Market Settlements Load (L201) July 2011 Henry Chu

Transcription

1 Market Settlements Load (L201) July 2011 Henry Chu

2 Market Settlement Training Series Market Settlements Training Modules: Overview O101 (Feb. 2011) ARR/FTR AF201 (Mar. 2011) Virtual and Financial Schedules VF201 (Apr. 2011) Physical Schedules PS201 (May 2011) Load L201 (Jul. 2011) Generation G201 (Sep. 2011) Overview O101 (Sep. 2011) 1

3 MISO Disclaimer The following training materials are intended for use as training materials only and are not intended to convey, support, prescribe or limit any market participant activities. These materials do not act as a governing document over any market rules or business practices manual. The data used in the examples is test data and should not be used to support market analyses. 2

4 Course Objective Provide a brief overview of the attributes of Load and its role in MISO; Provide overview of all the potential charges a Load may be subject to; Review the calculation of Day-Ahead and Real-Time Market charges which a Load may receive. 3

5 Key Assumptions This material will discuss Settlements concepts centered on the Energy and Operating Reserves Markets This is not a stakeholder meeting. The purpose of this training is NOT to make or to debate market design decisions, policies, or rules Participants will actively participate in the training by asking constructive questions in an effort to improve the overall learning experience 4

6 Agenda TOPICS Load Overview Load Market Overview Load Settlements Overview Load - RSG and RNU Charge review Lunch Load TX Charge Type Review Load Day Ahead Charge Types Example Break Load Real-Time Charge Types Example Summary and Quiz SCHEDULE 10:30 10:45 am 10:45 11:00 am 11:00 11:15 am 11:15 12:00 pm 12:00 12:45 pm 12:45 01:00 pm 01:00 02:00 pm 02:00 02:15 pm 02:15 03:30 pm 03:30 04:00 pm 5

7 Introduction 6

8 Introduction Outline Commonly Used Acronyms Load Overview Day-Ahead Market Overview Real-Time Market Overview Grandfathered Agreement Schedules Load Settlement Day-Ahead and Real-Time Load Related Charges 7

9 Introduction MP AO CPNode EPNode LBA LBAA RLA SCUC SCED NSI NAI Commonly Used Acronyms Market Participant Asset Owner Commercial Pricing Node Elemental Pricing Node Local Balancing Authority Local Balancing Authority Area Residual Load Account Security Constrained Unit Commitment Security Constrained Economic Dispatch Net Scheduled Interchange Net Actual Interchange 8

10 Introduction What is one of MISO s main functions? Reliability 9

11 What is a Load? Introduction A Load is an asset in MISO that withdraws energy from the Transmission System. BPM for Market Settlements Load Settlements 10

12 Examples of Loads Introduction Cities Muni s and Coops Large Industrial complex Load Serving Entities 11

13 Market Participants Assets Allocation % based on number of MPs in each category as compared to total MPs 12 Introduction

14 Commercial Model

15 Commercial Model Registration of Load. Market Registration process defines the relationships between entities in order to allocate charges and credits: Register as a Market Participant with assets under themselves Register assets under another Market Participant 14 Introduction

16 Commercial Model Load Serving Entities (LSEs) LSEs are parties taking Transmission Service on behalf of wholesale or retail power customers that have undertaken an obligation to provide or obtain Energy and/or Operating Reserves for end-use customers by statute, franchise, regulatory requirement or contract for Load located within or attached to the Transmission System. 15 Introduction

17 Load Serving Entities May not own Commercial assets Marketer Generation Owner Transmission Owner Load Serving Entity 16 Introduction

18 Commercial Model Load Serving Entities Responsibilities 1) Prior to the Operating Day: Coordinate with their LBA in the development of Load Forecasts (hourly for 7 days out) that the LBA submits to the MISO 2) During the Operating Day: Coordinate with MPs regarding development and submission of host Load Zone Dispatch Interval Demand Forecasts for Demand Response Resources-Type I and Type II. Respond to MISO interruptible Load and Load Shedding directives either directly with MISO or through their LBA. 17 Introduction

19 Commercial Model How is a Load modeled in MISO? A Load CPNode is comprised of one or more EPNodes. A CPNode allows for an aggregate price signal for multiple physical assets. EPNodes can be associated with more than one CPNode, however each CPNode will have its own distinct Locational Marginal Price (LMP). 18 Introduction

20 Commercial Model Financial representation of the Network Model used to facilitate Operations and Settlements MP Asset Owner CPNode Market Participant Generator Owner Load Serving Entity Marketer Can be Generation or Load Owner, or Other, required to transact in the Markets Commercial Pricing Node The published LMP/MCP represents the price at the CPNode EPNode Elemental Pricing Node An aggregate price for a collection of ENodes ENode ENode ENode Elemental Node Physical point of injection or withdrawal to the system Commercial and Network Model 19 Introduction

21 Market Participant Configuration Legend: Market Entities Non Market Entities Physical Assets MISO Market Participant MDMA, SA, & BA Generation Owner LSE Other Market Entities Transmission Customer Generation Resource Load Zone Demand Response Resource Emergency Demand Response Resource 20 Introduction

22 Load Market Options 21

23 Load Participation Options Day Ahead Market Price-Sensitive Demand Bids Fixed Demand Bids Real Time Market Price Takers Internal Bilateral Settled Energy outside of the market may be responsible for Congestion and Loss 22 Introduction

24 Load Participation Options Grandfathered Schedules Carve-outs and Option B schedules Settled Energy outside of the market Rebates Congestion and Loss Pseudo Tie Schedules Allow a load to be served by an entity external to MISO Responsible for the congestion and loss charges from the load and the interface point 23 Introduction

25 Load Participation Options Demand Response Type 1 is capable of supplying a specific amount of Energy or Contingency Reserve, at the choice of the Market Participant, to the Energy and Operating Reserve Markets through physical Load interruption. Type 2 is capable of supplying a range of Energy and/or Operating Reserve, at the choice of the MP, to the Energy and Operating Reserve Markets through behind-the-meter generation and/or controllable Load. Energy and Operating Reserve Markets Business Practices Manual BPM-002-r9 sec Introduction

26 Load Participation Options Emergency Demand Response (EDR) are designed to encourage parties that have demand response capabilities other than previously registered DRRs Type I or DRRs Type II to offer such capabilities for use by the MISO during specified Emergency - EEA2 or EEA3 events. Energy and Operating Reserve Markets Business Practices Manual BPM-002-r9 sec Introduction

27 MISO Market

28 Day-Ahead & Real-Time Market Timeline OD Resource Offers MISO Market Operations Cleared Supply Start Up Price MISO Market Operations Resource Parameters Physical Schedules Demand Bids Clear Day- Ahead Market Utilizes the following: SCUC SCED Cleared Demand Constraints Locational Marginal Prices No Load Price Resource Parameters Day-Ahead Market Schedules Perform Reliability Assessment Utilizes the following: SCUC Commitment Notification At 2000 and ongoing throughout the Operating day Network Model Market Clearing Prices Real-Time Load Forecast Approved Transmission Outages Publishes DA results by Introduction

29 Day-Ahead Market Overview The Day-Ahead (DA) Market is a forward, financial market where energy and operating reserves are sold prior to the Operating Day (OD) Simultaneously co-optimizes energy and operating reserves using SCUC and SCED algorithms Resource offers and demand bids are financially binding 28 Introduction

30 Day-Ahead Market Overview The Day-Ahead Market closes at 11:00 and the Market clears at 15:00. Any resources in the outage scheduler prior to 11:00 am will not clear the market. Load has two options to participate in the Day- Ahead Market either as Fixed Demand Bids or Price-Sensitive Demand Bids. 29 Introduction

31 Day-Ahead Market Overview Fixed Demand Bids: Fixed Demand Bids are price takers and are charged the LMP determined in the Day-Ahead Energy and Operating Reserve Market for that CPNode location. MPs may submit only one Fixed Demand Bid at a CPNode location they own. The following information is submitted for a Fixed Demand Bid: MW quantity, with a default of zero MW Location (Load Zone CPNode) at which the purchase occurs Hours over which the Fixed Demand Bid applies 30 Introduction

32 Day-Ahead Market Overview Price-Sensitive Demand Bids Price-Sensitive Demand Bids are charged the LMP determined in the Day-Ahead Energy and Operating Reserve Market for that CPNode location MPs are able to express a willingness to buy Energy at specified prices by submitting Price-Sensitive Demand Bids. Price-Sensitive Demand Bids are accepted in separate bid blocks only. Up to nine Bid blocks can be submitted per CPNode location. This is in addition to the one Fixed Demand Bid at that CPNode location. 31 Introduction

33 Day-Ahead Market Overview Price-Sensitive Demand Bids MW quantity/price representing the maximum price (positive or negative without price caps) the MP is willing to pay to purchase the desired MW of Energy. The (MW/Price) blocks can be entered in an arbitrary sequence with respect to MW block size. The application software will process the blocks in the proper sequence, as required. Location (Load Zone CPNode) at which the purchase occurs. Hours over which the Price-Sensitive Demand Bid applies. 32 Introduction

34 Day-Ahead Market Overview 33 Introduction

35 Real-Time Market Overview In the Real-Time (RT) Energy and Operating Reserve Market, Load does not get bid on or get cleared; energy is withdrawn as it is needed. The Real-Time Energy and Operating Reserve Market settles Load asset energy volumes based on their submitted Actual Energy Withdrawal meter data. In the absence of meter data, the MISO uses alternate meter data (state estimator). 34 Introduction

36 State Estimator RT_ALT_MTR is the state estimator value for a given CPNode. In Retail Choice States, the State Estimator (SE) value is based on the CPNode percentage defined in the quarterly Commercial model, while the meter data is the settlement-quality, after-the-fact, actual value. Differences between the State Estimator and Meter Data can occur due to intra-quarterly shifts in retail load. 35 Introduction

37 Grandfathered Agreements Grandfathered Agreements are only applicable to agreements executed or committed to prior to September 16, 1998 or ITC Grandfathered Agreements that are not subject to the specific terms and conditions of the EMT consistent with the Commission s policies. These agreements must have been previously identified to the MISO and set forth in the EMT Attachment P. 36 Introduction

38 Grandfathered Agreements 37 Introduction

39 Internal Bilateral Schedules (IBS) Financial Schedules are used for transactions within the MISO border Financial Schedules are entered into FinSched Every Financial Schedule specifies a Source, Sink, and Delivery Point (Optional) The Energy component associated with a Financial Schedule is settled outside of the MISO market Congestion and Losses are settled between the source and the Sink 38 Introduction

40 Internal Bilateral Schedules (IBS) In a Financial Schedule there are two counterparties: Buyer (Sink) and Seller (Source). In addition, there is a delivery point somewhere between the Source and Sink Nodes. Financial Schedules are subject to Congestion and Losses in MISO The Seller pays Congestion and Losses from Source to Delivery Pt. The Buyer pays Congestion and Losses from Delivery Pt. to Sink 39 Introduction

41 Pseudo Tie Pseudo Ties ties generation or load to an external control area DART will calculate and populate a schedule based on SE flows at internal source and sink and send to settlements 40 Introduction

42 Settlements

43 Settlement Cycle Cleared Bids Cleared Offers Charges Settlements Invoices Disputes Credits Meter Data 42 Introduction

44 Settlement Sign Convention Schedules (+) (-) Day-Ahead / Real-Time (DART) Withdrawal Injection Financial Bilateral Transactions (FBT) (Financial Schedules) Physical Bilateral Transactions (PBT) (Physical Schedules) Seller Buyer Buyer Seller Activity (+) (-) Settlement Statements Charges Payment due MISO Credits Payment due MP 43 Introduction

45 Load Settlements Day-Ahead Market Settlements charges use the cleared Day-Ahead Schedule load volume at a CPNode. There are 10 Day-Ahead Settlements Charge Types. 44 Introduction

46 Load Day-Ahead Settlements Statement 45 Introduction

47 Load Day-Ahead Settlements Statement 46 Introduction

48 Load - Day-Ahead Settlements Statement 47 Introduction

49 Load Real-Time Settlements Statement 48 Introduction

50 Load Settlements The Real-Time Energy and Operating Reserve Market uses Load Resource energy volumes based on their submitted CPNode Actual Energy Withdrawal meter data in the Real-Time Asset Energy Amount charge type or State Estimator value when the actual meter volume is not available The Real-Time imbalance volume from the Day- Ahead cleared schedule volume is subjected to 15 Real-Time Settlements Charge Types 49 Introduction

51 Residual Load MISO uses the term Residual Load to define the amount of over or under claimed Energy in a LBAA. Residual Load is equal to the combined following inputs multiplied by -1: 1) the reported amount of injections (-) 2) the reported amount of withdrawals (+), 3) the LBAA Net Actual Interchange, 4) the amount of SE determined Losses (+) for the LBAA. MISO assigns the Residual Load to an asset, and thus an AO, in each LBAA. The AO s MP for the asset is financially responsible for the effect of the Residual Load. 50 Introduction

52 Charge Types Type Energy Schedule Admin Distribution Description Charge or Credit for Energy procurement or Energy generation at a CPNode either through the transfer of ownership, purchase from or sale to MISO Energy market or a third party Charge or Credit associated to Financial and Physical Bilateral Transactions Recovery of MISO and LBA administrative costs Offsetting Allocation of Operational, Market, and/or Reliability costs 51 Introduction

53 Load Load - Day-Ahead Charges Charge Type Acronym Type Day-Ahead Asset Energy Amount DA_ASSET_EN Energy Day-Ahead Financial Schedule Congestion Amount DA_FIN_CG Schedule Day-Ahead Financial Schedule Loss Amount DA_FIN_LS Schedule Day-Ahead Congestion Rebate on Carved-Out Grandfathered Agreements Day-Ahead Losses Rebate on Carved-Out Grandfathered Agreements Day-Ahead Congestion Rebate on Option B Grandfathered Agreements DA_GFACO_RBT_CG DA_GFACO_RBT_LS DA_GFAOB_RBT_CG Schedule Schedule Schedule Day-Ahead Losses Rebate on Option B Grandfathered Agreements Day-Ahead Revenue Sufficiency Guarantee Distribution Amount DA_GFAOB_RBT_LS DA_RSG_DIST Schedule Distribution Day-Ahead Market Administration Amount DA_ADMIN Admin Day-Ahead Schedule 24 Allocation Amount DA_SCHD_24_ALC Admin 52 Introduction

54 Load Load - Real-Time Charges: Part 1 Charge Type Acronym Type Real-Time Asset Energy Amount RT_ASSET_EN Energy Real-Time Financial Schedule Congestion Amount RT_FIN_CG Schedule Real-Time Financial Schedule Loss Amount RT_FIN_LS Schedule Real-Time Congestion Rebate on Carved-Out Grandfathered Agreements Real-Time Losses Rebate on Carved-Out Grandfathered Agreements RT_GFACO_RBT_CG RT_GFACO_RBT_LS Schedule Schedule Real-Time Market Administration Amount RT_ADMIN Admin RT Schedule 24 Allocation Amount RT_SCHD_24_ALC Admin 53 Introduction

55 Load Load - Real-Time Charges: Part 2 Charge Type Acronym Type Real-Time Distribution of Losses Amount RT_LOSS_DIST Distribution Real-Time Miscellaneous Amount RT_MISC Distribution Real-Time Net Inadvertent Distribution RT_NI_DIST Distribution Real-Time Revenue Neutrality Uplift Amount RT_RNU Distribution Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount RT_RSG_DIST1 Distribution Regulation Cost Distribution Amount RT_ASM_REG_DIST Distribution Spinning Reserve Cost Distribution Amount RT_ASM_SPIN_DIST Distribution Supplemental Reserve Cost Distribution Amount RT_ASM_SUPP_DIST Distribution 54 Introduction

56 Review Questions 55 Introduction

57 Load Review Question 1 How many Day-Ahead Settlement Charges are related to Load? 1) 10 2) 9 3) 12 4) 7 56 Introduction

58 Load Review Question 2 Day Ahead Demand Bid must submitted by the day prior to the operating date. 1) 10:00 am 2) 9:00 am 3) 11:00 pm 4) 11:00 am 57 Introduction

59 Load Review Question 3 If a LSE has behind-the-meter generation at the Load CPNode, the LSE may submit a 1) Price-Sensitive Demand Bids 2) Fixed Demand Bids 3) No bids 58 Introduction

60 Load Review Question 4 If a LSE is under scheduled in Day Ahead Market, which is not a valid option. 1) Enter into Internal Bilateral deal for the difference 2) Buy the difference in the Real Time market 3) Reduce Load in Real Time if possible 4) Update the Day Ahead Schedule in Real time 59 Introduction

61 Load Review Question 5 If a LSE has industrial complex which can shed 10 MW in 30 minutes, the LSE can register the load as a 1) DRR1 2) DRR2 3) Pseudo-Tie 4) EDR 60 Introduction

62 Load Review Question 6 If a LSE has industrial complex which can dispatch up to 10 MW in 30 minutes, the LSE can register the load as a : 1) DRR1 2) DRR2 3) Pseudo-Tie 4) EDR 61 Introduction

63 Load Charges 62

64 Review of Two Difficult Load Charges 1) Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount 2) Real-Time Revenue Neutrality Uplift Amount 63 Load Charges

65 Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount (RT_RSG_DIST1) Post April

66 Pre vs. Post April 2011 Virtual RSG Summary Pre- April 2011 Only Virtual Supply volume is used Settled at the individual CPNode Set RSG rate for every CPNode No netting of deviations Post April 2011 Both Virtual Supply and Offer are used Netting of Volume across Asset Owner CPNodes before NDL Different Rates for each Active Transmission Constraint Two distribution buckets - CMC and DCC New concept of Constraint Contribution Factor (CCF) 65 Load Charges

67 RT_RSG_DIST1 Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount (RT_RSG_DIST1) This charge funds the RSG Make Whole Payments paid to the generation Asset Owners Charges Asset Owner s assets and schedules with an adverse impact on a constraint based on the amount of deviation and the Constraint Contribution Factor (CCF) for the Active Transmission Constraint Charges Asset Owner s sum total of asset-related deviations and demand changes which are deemed to be a cause for Real-Time RAC generation commitments 66 Load Charges

68 RT_RSG_DIST1 AO ATC CCF CMC DDC MP NDL RAC Commonly Used Acronyms Asset Owner Active Transmission Constraints Constraint Contribution Factor Constraint Management Charge Day-Ahead Deviation & Headroom Charge Market Participant Notification Deadline Reliability Assessment Commitment 67 Load Charges

69 RT_RSG_DIST1 Hierarchy 68 Load Charges

70 RT _RSG_DIST1 CMC1 DDC CMC2 CMC4 CMC3 CMC_DEV_VOL is for individual constraints DDC_DEV_VOL is for whole MISO constraints 69 Load Charges

