1. SPP.org1 1 MOPC Workshop Series on Future Markets: Session I August 24, 2010

2. SPP.org2 Agenda  Introduction  The Day Ahead Market  Reliability Unit Commitment (RUC)  The Real-Time Balancing Market  Financial Schedules  Virtual Transactions  Co-optimization  Scarcity Pricing

3. SPP.org3 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

4. SPP.org4 INTRODUCTION

5. SPP.org5 Future Markets Motivation Increase Market Participant savings by moving from self- commitment 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)

6. SPP.org6 Future Market Products  Energy  Operating Reserve  Regulation oRegulation Up oRegulation Down  Spinning  Supplemental

7. SPP.org7 SPP Regulation Reserve Definition  Regulation Deployment  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.  Regulation-Down  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.

8. SPP.org8 SPP Spinning Reserve Definition  “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.”  SPP defines contingency deployment period as 10 minute interval

9. SPP.org9 SPP Supplemental Reserve Definition  “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.”  SPP defines contingency deployment period as 10 minute interval

10. SPP.org10 Future Energy and Operating Reserve Market Functions

11. SPP.org11 Example Conventions  To stay consistent with SPP Settlements, all the examples throughout the presentation that involve settlement calculations follow the convention below:

12. SPP.org12 THE DAY-AHEAD MARKET (DA Market)

13. SPP.org13 Understanding The Day Ahead Market  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  SPP goal is to create a financially-binding day-ahead schedule for Energy and Operating Reserves  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

14. SPP.org14 Understanding The Day Ahead Market  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. 123456789101112131415161718192021222324 Megawatts Generation cleared in DA Market Bid in Load and Operating Reserves cleared in DA Market Hour Self Committed Resources (Day Ahead Input)

15. SPP.org15 Highlights  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  Security Constrained Unit Commitment (SCUC) scheduling software co-optimizes Energy and Operating Reserves for least cost solution

16. SPP.org16 Highlights  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  SPP guarantees revenue sufficiency of committed resource Offers  Supply-Demand deviations settled in Real-Time Market

17. SPP.org17 Cleared Energy & OR Offers Cleared Energy Bids: Virtuals & Demand Cleared Import, Export & Interchange Transactions RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements [SCUC] RTBM Resource Offers DA Resource Commit Schedules DA Confirmed Import, Export & Interchange Transactions Resource Outage Notifications SPP Operating Reserve Requirements SPP Forecasts (Load & Wind) DA Market Demand Bids DA Market Resource Offers: Energy and OR DA Market Import, Export & Interchange Transactions Resource Outage Notifications SPP Operating Reserve Requirements Virtual Energy Offers and Bids

18. SPP.org18 DA Market Timeline -SPP Publishes Load and Wind Forecast -SPP publishes Operating Reserve requirements -Submit DA Demand Bids, Unit Offers (Energy & OR), Virtual bids & offers and physical transactions to SPP -SPP runs SCUC in the day- ahead mode -Submit revised offers and/or self schedules for units that were not selected in DA run -SPP runs SCUC in RUC mode -SPP reports DA RUC results to affected market participants 060019001100160017002000 Day Prior to Operating Day

19. SPP.org19 What Data Will Market Participants Need to Submit to SPP for Resources?  3-Part Energy Offers  Energy Offer Curve ($/MWh as a function of MW)  Startup Offers ($/Start for hot, warm, and cold starts)  No-Load Offers ($/hr)  Operating Reserve Offers  Regulation Up ($/MW)  Regulation Down ($/MW)  Spin ($/MW)  Supplemental ($/MW)

20. SPP.org20 What Data Will Market Participants Need to Submit to SPP for Resources?  Operating Parameters and Limits  Ramp rates  Hourly min and max operation limits  Hourly min and max emergency limits  Min and max run time,  Min down time  Etc.  Commit Status  Market  Reliability  Self  Outage  Energy Dispatch Status  Market  VER  Not Qualified  OR Dispatch Status  Market  Fixed  Not Qualified

21. SPP.org21 Start-Up Offer No-Load Offer Energy Offer The cost for operating a synchronized Resource at zero (0) MW output. The cost that a Market Participant incurs in starting up a generating unit A set of price/quantity pairs that represents the offer to provide Energy from a Resource Energy 3-Part Offer

22. SPP.org22 Energy 3-Part Offer Example Resource Type120 MW Gas Unit FuelGas 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 Consider the following Market Participant Resource: Assuming the Market Participant decides to offer this Resource at cost, formulate its 3-part offer

