MW) 100 40 50 120 10 15 3 4. 5 4 100 45 Consolidated Balancing Authority Ø Let’s determine: Ø Each Market Participant awards (Energy, Reg. Up, Spin) and LMP, Ø Each Market Participant production cost, Ø The Reserve Zone Reg. Up and Spin MCPs, Ø SPP total production cost. SPP. org 94

|Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Gen 1 Energy Award (MW): |Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Gen 1 Energy Award (MW): Reg. Up Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): Reg. Up Requirement (MW): 107 3. 5 9. 5 Load 1 Energy Forecast (MW): MP 1 7 MW >> 20 8 Gen 2 Energy Award (MW): 93 Reg. Up Award (MW): 4. 5 Spin Award (MW): 10. 5 MP 2 Load 2 Energy Forecast (MW): 100 LMP = 10 $/MWH Reg. Up Market Clearing Price = 8 $/MW Spin Market Clearing Price = 4 $/MW MP 1 Gen. Schedule (MW) Operational Cost ($) Energy 107 856 Reg. Up 3. 5 Spin Total MP 2 Gen. Schedule (MW) Operational Cost ($) Energy 93 930 21 Reg. Up 4. 5 18 9. 5 19 Spin 10. 5 31. 5 - 896 Total - 979. 5 Total System Operational Cost = $ 1, 875. 5 SPP. org 95

|Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Gen 1 Energy Award (MW): |Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Gen 1 Energy Award (MW): Reg. Up Award (MW): Spin Award (MW): Load 1 Energy Forecast (MW): Reserve Zone Spin Requirement (MW): Reg. Up Requirement (MW): 107 3. 5 9. 5 MP 1 7 MW >> 20 8 Gen 2 Energy Award (MW): 93 Reg. Up Award (MW): 4. 5 Spin Award (MW): 10. 5 MP 2 Load 2 Energy Forecast (MW): 100 LMP = 10 $/MWH Reg. Up Market Clearing Price = 8 $/MW Spin Market Clearing Price = 4 $/MW Operating Profit Revenues ($) Generation MP 1: 1, 135. 98 Demand MP 1: Charges ($) 1, 072. 00 Costs ($) 896. 00 Net Profit ($) 239. 98 Generation MP 2: Revenues ($) Net Profit ($) 4, 000. 00 2, 928. 00 Demand MP 2: Revenues ($) 1, 008. 00 Charges ($) 1, 072. 00 Costs ($) 979. 50 Net Profit ($) 28. 50 Revenues ($) Net Profit ($) 4, 500. 00 3, 428. 00 MP 2 Profit = $ 3, 448. 50 MP 1 Profit = $ 3, 159. 98 SPP. org 96

|Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Gen 1 Econ. Oper. Cap. Min |Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Gen 1 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Reg. Up Cap. Max (MW): Reg. Up Offer Cost ($/MW): Load 1 Energy Forecast (MW): 50 120 8 15 2 4. 5 6 Reserve Zone Spin Requirement (MW): Reg Up Requirement (MW): MP 1 20 12 MP 2 Gen 2 Econ. Oper. Cap. Min (MW): Econ. Oper. Cap. Max (MW): Energy Offer Cost ($/MWH): Spin Cap. Max (MW): Spin Offer Cost ($/MW): Reg. Up Cap. Max (MW): Reg. Up Offer Cost (MW): Load 2 Energy Forecast (MW): 100 50 120 10 15 3 4. 5 4 100 Consolidated Balancing Authority Ø Let’s determine: Ø Each Market Participant awards (Energy, Reg. Up, Spin) and LMP, Ø Each Market Participant production cost, Ø The Reserve Zone Reg. Up and Spin MCPs, Ø SPP total production cost. SPP. org 97

|Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Gen 1 Energy Award (MW): Reg. |Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Gen 1 Energy Award (MW): Reg. Up Award (MW): Spin Award (MW): Reserve Zone Spin Requirement (MW): Reg. Up Requirement (MW): 106 4. 5 9. 5 Load 1 Energy Forecast (MW): MP 1 6 MW >> 20 12 Gen 2 Energy Award (MW): 94 Reg. Up Award (MW): 4. 5 Spin Award (MW): 10. 5 MP 2 Load 2 Energy Forecast (MW): 100 LMP = 10 $/MWH Reg. Up Market Clearing Price = 200 $/MW Reg. Up Shortage = 3 MW Spin Market Clearing Price = 4 $/MW MP 1 Gen. Schedule (MW) Operational Cost ($) Energy 106 848 Reg. Up 4. 5 Spin Total MP 2 Gen. Schedule (MW) Operational Cost ($) Energy 94 940 27 Reg. Up 4. 5 18 9. 5 19 Spin 10. 5 31. 5 - 894 Total - 989. 5 Total System Operational Cost = $ 1, 883. 5 SPP. org 98

|Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Gen 1 Energy Award (MW): Reg. |Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Gen 1 Energy Award (MW): Reg. Up Award (MW): Spin Award (MW): Load 1 Energy Forecast (MW): Reserve Zone Spin Requirement (MW): Reg. Up Requirement (MW): 106 4. 5 9. 5 MP 1 6 MW >> 20 12 Gen 2 Energy Award (MW): 94 Reg. Up Award (MW): 4. 5 Spin Award (MW): 10. 5 MP 2 Load 2 Energy Forecast (MW): 100 LMP = 10 $/MWH Reg. Up Market Clearing Price = 200 $/MW Reg. Up Shortage = 3 MW Spin Market Clearing Price = 4 $/MW Operating Profit Revenues ($) Generation MP 1: 1, 998. 00 Demand MP 1: Charges ($) 2, 240. 00 Costs ($) 894. 00 Net Profit ($) 1, 104. 00 Generation MP 2: Revenues ($) Net Profit ($) 4, 000. 00 1, 760. 00 Demand MP 2: MP 1 Profit = $ 2, 864. 00 Revenues ($) 1, 882. 00 Charges ($) 2, 240. 00 Costs ($) 989. 50 Net Profit ($) 892. 50 Revenues ($) Net Profit ($) 4, 500. 00 2, 260. 00 MP 2 Profit = $ 3, 152. 50 SPP. org 99

Understanding Scarcity Pricing: Conclusion Ø Operating Reserve Shortage will have an impact on Operating Understanding Scarcity Pricing: Conclusion Ø Operating Reserve Shortage will have an impact on Operating Reserve clearing prices Ø Even in case of Operating Reserve shortage, cooptimization based SCED provides the most economical system total operational cost SPP. org 100

Objectives § Describe high level overview of the relationships between the DA Market, RUC, Objectives § Describe high level overview of the relationships between the DA Market, RUC, and RTBM. § Define Demand Bids and Resource Offers in the Day-Ahead Market § Provide examples for Demand Bids and Resource Offers cleared in the DA Market. § Define virtual transactions and financial schedules § Explain examples for virtuals transactions and financial schedules. § Define co-optimization of Energy and Operating Reserve § Understand example of a co-optimized, lease-cost solution. § Define scarcity pricing of Operating Reserve § Identify examples of scarcity pricing in the Future Market design SPP. org 101

Debbie James Manager, Market Design djames@spp. org Carrie Simpson Senior Market Analyst, Market Design Debbie James Manager, Market Design [email protected] org Carrie Simpson Senior Market Analyst, Market Design [email protected] org SPP. org