71 RT_RSG_DIST1 - Formula H( ) *RT_RSG_DIST1 = *RT_RSG_DIST1_HR Hourly Real-Time RSG Distribution Amount *RT_RSG_DIST1_HR = CMC_DIST + DDC_DIST Load Charges

72 RT_RSG_DIST1 CMC_DEV_VOL = DDC_DEV_VOL = NDL Dev CMC_NDL_ VOL DDC_NDL_ VOL + + RT Dev CMC_RT_VOL DDC_ RT_VOL 71 Load Charges

73 RT_RSG_DIST1 Constraint Management Charge Distribution Calculation (CMC_DIST) Funds Real-Time RSG MWP amount credits paid to units committed in the RAC to manage Active Transmission Constraints (ATCs). AO s assets and schedules with an adverse impact on a constraint are charged based on the amount of deviation and the Constraint Contribution Factor for the ATC. Calculates deviations from the Day-Ahead to the Notification Deadline. Calculates deviations from the Notification Deadline to the Real- Time. 72 Load Charges

74 RT_RSG_DIST1 CMC_DEV_VOL = NDL Dev CMC_NDL_ VOL Sum of All +/- Deviation X CCF Net Positive Total is added to RT Dev RT Dev CMC_RT_VOL Sum of all Positive (Deviation x CCF) 73 Load Charges

75 RT_RSG_DIST1 Day-Ahead Deviation and Headroom Charge Distribution Calculation (DDC_DIST) Charges Asset Owners for asset-related deviations and demand changes for RAC-Committed Resources. Calculates deviations from Day-Ahead to the Notification Deadline. Calculates deviations from the Notification Deadline to Real-Time. 74 Load Charges

76 RT_RSG_DIST1 DDC_DEV_VOL = NDL Dev DDC_NDL_ VOL + Sum of All +/- Deviation Net Positive (Increase Demand) Total is added to RT Dev + RT Dev DDC_ RT_VOL Sum of all MAX(NDL Deviation,0 ) or ABS( RT Deviation) 75 Load Charges

77 RT_RSG_DIST1 Example - CMC: Assumption CCF =.3 Day Ahead Schedule volume = 100 Notification Deadline volume = 90 Difference = 10 *.3 = 3 Impact: 10 increased (Long) in Supply since the CCF is positive, it is hurting the Constraint If CCF is Positive Negative Hurt if Increased Supply, Help if Decreased Supply Help if Increased Supply, Hurt if Decreased Supply 76 Load Charges

78 RT_RSG_DIST1 Example - CMC : Notification Deadline volume = 90 Actual Meter Volume = 95 Real Time Deviation - 5 *.3 = -1.5 Impact: 5 decrease in Supply since the CCF is positive, it is helping the Constraint CMC_NDL_ VOL + CMC_RT_VOL 3 = Load Charges

79 RT_RSG_DIST1 Example - DDC : Day Ahead Schedule = 100 Notification Deadline volume = 90 Actual Meter Volume = 95 Real Time Deviation 5 DDC_NDL_ VOL + DDC_RT_VOL 5 = Load Charges

80 Notification Deadline In order for deviation volumes to be used for netting, Market Participant must update the RT Demand Forecast 4 hours before the start of the operating hour. 79 Load Charges

81 CMC Information Real-Time Settlement Statement shows the CMC rate and volume for each Constraint. 80 Load Charges

82 CMC Information On MISO portal > Market Reports > RSG Constraint Contribution Factor CCF (csv) file shows the CCF for each Constraint. 81 Load Charges

83 CMC Information CCF file shows the CCF for each CP Node for every hour of that Operating Day. 82 Load Charges

84 CMC and DDC Information Real-Time Settlement Statement shows the CMC Distribution Amount for each hour and the DDC Volume. 83 Load Charges

85 Real-Time Revenue Neutrality Uplift Amount (RT_RNU) 84

86 RT_RNU The Real-Time Revenue Neutrality Uplift Amount is a charge type set up as a revenue distribution balancing mechanism for charges and credits that have no other distribution method to AOs. On an hourly basis, all charges and credits that have no other distribution method are summed, and the subsequent total charge or credit for the Hour is distributed to AOs by multiplying this amount times the AO to MISO LRS factor. 85 Load Charges

87 RT_RNU 86 Load Charges

88 RT_RNU D Revenue Inadequacy Uplift: Revenue Inadequacy ensures on an hourly basis that MISO is not revenue short or long for each Hour. Specifically, Revenue Inadequacy verifies that revenue related to energy and losses remain balanced. The revenue for the Day-Ahead and Real-Time Markets are calculated and tracked separately. Day-Ahead and Real-Time hourly revenue shortfalls and excesses are dispersed through this charge type. Charge or Credit 87 Load Charges

89 RT_RNU D Joint Operating Agreement Uplift JOAs are arrangements with MISO and bordering ISOs that enable one ISO on an hourly basis to request the other to redispatch to relieve, or make available, additional transmission flowgate capacity for use by the requesting ISO. Collect shortfall if Day-Ahead or Real-Time Congestion is not sufficient Allocate additional fund received in Real-Time Charge or Credit 88 Load Charges

90 RT_RNU D.13.3 Option B Grandfathered Agreement Financial Schedule Congestion Rebate Distribution Amount Uplift The congestion charge rebate is primarily funded through MISO held FTR revenues representing the Option B transaction volume. Any funding shortfall is collected from AOs in this uplift. Charge 89 Load Charges

91 RT_RNU D.13.4 Carved-Out Grandfathered Agreement Congestion Rebate Distribution Amount Uplift The congestion charge rebate is primarily funded through MISO held FTR revenues representing the Carved-Out GFA transaction volume. Any funding shortfall is collected from AOs in this uplift. Charge 90 Load Charges

92 RT_RNU D.13.5 Real-Time Revenue Sufficiency Guarantee Make Whole Payments Second Pass Distribution Uplift RT RSG Second Pass Distribution is used to fund RT RSG MWPs attributable to Transmission De-rates and Topology Adjustments, Intra-Hour Demand Changes, and any residual amount not otherwise attributable to the two aforementioned reasons or collected via RT RSG First Pass Distribution. Charge 91 Load Charges

93 RT_RNU D.13.6 Real Time Contingency Reserve Deployment Failure Charge Uplift Amount The Real-Time Contingency Deployment Failure Charge Uplift Amount represents the offsetting credits to the Revenue Neutrality Uplift Charge type funded by the charges incurred by Resources that fail to deploy Contingency Reserves at or above the Contingency Reserve Deployment Instruction. Credit 92 Load Charges

94 RT_RNU D.13.7 Price Volatility Make-Whole Payment Uplift The Real-Time Price Volatility Make-Whole Payment Uplift Amount represents the charges to the Revenue Neutrality Uplift Charge type used to fund the credits received by Resources through the Real-Time Price Volatility Make-Whole Payment Amount Charge type. Charge 93 Load Charges

95 RT_RNU AO_LRS_VOL Hourly AO Total LRS Volume (MWh); represents the total load volume including physical exports (Wheel-Out transactions) out of MISO for an AO. Physical exports do not include pseudo tie schedules or Carved-Out Grandfather Agreement Transactions. AO to MISO LRS Factor (factor); the ratio of an AO s total positive meter volumes (Load) divided by the MISO total. The result is an hourly factor per AO that is rounded to eight decimal places. = AO_LRS_VOL / MISO ( AO_LRS_VOL ) RT_RNU _HR Hourly Real-Time Revenue Neutrality Uplift Amount for an AO ($); the result is rounded to the nearest cent. The hourly values are displayed beneath the Charge Type total in the line item section of the statement. = MISO_LRS_FCTAO * MISO_RT_RNU 94 Load Charges

96 RT_RNU RT_RNU Statement Information 95 Load Charges

97 LUNCH 96

98 Transmission Settlements 97

99 Transmission Settlements Transmission Service Transmission Settlement Services Firm Point to Point (Reserved Capacity) Non-Firm Point to Point (Reserved Capacity) Network Integration Transmission Service (Network Load) Schedule 10 - ISO Cost Recovery Adder Demand Schedule 10 - ISO Cost Recovery Adder Energy Schedule 10 - FERC Annual Charges Recovery Schedule 23 - GFA Recovery Demand Schedule 23 GFA Recovery Energy Schedule 23 GFA Recovery FERC Schedule 35 - HVDC Agreement Cost Recovery Demand 98

100 Transmission Settlements Transmission Settlement Services Firm Point to Point (Reserved Capacity) Non-Firm Point to Point (Reserved Capacity) Network Integration Transmission Service (Network Load) Schedule 1 - Scheduling, System Control and Dispatch Service Schedule 2 - Reactive Supply and Voltage Control Schedule 7 Long-term Firm and Short-term Firm Point-to-Point Transmission Service Schedule 8 Non-Firm Point- to-point Transmission Service Schedule 9 Network Integration Transmission Service Schedule 11 Wholesale Distribution Service (FERC orders and prior period adjustments) 99

101 Transmission Settlements cont d. Transmission Settlement Services Firm Point to Point (Reserved Capacity) Non-Firm Point to Point (Reserved Capacity) Network Integration Transmission Service (Network Load) Schedule 26 - Network Upgrade Charge from Transmission Expansion Plan Schedule 33 Recovery of Service Cost from Black Start Unit Owners Schedule 34 Allocations of Costs Associated with Penalty Assessments As Needed Schedule 36 Regional Charge to Recovery Costs of ITCTransmission Phase Angle Regulators (PARS) from PJM and NYISO RTO Regions (Flat fee to PJM and NYISO only) 100

102 Transmission Settlements Manager Gloria Bryant

103 Agenda TOPICS Load Overview Load Market Overview Load Settlements Overview Load - RSG and RNU Charge review SCHEDULE 10:30 10:45 am 10:45 11:00 am 11:00 11:15 am 11:15 12:00 pm Lunch Load Charge Type Review Load Day Ahead Charge Types Example Break Load Real-Time Charge Types Example Summary and Quiz 12:00 12:45 pm 12:45 01:00 pm 01:00 02:00 pm 02:00 02:15 pm 02:15 03:30 pm 03:30 04:00 pm 102

104 Load Settlements Review 103 Introduction

105 Load Review Question 7 How many components in Revenue Neutrality Charge? 1) 7 2) 8 3) 9 4) Introduction

106 Load Review Question 8 True/ False Can a load get paid for consuming energy? True When Load CPnode LMP is negative. 105 Introduction

107 Load Review Question 9 The deadline to submit meter data for Load is the noon of? 1) + 6 days after the Operating Day 2) + 13 days after the Operating Day 3) + 54 days after the Operating Day 4) days after the Operating Day 106 Introduction

108 Load Review Question 10 Which of the following statement is True? If the actual meter load volume is less than Day Ahead Schedule 1) RT_RSG_DIST charge would be zero 2) RT_RNU would be Zero 3) Received a credit for RT_ASSET_EN 4) RT_ ADMIN charge would decrease 107 Introduction

109 108

110 Charge Types Throughout this presentation, the evaluation of each Charge Type is divided into five parts: Purpose Hierarchy Formula Example Summary 109

111 Example Settlement Data Day-Ahead Line Items DA_SCHD DA_FINBuyer DA_GFACOBuyer DA_GFAOBBuyer 75 MW 25 MW 10 MW 15 MW Real-Time Line Items 100 MW RT_BLL_MTR 15 MW RT_FINBuyer 12 MW RT_GFACOBuyer Market Wide Determinants DA_LMP $27 RT_LMP $25 DART_ADMIN_RATE $.09 SCHD_24_ALC_RATE $

112 DA_ASSET_EN Wind Farm Coal Plant Load City (75 MW) Gas Plant CIN Hub 111

113 RT_ASSET_EN Wind Farm Coal Plant DA Load City (75 MW) RT Load City (100 MW) Gas Plant CIN Hub 112

114 Day-Ahead Energy Charge Type 113

115 Energy Procurement Charge An Asset Owner can satisfy its Load energy needs by purchasing the energy through the Day-Ahead Market, by purchasing the energy with financial bilateral contracts or by moving energy from a power source with its existing grandfathered agreement. The total Load Energy cost at a CPNode is captured by the Day-Ahead Asset Energy Charge. 114

116 Day-Ahead Asset Energy Amount (DA_ASSET_EN) 115

117 DA_ASSET_EN - Purpose Day-Ahead Asset Energy Amount (DA_ASSET_EN) Used to settle Load Purchases and Generator Sales in the Day-Ahead (DA) Market Asset Owners are paid to produce energy and are charged to consume energy Net charges or credits for all cleared energy schedules in the DA Market for each Commercial Pricing Node (CPNode) Includes Financial Bilateral Transactions (FBT), Option B Schedules and Grandfathered Carve Out Schedules that source or sink at an Asset Owner s CPNode Who gets the charge/credit? Asset Owners with Load Financial Bilateral sellers Where does it go? Asset Owners with cleared Energy Offers or self-schedules Financial Bilateral buyers 116

118 DA_ASSET_EN - Hierarchy 117

119 DA_ASSET_EN - Formula *DA_ASSET_EN = H ( ) ( CN DA_ASSET_VOL *DA_LMP_EN DA_ASSET_VOL = * DA _ SCHD + DA _ FIN _ ASSET _ VOL DA _ GFACO _ ASSET _ VOL SELLER SELLER + DA _ FIN _ ASSET _ VOL + DA _ GFACO _ ASSET _ VOL BUYER BUYER + Determinant Formula *DA_SCHD = Σ Asset (*DA_SCHD) DA_FIN_ASSET_VOL SELLER = Σ Transactions-CN (*DA_FIN Seller ) + Σ Transactions-CN (*DA_GFAOB Seller ) DA_FIN_ASSET_VOL BUYER = [Σ Transactions-CN (*DA_FIN Buyer )+Σ Transactions-CN (*DA_GFAOB Buyer )] (-1) DA_GFACO_ASSET_VOL SELLER = Σ Transactions-CN (*DA_GFACO Seller ) DA_GFACO_ASSET_VOL BUYER = Σ Transactions-CN (*DA_GFACO Buyer ) (-1) 118

120 DA_ASSET_EN Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Financial and Grandfathered agreement transactions The unit cleared 75 MW at the Load Zone for HE 1 Two Financial Schedule purchases, one for 20 Mw at the source and the other for 5 MW at the Load Zone from a Marketer Moved 10 MW from its Generator A to its Load with a GFACO schedule Moved 15 MW from Generator B to its Load with a GFAOB Schedule What is the charge/credit for DA_ASSET_EN? Load Asset Volume HE *DA_SCHD *DA_FINBuyer *DA_GFAOBBuyer *DA_GFACOBuyer *DA LMP Total MW , $27 25 *Note that LMPs will usually be different for each transaction 119

121 DA_ASSET_EN Wind Farm Coal Plant Load City (75 MW) Gas Plant CIN Hub 120

122 DA_ASSET_EN Intermediate Calculations Determinant Formula *DA_SCHD = Σ Asset (*DA_SCHD) 75 = Σ Asset(75 + 0) DA_FIN_ASSET_VOL SELLER = Σ Transactions-CN (*DA_FIN Seller ) + Σ Transactions-CN (*DA_GFAOB Seller ) 0 = Σ Transactions-CN ( 0 ) + Σ Transactions-CN ( 0 ) DA_FIN_ASSET_VOL BUYER = [Σ Transactions-CN (*DA_FIN Buyer )+Σ Transactions-CN (*DA_GFAOB Buyer )] (-1) -40 = [Σ Transactions-CN (20+5)+Σ Transactions-CN (15)] (-1) DA_GFACO_ASSET_VOL SELLER = Σ Transactions-CN (*DA_GFACO Seller ) 0 = Σ Transactions-CN (0) DA_GFACO_ASSET_VOL BUYER = Σ Transactions-CN (*DA_GFACO Buyer ) (-1) *DA_ASSET_VOL -10 = Σ Transactions-CN (10) (-1) * DA _ SCHD + DA _ FIN _ ASSET _ VOL DA _ GFACO _ ASSET _ VOL SELLER SELLER + DA _ FIN _ ASSET _ VOL + DA _ GFACO _ ASSET _ VOL BUYER BUYER ( -40 ) ( -10 ) 121

123 DA_ASSET_EN Charge Type Calculation *DA_ASSET_EN ( = DA_ASSET_VOL H CN ( ) *DA_LMP_EN $675 = 25 MW H ( ( ) $27 CN Results in a $675 charge for HE 1 122

124 DA_ASSET_EN Summary The Day-Ahead Asset Energy Amount is the product of (1) the sum of (a) cleared Day-Ahead energy schedules, (b) Day-Ahead Financial Bilateral Transactions, (c) Day-Ahead Valid Option B Grandfathered Agreement Transactions, and (d) Day-Ahead Carve Out Grandfathered Agreement Transactions; and (2) the LMP at each Commercial Pricing Node to settle Load Purchases and Generator Sales for an Asset Owner. Questions? 123

125 Day-Ahead Schedule Charges 124

126 Schedule Charges Asset Owners are responsible for the congestion and loss when moving energy using a financial bilateral schedule or grandfathered carve-out from another node to its Load node to satisfy its energy obligations. The congestion and loss are charged first and may be recovered depending on the schedule type. 125

127 Day-Ahead Financial Schedule Congestion Amount (DA_FIN_CG) 126

128 DA_FIN_CG - Purpose Day-Ahead Financial Schedule Congestion Amount (DA_FIN_CG) Represents an AO s total FBT congestion costs and Carved-Out GFA Transaction congestion costs for an OD Charge or credit based on the difference between two CPNodes congestion costs multiplied by the transaction volume Calculated on FBTs (IBS and GFAOB transaction types) and Carved-Out GFA Transactions Who gets the charge/credit? Sellers for congestion between the source and Delivery Point CPNode Buyers for congestion between Delivery Point and Sink CPNode Where does it go? GFAOB and GFACO Holders Financial Transmission Rights Holders (FTRs) 127

129 DA_FIN_CG - Hierarchy *Note that the DA_GFAOB Buyer and Seller determinants must first be validated against each other in order to ensure sufficient supply and load volume. 128

130 DA_FIN_CG - Formula *DA_FIN_CG ( = + DA_FIN_BUY_CG DA_FIN_SELL_CG H DA_FIN_GFAOB_BUY_CG DA_FIN_GFAOB_SELL_CG DA_GFACO_BUY_CG + DA_GFACO_SELL_CG ) DA_FIN_BUY_CG = Hourly Total Day-Ahead Buyer FBT Congestion Charge ($) Σ Transactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] DA_FIN_SELL_CG = Hourly Total Day-Ahead Seller FBT Congestion Charge ($) Σ Transactions [ (*DA_FIN Seller ) x (*DA_LMP_CG DP - *DA_LMP_CG SO ) ] 129