23. SPP.org23 Energy 3-Part Offer Example Resource Type120 MW Gas Unit FuelGas Fuel Cost ($/MMBTU)7 Incremental Heat Rate (MMBTU/MWh)10 No-Load Heat (MMBTU/Hr)100 Startup Fuel Requirement (MMBTU)Hot=1000;Warm=2000;Cold=2500 Min Econ. Capacity Limit (MW)25 Max Econ. Capacity Limit (MW)120 Consider the following Market Participant Resource: HotWarmCold 7,00014,00017,500 MW$/MWh 2570 12070 700 Startup Offer ($)No Load Offer ($/h)Incremental Offer

24. SPP.org24 Operating Reserve Offers  An Operating Reserve Offer is an offer to supply Reserve Product capacity  Impact:  Financial o Market Participants receive payment for cleared Offers  Reliability oAdditional capacity offered into the DA Market allows SPP to cover all of its Operating Reserve Requirements

25. SPP.org25 What Data Will Market Participants Need to Submit to SPP for Loads?  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.  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.

26. SPP.org26 |Example 1| Day Ahead Market: Incremental Energy Offer 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 $40/MWh, determine Gen1’s expected: DA Energy award DA Energy credit / charge DA Energy Award = 65 MWh MW$/MWh 2510 5025 7550 12060 Gen1 DA Energy Offer Curve MP1 Gen1 Load1 DA Energy Credit/Charge = - DA Award * DA LMP = -65 x 40 = -$2600 (credit)

27. SPP.org27 |Example 2| Day Ahead Market: Price Sensitive Demand Bid Assume MP1 submits the DA Price Sensitive Demand Bid Curve below for resource Load1 for hour 1100. If DA Market LMP clears at $40/MW, determine Load1’s expected: DA Energy award DA Energy credit / charge DA Energy Award = 65 MWh MW$/MWh 2580 5055 7530 10025 Load1 DA Energy Bid Curve MP1 Gen1 Load1 DA Energy Credit/Charge = DA Award * DA LMP = 65 x 40 = $2,600 (charge)

28. SPP.org28 |Example 3| Day Ahead Market: Operating Reserve Offer Gen 1 Oper. Cap. Max(MW):120 Spin Cap. Max (MW):15 MP1 submits a $5/MW DA Spin Offer for resource Gen1 for 1100. Assume Spin clears the DA Market at a 12 $/MW MCP and that Gen1 cleared 65 MW of Energy. Determine Gen1’s expected: DA Spin award DA Spin credit/charge DA Spin Award = Min [15, 120 – 65] = 15 MW DA Spin Credit/Charge = - DA Award * DA MCP = - 15 x 12 = -$110 (credit) MP1 Gen1 Load1 Max Spin Cap.(MW) $/MW 155 Gen1 DA Spin Offer

29. SPP.org29 Understanding Make Whole Payments  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 Energy Offer No-Load Offer Startup Offer Market Revenues Make-Whole Payment OR Reserve Offer

30. SPP.org30 |Example 4| Day Ahead Market: Understanding Make Whole Payments Assume that: Gen1 is initially on-line SPP Commits Gen1 unit for all 24 hours DA LMP = 40 $/MWh for all 24 hours DA Schedule = 65 MWh for all 24 hours Let’s determine: a.DA Revenues b.DA Costs c.DA Make-whole Payment MP1 Gen1 Load1 MW$/MWh 2510 5025 7550 12060 Gen1 DA Energy Offer Curve Gen 1 Oper. Cap. Max(MW):120 Startup Offer ($/start)17,500 No-Load ($/hr)700

31. SPP.org31 Assume that: Gen1 is initially on-line ISO Commits Gen1 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 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) = $ 0 MP1 Gen1 Load1 MW$/MWh 2510 5025 7550 12060 Gen1 DA Energy Offer Curve Gen 1 Oper. Cap. Max(MW):120 Startup Offer ($/start)17,500 No-Load ($/hr)700 |Example 4| Day Ahead Market: Understanding Make-Whole Payments

32. SPP.org32 Assume that: Gen1 is initially off-line SPP Commits Gen1 unit (cold start) for all 24 hours DA Schedule = 65 MWh for all 24 hours DA LMP = 40 $/MWh for all 24 hours Let’s determine: a.DA Revenues b.DA Costs c.DA Make-Whole Payment MP1 Gen1 Load1 MW$/MWh 2510 5025 7550 12060 Gen1 DA Energy Offer Curve Gen 1 Oper. Cap. Max(MW):120 Startup Offer ($/start)17,500 No-Load ($/hr)700 |Example 5| Day Ahead Market: Understanding Make-Whole Payments