131 DA_FIN_CG - Formula = Σ H (DA_FIN_BUY_CG + DA_FIN_SELL_CG + DA_FIN_GFAOB_BUY_CG + DA_FIN_GFAOB_SELL_CG + DA_GFACO_BUY_CG + DA_GFACO_SELL_CG) DA_FIN_GFAOB_BUY_CG Hourly Total Day-Ahead Buyer Option B FBT Congestion Charge ($) = Σ Transactions [ (DA_GFAOB Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] DA_FIN_GFAOB_SELL_CG Hourly Total Day-Ahead Seller Option B FBT Congestion Charge ($) = Σ Transactions [ (DA_GFAOB Seller ) x (*DA_LMP_CG DP - *DA_LMP_CG SO ) ] DA_GFACO_BUY_CG DA_GFACO_SELL_CG Hourly Total Day-Ahead Buyer Carved-Out GFA Transaction Congestion Charge ($) Σ Transactions [ (*DA_GFACO Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] = Hourly Total Day-Ahead Seller Carved-Out GFA Transaction Congestion Charge ($) Σ Transactions [ (*DA_GFACO Seller ) x (*DA_LMP_CG DP - *DA_LMP_CG SO ) ] = 130

132 DA_FIN_CG Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Financial Transactions and Grandfathered agreements Used two Financial Schedules to make purchases, one for 20 MW at the source and the other for 5 MW sinking at the Load Zone from a Marketer Moved 10 MW from Generator A to its Load with a GFACO schedule Moved another 15 MW from Generator B to its Load with a GFAOB Schedule What is the charge/credit for DA_FIN_CG? Load Asset Volume HE DA_FIN Buyer DA_FIN Seller DA_GFAOB Buyer DA_GFAOB Seller DA_GFACO Buyer DA_GFACO Seller *DA_LMP_CG SO DA_LMP_CG SI 1 20, $5 $7 *Note that LMPs will usually be different for each transaction 131

133 DA_FIN_CG Intermediate Calculations Determinant DA_FIN_BUY_CG DA_FIN_BUY_CG DA_FIN_GFAOB_BUY_CG DA_GFACO_BUY_CG Formula =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 40 =ΣTransactions [ (20) x (7-5 ) ] =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 0 =ΣTransactions [ (5) x (7-7 ) ] =ΣTransactions [ (DA_GFAOB Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 30 =ΣTransactions [ (15) x (7-5 ) ] =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 20 =ΣTransactions [ (10) x (7-5 ) ] 132

134 DA_FIN_CG Charge Type Calculation ( = + DA_FIN_BUY_CG DA_FIN_SELL_CG + *DA_FIN_CG H + + DA_FIN_GFAOB_BUY_CG DA_FIN_GFAOB_SELL_CG DA_GFACO_BUY_CG + ) DA_GFACO_SELL_CG ( = $90 $40 $0 $30 $0 $20 $0 H ) Results in a $90 charge for HE 1 133

135 DA_FIN_CG Summary The Day-Ahead Financial Schedule Congestion Amount is the product of the transaction volume and the difference between two CPNodes congestion costs. GFAOB and GFACO FBTs exist between: A generation source and a Load Zone A generation source and an Interface CPNode An Interface CPNode and a Load Zone IBS FBTs can exist at any CPNodes Questions? 134

136 Day-Ahead Financial Schedule Loss Amount (DA_FIN_LS) 135

137 DA_FIN_LS - Purpose Day-Ahead Financial Schedule Loss Amount (DA_FIN_LS) Represents an AO s total FBT loss costs and Carved-Out GFA Transaction congestion costs for an Operating Day Charge or credit based on the difference between two CPNodes LMP loss component multiplied by the transaction volume Calculated on GFAOB, GFACO, and IBS FBTs Who gets the charge/credit? Sellers - for losses between the Source CPNode and Delivery Point Buyers - for losses between Delivery Point and Sink CPNode Where does it go? GFAOB and GFACO Holders Load Zone AOs (RT_LOSS_DIST) 136

138 DA_FIN_LS - Hierarchy *Note that the DA_GFAOB Buyer and Seller determinants must first be validated against each other in order to ensure sufficient supply and load volume. 137

139 DA_FIN_LS - Formula *DA_FIN_LS ( = + DA_FIN_BUY_LS DA_FIN_SELL_LS H DA_FIN_GFAOB_BUY_LS DA_FIN_GFAOB_SELL_LS DA_GFACO_BUY_LS + DA_GFACO_SELL_LS ) DA_FIN_BUY_LS = Hourly Total Day-Ahead Buyer FBT Loss Charge ($) Σ Transactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] DA_FIN_SELL_LS = Hourly Total Day-Ahead Seller FBT Loss Charge ($) Σ Transactions [ (*DA_FIN Seller ) x (*DA_LMP_LS DP - *DA_LMP_LS SO ) ] 138

140 DA_FIN_LS - Formula = Σ H (DA_FIN_BUY_LS + DA_FIN_SELL_LS + DA_FIN_GFAOB_BUY_LS + DA_FIN_GFAOB_SELL_LS + DA_GFACO_BUY_LS + DA_GFACO_SELL_LS) DA_FIN_GFAOB_BUY_LS DA_FIN_GFAOB_SELL_LS DA_GFACO_BUY_LS DA_GFACO_SELL_LS = = Hourly Total Day-Ahead Buyer Carved-Out GFA Transaction Loss Charge ($) Σ Transactions [ (*DA_GFACO Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] = Hourly Total Day-Ahead Seller Carved-Out GFA Transaction Loss Charge ($) = Hourly Total Day-Ahead Buyer Option B FBT Loss Charge ($) Σ Transactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] Hourly Total Day-Ahead Seller Option B FBT Loss Charge ($) Σ Transactions [ (*DA_GFAOB Seller ) x (*DA_LMP_LS DP - *DA_LMP_LS SO ) ] Σ Transactions [ (*DA_GFACO Seller ) x (*DA_LMP_LS DP - *DA_LMP_LS SO ) ] 139

141 DA_FIN_LS Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Financial Transactions and Grandfathered agreements Used two Financial Schedules to make purchases, one for 20 MW at source and the other for 5 MW sinking at the Load Zone from a Marketer Moved 10 MW from Generator A to its Load with a GFACO schedule Moved another 15 MW from Generator B to its Load with a GFAOB Schedule What is the charge/credit for DA_FIN_LS? Load Asset Volume HE DA_FIN DA_FIN DA_GFAOB DA_GFAOB DA_GFACO *A_GFACO *DA_LMP_LS *DA_LMP_LS Buyer Seller Buyer Seller Buyer Seller SO SI 1 20, $2 $3 *Note that LMPs will usually be different for each transaction 140

142 DA_FIN_LS Intermediate Calculations DA_FIN_BUY_LS Determinant Formula =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 20 =Σ Transactions [ (20) x (3-2 ) ] DA_FIN_BUY_LS =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 0 =Σ Transactions [ (5) x (3-3 ) ] DA_FIN_GFAOB_BUY_LS =ΣTransactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 15 =ΣTransactions [ (15) x (3-2 ) ] DA_GFACO_BUY_LS =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 10 =ΣTransactions [ (10) x (3-2 ) ] 141

143 DA_FIN_LS Charge Type Calculation ( = + DA_FIN_BUY_LS DA_FIN_SELL_LS + *DA_FIN_LS H DA_FIN_GFAOB_BUY_LS + + DA_FIN_GFAOB_SELL_LS + ) DA_GFACO_BUY_LS DA_GFACO_SELL_LS ( = $45 $25 $0 $15 $0 $10 $0 H ) Results in a $45 charge for HE 1 142

144 DA_FIN_LS Summary The Day-Ahead Financial Schedule Loss Amount is the product of the transaction volume and the difference between two Commercial Pricing Nodes loss cost components. The Delivery Point is defined as the financial location, which can be either the source, sink or any other CPNode, where responsibility for the cost of losses is transferred from seller to buyer, or shared in the case of a Delivery Point other than the source or sink. Transaction sellers are responsible for losses between the Delivery Point and the source CPNode. Transaction buyers are responsible for losses between the sink and Delivery Point CPNode. Questions? 143

145 Day-Ahead Congestion Rebate on Carved-Out Grandfathered Agreements (DA_GFACO_RBT_CG) 144

146 DA_GFACO_RBT_CG - Purpose Day-Ahead Congestion Rebate on Carved-Out Grandfathered Agreements (DA_GFACO_RBT_CG) Represents an AO s total Operating Day rebate, equal to all Day- Ahead FBT Congestion Amount charge type charges and credits for Carved-Out GFAs Transactions Similar to the Day-Ahead FBT Congestion Amount, the rebate can be a charge or credit depending upon the CPNodes of the transaction Calculated hourly by AO for every valid GFACO Transaction where it is buying and/or selling, and then is summed to a daily total Who gets the charge/credit? Asset Owners with valid Day-Ahead Carved-Out GFAs Transactions Where does it go? Uses funds collected for Congestion through the DA_FIN_CG (GFACO) Charge Type If insufficient funds, the Revenue Neutrality Uplift Amount is used 145

147 DA_GFACO_RBT_CG - Hierarchy 146

148 DA_GFACO_RBT_CG - Formula ( ) *DA_GFACO_RBT_CG = DA_GFACO_BUY_CG DA_GFACO_SELL_CG x (-1 ) H + Hourly Total Day-Ahead Carved-Out GFA Buyer Transaction Congestion Charges ($) DA_GFACO_BUY_CG = Σ Transactions [ (*DA_GFACO Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] DA_GFACO_SELL_CG = Hourly Total Day-Ahead Carved-Out GFA Seller Transaction Congestion Charges ($) Σ Transactions [ (*DA_GFACO Seller ) x (*DA_LMP_CG DP - *DA_LMP_CG SO ) ] 147

149 DA_GFACO_RBT_CG Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Grandfathered agreements Moved 10 MW from Generator A to its Load with a GFACO schedule What is the charge/credit for DA_GFACO_RBT_CG? Load Asset Volume HE *DA_GFACO *DA_GFACO *DA_LMP_CG SO *DA_LMP_CG SI Buyer Seller $5 $7 148

150 DA_GFACO_RBT_CG Intermediate Calculations Determinant Formula DA_GFACO_BUY_CG =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 20 =ΣTransactions [ (10) x (7-5 ) ] Recall from DA_FIN_CG Load example: Determinant Formula DA_FIN_BUY_CG = ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - DA_LMP_CG DP ) ] 40 =ΣTransactions [ (20) x (7-5 ) ] DA_FIN_BUY_CG =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 0 =ΣTransactions [ (5) x (7-7 ) ] DA_FIN_GFAOB_BUY_CG =ΣTransactions [ (DA_GFAOB Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 30 =ΣTransactions [ (15) x (7-5 ) ] DA_GFACO_BUY_CG =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 20 =ΣTransactions [ (10) x (7-5 ) ] 149

151 DA_GFACO_RBT_CG Charge Type Calculation ( *DA_GFACO_RBT_CG = + DA_GFACO_BUY_CG DA_GFACO_SELL_CG x (-1 ) H ) -$20 ( = $20 ) + $0 ) x (-1 H Results in a $20 credit for HE 1 150

152 DA_GFACO_RBT_CG Summary The Day-Ahead Congestion Rebate on Carved-Out GFAs Amount represents an AO s total OD rebate of all congestion charges and credits from the DA_FIN_CG Amount charge type. Questions? 151

153 Day-Ahead Losses Rebate on Carved-Out Grandfathered Agreements (DA_GFACO_RBT_LS) 152

154 DA_GFACO_RBT_LS - Purpose Day-Ahead Losses Rebate on Carved-Out Grandfathered Agreements (DA_GFACO_RBT_LS) Represents an AO s total Operating Day rebate of all loss charges and credits paid in the Day-Ahead FBT Loss Amount charge type related to Carved-Out GFAs Transactions Like the original losses amount, the rebate can be a charge or credit depending on the CPNode(s) being settled Calculated hourly, by AO, for every valid GFACO Transaction, where buying and/or selling, and then is summed to a daily total Who gets the charge/credit? Asset Owners with valid Day-Ahead Carved-Out GFAs Transactions Where does it go? Uses funds collected for Losses through the Real-Time Over-Collected Losses Charge Type 153

155 DA_GFACO_RBT_LS - Hierarchy 154

156 DA_GFACO_RBT_LS - Formula ( ) *DA_GFACO_RBT_LS = DA_GFACO_BUY_LS DA_GFACO_SELL_LS x (-1 ) H + Hourly Total Day-Ahead Carved-Out GFA Buyer Transaction Losses Charges ($) DA_GFACO_BUY_LS = Σ Transactions [ (*DA_GFACO Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] DA_GFACO_SELL_LS = Hourly Total Day-Ahead Carved-Out GFA Seller Transaction Losses Charges ($) Σ Transactions [ (*DA_GFACO Seller ) x (*DA_LMP_LS DP - *DA_LMP_LS SO ) ] 155

157 DA_GFACO_RBT_LS Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Grandfathered Carve-out agreements Moved 10 MW from Generator A to its Load with a GFACO schedule What is the charge/credit for DA_GFACO_RBT_LS? Load Asset Volume HE *DA_GFACO *DA_GFACO *DA_LMP_LS SO *DA_LMP_LS SI Buyer Seller $2 $3 156

158 DA_GFACO_RBT_LS Intermediate Calculations Determinant Formula DA_GFACO_BUY_LS =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 10 =ΣTransactions [ (10) x (3-2 ) ] Recall from DA_FIN_LS Load example: Determinant Formula DA_FIN_BUY_LS =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 20 =ΣTransactions [ (20) x (3-2 ) ] DA_FIN_BUY_LS =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 0 =ΣTransactions [ (5) x (3-3 ) ] DA_FIN_GFAOB_BUY_LS =ΣTransactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 15 =ΣTransactions [ (15) x (3-2 ) ] DA_GFACO_BUY_LS =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 10 =ΣTransactions [ (10) x (3-2 ) ] 157

159 DA_GFACO_RBT_LS Charge Type Calculation ( *DA_GFACO_RBT_LS = + DA_GFACO_BUY_LS DA_GFACO_SELL_LS x (-1 ) H ) -$10 ( = $10 ) + $0 ) x (-1 H Results in a $10 credit for HE 1 158

160 DA_GFACO_RBT_LS Summary The Day-Ahead Losses Rebate on Carved-Out GFAs Amount represents an AO s total OD rebate of all loss charges and credits from the Real-Time Over-Collected Losses charge type. The DA_GFACO_RBT_LS amount is equal and offsetting to the amount paid through the GFACO portion of the DA_FIN_LS charge type. Questions? 159

161 Day-Ahead Congestion Rebate on Option B Grandfathered Agreements (DA_GFAOB_RBT_CG) 160

162 DA_GFAOB_RBT_CG - Purpose Day-Ahead Congestion Rebate on Option B Grandfathered Agreements (DA_GFAOB_RBT_CG) Represents an AO s total Operating Day rebate, equal to all Day-Ahead FBT Congestion Amount charge type charges and credits for Option B GFAs Transactions Similar to the Day-Ahead FBT Congestion Amount, the rebate can be a charge or credit depending upon the CPNodes of the transaction Calculated hourly by AO for every valid GFAOB Transaction where it is buying and/or selling, and then is summed to a daily total Who gets the charge/credit? Asset Owners with valid Day-Ahead Option B GFAs Transactions Where does it go? Uses funds collected for Congestion through the DA_FIN_CG (GFAOB) Charge Type If insufficient funds, the Revenue Neutrality Uplift Amount is used 161

163 DA_GFAOB_RBT_CG - Hierarchy 162

164 DA_GFAOB_RBT_CG - Formula ( ) *DA_GFAOB_RBT_CG = DA_FIN_GFAOB_BUY_CG DA_FIN_GFAOB_SELL_CG x (-1 ) H + Hourly Total Day-Ahead Option B Buyer FBT Congestion Charge ($) DA_FIN_GFAOB_BUY_CG = Σ Transactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] Hourly Total Day-Ahead Option B Seller FBT Congestion Charge ($) DA_FIN_GFAOB_SELL_CG = Σ Transactions [ (*DA_GFAOB Seller ) x (*DA_LMP_CG DP - *DA_LMP_CG SO ) ] 163

165 DA_GFAOB_RBT_CG Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Grandfathered agreements Moved 15 MW from Generator B to its Load with a GFAOB Schedule What is the charge/credit for DA_GFAOB_RBT_CG? Load Asset Volume HE *DA_GFAOB *DA_GFAOB *DA_LMP_CG SO *DA_LMP_CG SI Buyer Seller $5 $7 164

166 DA_GFAOB_RBT_CG Intermediate Calculations Determinant Formula DA_FIN_GFAOB_BUY_CG =ΣTransactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 30 =ΣTransactions [ (15) x (7-5 ) ] Recall from DA_FIN_CG Load example: Determinant Formula DA_FIN_BUY_CG = ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - DA_LMP_CG DP ) ] 40 =ΣTransactions [ (20) x (7-5 ) ] DA_FIN_BUY_CG =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 0 =ΣTransactions [ (5) x (7-7 ) ] DA_FIN_GFAOB_BUY_CG =ΣTransactions [ (DA_GFAOB Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 30 =ΣTransactions [ (15) x (7-5 ) ] DA_GFACO_BUY_CG =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_CG SI - *DA_LMP_CG DP ) ] 20 =ΣTransactions [ (10) x (7-5 ) ] 165

167 DA_GFAOB_RBT_CG Charge Type Calculation ( *DA_GFAOB_RBT_CG = + DA_FIN_GFAOB_BUY_CG DA_FIN_GFAOB_SELL_CG x (-1 ) H ) -$30 ( = $30 ) + $0 ) x (-1 H Results in a $30 credit for HE 1 166

168 DA_GFAOB_RBT_CG Summary The Day-Ahead Congestion Rebate on Option B GFAs Amount represents an AO s total OD rebate of all congestion charges and credits from the DA FBT Congestion Amount charge type. Option B FBTs that did not pass validation in the Day-Ahead Option B Financial Schedule Validation are not charged the DA_FIN_CG charge type amount and as such are not assessed any rebates in this charge type. Questions? 167

169 Day-Ahead Losses Rebate on Option B Grandfathered Agreements (DA_GFAOB_RBT_LS) 168

170 DA_GFAOB_RBT_LS - Purpose Day-Ahead Losses Rebate on Option B Grandfathered Agreements (DA_GFAOB_RBT_LS) Represents an AO s total Operating Day rebate of the difference between Marginal Losses and GFA Average Losses (50%) in the Day-Ahead FBT Loss Amount charge type related to GFAOB FBTs Calculated hourly by AO for every valid GFAOB Transaction where it is buying and/or selling and then is summed to a daily total Who gets the charge/credit? Asset Owners with valid Day-Ahead Option B GFAs Transactions Where does it go? Uses funds collected for Losses through the DA_FIN_LS (GFAOB) Charge Type 169

171 DA_GFAOB_RBT_LS - Hierarchy 170

172 DA_GFAOB_RBT_LS - Formula *DA_GFAOB_RBT_LS ( = + DA_FIN_GFAOB_BUY_LS DA_FIN_GFAOB_SELL_LS H ) x [ ( 100) ] 1 *GFA_AVG_LOSS_PCT / x (-1 ) Hourly Total Day-Ahead Buyer GFAOB FBT Loss Charge ($) DA_FIN_GFAOB_BUY_LS = Σ Transactions [ ( IF ( Pre 888 Loss Flag = B, THEN *DA_GFAOB Buyer, ELSE 0 ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] DA_FIN_GFAOB_SELL_LS = Hourly Total Day-Ahead Seller GFAOB FBT Loss Charge ($) Σ Transactions [ ( IF ( Pre 888 Loss Flag = B, THEN *DA_GFAOB Seller, ELSE 0 ) x (*DA_LMP_LS DP - *DA_LMP_LS SO ) ] *GFA_AVG_LOSS_PCT = GFA Average Loss Rate Percentage (%) MISO System Average Loss Rate / MISO Average Marginal Loss Rate (estimate set to 50%) 171

173 DA_GFAOB_RBT_LS Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Grandfathered agreements Moved 15 MW from Generator B to its Load with a GFAOB Schedule What is the charge/credit for DA_GFAOB_RBT_LS? Load Asset Volume HE *DA_GFAOB *DA_GFAOB *DA_LMP_LS SO *DA_LMP_LS SI *GFA_AVG_LOSS_PCT Buyer Seller $2 $3 50 *Note that the GFA_AVG_LOSS_PCT is given in the Settlements system as 50% 172

174 DA_GFAOB_RBT_LS Intermediate Calculations Determinant DA_FIN_GFAOB_BUY_LS Pre 888 Loss Flag = B, so Formula =ΣTransactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 15 =ΣTransactions [ (15) x (3-2 ) ] Recall from DA_FIN_LS Load example: Determinant Formula DA_FIN_BUY_LS =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 20 =ΣTransactions [ (20) x (3-2 ) ] DA_FIN_BUY_LS =ΣTransactions [ (*DA_FIN Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 0 =ΣTransactions [ (5) x (3-3 ) ] DA_FIN_GFAOB_BUY_LS =ΣTransactions [ (*DA_GFAOB Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 15 =ΣTransactions [ (15) x (3-2 ) ] DA_GFACO_BUY_LS =ΣTransactions [ (*DA_GFACO Buyer ) x (*DA_LMP_LS SI - *DA_LMP_LS DP ) ] 10 =ΣTransactions [ (10) x (3-2 ) ] 173

175 DA_GFAOB_RBT_LS Charge Type Calculation *DA_GFAOB_RBT_LS ( = + DA_FIN_GFAOB_BUY_LS DA_FIN_GFAOB_SELL_LS H ) x [ ( 100) ] 1 *GFA_AVG_LOSS_PCT / x (-1 ) ( ) -$7.50 = $15 + $0 x H [ ( 100) ] 1 50 / x (-1 ) Results in a $ 7.50 credit for HE 1 174

176 DA_GFAOB_RBT_LS Summary All valid GFAOB FBTs are assessed the full loss charge or credit per the DA_FIN_LS amount and receive a rebate of the difference between Marginal Losses and System Average Losses. Questions? 175

177 Day-Ahead Distribution Charges 176

178 Distribution Charges For each AO for an Operating Day, Market Settlements distributes market costs related to maintaining Real-Time Market reliability and operation of the Day-Ahead Energy and Operating Reserve Market based on the AO s action or inaction to follow MISO directives, and allocate any residual cost or funds either by load ratio share or based on market participation volume. 177

179 Day-Ahead Revenue Sufficiency Guarantee Distribution Amount (DA_RSG_DIST) 178

180 DA_RSG_DIST - Purpose Day-Ahead Revenue Sufficiency Guarantee Distribution Amount (DA_RSG_DIST) This charge funds the Day-Ahead Make Whole Payments paid to the generation asset owners Charges load asset owners for a portion of the total market wide Make Whole Payment amount based on the percentage of their load to the overall market load Who gets the charge/credit? Asset Owners with Load, Virtual Schedules and/or Exports Where does it go? Asset Owners with cleared Energy Offers (via Make Whole Payment) 179

181 DA_RSG_DIST Hierarchy 180

182 DA_RSG_DIST - Formula H( ( ( = x )x *DA_RSG_DIST *MISO_DA_RSG_MWP DA_RSG_DIST_FCT -1 ) *MISO_DA_RSG_MWP = Hourly MISO Day-Ahead RSG MWP Amount ($) Σ MISO ( DA_RSG_MWP_HR ) DA_RSG_DIST_FCT = Hourly Day-Ahead RSG Distribution Factor by AO (factor) ( DA_RSG_DIST_VOL AO / MISO_DA_RSG_DIST_VOL ) = DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP 181

183 Intermediate Calculations DA_RSG_DIST Formula = Hourly Day-Ahead RSG Distribution Factor by AO (factor) DA_RSG_DIST_FCT ( DA_RSG_DIST_VOL / MISO_DA_RSG_DIST_VOL ) = DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP Determinant Formula DA_ASSET_DEMD DA_VIRT_DEMD DA_PHYS_EXP = ΣAO-CN MAX { [ MAX (DA_SCHD, 0 ) - ΣTransactions ( DA_GFACO Buyer ) ], 0 } * IF { DA_RSG_DIST_XMPT = Y, THEN 0, ELSE 1 } = ΣCN [ MAX ( DA_VSCHD, 0 ) ] * IF { DA_RSG_DIST_XMPT = Y, THEN 0, ELSE 1 } = Σ Transactions [ MAX ( DA_PHYS_TRNS, 0 ) ] DA_PHYS_TRNS = DA_PHYS Buyer + [ DA_PHYS Seller x (-1) ] 182

184 DA_RSG_DIST Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Virtual and Grandfathered agreement transactions The unit cleared 75 MW at the Load Zone for HE 1 Moved 10 MW from Generator A to its Load with a GFACO schedule The MISO Day-Ahead RSG MWP Amount is -$47,500 for HE 1 The MISO Day-Ahead RSG Distribution Volume is 18,750 MW for HE 1 The Asset Owner did not have any export schedules What is the charge/credit for DA_RSG_DIST? Load Asset Volume HE *DA_SCHD *DA_GFACOBuyer *MISO_DA_RSG_MWP *MISO_DA_RSG_DIST_VOL $47,500 18,

185 DA_RSG_DIST Intermediate Calculations Determinant Formula DA_ASSET_DEMD = ΣAO-CN MAX { [ MAX (DA_SCHD, 0 ) - ΣTransactions ( DA_GFACO Buyer ) ], 0 } 65 DA_VIRT_DEMD = ΣCN [ MAX ( DA_VSCHD, 0 ) ] 0 = ΣCN [ MAX ( 0, 0 ) ] = ΣAO-CN MAX { [ MAX ( 75, 0 ) - ΣTransactions ( 10 ) ], 0 } DA_RSG_DIST_FCT = ( DA_RSG_DIST_VOL / MISO_DA_RSG_DIST_VOL ) = DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP = ( 65 / 18,750 ) = 65 MW

186 DA_RSG_DIST Charge Type Calculation H( ( ( = x )x *DA_RSG_DIST *MISO_DA_RSG_MWP DA_RSG_DIST_FCT -1 ) H( ( ( )x -1 ) ) $59.5 = -$17,500 x.0034 Results in a $59.5 charge for HE 1 185

187 DA_RSG_DIST Summary The Day-Ahead Revenue Sufficiency Guarantee Distribution Amount funds the Make Whole Payments paid to the generation asset owners. This charge type issues a charge to Load AOs for a portion of the total market-wide Make Whole Payment amount based on the percentage of their Load to the overall market Load. This amount is calculated hourly for an AO by multiplying the MISO Day-Ahead RSG MWP Amount times the Day-Ahead RSG Distribution Factor for that AO to arrive at their proportional share of the DA RSG MWP. Questions? 186

188 Day-Ahead Admin Charges 187

189 Admin Charges For each AO for an Operating Day, Market Settlements assesses an administration charge (DA_ADMIN) on the AO participation in the Day-Ahead Energy and Operating Reserve Market. Load volume is part of the AO Participation. In addition, MISO uses a DA_SCHD_24_ALC charge for Local Balancing Authorities (LBAs) to recover the cost of labor and materials associated with market operations. Load share is the same as the volume used to calculate the DA_ADMIN Charge. 188

190 Day-Ahead Market Administration Amount (DA_ADMIN) 189

191 DA_ADMIN - Purpose Day-Ahead Market Administration Amount (DA_ADMIN) Collectively referred to as Tariff Schedule 17, the DA_ADMIN and RT_ADMIN charge types are designed to recover the cost of operating the Day-Ahead and Real-Time Energy and Operating Reserves Markets Calculated at each CPNode for each hour by multiplying an AO s Day- Ahead Market participation volume by the Hourly Energy and Operating Reserve Markets Administration Rate An AO s DA participation volume at a CPNode is based on the total directional energy volume into and out of the CPNode, by the AO Who gets the charge/credit? AOs with cleared schedules originating or terminating at a CPNode in the Day-Ahead Market Where does it go? To the MISO to recover the cost of operating the Day-Ahead Energy and Operating Reserve Market 190

192 DA_ADMIN - Hierarchy *Note that the ADMIN_TXN_CNT and ADMIN_TXN_RATE determinants are currently ignored since the Transactional Charge Rate is set to zero, making virtual schedule transaction amounts not applicable for this part of the calculation. 191

193 DA_ADMIN Schedule 17 Rate The Schedule 17 Rate is updated on or near the first of each month. Rate updates can be found on the MISO Website > Markets and Operations > Market Settlements 192

194 DA_ADMIN - Formula *DA_ADMIN = H ( ) x *DA_ADMIN_VOL *DART_ADMIN_RATE = ( ) DA_NET_SELL_ADMIN + DA_NET_SELL_ADMIN_INT + *DA_ADMIN_VOL DA_NET_BUY_ADMIN + DA_NET_BUY_ADMIN_INT + DA_VSCHD_VOL CN Determinant DA_NET_SELL_ADMIN DA_NET_SELL_ADMIN_INT DA_NET_BUY_ADMIN DA_NET_BUY_ADMIN_INT DA_VSCHD_VOL Formula An AO's Hourly Admin Volume from Cleared DA Schedules, selling FBTs, and Carve-Out GFA Transactions at Non-Interface CPNodes (MWh) An AO's Hourly Admin Volume from Cleared DA Schedules, selling FBTs, PBTs, and Carve-Out GFA Transactions at Interface CPNodes (MWh) An AO's Hourly Admin Volume from Cleared DA Schedules, buying FBTs, and Carve-Out GFA Transactions at Non-Interface CPNodes (MWh) An AO's Hourly Admin Volume from Cleared DA Schedules, buying FBTs, PBTs, and Carve-Out GFA Transactions at Interface CPNodes (MWh) The Hourly Day-Ahead Net Virtual Schedule Volume at a CPNode for an AO (MWh) 193

195 DA_ADMIN - Formula = *DA_ADMIN_VOL CN( ) DA_NET_SELL_ADMIN + DA_NET_SELL_ADMIN_INT + DA_NET_BUY_ADMIN + DA_NET_BUY_ADMIN_INT + DA_VSCHD_VOL Determinant Formula DA_NET_SELL_ADMIN = MAX {ABS [MIN ( 0, DA_SCHD ) ], [ Σ (DA_FIN Seller ) + Σ (DA_GFAOB Seller ) + Σ (DA_GFACO Seller ) ] } DA_NET_SELL_ADMIN_INT DA_NET_BUY_ADMIN DA_NET_BUY_ADMIN_INT = MAX {[ Σ ( DA_FIN Seller ) + Σ ( DA_GFAOB Seller ) ], Σ ( DA_PHYS Seller ) } + Σ ( DA_GFACO Seller ) = MAX { MAX ( 0, DA_SCHD ), [ Σ (DA_FIN Buyer ) + Σ (DA_GFAOB Buyer ) + Σ (DA_GFACO Buyer ) ] } = MAX { [ Σ ( DA_FIN Buyer ) + Σ ( DA_GFAOB Buyer ) ], Σ ( DA_PHYS Buyer ) } + Σ ( DA_GFACO Buyer ) DA_VSCHD_VOL = Σ [ ABS ( DA_VSCHD ) ] 194

196 DA_ADMIN Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market with Financial Transactions and Grandfathered agreements The unit cleared 75 MW at the Load Zone for HE 1 Used two Financial Schedules to make purchases, one for 20 MW and the other for 5 MW sinking at the Load Zone from a Marketer Moved 10 MW from Generator A to its Load with a GFACO schedule Moved another 15 MW from Generator B to its Load with a GFAOB Schedule What is the charge/credit for DA_ADMIN? Load Asset Volume HE *DA_SCHD *DA_FIN *DA_GFAOB *DA_GFACO *DART_ADMIN_RATE Buyer Buyer Buyer , $

197 DA_ADMIN Intermediate Calculations Determinant Formula DA_NET_BUY_ADMIN = MAX { MAX ( 0, DA_SCHD ), [ Σ (DA_FIN Buyer ) + Σ (DA_GFAOB Buyer ) + Σ (DA_GFACO Buyer ) ] } 75 = MAX { MAX ( 0, 75 ), [ ( 25 ) + ( 15 ) + ( 10 ) ] } * Without directional netting, AO would pay for MWh DA_NET_BUY_ADMIN_INT = MAX { [ Σ ( DA_FIN Buyer ) + Σ ( DA_GFAOB Buyer ) ], Σ ( DA_PHYS Buyer ) } + Σ ( DA_GFACO Buyer ) 0 = MAX { [ Σ ( 0 ) + Σ ( 0 ) ], Σ ( 0 ) } + Σ ( 0 ) *All values are 0 since no transactions occurred at an Interface CPNode DA_VSCHD_VOL = Σ [ ABS ( DA_VSCHD ) ] 0 = Σ [ ABS ( 0 ) ] 196

198 DA_ADMIN Charge Type Calculation *DA_ADMIN_VOL = CN( 75 MW = CN( ) DA_NET_SELL_ADMIN + DA_NET_SELL_ADMIN_INT + DA_NET_BUY_ADMIN + DA_NET_BUY_ADMIN_INT + DA_VSCHD_VOL ) *DA_ADMIN = H ( ) x *DA_ADMIN_VOL *DART_ADMIN_RATE $6.75 = H ( 75 MW $.09 ) x Results in a $6.75 credit for HE 1 197

199 DA_ADMIN Summary The Day-Ahead Market Administration Amount is calculated by multiplying an AO s DA participation volume by the Market Administration Rate. This charge type is designed to recover the cost of operating the Day-Ahead and Real-Time Energy and Operating Reserves Markets under Tariff Schedule 17. In accordance with the Tariff, all assets meeting the administrative charge exemption are not subject to the Day-Ahead Market Administrative Amount charge type. All transactions and schedules that are not exempt, originating at, or terminating at a CPNode are subject to this charge type. Questions? 198

200 Day-Ahead Schedule 24 Allocation Amount (DA_SCHD_24_ALC) 199

201 DA_SCHD_24_ALC - Purpose Day-Ahead Schedule 24 Allocation Amount (DA_SCHD_24_ALC) Cost mechanism by which Local Balancing Authorities recover the cost of labor and material associated with market operations Calculated by multiplying the DA Administrative volume by the Schedule 24 Rate to obtain an hourly dollar amount An AO s DA participation volume at a CPNode is based on the total cleared energy volume for each CPNode, by the AO Who gets the charge/credit? Asset Owners participating in the Day- Ahead Energy and Operating Reserve Market Where does it go? Used to fund Schedule 24 distribution back to the LBAs 200

202 DA_SCHD_24_ALC - Hierarchy 201

203 DA_SCHD_24_ALC - Formula *DA_SCHD_24_ALC ( = x *DA_ADMIN_VOL *SCHD_24_ALC_RATE H ) *DA_ADMIN_VOL = See Day-Ahead Market Administration Volume for an AO (MWh) DA_ADMIN Charge Type *SCHD_24_ALC_RATE = Hourly Schedule 24 Allocation Rate ($/MWh) LBAs submit the previous year s applicable costs to the MISO by May 1 st in order to calculate the rate(s) for the upcoming Schedule year (June 1 st - May 31 st ). The allocation rate is published for each calendar month. 202

204 DA_SCHD_24_ALC Load Scenario 1 Load Serving Entity participating in the Day-Ahead Energy and Operating Reserve Market for HE 1 Total cleared Load is 75 MW for the CPNode What is the charge/credit for DA_SCHD_24_ALC? Load Asset Volume HE *DA_ADMIN_VOL *SCHD_24_ALC_RATE 1 75 $

205 DA_SCHD_24_ALC Charge Type Calculation *DA_SCHD_24_ALC ( = x *DA_ADMIN_VOL *SCHD_24_ALC_RATE H ) $.75 ( = 75 MW $.01 H x ) Results in a $.75 charge for HE 1 204

206 DA_SCHD_24_ALC Summary The DA Schedule 24 Allocation Amount constitutes the collected monies, in the Day-Ahead Market, used to fund Schedule 24 distribution back to the LBAs and is calculated by multiplying the DA Admin Volume by the Schedule 24 Rate. The aggregation of Day-Ahead and Real-Time Allocation amounts is equal to the full daily distribution of Schedule 24 funds back to the LBAs. Questions? 205

207 Day-Ahead Summary DAY AHEAD SETTLEMENT STATEMENT MISO Settlement Type S7 Total Day Ahead Market Administration Amount Day Ahead Regulation Amount 0 0 Day Ahead Spinning Reserve Amount 0 0 Day Ahead Supplemental Reserve Amount 0 0 Day Ahead Asset Energy Amount Day Ahead Financial Bilateral Transaction Congestion Amount Day Ahead Financial Bilateral Transaction Loss Amount Day Ahead Congestion Rebate on Carve-Out Grandfathered Agrmnts Day Ahead Losses Rebate on Carve-Out Grandfathered Agrmnts Day Ahead Congestion Rebate on Option B Grandfathered Agrmnts Day Ahead Losses Rebate on Option B Grandfathered Agrmnts Day Ahead Non-Asset Energy Amount 0 Day Ahead Revenue Sufficiency Guarantee Distribution Amount Day Ahead Revenue Sufficiency Guarantee Make Whole Payment Amt 0 0 Day Ahead Schedule 24 Allocation Amount Day Ahead Virtual Energy Amount 0 0 Total