33. SPP.org33 Assume that: Gen1 is initially off-line SPP Commits Gen1 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)x24 + 17,500 = $62,500 DA Make-Whole Payment = Min{0;DA Rev-DA Cost) = - $100 (credit) MP1 Gen1 Load1 MW$/MWh 2510 5025 7550 12060 Gen1 DA Energy Offer Curve Gen 1 Oper. Cap. Max(MW):120 Startup Offer ($/start)17,500 No-Load ($/hr)700 |Example 5| Day Ahead Market: Understanding Make-Whole Payments

34. SPP.org34 RELIABILITY UNIT COMMITMENT (RUC)

35. SPP.org35 Understanding RUC  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

36. SPP.org36 Understanding RUC Hour 123456789101112131415161718192021222324 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)

37. SPP.org37 Highlights  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  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)  RUC will take into consideration the cleared resource commitment schedules from the DA Market or previous RUC clearing process (dependent upon market timeline)  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

38. SPP.org38 Highlights  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  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)

39. SPP.org39 Resource Commit / De-commit Schedules Resource Dispatch and AGC Notifications Fixed Interchange Transaction Curtailment Notification RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements RTBM Resource Offers DA Resource Commit Schedules SPP Operating Reserve Requirements [SCUC] RTBM Resource Offers DA Resource Commit Schedules DA Confirmed Import, Export & Interchange Transactions Resource Outage Notifications SPP Operating Reserve Requirements SPP Forecasts (Load & Wind) DA Confirmed Import, Export & Interchange Transactions RTBM Resource Offers DA Resource Commit Schedules Resource Outage Notifications SPP Operating Reserve Requirements SPP Forecasts (Load & Wind)

40. SPP.org40 Day-Ahead RUC vs. Intra-Day RUC  Both RUC processes share the same purpose: ensure a reliable operating plan during the operating day  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

41. SPP.org41 Day-Ahead RUC Timeline -SPP runs SCUC in RUC mode -SPP reports DA RUC results to affected Market Participants -Submit revised offers and/or self schedules for units that were not selected in DA run 19002000 Day Prior to Operating Day 1700

42. SPP.org42 Intra-Day RUC Timeline 0800 Operating Day 040000001200 1600 2000 2400 -SPP runs SCUC in RUC mode -SPP reports RUC results to affected Market Participants -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 =

43. SPP.org43 THE REAL-TIME BALANCING MARKET (RTBM)

44. SPP.org44 Understanding the Real-Time Balancing Market  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 Load

45. SPP.org45 Highlights  Uses Security Constrained Economic Dispatch (SCED) to ensure results are physically feasible.  Operates on a continuous 5-minute basis; calculates Dispatch Instructions for Energy and clears Operating Reserve by resource.  Energy and Operating Reserve are co-optimized.  Settlements are based on the difference between the results of the RTBM process and the DA Market clearing.  Charges are imposed on Market Participants for failure to deploy Energy and Operating Reserve as instructed.

46. SPP.org46 Highlights  1-part offer: Energy Offer Curve  Operating Reserve Offers  Regulation-up and Regulation-down  Spinning Reserve and Supplemental Reserves  Accommodates participation of supply and demand external to SPP  Imports, exports and through transactions and external resources

47. SPP.org47 |Example 6| Real-Time Balancing Market Energy Offer Curve MP1 clears DA as shown in Example 1 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 $40/MWh, Gen1’s dispatch instruction is 60MW for each interval of the hour. What will be settlement for this scenario? RT Energy Actual= 60MWh MW$/MWh 2510 5025 7560 12065 Gen1 RT Energy Offer Curve MP1 Gen1 Load1 RT Energy Settlement = (RT Actual -DA Award) x RT LMP = (-60 + 65) x 40 = $200.00 (charge)

48. SPP.org48 MP1 clears DA as shown in Example 1. Assuming Gen1 is metered at 70 MWh at hour 1100 and that RT Market LMP clears at $40/MWh, determine Gen1’s: RT Energy award RT Energy settlement RT Energy Award = 70MWh MW$/MWh 2510 5025 7550 12060 Gen1 RT Energy Offer Curve MP1 Gen1 Load1 RT Energy Settlement = (RT Actual -DA Award) x RT LMP = (-70+65) x 40 = -$200 (credit) |Example 7| Real Time Balancing Market Incremental Energy Offer

49. SPP.org49 FINANCIAL SCHEDULES

50. SPP.org50 Understanding Financial Schedules  Bilateral Transactions that transfer financial responsibility within the SPP Market Footprint  Energy  Operating Reserve  May be entered up to 4 days after Operating Day

51. SPP.org51 Understanding Financial Schedules  Energy Financial Schedules  Must specify oSettlement Location oMW amount oBuyer oSeller oPricing (Day-Ahead or Real-Time Balancing Market) oSeller and Buyer confirmation of the transaction