208 Break 207

209 Real-Time Energy Charges 208

210 Real-Time Charges Load Related Real-Time Charges Charge Type Acronym Type Real-Time Asset Energy Amount RT_ASSET_EN Energy Real-Time Financial Schedule Congestion Amount RT_FIN_CG Schedule Real-Time Financial Schedule Loss Amount RT_FIN_LS Schedule Real-Time Congestion Rebate on Carved-Out Grandfathered Agreements RT_GFACO_RBT_CG Real-Time Losses Rebate on Carved-Out Grandfathered Agreements RT_GFACO_RBT_LS Schedule Schedule Real-Time Market Administration Amount RT_ADMIN Admin RT Schedule 24 Allocation Amount RT_SCHD_24_ALC Admin Real-Time Distribution of Losses Amount RT_LOSS_DIST Distribution Real-Time Miscellaneous Amount RT_MISC Distribution Real-Time Net Inadvertent Distribution RT_NI_DIST Distribution Real-Time Revenue Neutrality Uplift Amount RT_RNU Distribution Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount RT_RSG_DIST1 Distribution Regulation Cost Distribution Amount RT_ASM_REG_DIST Distribution Spinning Reserve Cost Distribution Amount RT_ASM_SPIN_DIST Distribution Supplemental Reserve Cost Distribution Amount RT_ASM_SUPP_DIST Distribution 209

211 Real-Time Energy Procurement Charge 210

212 Energy Procurement Charge An Asset Owner can satisfy its incremental Real- Time Load energy needs by purchasing the energy through the Real-Time Market, by purchasing the energy with financial bilateral contracts or by moving energy from a power source with its existing grandfathered agreement. The total incremental Real-Time Load Energy cost at a CPNode is captured by the Real-Time Asset Energy Charge. 211

213 Real-Time Asset Energy Amount (RT_ASSET_EN) 212

214 RT_ASSET_EN - Purpose Real-Time Asset Energy Amount (RT_ASSET_EN) Net charges or credits for all energy schedules at a Market Participant s owned Load Assets Includes Financial Bilateral that source or sink at the seller or the buyers asset, respectively Calculated at Load Asset CPNode ONLY Who gets the charge/credit? Asset Owners with net Load Financial Bilateral Sellers Load (if RT MWs > DA MWs) Where does it go? Asset Owners with net Generation Financial Bilateral Buyers Load (if RT MWs < DA MWs) 213

215 RT_ASSET_EN - Hierarchy 214

216 RT_ASSET_EN - Formula *RT_ASSET_EN ( = x RT_ASSET_VOL H CN ( ) *RT_LMP_EN RT_ASSET_VOL = * RT _ BLL _ MTR * DA _ SCHD + RT _ FIN _ NET + RT _ GFACO _ NET Determinant Formula *RT_BLL_MTR = Hourly Real-Time Metered Billable Volume at a Commercial Pricing Node (MWh) *DA_SCHD = Σ Asset (*Cleared Bids + *Cleared Offers) RT_FIN_NET = Σ Schedule (RT_FIN Seller ) + Σ Schedule [ (-1) * RT_FIN Buyer ] RT_GFACO_NET = Σ Schedule [ (RT_GFACO Seller ) - (DA_GFACO Seller ) ] - Σ Schedule [ (RT_GFACO Buyer ) - (DA_GFACO Buyer ) ] 215

217 RT_ASSET_EN Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market The unit cleared 75 MW for HE 1 in DA. Actual Meter Volume in Real time is 100 MW RT Market has commenced and the AO has submitted data for his Load Asset. In addition, Financial Bilateral and Grandfathered transactions were utilized for HE 1. Moved 12 MW from Generator A to its Load with a GFACO schedule, but scheduled 10 MW in the DA Market Also, a RT Financial Schedule purchase was made for another 15 MW What is the charge/credit for RT_ASSET_EN? Load Asset Volume HE *RT_BLL_MTR *DA_SCHD *RT_FIN *RT_GFACO *DA_GFACO *RT_LMP RT Buyer Buyer Buyer MW $

218 RT_ASSET_EN 15 MW RT FS 12 MW RT GFACO Gas Plant DA Load City (75 MW) RT Load City (100 MW) Coal Plant 217

219 RT_ASSET_EN Intermediate Calculations *RT_BLL_MTR *DA_SCHD Determinant 100 Formula = Hourly Real-Time Metered Billable Volume at a Commercial Pricing Node (MWh) = 100 (submitted by MDMA) = Σ Asset DA_SCHD 75 = Σ Asset(75 + 0) RT_FIN_NET = Σ Schedule (RT_FIN Seller ) + Σ Schedule [ ( -1 ) x RT_FIN Buyer ] -15 = Σ Schedule (0) + Σ Schedule [ (-1) x (15) ] RT_GFACO_NET = Σ Schedule [ ( RT_GFACO Seller ) - ( DA_GFACO Seller ) ] - Σ Schedule [ ( RT_GFACO Buyer ) - ( DA_GFACO Buyer ) ] -2 = Σ Schedule [ (0) - (0) ] - Σ Schedule [ ( 12 ) - ( 10 ) ] *RT_ASSET_VOL *RT_BLL_MTR - *DA_SCHD + RT_FIN_NET + RT_GFACO_NET (-15) - (2) 218

220 RT_ASSET_EN Charge Type Calculation *RT_ASSET_EN ( = RT_ASSET_VOL H CN ( ) *RT_LMP_EN $200 = 8 MW H ( ( ) $25 CN Results in a $200 charge for HE 1 219

221 RT_ASSET_EN Summary The hourly Real-Time Asset Energy Amount is the hourly Real-Time LMP multiplied by the summation of the following AO related items: 1) The Hourly Billable Metered Volume at a Load CPNode, plus 2) The sum of the hourly Real-Time FBT Volume, plus 3) The LBA Residual Load if applicable, and less 4) The hourly Day-Ahead Asset Energy Volume, plus 5) The Real-Time Carved-Out Grandfathered Transaction volume, less 6) The Day-Ahead Carved-Out Grandfathered Transaction volume. Questions? 220

222 Real-Time Schedule Charges 221

223 Scheduling Charges Asset Owners are responsible for the congestion and loss when moving energy using a financial bilateral schedule or grandfathered carve-out from another node to its Load node to satisfy its energy needs. The congestion and loss are charged first and may be recovered depending on the schedule type. 222

224 Real-Time Financial Schedule Congestion Amount (RT_FIN_CG) 223

225 RT_FIN_CG - Purpose Real-Time Financial Schedule Congestion Amount (RT_FIN_CG) Represents an AO s total Real-Time FBT (IBS and Pseudo) congestion costs and Carved-Out GFA Transaction congestion costs for an OD Pseudo FBTs are established by the MISO and account for congestion and loss charges on generation and Load that is pseudo-tied to an external LBA Who gets the charge/credit? Sellers for congestion between the source and Delivery Point CPNode Buyers for congestion between Delivery Point and Sink CPNode Where does it go? GFACO Holders Surplus to AO by Load Ratio volume 224

226 RT_FIN_CG Hierarchy 225

227 Charge Type Calculation RT_FIN_CG - Formula ( = + + *RT_FIN_CG RT_FIN_BUY_CG RT_FIN_SELL_CG H + + RT_FIN_PSD_BUY_CG RT_FIN_PSD_SELL_CG RT_GFACO_BUY_CG + RT_GFACO_SELL_CG ) Hourly Total Real-Time Buyer (non-pseudo) FBT Congestion Charge ($) RT_FIN_BUY_CG = Σ Transactions [ (RT_FIN Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP ) ] Hourly Total Real-Time Seller (non-pseudo) FBT Congestion Charge ($) RT_FIN_SELL_CG = Σ Transactions [ (RT_FIN Seller ) x (RT_LMP_CG DP - RT_LMP_CG SO ) ] 226

228 RT_FIN_CG - Formula = Σ H (RT_FIN_BUY_CG + RT_FIN_SELL_CG + RT_FIN_PSD_BUY_CG + RT_FIN_PSD_SELL_CG + RT_GFACO_BUY_CG + RT_GFACO_SELL_CG) RT_FIN_PSD_BUY_CG Hourly Total Real-Time Buyer Pseudo FBT Congestion Charge ($) = Σ Transactions [ (RT_FIN Pseudo_Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP ) ] RT_FIN_PSD_SELL_CG Hourly Total Real-Time Seller Pseudo FBT Congestion Charge ($) = Σ Transactions [ (RT_FIN Pseudo_Seller ) x (RT_LMP_CG DP - RT_LMP_CG SO ) ] RT_GFACO_BUY_CG = Hourly Total Real-Time Buyer Carved-Out GFA Transaction Congestion Charge ($) Σ Transactions [(RT_GFACO Buyer - DA_GFACO Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP )] RT_GFACO_SELL_CG = Hourly Total Real-Time Seller Carved-Out GFA Transaction Congestion Charge ($) Σ Transactions [(RT_GFACO Seller - DA_GFACO Seller ) x (RT_LMP_CG DP - RT_LMP_CG SO )] 227

229 RT_FIN_CG Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market Used a Real-Time Financial Schedule to purchase extra15 MW at the Load Zone from the Marketer Moved 12 MW from Generator A to its Load with a GFACO schedule, but scheduled 10 MW in the DA Market What is the charge/credit for RT_FIN_CG? Load Asset Volume HE *RT_FIN *RT_FIN *RT_GFACO *DA_GFACO *RT_LMP_CG SO *RT_LMP_CG SI Buyer Pseudo_Buyer Buyer Buyer $6 $7 *Note that LMPs will usually be different for each transaction 228

230 RT_FIN_CG Intermediate Calculations Determinant Formula RT_FIN_BUY_CG =Σ Transactions [ (RT_FIN Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP ) ] 0 =ΣTransactions [ (15) x (7-7 ) ] RT_FIN_PSD_BUY_CG =Σ Transactions [ (RT_FIN Pseudo_Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP ) ] 0 =ΣTransactions [ (0) x (7-6 ) ] RT_GFACO_BUY_CG =Σ Transactions [(RT_GFACO Buyer - DA_GFACO Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP )] 2 =ΣTransactions [ (12-10) x (7-6 ) ] 229

231 RT_FIN_CG Charge Type Calculation ( = + RT_FIN_BUY_CG RT_FIN_SELL_CG + *RT_FIN_CG H RT_FIN_PSD_BUY_CG + RT_FIN_PSD_SELL_CG + + ) RT_GFACO_BUY_CG RT_GFACO_SELL_CG ( = $2 0 $0 0 $0 $2 $0 H ) Results in a $2 charge for HE 1 230

232 RT_FIN_CG Summary The Real-Time FBT Congestion Amount is calculated hourly and represents an AO s total RT FBT, Pseudo-Tie and GFACO Transaction congestion costs for each OD. The RT FBT buyer is responsible for the congestion charge difference between the sink and Delivery Point CPNode while the seller is responsible between the Delivery Point and the source. Pseudo FBTs: Pseudo-tied generation and load Energy are not settled in the MISO The energy volume is subject to congestion and loss charges from the sink to the Delivery Point and from the Delivery Point to the source The pseudo-tied asset is initially estimated by the state estimator and subsequently update by the MDMA The MISO will create pseudo-tie FBTs contracts for all registered pseudo-tie CPNodes Questions? 231

233 Real-Time Financial Schedule Loss Amount (RT_FIN_LS) 232

234 RT_FIN_LS - Purpose Real-Time Financial Schedule Loss Amount (RT_FIN_LS) Represents an AO s total Real-Time FBT (IBS and Pseudo) loss costs and Carved-Out GFA Transaction congestion costs for an Operating Day For FBTs, the concept of a Delivery Point is incorporated to provide the parties to the transaction a location other than the source or sink where responsibility for congestion and losses is transferred from seller to buyer (can be any CPNode, including the source or sink) For Carved-Out GFA Transactions, the Delivery Point is always the source Commercial Pricing Node FBT sellers for losses between the Delivery Point and source CPNode Who gets the charge/credit? FBT buyers for losses between the sink and Delivery Point CPNode GFACO buyers for losses between the sink and source CPNode Where does it go? GFACO Holders Load Zone AOs (RT_LOSS_DIST) 233

235 RT_FIN_LS - Hierarchy 234

236 RT_FIN_LS - Formula ( = + + *RT_FIN_LS RT_FIN_BUY_LS RT_FIN_SELL_LS H + + RT_FIN_PSD_BUY_LS RT_FIN_PSD_SELL_LS RT_GFACO_BUY_LS + RT_GFACO_SELL_LS ) Hourly Total Real-Time Buyer FBT Loss Charge ($) RT_FIN_BUY_LS = Σ Transactions [ (*RT_FIN Buyer ) x (*RT_LMP_LS SI - *RT_LMP_LS DP ) ] Hourly Total Real-Time Seller FBT Loss Charge ($) RT_FIN_SELL_LS = Σ Transactions [ (*RT_FIN Seller ) x (*RT_LMP_LS DP - *RT_LMP_LS SO ) ] 235

237 RT_FIN_LS - Formula = Σ H (RT_FIN_BUY_LS + RT_FIN_SELL_LS + RT_FIN_PSD_BUY_LS + RT_FIN_PSD_SELL_LS + RT_GFACO_BUY_LS + RT_GFACO_SELL_LS) RT_FIN_PSD_BUY_LS = Hourly Total Real-Time Buyer Pseudo FBT Loss Charge ($) Σ Transactions [ (*RT_FIN Pseudo_Buyer ) x (*RT_LMP_LS SI - *RT_LMP_LS DP ) ] RT_FIN_PSD_SELL_LS = Hourly Total Real-Time Seller Pseudo FBT Loss Charge ($) Σ Transactions [ (*RT_FIN Pseudo_Seller ) x (*RT_LMP_LS DP - *RT_LMP_LS SO ) ] RT_GFACO_BUY_LS RT_GFACO_SELL_LS Hourly Total Real-Time Buyer Carved-Out GFA Transaction Losses Charge ($) = Hourly Total Real-Time Seller Carved-Out GFA Transaction Losses Charge ($) = Σ Transactions [(RT_GFACO Buyer - DA_GFACO Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP )] Σ Transactions [(RT_GFACO Seller - DA_GFACO Seller ) x (RT_LMP_LS DP - RT_LMP_LS SO )] 236

238 RT_FIN_LS Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market Used a Real-Time Financial Schedule to purchase 15 MW sinking at the Load Zone from a Marketer Moved 12 MW from Generator A to its Load with a GFACO schedule, but scheduled 10 MW in the DA Market What is the charge/credit for RT_FIN_LS? Load Asset Volume HE *RT_FIN *RT_FIN *RT_GFACO *DA_GFACO *RT_LMP_LS SO *RT_LMP_LS SI Buyer Pseudo_Buyer Buyer Buyer $4 $5 *Note that LMPs will usually be different for each transaction 237

239 RT_FIN_LS Intermediate Calculations Determinant Formula RT_FIN_BUY_LS =Σ Transactions [ (RT_FIN Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP ) ] 0 =ΣTransactions [ (15) x (5-5 ) ] RT_FIN_PSD_BUY_LS =Σ Transactions [ (RT_FIN Pseudo_Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP ) ] 0 =ΣTransactions [ (0) x (5-5 ) ] RT_GFACO_BUY_LS =Σ Transactions [(RT_GFACO Buyer - DA_GFACO Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP )] 2 =ΣTransactions [ (12-10) x (5-4 ) ] 238

240 Charge Type Calculation RT_FIN_LS ( = + RT_FIN_BUY_LS RT_FIN_SELL_LS + *RT_FIN_LS H RT_FIN_PSD_BUY_LS + RT_FIN_PSD_SELL_LS + + ) RT_GFACO_BUY_LS RT_GFACO_SELL_LS ( = $2 $0 $0 $0 $0 $2 $0 H ) Results in a $2 charge for HE 1 239

241 RT_FIN_LS Summary The RT_FIN_LS Charge Type consists of the sum of: FBT volume multiplied by the difference between two CPNodes losses components, plus The net transaction volume of Real-Time Carved-Out GFA less Day-Ahead Carved-Out GFA transaction volume, multiplied by the difference between two CPNodes losses components Pseudo FBTs: Pseudo-tied generation and load Energy are not settled in the MISO The energy volume is subject to congestion and loss charges from the sink to the Delivery Point and from the Delivery Point to the source The pseudo-tied asset is initially estimated by the state estimator and subsequently update by the MDMW The MISO will create pseudo-tie FBTs contracts for all registered pseudo-tie CPNodes Questions? 240

242 Real-Time Congestion Rebate on Carved-Out Grandfathered Agreements (RT_GFACO_RBT_CG) 241

243 RT_GFACO_RBT_CG - Purpose Real-Time Congestion Rebate on Carved-Out Grandfathered Agreements (RT_GFACO_RBT_CG) Represents an AO s total Operating Day rebate of all congestion charges and credits paid through the RT_FIN_CG Charge Type related to Carved- Out GFA Transactions Like the RT_FIN_CG amount, the rebate can be a charge or credit depending upon the CPNodes being settled Calculated hourly by AO for every valid GFACO Transaction where it is buying and/or selling and then is summed to a daily total Who gets the charge/credit? Asset Owners with valid Real-Time Carved-Out GFA Transactions Where does it come from? Uses funds collected for Congestion through the RT_FIN_CG (GFACO) Charge Type If insufficient funds, the Revenue Neutrality Uplift Amount is used 242

244 RT_GFACO_RBT_CG - Hierarchy Note: The RT_GFACO buyer and seller determinant amounts represent the net of RT and DA GFACO Transactions. 243

245 RT_GFACO_RBT_CG - Formula ( ) *RT_GFACO_RBT_CG = RT_GFACO_BUY_CG RT_GFACO_SELL_CG x (-1 ) H + Hourly Total Real-Time Carved-Out GFA Buyer Transaction Congestion Charges ($) RT_GFACO_BUY_CG = Σ Transactions [(*RT_GFACO Buyer - *DA_GFACO Buyer ) x (*RT_LMP_CG SI - *RT_LMP_CG DP )] RT_GFACO_SELL_CG = Hourly Total Real-Time Carved-Out GFA Seller Transaction Congestion Charges ($) Σ Transactions [(*RT_GFACO Seller - *DA_GFACO Seller ) x (*RT_LMP_CG DP - *RT_LMP_CG SO )] 244

246 RT_GFACO_RBT_CG Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market with Grandfathered agreements Moved 10 MW from Generator A to its Load with a GFACO schedule (DA) Used a Carved-Out GFA Transaction to move a total of 12 MW to its Load (RT) What is the charge/credit for RT_GFACO_RBT_CG? Load Asset Volume HE *RT_GFACO *DA_GFACO *RT_LMP_CG SO *RT_LMP_CG SI Buyer Buyer $6 $7 245

247 RT_GFACO_RBT_CG Intermediate Calculations Determinant RT_GFACO_BUY_CG Formula ΣTransactions [(*RT_GFACO Buyer - *DA_GFACO Buyer ) x (*RT_LMP_CG SI - *RT_LMP_CG DP )] 2 =ΣTransactions [ (12-10) x (7-6 ) ] Recall from RT_FIN_CG Load example: Determinant Formula RT_FIN_BUY_CG =Σ Transactions [ (RT_FIN Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP ) ] 0 =ΣTransactions [ (15) x (7-7 ) ] RT_FIN_PSD_BUY_CG =Σ Transactions [ (RT_FIN Pseudo_Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP ) ] 0 =ΣTransactions [ (0) x (7-6 ) ] RT_GFACO_BUY_CG =Σ Transactions [(RT_GFACO Buyer - DA_GFACO Buyer ) x (RT_LMP_CG SI - RT_LMP_CG DP )] 2 =ΣTransactions [ (12-10) x (7-6 ) ] 246

248 RT_GFACO_RBT_CG Charge Type Calculation ( *RT_GFACO_RBT_CG = + RT_GFACO_BUY_CG RT_GFACO_SELL_CG x (-1 ) H ) -$2 ( = $2 ) + $0 ) x (-1 H Results in a $2 credit for HE 1 247

249 RT_GFACO_RBT_CG Summary The Real-Time Congestion Rebate on Carved-Out GFAs Amount represents an AO s total OD rebate of all congestion charges and credits paid in the RT FBT Congestion Amount Charge Type related to GFACO Transactions. All Day-Ahead Carved-Out GFA Transactions must have a corresponding Real-Time Carved-Out GFA Transaction, but a Real-Time Carved-Out Grandfathered Transaction does not need to have a corresponding Day-Ahead Transaction. If the Asset Owner is both the buyer and seller, the transaction will be listed once for each end of the transaction. Questions? 248

250 Real-Time Losses Rebate on Carved-Out Grandfathered Agreements (RT_GFACO_RBT_LS) 249

251 RT_GFACO_RBT_LS - Purpose Real-Time Losses Rebate on Carved-Out Grandfathered Agreements (RT_GFACO_RBT_LS) Represents an AO s total Operating Day rebate, equal to all RT_FIN_LS charge type amounts for Carved-Out GFAs Transactions Similar to the Real-Time FBT Losses Amount, the rebate can be a charge or credit depending upon the CPNodes of the transaction Calculated hourly by AO for every valid GFACO Transaction where it is buying and/or selling, and then is summed to a daily total Who gets the charge/credit? Asset Owners with valid Real-Time Carved-Out GFAs Transactions Where does it come from? Uses funds collected for Losses through the Real-Time Over-Collected Losses Charge Type 250

252 RT_GFACO_RBT_LS - Hierarchy Note: The RT_GFACO buyer and seller determinant amounts represent the net of RT and DA GFACO Transactions. 251

253 RT_GFACO_RBT_LS - Formula ( ) *RT_GFACO_RBT_LS = RT_GFACO_BUY_LS RT_GFACO_SELL_LS x (-1 ) H + Hourly Total Real-Time Carved-Out GFA Buyer Transaction Losses Charges ($) RT_GFACO_BUY_LS = Σ Transactions [(*RT_GFACO Buyer - *DA_GFACO Buyer ) x (*RT_LMP_LS SI - *RT_LMP_LS DP )] RT_GFACO_SELL_LS = Hourly Total Real-Time Carved-Out GFA Seller Transaction Losses Charges ($) Σ Transactions [(*RT_GFACO Seller - *DA_GFACO Seller ) x (*RT_LMP_LS DP - *RT_LMP_LS SO )] 252

254 RT_GFACO_RBT_LS Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market with Grandfathered agreements Moved 10 MW from Generator A to its Load with a GFACO schedule (DA) Used a Carved-Out GFA Transaction to move a total of 12 MW to its Load (RT) What is the charge/credit for RT_GFACO_RBT_LS? Load Asset Volume HE *RT_GFACO *DA_GFACO *RT_LMP_CG SO *RT_LMP_CG SI Buyer Buyer $4 $5 253

255 RT_GFACO_RBT_LS Intermediate Calculations Determinant Formula RT_GFACO_BUY_LS = Σ Transactions [(*RT_GFACO Buyer - *DA_GFACO Buyer ) x (*RT_LMP_LS SI - *RT_LMP_LS DP )] 2 =ΣTransactions [ (12-10) x (5-4 ) ] Recall from RT_FIN_LS Load example: Determinant Formula RT_FIN_BUY_LS =Σ Transactions [ (RT_FIN Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP ) ] 0 =ΣTransactions [ (15) x (5-5 ) ] RT_FIN_PSD_BUY_LS =Σ Transactions [ (RT_FIN Pseudo_Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP ) ] 0 =ΣTransactions [ (0) x (5-5 ) ] RT_GFACO_BUY_LS =Σ Transactions [(RT_GFACO Buyer - DA_GFACO Buyer ) x (RT_LMP_LS SI - RT_LMP_LS DP )] 2 =ΣTransactions [ (12-10) x (5-4 ) ] 254

256 RT_GFACO_RBT_LS Charge Type Calculation ( *RT_GFACO_RBT_LS = + RT_GFACO_BUY_LS RT_GFACO_SELL_LS x (-1 ) H ) -$2 ( = $2 ) + $0 ) x (-1 H Results in a $2 credit for HE 1 255

257 RT_GFACO_RBT_LS Summary The Real-Time Losses Rebate on Carved-Out GFAs Amount represents an AO s total OD rebate of all loss charges and credits from the Real-Time Over-Collected Losses charge type. The RT_GFACO_RBT_LS amount is equal and offsetting to the amount paid through the GFACO portion of the RT_FIN_LS charge type. Questions? 256

258 Real-Time Admin Charges 257

259 Admin Charges For each AO for an Operating Day, Market Settlements assesses an administration charge (RT_ADMIN) on the AO participation in the Day-Ahead Energy and Operating Reserve Market. Load volume is part of the AO Participation. In addition, MISO uses a RT_SCHD_24_ALC charge for Local Balancing Authorities (LBAs) to recover the cost of labor and materials associated with market operations. The Load share is the same as the volume used to calculate the RT_ADMIN Charge. 258

260 Real-Time Market Administration Amount (RT_ADMIN) 259

261 RT_ADMIN - Purpose Real-Time Market Administration Amount (RT_ADMIN) Collectively referred to as Tariff Schedule 17, the DA and RT_ADMIN charge types are designed to recover the cost of operating the Day-Ahead and Real-Time Energy and Operating Reserves Markets Calculated at each CPNode for each hour by multiplying an AO s Real-Time Market participation volume by the Hourly Energy and Operating Reserve Markets Administration Rate An AO s RT participation volume at a CPNode is based on the total directional energy volume into and out of the CPNode, by the AO Who gets the charge/credit? AOs with net schedules originating or terminating at the asset CPNode in the Real-Time Market Where does it go? To the MISO to recover the cost of operating the Real-Time Energy and Operating Reserve Market 260

262 RT_ADMIN Schedule 17 Rate The Schedule 17 Rate is updated on or near the first of each month. Rate updates can be found on the MISO Website > Markets and Operations > Market Settlements 261

263 RT_ADMIN - Hierarchy 262

264 RT_ADMIN - Formula ( ) AO( x *RT_ADMIN *RT_ADMIN_VOL = H *DART_ADMIN_RATE *RT_ADMIN_VOL = CN ( ) RT_NET_SELL_ADMIN + RT_NET_SELL_ADMIN_INT + RT_NET_BUY_ADMIN + RT_NET_BUY_ADMIN_INT + RT_PSEUDO_VOL Determinant RT_NET_SELL_ADMIN RT_NET_SELL_ADMIN_INT RT_NET_BUY_ADMIN RT_NET_BUY_ADMIN_INT RT_PSEUDO_VOL Formula An AO's Net Hourly Admin Volume from Injection/Withdrawal, selling FBTs, and Carve-Out GFA Transactions at Non-Interface CPNodes (MWh) An AO's Net Hourly Admin Volume from Injection/Withdrawal, selling FBTs, PBTs, and GFACO Transactions at Interface CPNodes (MWh) An AO's Net Hourly Admin Volume from Injection/Withdrawal, buying FBTs, and Carve-Out GFA Transactions at Non-Interface CPNodes (MWh) An AO's Net Hourly Admin Volume from Injection/Withdrawal, buying FBTs, PBTs, and GFACO Transactions at Interface CPNodes (MWh) Hourly Pseudo Real-Time FBT Volume (MWh) 263

265 RT_ADMIN - Formula = *RT_ADMIN_VOL CN( ) RT_NET_SELL_ADMIN + RT_NET_SELL_ADMIN_INT + RT_NET_BUY_ADMIN + RT_NET_BUY_ADMIN_INT + RT_PSEUDO_VOL Determinant Formula RT_NET_SELL_ADMIN = MAX {ABS [MIN ( 0, RT_ASSET_IMB ) ], [ Σ (RT_FIN Seller ) + NET_RT_GFACO_SELL ] } RT_NET_SELL_ADMIN_INT RT_NET_BUY_ADMIN RT_NET_BUY_ADMIN_INT = MAX [ Σ ( RT_FIN Seller ), NET_RT_PHYS_SELL ], + NET_RT_GFACO_SELL = MAX { MAX ( 0, RT_ASSET_IMB ), [ Σ (RT_FIN Buyer ) + NET_RT_GFACO_BUY ] } = MAX [ Σ ( RT_FIN Buyer ), NET_RT_PHYS_BUY ], + NET_RT_GFACO_BUY RT_PSEUDO_VOL = Σ ( RT_FIN Pseudo-Buyer ) + Σ ( RT_FIN Pseudo-Seller ) 264

266 Load Scenario 1 RT_ADMIN Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market The unit cleared 75 MW in Day Ahead for HE 1 Real-Time Market has commenced and the Asset Owner has submitted data for his Load Asset. In addition, Financial Bilateral and Grandfathered transactions were utilized for HE 1. Moved 12 MW from Generator A to its Load with a GFACO schedule, but scheduled 10 MW in the DA Market Also, a Real-Time Financial Schedule purchase was made for another 15 MW What is the charge/credit for RT_ADMIN? Load Asset Volume HE *RT_BLL_MTR *DA_SCHD *RT_FIN *RT_GFACO *DA_GFACO *DART_ADMIN_RATE Buyer Buyer Buyer $

267 RT_ADMIN Intermediate Calculations Determinant RT_NET_BUY_ADMIN Formula = MAX { MAX ( 0, RT_ASSET_IMB ), [ Σ (RT_FIN Buyer ) + NET_RT_GFACO_BUY ] } 25 = MAX { MAX ( 0,25 ), [ Σ (15) + (12-10) ] } = *RT_ADMIN_VOL CN( ) RT_NET_SELL_ADMIN + RT_NET_SELL_ADMIN_INT + RT_NET_BUY_ADMIN + RT_NET_BUY_ADMIN_INT + RT_PSEUDO_VOL 25 MW = CN( )

268 RT_ADMIN Charge Type Calculation *RT_ADMIN = H ( ) x *RT_ADMIN_VOL *DART_ADMIN_RATE $2.25 = H ( 25 MW $.09 ) x Results in a $2.25 charge for HE 1 267

269 RT_ADMIN Summary The Real-Time Market Administration Amount is calculated by multiplying an AO s RT participation volume by the Market Administration Rate. This charge type is designed to recover the cost of operating the Day-Ahead and Real-Time Energy and Operating Reserves Markets under Tariff Schedule 17. In accordance with the Tariff, all assets meeting the administrative charge exemption are not subject to the Day-Ahead Market Administrative Amount charge type. All transactions and schedules that are not exempt, originating at, or terminating at a CPNode are subject to this charge type. Questions? 268

270 Real-Time Schedule 24 Allocation Amount (RT_SCHD_24_ALC) 269

271 RT_SCHD_24_ALC - Purpose Real-Time Schedule 24 Allocation Amount (RT_SCHD_24_ALC) Cost mechanism by which LBAs recover the cost of labor and material associated with market operations Calculated by multiplying the RT Administrative volume by the Schedule 24 Rate to obtain an hourly dollar amount An AO s RT participation volume at a CPNode is based on the total directional energy volume, into and out of the CPNode, by the AO Who gets the charge/credit? Asset Owners participating in the Real-Time Energy and Operating Reserve Market Where does it go? Used to fund Schedule 24 distribution back to the LBAs 270

272 RT_SCHD_24_ALC - Hierarchy 271

273 RT_SCHD_24_ALC - Formula *RT_SCHD_24_ALC ( = x *RT_ADMIN_VOL *SCHD_24_ALC_RATE H ) *RT_ADMIN_VOL = See Real-Time Administration Volume (MWh) *RT_ADMIN Charge Type *SCHD_24_ALC_RATE = Hourly Schedule 24 Allocation Rate ($/MWh) LBAs submit the previous year s applicable costs to the MISO by May 1 st order to calculate the rate(s) for the upcoming Schedule year (June 1 st - May 31 st ). The allocation rate is set for each calendar month. in 272

274 RT_SCHD_24_ALC Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market The RT_ADMIN_VOL was 25 MW for the CPNode What is the charge/credit for RT_SCHD_24_ALC? Load Asset Volume HE *RT_ADMIN_VOL *SCHD_24_ALC_RATE 1 25 $

275 RT_SCHD_24_ALC Charge Type Calculation *RT_SCHD_24_ALC ( = x *RT_ADMIN_VOL *SCHD_24_ALC_RATE H ) $.25 ( = 25 MW $.01 H x ) Results in a $.25 charge for HE 1 274

276 RT_SCHD_24_ALC Summary The RT Schedule 24 Allocation Amount constitutes the collected monies, on the Real-Time Market, used to fund Schedule 24 distribution back to the LBAs and is calculated by multiplying the RT Administrative volume by the Schedule 24 Rate. The aggregation of Day-Ahead and Real-Time Allocation amounts is equal to the full daily distribution of Schedule 24 funds back to the LBAs. Questions? 275

277 Real-Time Distribution Charges 276

278 Distribution Charges For each AO for an Operating Day, Market Settlements distributes market costs related to maintaining Real-Time market reliability and operation of the Real-Time Energy and Operating Reserve Market based on the AO s action or inaction to follow MISO directives, and allocate any residual cost or funds either by load ratio share or based on market participation volume. 277

279 Real-Time Distribution of Losses Amount (RT_LOSS_DIST) 278

280 RT_LOSS_DIST - Purpose Real-Time Distribution of Losses Amount (RT_LOSS_DIST) Distributes surplus collected losses to Load Zone AO s The charge type has three main calculations: The determination of the Marginal Losses Surplus to be distributed The allocation of the surplus into loss pools, and The distribution of the loss pools to each AO within each loss pool The MISO calculates the Marginal Loss Surplus as the sum of: Total Real-Time Over-Collected Losses, plus Total Day-Ahead Losses Rebate on GFAOBs FBTs Amount, plus Total Day-Ahead and Real-Time Losses Rebate on Carved-Out GFAs Charge Type Amount Who gets the charge/credit? Surplus is distributed to loss pools based upon a weighted loss distribution factor Determined by the estimated cost of marginal Losses and by the average marginal cost of losses of any imported energy Distributed based upon Load consumed within each Loss Pool Where does it come from? A specific charge type is not used Uses surplus from Real-Time and Day-Ahead Financial Schedule Loss Amount charge types 279

281 RT_LOSS_DIST - Hierarchy *Further determinant calculations have been left out for simplicity. These and other Charge Type calculations can be found in the Market Settlements BPM Calculation Guide. 280

282 RT_LOSS_DIST - Formula *RT_LOSS_DIST ( = x *MISO_LOSS_SURPLUS H Assets ( x ) *LP_FCT *LP_LRS_FCT Hourly MISO Loss Surplus Amount ($) *MISO_LOSS_SURPLUS = (RT_OCL + *MISO_GFAOB_LS_RBT + *MISO_GFACO_LS_RBT) * (-1) *LP_FCT = Loss Pool to MISO Losses Distribution Factor at Loss Pool (LP_LOSS_MLC / MISO_LOSS_MLC) *LP_LRS_FCT = Hourly Real-Time Distribution Factor for an Asset in a Loss Pool (WDR_MTR / LP_WDR_MTR) 281

283 RT_LOSS_DIST Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market The DART calculated total MISO over-collected losses of $5,000 The MISO total DA Losses Rebate on GFAOB FBTs for HE 1 is $2,000 The MISO total DA and RT Losses Rebate on Carved-Out GFAs is $3,000 Cost of losses in the Loss Pool netted against generation and DRR volume costs used to serve the Load, plus the Import Loss Factor is $1,500 Aggregated cost of losses in all of the MISO is $8,000 Withdrawal Meter Volume for an Asset at a Load Zone CPNode is 100 MW Total Withdrawal Meter Volume for all assets in a Loss Pool is 750 MW What is the charge/credit for RT_LOSS_DIST? Load Asset Volume HE RT_OCL *MISO_GFAOB_LS_RB *MISO_GFACO_LS_RBT LP_LOSS_ML MISO_LOSS_ML WDR_MTR LP_WDR_MTR T C C 1 $5,000 $2,000 $3,000 $1,500 $8,

284 RT_LOSS_DIST Intermediate Calculations Determinant Formula MISO_LOSS_SURPLUS = (RT_OCL + MISO_GFAOB_LS_RBT + MISO_GFACO_LS_RBT) * (-1) LP_FCT LP_LRS_FCT -$10,000 = ($ $ $2000) x (-1) = (LP_LOSS_MLC / MISO_LOSS_MLC).1875 = ($1500 / $8000) = (WDR_MTR / LP_WDR_MTR).1333 = (100 / 750) 283

285 RT_LOSS_DIST Charge Type Calculation *RT_LOSS_DIST ( = x *MISO_LOSS_SURPLUS H Assets ( x ) *LP_FCT *LP_LRS_FCT = x $ $10, H x ( ( ) Assets Results in a $ credit to the AO for HE 1 284

286 RT_LOSS_DIST Summary Surplus collected losses are distributed to Load Zone AOs by: Determining the Marginal Losses Surplus to be distributed Allocating the surplus into loss pools, and Distributing the loss pools to each AO within each loss pool Real-Time Over-Collected Losses is a dollar value calculated by the DART every 5 minutes as the Real-Time Market is cleared and is aggregated to an hourly value A Loss Pool is defined as a one or more LBAs for the purpose of distributing Marginal Losses Surplus All Load supplied by GFAOB FBTs and Carved-Out GFA Transactions are excluded from surplus loss distributions since their losses are rebated in other Charge Types Questions? 285

287 Real-Time Miscellaneous Amount (RT_MISC) 286

288 RT_MISC - Purpose Real-Time Miscellaneous Amount (RT_MISC) A mechanism that allows the MISO to issue charges and/or credits based on specific requirements to either one AO or to the entire market Facilitates the following charges and/or credits: Method A: Charge or credit applied to a single AO Method B: Charge or credit applied to a single AO with the opposite charge or credit spread to all other AOs based on the OD s: 1) LRS, 2) MRS, or 3) FRS Method C: Charge or credit applied to all AOs based on an OD s: 1) LRS, 2) MRS, or 3) FRS Who gets the charge/credit? Individual AOs or all AOs participating in the Real-Time Market Where does it go? Individual AOs or all AOs participating in the Real-Time Market 287