52. SPP.org52 Understanding Financial Schedules  Operating Reserve Financial Schedules  Must specify oReserve Zone oOperating Reserve Product oMW amount oBuyer oSeller oPricing oSeller and Buyer confirmation of the transaction

53. SPP.org53 MP1 MP2 Gen1 Load2 |Example 8| Understanding Financial Schedules: Energy Bilateral DA Market Clearing (Supply) Energy Award(MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50 Assume DA Market clears as shown above. MP2 purchases 100 MW from MP1 @ 45 $/MWH by entering into a bilateral transaction. The parties agree to submit an 100 MW Financial Schedule that is settled at MP1 Settlement Location. Determine MP1 and MP2 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

54. SPP.org54 |Example 8| Understanding Financial Schedules: Energy Bilateral a) Financial Schedule not confirmed by Market Participants with SPP MP1 MP2 Gen1 Load2 DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50 MP1 SPP Settlement DA Market Settlement = - DA Award x DA LMP = 100 x 40 = -$4,000 (credit) MP1 Books (this bilateral 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 $8,500 since the Financial Schedule was not confirmed with SPP

55. SPP.org55 |Example 8| Understanding Financial Schedules: Energy Bilateral a) Financial Schedule not confirmed by Market Participants with SPP MP1 MP2 Gen1 Load2 DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50 MP2 SPP Settlement DA Market Settlement = DA Award x DA LMP = 100 x 50= $5,000 (charge) MP2 Books (this bilateral 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 $9,500 since the Financial Schedule was not confirmed with SPP

56. SPP.org56 |Example 8| Understanding Financial Schedules: Energy Bilateral MP1 SPP Settlement Gen1 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 MP1 Books (this bilateral 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 $4,500 since the Financial Schedule was confirmed with SPP b) Financial Schedule confirmed by Market Participants to SPP MP1 MP2 Gen1 Load2 DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50

57. SPP.org57 |Example 8| Understanding Financial Schedules: Energy Bilateral MP2 SPP Settlement Load2 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) MP2 Books (this bilateral 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 $5,500 since the Financial Schedule was confirmed with SPP b) Financial Schedule confirmed by Market Participants to SPP MP1 MP2 Gen1 Load2 DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50

58. SPP.org58 MP1 MP2 Gen1 Load2 |Example 9| Understanding Financial Schedules: Energy Bilateral DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50 Assume DA Market clears as shown above. MP2 purchases 100 MW from MP1 @ 45 $/MWH by entering into a bilateral transaction. The parties agree to submit an 100 MW Financial Schedule that is settled at MP2 Settlement Location. Determine MP1 and MP2 DA impacts if both Market Participants confirm the financial schedule with SPP

59. SPP.org59 |Example 9| Understanding Financial Schedules: Energy Bilateral MP1 SPP Settlement Gen1 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) MP1 Books (this bilateral 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 $3500 since the Financial Schedule was confirmed with SPP b) Financial Schedule confirmed by Market Participants to SPP MP1 MP2 Gen1 Load2 DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50

60. SPP.org60 |Example 9| Understanding Financial Schedules: Energy Bilateral MP2 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 MP2 Books (this bilateral 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 $4500 since the Financial Schedule was confirmed with SPP b) Financial Schedule confirmed by Market Participants to SPP MP1 MP2 Gen1 Load2 DA Market Clearing (Supply) Energy Award (MW):100 DA LMP ($/MWH):40 DA Market Clearing (Load) Energy Award (MW):100 DA LMP ($/MWH):50

61. SPP.org61 VIRTUAL TRANSACTIONS

62. SPP.org62 Understanding Virtual Transactions  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. oIf 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.

63. SPP.org63 Understanding Virtual Transactions: Settlement  Virtual Offer  Offer Quantity (MW) into DA Market at an Offer Price ($/MWh)  If DA LMP > Offer Price, Offer is cleared in Day-Ahead for Offer Quantity  If cleared, Market Participant must buy back Energy awarded from SPP at the Real- Time price  If DA LMP > RT LMP  Market Participant realizes a profit  If DA LMP < RT LMP  Market Participant incurs losses  Virtual Bid  Bid Quantity (MW) into DA Market at Bid Price ($/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

64. SPP.org64 |Example 10| Understanding Virtual Transactions: Virtual Offer MP1 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 $35/MWh, determine the virtual’s: DA Energy award Net Energy Settlement of the Virtual financial position MW$/MWh 525 1035 1545 MP1 DA Virtual Offer Curve MP1 Gen1 Load1 DA Energy Award = 12.5 MWh Net Energy Settlement = - DA Award x (DA LMP – RT LMP) = -12.5 x (40-35) = - $62.5 (credit)