289 RT_MISC - Hierarchy 288

290 RT_MISC - Formula *RT_MISC ( = + METHOD_A METHOD_B METHOD_C + ) METHOD_A The charge or credit applied to a single AO ($) = This charge only applies to the AO that matches the single Designated AO that is identified to receive the full charge or credit. METHOD_B = The daily charge or credit applied by AO based on LRS, MRS, or FRS for an Operating Day ($) METHOD_C = The daily charge or credit applied by AO based on LRS, MRS, or FRS for an Operating Day ($) 289

291 RT_MISC - Formula The following must be known in order to apply a single miscellaneous transaction: 1) Determine the total transaction miscellaneous charge or credit amount. 2) Determine whether the full amount is for a single AO (Method A or B) or is to be allocated to the entire market (Method C). 3) If in step 2 the full amount is for a single AO, determine whether all other AOs are responsible for paying for or collecting the amount that is given to the single AO (Method B if they are, Method A if they are not). 4) If Method C was chosen in step 2 or if Method B was chosen in step 3, determine which distribution ratio share allocation method must be used. Load Ratio Share (LRS) Market Ratio Share (MRS) FTR Ratio Share (FRS) LRS is equal to an AO s total hourly Load divided by the total hourly Load for all the MISO. MRS is equal to an AO s total hourly DA and RT Administration Volume divided by the total hourly DA and RT Administration Volume for all the MISO. FRS is equal to an AO s total hourly FTR Profile Volume divided by the total hourly AO FTR Profile Volume for all the MISO. 290

292 RT_MISC Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market The MISO determined that an AO was overcharged by $75. An Example Asset Owner had Load of 100 MW for HE 1. Total Load for all the MISO for HE 1 is 57,500 MW. What is the charge/credit for RT_MISC for the first AO? What is the charge/credit for RT_MISC for the Example Asset Owner? Load Asset Volume HE AO Load MISO Load LRS AO Credit , $75 291

293 Charge Type Calculation RT_MISC ( *RT_MISC METHOD_B + METHOD_C = METHOD_A ) + ( $75 $75 + $0 = $0 ) + Results in a $75 credit to the AO for HE 1 ( $.13 ($75 x ) + $0 = $0 ) + Results in a $.13 charge for this AO 292

294 RT_MISC Summary The Real-Time Miscellaneous Amount allows MISO to issue charges and/or credits based on specific requirements to either one AO or to the entire market. Can be used for charges or credits ordered by the IMM. MISO follows a strict internal approval process prior to initiating this charge. The Real-Time Settlement Statement specifically lists each miscellaneous charge along with: A reference identifier The reason for the charge Whether the charge or credit is for a single AO or the entire market The ratio share being applied if applicable The amount of the charge or credit Questions? 293

295 Real-Time Net Inadvertent Distribution (RT_NI_DIST) 294

296 RT_NI_DIST - Purpose Real-Time Net Inadvertent Distribution (RT_NI_DIST) Represents daily allocation to AOs of any energy dollars that result from MISO BA Net Inadvertent for an Operating Day On an hourly basis each LBA is tasked with balancing their energy generation supply, load, and Net Scheduled Interchange (NSI) The difference between the NAI and the NSI is Net Inadvertent Calculated by averaging the LMP from all generators in the LBA times the volume of the Inadvertent and summing to a daily total. This amount is allocated based on market participation using the Net Inadvertent Distribution Factor for each AO Who gets the charge/credit? AOs participating in the DA and RT Energy Markets (by LBA) Where does it come from? Uses energy dollars that result from the MISO BA Net Inadvertent for an OD 295

297 RT_NI_DIST - Hierarchy 296

298 RT_NI_DIST - Formula *RT_NI_DIST = *MISO_NI *NI_DIST_FCT x MISO Daily Total Net Inadvertent Cost ($) *MISO_NI = Σ H ( Σ MISO ( ( NAI - NSI ) x RT_GEN_BA_LMP) ) = AVG [ IF ( CPNode = Gen Asset, RT_LMP_EN, 0 ) ] *NI_DIST_FCT = Daily Net Inadvertent Distribution Factor by AO (factor) AO_MKT_VOL / MISO_MKT_VOL = Σ H ( RT_ADMIN_VOL + DA_ADMIN_VOL ) 297

299 RT_NI_DIST Scenario 1 Entity participating in the Real-Time Energy and Operating Reserve Market The LBA reports NAI of 4500 MW and NSI of 4375 MW for the Operating Day Day-Ahead and Real-Time AO Market Administration Volumes sum to 100 MW The MISO reports the total Administration Volume for the OD for all AOs as 57,500 MW What is the charge/credit for RT_NI_DIST? Asset Volume HE NAI NSI RT_GEN_BA_LMP AO_MKT_VOL MISO_MKT_VOL $ ,

300 RT_NI_DIST Intermediate Calculations Determinant Formula MISO_NI = ΣH ( ΣMISO ( ( NAI - NSI ) x RT_GEN_BA_LMP) ) $500 = ΣH ( ΣMISO ( ( ) x $4) ) NI_DIST_FCT = AO_MKT_VOL / MISO_MKT_VOL = 100 / 57,500 *Note that only the MISO_NI and NI_DIST_FCT values are given on the Real-Time Settlement Statement, not the determinants that go into the calculations. The MISO_NI amount can be found in the Market Wide Determinants section of the Statement and the NI_DIST_FCT value can be found in the Asset Owner Determinants section. 299

301 RT_NI_DIST Charge Type Calculation *RT_NI_DIST = *MISO_NI *NI_DIST_FCT x $.87 = $500 x Results in a $.87 charge for the OD 300

302 RT_NI_DIST Summary Real-Time Net Inadvertent Distribution represents the daily allocation to AOs of any energy dollars that result from the MISO BA Net Inadvertent for an Operating Day. The hourly energy cost of the Net Inadvertent is calculated by averaging the LMP from all generators in the LBA times the volume of the Inadvertent (NAI NSI) for that same Hour The dollar impact for all hours in an OD for all the MISO LBAs is summed and is allocated to AOs based on their participation in the DA and RT Energy Markets for the OD using the Net Inadvertent Distribution Factor. Questions? 301

303 Real-Time Revenue Neutrality Uplift Amount (RT_RNU) 302

304 RT_RNU - Purpose Real-Time Revenue Neutrality Uplift Amount (RT_RNU) Charge type set up as a revenue distribution balancing mechanism for charges and credits attributable to load or that have no other distribution method to AOs On an hourly basis, all charges and credits are summed, and the subsequent total charge or credit for the Hour is distributed to AOs based on their LRS Calculated by multiplying the MISO Hourly Revenue Neutrality Adjustment Credit or Charge Amount times the AO to MISO LRS factor Who gets the charge/credit? Real-Time MISO Load based on LRS Where does it go? Various depending on component 303

305 RT_RNU Components The RT_RNU Charge Type is made up of seven components. The total dollar amount for all of the MISO is given on each AO s Settlement Statement for each hour. The following charges and/or credits are distributed through this charge type: Revenue Inadequacy Uplift (RI_UPLIFT) Revenue Inadequacy ensures on an hourly basis that the MISO is not revenue short or long for each Hour. Specifically, Revenue Inadequacy verifies that revenue related to energy and losses remain balanced. DA and RT hourly revenue shortfalls and excesses are dispersed through this charge type. Joint Operating Agreement Uplift (JOA_MISO_UPLIFT) JOAs are arrangements with the MISO and bordering ISOs that enable one ISO on an hourly basis to request the other to re-dispatch to relieve, or make available, additional transmission flowgate capacity for use by the requesting ISO. *For MISO, any funds received for DA or RT Market coordination will be added to the DA or RT Congestion Funds and any funds paid will reduce the Congestion Funds. If during an Hour there are not sufficient funds to pay for requested additional flowgate capacity, the additional funds are collected as an uplift in this charge type. 304

306 RT_RNU Components GFAOB FBT Congestion Rebate Distribution Amount Uplift (MISO_RT_GFAOB_DIST) DA GFAOB Transactions are charged the Marginal Cost of Congestion of the LMP per the DA FBT Congestion Amount charge type. The congestion charge rebate is primarily funded through MISO held FTRs revenues representing the Option B transaction volume. Any funding shortfall is collected from AOs in this uplift. Carved-Out GFA Congestion Rebate Distribution Amount Uplift (MISO_RT_GFACO_DIST) DA and RT GFACO Transactions are charged the Marginal Cost of Congestion of the LMP per the DA and RT FBT Congestion Amount charge types. The congestion charge rebates are primarily funded through MISO held FTRs revenues representing the Carved-Out GFA volume. Any funding shortfall is collected from AOs in this uplift. 305

307 RT_RNU Components Real-Time RSG MWPs Second Pass Distribution Uplift Amount (MISO_RT_RSG_DIST2) This is the secondary funding mechanism for the RT RSG MWP Amount credited to AOs. This uplift is only used when the total RT RAC Generation Resource committed volume for the Hour exceeds the AO s total RT RSG First Pass Distribution Volume. Real-Time Contingency Reserve Deployment Failure Charge Uplift Amount (MISO_CRDFC_UPLIFT) This amount represents the offsetting credits to the Revenue Neutrality Uplift Charge Type funded by the charges (RT_ASM_CRDFC) incurred by Resources that fail to deploy Contingency Reserves at or above the Contingency Reserve Deployment Instruction. Real-Time Price Volatility Make-Whole Payment Uplift (MISO_PV_MWP_UPLIFT) This amount represents the charges to the Revenue Neutrality Uplift Charge Type used to fund the credits received by Resources through the RT_PV_MWP Charge Type. 306

308 RT_RNU - Hierarchy 307

309 RT_RNU - Formula *RT_RNU ( = x *MISO_LRS_FCT AO MISO_RT_RNU H ) AO to MISO Load Ratio Share Factor (factor) *MISO_LRS_FCT AO = AO_LRS_VOL / Σ MISO ( AO_LRS_VOL ) The Hourly AO Total LRS Volume represents the total load volume including physical exports out of the MISO for an AO. Physical exports do not include pseudo-tie schedules or Carved-Out Grandfather Agreement Transactions. MISO_RT_RNU = MISO Hourly Revenue Neutrality Adjustment Credit or Charge Amount ($) *RI_UPLIFT + *JOA_MISO_UPLIFT + *MISO_RT_RSG_DIST2 + *MISO_RT_GFAOB_DIST + *MISO_RT_GFACO_DIST + *MISO_CRDFC_UPLIFT + *MISO_PV_MWP_UPLIFT 308

310 RT_RNU - Formula MISO_RT_RNU = *RI_UPLIFT + *JOA_MISO_UPLIFT + *MISO_RT_RSG_DIST2 + *MISO_RT_GFAOB_DIST + *MISO_RT_GFACO_DIST + *MISO_CRDFC_UPLIFT + *MISO_PV_MWP_UPLIFT *RI_UPLIFT *JOA_MISO_UPLIFT *MISO_RT_GFAOB_DIST = = = Total MISO Hourly Revenue Inadequacy Uplift ($) [ (MISO_DA_RI + MISO_RT_RI + MISO_RT_HR_CG_FND) x (-1) ] + MISO_LOSS_DIST_UPLIFT Total MISO Hourly Revenue JOA Uplift ($) MISO_DA_JOA_UPLIFT + MISO_RT_JOA_UPLIFT = MAX [ 0, (MISO_DA_JOA_AP - MISO_DA_HR_CG_FOR_JOA) ] Hourly Real-Time GFAOB Congestion Rebate Distribution Amount ($) MAX { 0, [ (-1) x MISO_GFAOB_RBT_CG ] - [ (-1) x FTR_HR_ALC_FCT x MISO_OB_FTR_TARG_CR ] } *MISO_RT_GFACO_DIST = Hourly Total GFACO Congestion Rebate Distribution Amount ($) MAX { 0, [ (-1) x (MISO_DA_GFACO_RBT_CG + MISO_RT_GFACO_RBT_CG)] - [ (-1) x FTR_HR_ALC_FCT x MISO_CO_FTR_TARG_CR ] } 309

311 RT_RNU - Formula MISO_RT_RNU = *RI_UPLIFT + *JOA_MISO_UPLIFT + *MISO_RT_RSG_DIST2 + *MISO_RT_GFAOB_DIST + *MISO_RT_GFACO_DIST + *MISO_CRDFC_UPLIFT + *MISO_PV_MWP_UPLIFT *MISO_RT_RSG_DIST2 Hourly MISO RT RSG Second Pass Distribution Uplift Amount ($) = (MISO_RT_RSG_MWP + MISO_RT_RSG_DIST1) x (-1) *Only calculated when total MWPs exceed the amount which can be distributed via the first pass charge type (RT_RSG_DIST1). Hourly RT Contingency Response Deployment Failure Uplift Amount ($) *MISO_CRDFC_UPLIFT = Represents the offsetting credit for the total funds collected through the RT_ASM_CRDFC Charge Type from all AOs. Hourly Real-Time Price Volatility Make-Whole Payment Uplift Amount ($) *MISO_PV_MWP_UPLIFT = Represents the charges used to fund the credits received by Resources through the RT_PV_MWP Charge Type from all AOs. 310

312 RT_RNU Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market The unit had a Metered Billable Volume of 100 MW at the Load Zone for HE 1 Moved 12 MW from Generator A to its Load with a GFACO schedule MISO total Load Volume (net of GFA Transaction Volume) is 57,500 MW The MISO submitted credit or charge amounts for each component of MISO_RT_RNU. The total amount to be allocated to AOs is $1,400 for HE 1 What is the charge/credit for RT_RNU? Load Asset Volume HE AO_LRS _VOL AO_LRS_VOL MISO MISO_RT_RNU ,500 $1,

313 RT_RNU Intermediate Calculations *MISO_LRS_FCT AO = AO_LRS_VOL / Σ MISO ( AO_LRS_VOL ) = 88 / 57,

314 RT_RNU Charge Type Calculation *RT_RNU ( = x *MISO_LRS_FCT AO MISO_RT_RNU H ) $2.14 ( = x $1,400 H ) Results in a $2.14 charge for HE 1 313

315 RT_RNU Summary The Real-Time Revenue Neutrality Uplift Amount is a charge type set up as a revenue distribution balancing mechanism for charges and credits that have no other distribution method to AOs. On an hourly basis, all charges and credits that have no other distribution method are summed, and the subsequent total charge or credit for the Hour is distributed to AOs by multiplying this amount times the AO to MISO LRS factor. Questions? 314

316 Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount (RT_RSG_DIST1) 315

317 RT_RSG_DIST1 - Purpose Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount (RT_RSG_DIST1) This charge funds the RSG Make Whole Payments paid to the generation Asset Owners Charges Asset Owner s assets and schedules with an adverse impact on a constraint based on the amount of deviation and the Constraint Contribution Factor (CCF) for the Active Transmission Constraint Charges Asset Owner s sum total of asset-related deviations and demand changes which are deemed to be a cause for Real-Time RAC generation commitments Who gets the charge/credit? Asset Owners with assets and schedules which adversely impact Constraints and deviations and demand changes resulting in commitments Where does it go? Asset Owners with generation (via Make Whole Payment) 316

318 RT_RSG_DIST1 Hierarchy 317

319 RT_RSG_DIST1 - Formula H( ) *RT_RSG_DIST1 = *RT_RSG_DIST1_HR Hourly Real-Time RSG Distribution Amount *RT_RSG_DIST1_HR = CMC_DIST + DDC_DIST 318

320 RT_RSG_DIST1 Hierarchy 319

321 RT_RSG_DIST1 Constraint Management Charge Distribution Calculation (CMC_DIST) Funds Real-Time RSG MWP amount credits paid to units committed in the RAC to manage Active Transmission Constraints (ATCs). AO s assets and schedules with an adverse impact on a constraint are charged based on the amount of deviation and the Constraint Contribution Factor for the ATC. Calculates deviations from the Day-Ahead to the Notification Deadline. Calculates deviations from the Notification Deadline to the Real- Time. 320

322 RT_RSG_DIST1 Formula Intermediate Calculations *CMC_DIST = ATC Σ Constraint Management Charge Distribution (ATC_CMC_DIST_HR) ATC_CMC_DIST_HR = Hourly Constraint Management Distribution (CMC_DEV_VOL * ATC_CMC_RATE) 321

323 RT_RSG_DIST1 Market Participant A cleared 75 MW in the Day-Ahead Market, no change at the Notification Deadline, and the actual meter value is 100 MW The Constraint Contribution Factor is -0.5 for both A and B The ATC_CMC_RATE is $3.89 The MISO_DDC_RATE is $1.56 What is the CMC_DIST? What is the DDC_DIST? 322

324 RT_RSG_DIST1 Formula Intermediate Calculations Hourly Active Transmission Constraint Management Charge Deviation Volume *CMC_DEV_VOL = MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL + CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL + CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) + CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL + CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL + CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL Determinant CMC_NDL_LOAD_VOL CMC_RT_LOAD_VOL Description Hourly Constraint Management Charge Notification Deadline Load Imbalance Volume (MWh) = IF DEV_EXEMPT = Y THEN 0 ELSE ( DA_SCHD NDL_DMD_FCST ) * ( 1 - RT_CO_LOAD_PCT ) * CCF Hourly Constraint Management Charge Real-Time Load Imbalance Volume (MWh) = IF DEV_EXEMPT = Y THEN 0 ELSE MAX { ( NDL_DMD_FCST AEW ) * ( 1 - RT_CO_LOAD_PCT ) * CCF, 0 } 323

325 Intermediate Calculations *CMC_DEV_VOL RT_RSG_DIST1 Formula Hourly Active Transmission Constraint Management Charge Deviation Volume = MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL + CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL + CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) + CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL + CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL + CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL Determinant CMC_NDL_LOAD_VOL CMC_RT_LOAD_VOL Description Hourly Constraint Management Charge Notification Deadline Load Imbalance Volume (MWh) = IF DEV_EXEMPT = Y THEN 0 ELSE ( DA_SCHD NDL_DMD_FCST ) * ( 1 - RT_CO_LOAD_PCT ) * CCF 0 = (75-75) *(1-12/100) Hourly Constraint Management Charge Real-Time Load Imbalance Volume (MWh) = IF DEV_EXEMPT = Y THEN 0 ELSE MAX { ( NDL_DMD_FCST AEW ) * ( 1 - RT_CO_LOAD_PCT ) * CCF, 0 } 11 = (75-100) *(1-12/100) *