65. SPP.org65 |Example 11| Understanding Virtual Transactions: Virtual Offer MP1 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 $45/MWh, determine the virtual’s: DA Energy award Net Energy Settlement of the Virtual financial position MW$/MWh 525 1035 1545 MP1 DA Virtual Offer Curve MP1 Gen1 Load1 DA Energy Award = 12.5 MWh Net Energy Settlement = - DA Award x (DA LMP – RT LMP) = -12.5 x (40-45) = $62.5 (charge)

66. SPP.org66 |Example 12| Understanding Virtual Transactions: Virtual Bid MP1 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 $35/MWh, determine the virtual’s: DA Energy award Net Energy Settlement of the Virtual financial position MW$/MWh 545 1020 155 MP1 DA Virtual Bid Curve MP1 Gen1 Load1 DA Energy Award = 6 MWh Net Energy Settlement = DA Award x (DA LMP – RT LMP) = 6 x (40-35) = $30 (charge)

67. SPP.org67 |Example 13| Understanding Virtual Transactions: Virtual Bid MP1 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 $45/MWh, determine the virtual’s: DA Energy award Net Energy Settlement of the Virtual financial position MW$/MWh 545 1020 155 MP1 DA Virtual Bid Curve MP1 Gen1 Load1 DA Energy Award = 6 MWh Net Energy Settlement = DA Award x (DA LMP – RT LMP) = 6 x (40-45) = - $30 (credit)

68. SPP.org68 CO-OPTIMIZATION

69. SPP.org69 Understanding Co-optimization Why co-optimize?  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)

70. SPP.org70 Understanding Co-optimization  When clearing the market (Day-Ahead and Real-Time), SPP must determine an operating schedule that:  Minimizes the SPP total production costs, based on Offers and Bids of Market Participants and,  Maximizes Market Participants benefits for all the market products that they have submitted Bids and Offers on,  Ensures that all reliability and transmission constraints are met.  The market clearing optimization engine proposed by SPP is a co- optimization 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.

71. SPP.org71 Understanding Co-optimization  Does co-optimization produce a schedule that minimizes the total production cost for SPP?  Does co-optimization produce a schedule that maximizes operating profits for Market Participants?  Can we explain Operating Reserve prices calculated by the optimization engine?

72. SPP.org72 MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 Load 1 Energy Forecast (MW):100 End User Rate ($/MWH):40 Spin Requirement (MW):10 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 Load 2 Energy Forecast (MW):100 End User Rate ($/MWH):45 Spin Requirement (MW):10 Understanding Co-optimization: Examples  Consider 2 Market Participants MP1 and MP2 as above, each with generation resources and load to serve with a reliability requirement in the form of Spinning Reserve.  How can these Market Participants benefit most from SPP future market operations? Balancing Authority 1 Balancing Authority 2 MP1

73. SPP.org73 MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 Load 1 Energy Forecast (MW):100 End User Rate ($/MWH):40 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 Load 2 Energy Forecast (MW):100 End User Rate ($/MWH):45 Understanding Co-optimization: Examples  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. Reserve Zone Spin Requirement (MW):20 Consolidated Balancing Authority MP1

74. SPP.org74 MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 Load 1 Energy Forecast (MW):100 End User Rate ($/MWH):40 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 Load 2 Energy Forecast (MW):100 End User Rate ($/MWH):45  Let’s determine:  Each Market Participant awards (Energy and Spin), operational cost and LMP,  The Reserve Zone Spin MCP,  SPP total production cost,  Each Market Participant profit margin. Reserve Zone Spin Requirement (MW):20 MP1 |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)

75. SPP.org75 MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 Load 1 Energy Forecast (MW):100 End User Rate ($/MWH):40 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 Load 2 Energy Forecast (MW):100 End User Rate ($/MWH):45  Let’s determine:  Each Market Participant awards (Energy and Spin), operational cost and LMP,  The Reserve Zone Spin MCP,  SPP total production cost,  Each Market Participant profit margin. Reserve Zone Spin Requirement (MW):20 MP1 |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)

76. SPP.org76 MP2 Gen 1 Energy Award (MW):100 Spin Award (MW):10 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):100 Spin Award (MW):10 Load 2 Energy Forecast (MW):100 |Example 14| Understanding Co-optimization: Non-Co-optimized case MP1Gen. Schedule (MW) Operational Cost ($) Energy100800 Spin1020 Total-820 MP2Gen. Schedule (MW) Operational Cost ($) Energy1001,000 Spin1030 Total-1,030 LMP = 8 $/MWH Total System Operational Cost = $ 1,850 Spin Market Clearing Price = 2 $/MW Reserve Zone Spin Requirement (MW):20 Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) MP1 0 MW >>

77. SPP.org77 MP2 Gen 1 Energy Award (MW):100 Spin Award (MW):10 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):100 Spin Award (MW):10 Load 2 Energy Forecast (MW):100 LMP = 8 $/MWH Explaining LMPs: Why is LMP = 8 $/MWH at MP1’s price node? Answer: if we increase the load at MP1’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 Spin Market Clearing Price = 2 $/MW |Example 14| Understanding Co-optimization: Non-Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) MP1 0 MW >>

78. SPP.org78 MP2 Gen 1 Energy Award (MW):100 Spin Award (MW):10 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):100 Spin Award (MW):10 Load 2 Energy Forecast (MW):100 LMP = 8 $/MWH Spin Market Clearing Price = 2 $/MW |Example 14| Understanding Co-optimization: Non-Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) MP1 0 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

79. SPP.org79 MP2 Gen 1 Energy Award (MW):100 Spin Award (MW):10 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):100 Spin Award (MW):10 Load 2 Energy Forecast (MW):100 LMP = 8 $/MWH Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP1:820.00 0.00 Charges ($)Revenues ($)Net Profit ($) Demand MP1:820.004,000.003,180.00 Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP2:820.001,030.00-210.00 Charges ($)Revenues ($)Net Profit ($) Demand MP2:820.004,500.003,680.00 MP1 Profit = $ 3,180MP2 Profit = $ 3,470 Spin Market Clearing Price = 2 $/MW |Example 14| Understanding Co-optimization: Non-Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin each) MP1 0 MW >>

80. SPP.org80 MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 Load 1 Energy Forecast (MW):100 End User Rate ($/MWH):40 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 Load 2 Energy Forecast (MW):100 End User Rate ($/MWH):45  Let’s determine:  Each Market Participant awards (Energy and Spin), operational cost and LMP,  The Reserve Zone Spin MCP,  SPP total production cost,  Each Market Participant profit margin. Reserve Zone Spin Requirement (MW):20 Consolidated Balancing Authority MP1 |Example 15| Understanding Co-optimization: Co-optimized case Market Participants offer their true economic limits and let SPP co-optimize the market

81. SPP.org81 MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 MP1Gen. Schedule (MW) Operational Cost ($) Energy115920 Spin510 Total-930 MP2Gen. Schedule (MW) Operational Cost ($) Energy85850 Spin1545 Total-895 LMP = 10 $/MWH Total System Operational Cost = $ 1,825 15 MW >> Spin Market Clearing Price = 4 $/MW (vs. $ 1,850 in Example 14) |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):20 MP1

82. SPP.org82 MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 15 MW >> Explaining LMPs : Why is LMP = 10 $/MWH at MP1’s price node? Answer: if we increase the load at MP1’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) x10 = $ 10 Spin Market Clearing Price = 4 $/MW |Example 15| Understanding Co-optimization: Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants offer their true economic limits and let SPP co-optimize the market MP1

83. SPP.org83 MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 15 MW >> Explaining LMPs : Why is LMP = 10 $/MWH at MP1’s price node? Answer: if we increase the load at MP1’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) x10 = $ 10 Spin Market Clearing Price = 4 $/MW |Example 15| Understanding Co-optimization: Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants offer their true economic limits and let SPP co-optimize the market MP1

84. SPP.org84 MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 15 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 Spin Market Clearing Price = 4 $/MW |Example 15| Understanding Co-optimization: Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants offer their true economic limits and let SPP co-optimize the market MP1

85. SPP.org85 MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP1:1,170.00930.00240.00 Charges ($)Revenues ($)Net Profit ($) Demand MP1:1,040.004,000.002,960.00 Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP2:910.00895.0015.00 Charges ($)Revenues ($)Net Profit ($) Demand MP2:1,040.004,500.003,460.00 MP1 Profit = $ 3,200MP2 Profit = $ 3,475 15 MW >> (vs. $ 3,180 in Example 14) (vs. $ 3,470 in Example 14) Spin Market Clearing Price = 4 $/MW |Example 15| Understanding Co-optimization: Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants offer their true economic limits and let SPP co-optimize the market MP1

86. SPP.org86 MP1MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 15 MW >> Explaining Profit Maximization: Is MP2 Profit maximized? Answer: Yes, since MP2 is being awarded as much spinning reserve (its most profitable product) first followed by energy next (less profitable product). Offer ($/MW) Market Price ($/MW) Profit Margin ($/MW) Energy:10 10 – 10 = 0 Spin:344 – 3 = 1 Spin Market Clearing Price = 4 $/MW |Example 15| Understanding Co-optimization: Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants offer their true economic limits and let SPP co-optimize the market

87. SPP.org87 MP2 Gen 1 Energy Award (MW):115 Spin Award (MW):5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):85 Spin Award (MW):15 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 15 MW >> Explaining Profit Maximization: Is MP1 Profit maximized? Answer: Yes, since MP1 is being awarded as much energy first, followed by Spinning Reserve. Note that both products are equally profitable for this Market Participant. Offer ($/MW) Market Price ($/MW) Profit Margin ($/MW) Energy:81010 – 8 = 2 Spin:244 – 2 = 2 Spin Market Clearing Price = 4 $/MW |Example 15| Understanding Co-optimization: Co-optimized case Reserve Zone Spin Requirement (MW):20 Market Participants offer their true economic limits and let SPP co-optimize the market MP1

88. SPP.org88 Understanding Co-optimization: Conclusion  Does co-optimization produce a schedule that minimizes the total production cost for SPP?  Answer: YES  Does co-optimization produce a schedule that maximizes operating profits for Market Participants?  Answer: YES No Co- optimization With Co- optimization System Cost ($):1,8501,825 No Co- optimization With Co- optimization MP1 Profit ($):3,1803,200 MP2 Profit ($):3,4703,475 Total MPs Profits ($):6,6506,675

89. SPP.org89  Can we explain Operating Reserve prices calculated by the optimization engine?  Answer: YES  Operating Reserve Clearing Price = Lost Opportunity Cost + Operating Reserve Offer Price for marginal unit (which provides the next MW for the Operating Reserve product) Decreasing Gen 1’s energy schedule by 1 MW: production cost impact = (114 – 115) x 8 = - $ 8 Decreasing Gen 1’s energy schedule by 1 MW: production cost impact = (114 – 115) x 8 = - $ 8 Lost Opportunity Cost = 2 $ Marginal Unit Offer Price = 2 $ Increasing Gen1’s Spinning Reserve schedule by 1 MW: production cost impact = (6-5) x 2 = $ 2 Increasing Gen 2’s energy schedule by 1 MW: production cost impact = (86 – 85) x 10 = $ 10 Increasing Gen 2’s energy schedule by 1 MW: production cost impact = (86 – 85) x 10 = $ 10 Co-optimized Scenario (Example 9): MCP for Spinning Reserve + + Understanding Co-optimization: Conclusion

90. SPP.org90 SCARCITY PRICING

91. SPP.org91 Understanding Scarcity Pricing  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 oMay stimulate demand response oDraw supply from outside the SPP Balancing Authority oIncentivizes generation availability during peak loads oPromotes long-term contracting

92. SPP.org92 Understanding Scarcity Pricing  SPP has implemented Scarcity Pricing in its Future Market Protocols through a set of Demand Curves for Operating Reserve  Demand Curves: Set pre-determined prices at different levels of shortages for each of the reserve products: oOperating Reserve oRegulation – Up oRegulation - Down

93. SPP.org93 MP1MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 RegUp Cap. Max (MW):4.5 RegUp Offer Cost ($/MW):6 Load 1 Energy Forecast (MW):100 End User Rate ($/MW)40 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 RegUp Cap. Max (MW):4.5 RegUp Offer Cost (MW):4 Load 2 Energy Forecast (MW):100 End User Rate ($/MW)45 Understanding Scarcity Pricing: Examples  In the following case studies, we assume that:  Both Market Participants belong to the same Reserve Zone and offer their generation at cost as well as their true economic limits,  Reliability requirements are in the form of Regulation-Up and Spinning Reserve, with demand curves set to $200/MW and $75/MW respectively,  The network has no congestion and no losses. Reserve Zone Spin Requirement (MW):- Reg Up Requirement (MW):- Consolidated Balancing Authority

94. SPP.org94 MP1MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 RegUp Cap. Max (MW):4.5 RegUp Offer Cost ($/MW):6 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 RegUp Cap. Max (MW):4.5 RegUp Offer Cost (MW):4  Let’s determine:  Each Market Participant awards (Energy, RegUp, Spin) and LMP,  Each Market Participant production cost,  The Reserve Zone RegUp and Spin MCPs,  SPP total production cost. Reserve Zone Spin Requirement (MW):20 Reg Up Requirement (MW):8 Consolidated Balancing Authority |Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Load 1 Energy Forecast (MW):100 End User Rate ($/MW)40 Load 2 Energy Forecast (MW):100 End User Rate ($/MW)45

95. SPP.org95 MP2 Gen 1 Energy Award (MW):107 RegUp Award (MW):3.5 Spin Award (MW):9.5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):93 RegUp Award (MW):4.5 Spin Award (MW):10.5 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 7 MW >> RegUp Market Clearing Price = 8 $/MW Spin Market Clearing Price = 4 $/MW Reserve Zone Spin Requirement (MW):20 RegUp Requirement (MW):8 MP1 Gen. Schedule (MW) Operational Cost ($) Energy107856 RegUp3.521 Spin9.519 Total-896 MP2Gen. Schedule (MW) Operational Cost ($) Energy93930 RegUp4.518 Spin10.531.5 Total-979.5 |Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Total System Operational Cost = $ 1,875.5

96. SPP.org96 MP2 Gen 1 Energy Award (MW):107 RegUp Award (MW):3.5 Spin Award (MW):9.5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):93 RegUp Award (MW):4.5 Spin Award (MW):10.5 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 7 MW >> RegUp Market Clearing Price = 8 $/MW Spin Market Clearing Price = 4 $/MW Reserve Zone Spin Requirement (MW):20 RegUp Requirement (MW):8 MP1 |Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP1:1,135.98896.00239.98 Charges ($)Revenues ($)Net Profit ($) Demand MP1:1,072.004,000.002,928.00 Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP2:1,008.00979.5028.50 Charges ($)Revenues ($)Net Profit ($) Demand MP2:1,072.004,500.003,428.00 MP1 Profit = $ 3,159.98 MP2 Profit = $ 3,448.50

97. SPP.org97 MP1MP2 Gen 1 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):8 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):2 RegUp Cap. Max (MW):4.5 RegUp Offer Cost ($/MW):6 Load 1 Energy Forecast (MW):100 Gen 2 Econ. Oper. Cap. Min (MW):50 Econ. Oper. Cap. Max (MW):120 Energy Offer Cost ($/MWH):10 Spin Cap. Max (MW):15 Spin Offer Cost ($/MW):3 RegUp Cap. Max (MW):4.5 RegUp Offer Cost (MW):4 Load 2 Energy Forecast (MW):100  Let’s determine:  Each Market Participant awards (Energy, RegUp, Spin) and LMP,  Each Market Participant production cost,  The Reserve Zone RegUp and Spin MCPs,  SPP total production cost. Reserve Zone Spin Requirement (MW):20 Reg Up Requirement (MW):12 Consolidated Balancing Authority |Example 17| Understanding Scarcity Pricing: Operating Reserve shortage

98. SPP.org98 MP2 Gen 1 Energy Award (MW):106 RegUp Award (MW):4.5 Spin Award (MW):9.5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):94 RegUp Award (MW):4.5 Spin Award (MW):10.5 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 6 MW >> RegUp Market Clearing Price = 200 $/MW Spin Market Clearing Price = 4 $/MW Reserve Zone Spin Requirement (MW):20 RegUp Requirement (MW):12 MP1 Gen. Schedule (MW) Operational Cost ($) Energy106848 RegUp4.527 Spin9.519 Total-894 MP2Gen. Schedule (MW) Operational Cost ($) Energy94940 RegUp4.518 Spin10.531.5 Total-989.5 |Example 17| Understanding Scarcity Pricing: Operating Reserve shortage Total System Operational Cost = $ 1,883.5 RegUp Shortage = 3 MW

99. SPP.org99 MP2 Gen 1 Energy Award (MW):106 RegUp Award (MW):4.5 Spin Award (MW):9.5 Load 1 Energy Forecast (MW):100 Gen 2 Energy Award (MW):94 RegUp Award (MW):4.5 Spin Award (MW):10.5 Load 2 Energy Forecast (MW):100 LMP = 10 $/MWH 6 MW >> RegUp Market Clearing Price = 200 $/MW Spin Market Clearing Price = 4 $/MW Reserve Zone Spin Requirement (MW):20 RegUp Requirement (MW):12 MP1 |Example 17| Understanding Scarcity Pricing: Operating Reserve shortage RegUp Shortage = 3 MW Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP1:1,998.00894.001,104.00 Charges ($)Revenues ($)Net Profit ($) Demand MP1:2,240.004,000.001,760.00 Operating Profit Revenues ($)Costs ($)Net Profit ($) Generation MP2:1,882.00989.50892.50 Charges ($)Revenues ($)Net Profit ($) Demand MP2:2,240.004,500.002,260.00 MP1 Profit = $ 2,864.00MP2 Profit = $ 3,152.50

100. SPP.org100 Understanding Scarcity Pricing: Conclusion  Operating Reserve Shortage will have an impact on Operating Reserve clearing prices  Even in case of Operating Reserve shortage, co- optimization based SCED provides the most economical system total operational cost

101. SPP.org101 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

102. SPP.org Debbie James Manager, Market Design djames@spp.org Carrie Simpson Senior Market Analyst, Market Design csimpson@spp.org djames@spp.org csimpson@spp.org