326 RT_RSG_DIST1 Formula Intermediate Calculations *CMC_DEV_VOL Hourly Active Transmission Constraint Management Charge Deviation Volume = MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL + CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL + CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) + CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL + CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL + CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL *CMC_DEV_VOL = MAX ( , 0 ) *CMC_DEV_VOL = 11 MW 325

327 RT_RSG_DIST1 Formula Intermediate Calculations ATC_CMC_DIST_HR Hourly Constraint Management Distribution = (CMC_DEV_VOL * ATC_CMC_RATE) ATC_CMC_DIST_HR = (11 * 3.89) ATC_CMC_DIST_HR = $

328 RT_RSG_DIST1 Formula Intermediate Calculations Constraint Management Charge Distribution *CMC_DIST = Σ ATC (ATC_CMC_DIST_HR) *CMC_DIST = $ * Note This example has only one Constraint. 327

329 RT_RSG_DIST1 Hierarchy 328

330 RT_RSG_DIST1 Day-Ahead Deviation and Headroom Charge Distribution Calculation (DDC_DIST) Charges Asset Owners for asset-related deviations and demand changes for RAC-Committed Resources. Calculates deviations from Day-Ahead to the Notification Deadline. Calculates deviations from the Notification Deadline to Real-Time. 329

331 RT_RSG_DIST1 Formula Intermediate Calculations *DDC_DIST Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($) = DDC_DEV_VOL * MISO_DDC_RATE 330

332 Intermediate Calculations *DDC_DEV_VOL RT_RSG_DIST1 Formula Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh) = MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL + DDC_NDL_PHYS_IMP_VOL + DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL + DDC_NDL_FIN_VOL + DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) + DDC_RAC_DR_VOL + DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL + DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL + DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL Determinant DDC_NDL_LOAD_VOL DDC_RT_LOAD_VOL Description Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline Load Imbalance Volume (MWh); = IF DEV_EXEMPT = Y THEN 0 ELSE ( NDL_DMD_FCST DA_SCHD ) * ( 1 - RT_CO_LOAD_PCT ) Hourly Constraint Management Charge Real-Time Load Imbalance Volume (MWh) = IF DEV_EXEMPT = Y THEN 0 ELSE ABS ( AEW NDL_DMD_FCST ) * ( 1 - RT_CO_LOAD_PCT ) 331

333 Intermediate Calculations RT_RSG_DIST1 Formula *DDC_DEV_VOL Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh) = MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL + DDC_NDL_PHYS_IMP_VOL + DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL + DDC_NDL_FIN_VOL + DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) + DDC_RAC_DR_VOL + DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL + DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL + DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL Determinant DDC_NDL_LOAD_VOL Formula Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline Load Imbalance Volume (MWh); = IF DEV_EXEMPT = Y THEN 0 ELSE ( NDL_DMD_FCST DA_SCHD ) * ( 1 - RT_CO_LOAD_PCT ) 0 =(75-75) * ( 1-12/100) Hourly Constraint Management Charge Real-Time Load Imbalance Volume (MWh) DDC_RT_LOAD_VOL = IF DEV_EXEMPT = Y THEN 0 ELSE ABS ( AEW NDL_DMD_FCST ) * ( 1 - RT_CO_LOAD_PCT ) 22 =ABS(100-75) * ( 1-12/100) 332

334 RT_RSG_DIST1 Formula Intermediate Calculations *DDC_DEV_VOL Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh) = MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL + DDC_NDL_PHYS_IMP_VOL + DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL + DDC_NDL_FIN_VOL + DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) + DDC_RAC_DR_VOL + DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL + DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL + DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh) *DDC_DEV_VOL = MAX ( , 0 ) *DDC_DEV_VOL = 22 MW 333

335 RT_RSG_DIST1 Formula Intermediate Calculations Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($) *DDC_DIST = DDC_DEV_VOL * MISO_DDC_RATE *Assume the MISO_DDC_RATE = $1.56 *DDC_DIST = 22 MW * $1.56 *DDC_DIST = $

336 RT_RSG_DIST1 Hierarchy 335

337 RT_RSG_DIST1 - Formula *RT_RSG_DIST1_HR Hourly Real-Time RSG Distribution Amount ($) = CMC_DIST + DDC_DIST = *RT_RSG_DIST1_HR $ $ = *RT_RSG_DIST1_HR $

338 RT_RSG_DIST1 - Formula H( ) *RT_RSG_DIST1 = *RT_RSG_DIST1_HR H( ) $77.11 = $77.11 Results in a $77.11 charge for HE 1 337

339 RT_RSG_DIST1 Summary The Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount funds the RSG Make Whole Payments paid to the generation Asset Owners. This amount is calculated hourly for an AO by adding the Constraint Management Charge Distribution Amount and the Day-Ahead Deviation and Headroom Charge Distribution Amount. Questions? 338

340 RSG Summary Post April 2011 Load has the opportunity to submit an Hourly Notification Deadline Demand Forecast before 4 hours prior to the start of the Operating Hour. Netting of Volume across an Asset Owner s CPNodes for volumes occurring prior to the Notification Deadline Different Rates for each Active Transmission Constraint Two distribution buckets - CMC and DCC New concept of Constraint Contribution Factor (CCF) 339

341 Real-Time Regulation Reserve Cost Distribution Amount (RT_ASM_REG_DIST) 340

342 RT_ASM_REG_DIST - Purpose Real-Time Regulation Reserve Cost Distribution Amount (RT_ASM_REG_DIST) Represents the allocation of the total cost of procurement of Regulating Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve Market by the AO percent share of Load in a Reserve Zone Calculated hourly for AOs in a Reserve Zone Amount is offset by credits from the distribution of funds collected in the Real-Time Excessive/Deficient Energy Deployment Charge Amount Who gets the charge/credit? Payments are funded by AOs in a Reserve Zone through the RT_ASM_REG Charge Type Where does it go? Asset Owners that own Resources with cleared Regulating Reserve 341

343 RT_ASM_REG_DIST Hierarchy *In order to conserve space, determinants for the ASM_REG_DIST_RATE ZN and ASM_REG_GFA_DIST_RATE ZN calculations are not shown. These rates are given on an AO s Real-Time statement and the calculations will be discussed later. 342

344 RT_ASM_REG_DIST - Formula *RT_ASM_REG_DIST = H x ( *ASM_REG_DIST_VOL [( AO-ZN AO-ZN ) *ASM_REG_DIST_RATE ZN + ( x ) *RT_ASM_REG_GFA_ SELLER_DIST_VOL AO-ZN *ASM_REG_GFA_ DIST_RATE ZN + (( ) ) *ASM_REG_ + *RT_ASM_REG_GFA_ x MISO_EDEDC_ DIST_VOL AO-ZN SELLER_DIST_VOL AO-ZN UPLIFT_RATE )] 343

345 RT_ASM_REG_DIST - Formula *ASM_REG_DIST_VOL AO-ZN *ASM_REG_DIST_RATE ZN Hourly Regulation Reserve Distribution Volume (MWh) = Σ CN ( ASM_REG_DIST_VOL CN x PCT_CPN_IN_ZN ) = = IF ASM_REG_DIST_EXEMPT = N THEN [ MAX (RT_BLL_MTR CN, 0 ) - { Σ Transactions (RT_GFACO Buyer x PRE_888_REG ) } ] ELSE 0 Hourly Regulation Reserve Distribution Rate ($/MWh) Σ CN [ { ( ( DA_REG_VOL CN x DA_REG_MCP CN ) + ( RTN_REG_VOL CN x RT_REG_MCP CN ) - ( RT_ASM_REG_GFA_SELLER_DIST_VOL CN x ASM_REG_GFA_DIST_RATE ZN ) ) x PCT_CPN_IN_ZN } / ( ASM_REG_DIST_VOL CN x PCT_CPN_IN_ZN ) ] *RT_ASM_REG_GFA_ SELLER_DIST_VOL AO-ZN = Hourly Regulation Reserve GFA Distribution Volume (MWh) Σ CN ( RT_ASM_REG_GFA_SELLER_DIST_VOL CN x PCT_CPN_IN_ZN ) = IF ASM_REG_DIST_EXEMPT = N THEN { Σ Transactions (RT_GFACO Seller x PRE_888_REG ) } ELSE 0 *ASM_REG_GFA_ DIST_RATE ZN MISO_EDEDC_ UPLIFT_RATE = = Hourly Regulation Reserve GFA Distribution Rate ($/MWh) Σ CN [ { ( ( DA_REG_VOL CN x DA_REG_MCP CN ) + ( RTN_REG_VOL CN x RT_REG_MCP CN ) ) x PCT_CPN_IN_ZN } / ( ( RT_ASM_REG_GFA_SELLER_DIST_VOL CN + ASM_REG_DIST_VOL CN ) x PCT_CPN_IN_ZN ) ] Hourly Excessive/Deficient Energy Deployment Charge Uplift Rate ($/MWh) (CREDIT) MISO_EDEDC_UPLIFT / ( MISO_ASM_REG_DIST_VOL + MISO_RT_ASM_REG_GFA_SELLER_DIST_VOL ) 344

346 RT_ASM_REG_DIST Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market Total asset withdrawal volume at the CPNode is 100 MW Moved 12 MW from Generator A to its Load with a GFACO schedule Carved-Out Grandfathered Agreements cover the Regulation Reserve service required of the Asset Owner Applicable rates have been provided by the MISO What is the charge/credit for RT_ASM_REG_DIST? Load Asset Volume HE *RT_BLL _MTR *RT_GFACO Buyer *PRE_888_ REG *PCT_CPN_ IN_ZN *ASM_REG_ DIST_RATE ZN *ASM_REG_GFA _DIST_RATE ZN MISO_EDEDC_ UPLIFT_RATE N (1) 100% $.35 $.25 -$

347 RT_ASM_REG_DIST Intermediate Calculations Determinant Formula ASM_REG_DIST_VOL CN = IF ASM_REG_DIST_EXEMPT = N THEN [ MAX (RT_BLL_MTR CN, 0 ) - { Σ Transactions (RT_GFACO Buyer x PRE_888_REG ) } ] ELSE = IF ASM_REG_DIST_EXEMPT = N THEN [ MAX ( 100, 0 ) - { Σ Transactions ( 12 x 0 ) } ] ELSE 0 RT_ASM_REG_GFA_SELLER_ = IF ASM_REG_DIST_EXEMPT = N THEN { Σ Transactions (RT_GFACO Seller x DIST_VOL CN PRE_888_REG ) } ELSE 0 0 = IF ASM_REG_DIST_EXEMPT = N THEN { ΣTransactions ( 12 x 1 ) } ELSE 0 Determinant Formula *ASM_REG_DIST_VOL AO-ZN = Σ CN ( ASM_REG_DIST_VOL CN x PCT_CPN_IN_ZN ) 100 = ΣCN (100 x 100% ) *RT_ASM_REG_GFA_ SELLER_DIST_VOL AO-ZN = Σ CN ( RT_ASM_REG_GFA_SELLER_DIST_VOL CN x PCT_CPN_IN_ZN ) 0 = ΣCN ( 12 x 100% ) 346

348 RT_ASM_REG_DIST Charge Type Calculation = H x ( *ASM_REG_DIST_VOL [( AO-ZN AO-ZN ) *ASM_REG_DIST_RATE ZN + ( x ) *RT_ASM_REG_GFA_ SELLER_DIST_VOL AO-ZN *ASM_REG_GFA_ DIST_RATE ZN + )] (( ) ) *ASM_REG_ + *RT_ASM_REG_GFA_ x MISO_EDEDC_ DIST_VOL AO-ZN SELLER_DIST_VOL AO-ZN UPLIFT_RATE $30 = H x ( 100 MW AO-ZN [( ) $.35 + ( 0 MW x $0.25)+ 100 MW + 0MW x -$.05 (( ) )] ) Results in a $30.0 charge for HE 1 347

349 RT_ASM_REG_DIST Summary The Regulation Cost Distribution Amount represents the allocation of the total cost of procurement of Regulating Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve Market by the AO percent share of Load in a Reserve Zone. Calculated by taking the sum of: The Hourly Regulation Reserve Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Regulation Reserve Distribution Rate, The Hourly Regulation Reserve GFA Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Regulation Reserve GFA Distribution Rate, and The sum of both Distribution Volumes multiplied by the Hourly EDEDC Uplift Rate. Questions? 348

350 Real-Time Spinning Reserve Cost Distribution Amount (RT_ASM_SPIN_DIST) 349

351 RT_ASM_SPIN_DIST - Purpose Spinning Reserve Cost Distribution Amount (RT_ASM_SPIN_DIST) Represents the allocation of the total cost of procurement of Spinning Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve Market by the AO percent share of Load in a Reserve Zone Calculated hourly by taking the sum of: The Hourly Spinning Reserve Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Spinning Reserve Distribution Rate, and The Hourly Spinning Reserve GFA Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Spinning Reserve GFA Distribution Rate Who gets the charge/credit? Payments are funded by AOs in a Reserve Zone through the RT_ASM_SPIN Charge Type Where does it go? Asset Owners that own Resources with cleared Spinning Reserve 350

352 RT_ASM_SPIN_DIST Hierarchy *In order to conserve space, determinants for the ASM_SPIN_DIST_RATE ZN and ASM_SPIN_GFA_DIST_RATE ZN calculations are not shown. These rates are given on an AO s Real-Time statement and the calculations will be discussed later. 351

353 RT_ASM_SPIN_DIST - Formula *RT_ASM_SPIN_DIST = H x ( *ASM_SPIN_DIST_VOL [( AO-ZN AO-ZN ) *ASM_SPIN_DIST_RATE ZN + ( x ) *RT_ASM_SPIN_GFA_ SELLER_DIST_VOL AO-ZN *ASM_SPIN_GFA_ DIST_RATE ZN 352

354 RT_ASM_SPIN_DIST - Formula Hourly Spinning Reserve Distribution Volume (MWh) *ASM_SPIN_DIST_VOL AO-ZN *ASM_SPIN_DIST_RATE ZN = Σ CN ( ASM_SPIN_DIST_VOL CN x PCT_CPN_IN_ZN ) = = IF ASM_SPIN_DIST_EXEMPT = N THEN [ MAX (RT_BLL_MTR CN, 0 ) - { Σ Transactions (RT_GFACO Buyer x PRE_888_SPIN ) } + { Σ Transactions RT_PHYS Buyer } ] ELSE 0 Hourly Spinning Reserve Distribution Rate ($/MWh) Σ CN [ { ( ( DA_SPIN_VOL CN x DA_SPIN_MCP CN ) + ( RTN_SPIN_VOL CN x RT_SPIN_MCP CN ) - ( RT_ASM_SPIN_GFA_SELLER_DIST_VOL CN x ASM_SPIN_GFA_DIST_RATE ZN ) ) x PCT_CPN_IN_ZN } / ( ASM_SPIN_DIST_VOL CN x PCT_CPN_IN_ZN ) ] *RT_ASM_SPIN_GFA_ SELLER_DIST_VOL AO-ZN *ASM_SPIN_GFA_ DIST_RATE ZN = = Hourly Spinning Reserve GFA Distribution Volume (MWh) Σ CN ( RT_ASM_SPIN_GFA_SELLER_DIST_VOL CN x PCT_CPN_IN_ZN ) = IF ASM_SPIN_DIST_EXEMPT = N THEN { Σ Transactions (RT_GFACO Seller x PRE_888_SPIN ) } ELSE 0 Hourly Spinning Reserve GFA Distribution Rate ($/MWh) Σ CN [ { ( ( DA_SPIN_VOL CN x DA_SPIN_MCP CN ) + ( RTN_SPIN_VOL CN x RT_SPIN_MCP CN ) ) x PCT_CPN_IN_ZN } / ( ( RT_ASM_SPIN_GFA_SELLER_DIST_VOL CN + ASM_SPIN_DIST_VOL CN ) x PCT_CPN_IN_ZN ) ] 353

355 RT_ASM_SPIN_DIST Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market Total asset withdrawal volume at the CPNode is 100 MW Moved 12 MW from Generator A to its Load with a GFACO schedule Carved-Out Grandfathered Agreements cover the Spinning Reserve service required of the Asset Owner Applicable rates have been provided by the MISO What is the charge/credit for RT_ASM_SPIN_DIST? Load Asset Volume HE *RT_BLL_MTR *RT_GFACO *PRE_888 *PCT_CPN_ Buyer _SPIN IN_ZN *ASM_SPIN_ DIST_RATE ZN *ASM_SPIN_GFA _DIST_RATE ZN N (0) 100% $.08 $

356 RT_ASM_SPIN_DIST Intermediate Calculations Determinant Formula ASM_SPIN_DIST_VOL CN = IF ASM_SPIN_DIST_EXEMPT = N THEN [ MAX (RT_BLL_MTR CN, 0 ) - { Σ Transactions (RT_GFACO Buyer x PRE_888_SPIN ) } + { Σ Transactions RT_PHYS Buyer } ] ELSE = IF ASM_SPIN_DIST_EXEMPT = N THEN [ MAX ( 100, 0 ) - { Σ Transactions ( 12 x 0 ) } + {Σ Transactions 0 } ] ELSE 0 RT_ASM_SPIN_GFA_SELLER_ = IF ASM_SPIN_DIST_EXEMPT = N THEN { Σ Transactions (RT_GFACO Seller x DIST_VOL CN PRE_888_SPIN ) } ELSE 0 0 = IF ASM_SPIN_DIST_EXEMPT = N THEN { ΣTransactions ( 0 x 1 ) } ELSE 0 Determinant Formula *ASM_SPIN_DIST_VOL AO-ZN = Σ CN ( ASM_SPIN_DIST_VOL CN x PCT_CPN_IN_ZN ) 100 = ΣCN ( 100 x 1 ) *RT_ASM_SPIN_GFA_ SELLER_DIST_VOL AO-ZN = Σ CN ( RT_ASM_SPIN_GFA_SELLER_DIST_VOL CN x PCT_CPN_IN_ZN ) 0 = ΣCN ( 1 x.1 ) 355

357 RT_ASM_SPIN_DIST Charge Type Calculation = H x ( *ASM_SPIN_DIST_VOL [( AO-ZN AO-ZN ) *ASM_SPIN_DIST_RATE ZN + ( x ) *RT_ASM_SPIN_GFA_ SELLER_DIST_VOL AO-ZN *ASM_SPIN_GFA_ DIST_RATE ZN $8.00 = H x ( 100 MW AO-ZN [( ) $.08 + ( ) 0 MW x $.06 Results in a $8.00 charge for HE 1 356

358 RT_ASM_SPIN_DIST Summary The Spinning Reserve Cost Distribution Amount represents the allocation of the total cost of procurement of Spinning Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve Market by the AO percent share of Load in a Reserve Zone. Calculated hourly by taking the sum of: The Hourly Spinning Reserve Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Spinning Reserve Distribution Rate, and The Hourly Spinning Reserve GFA Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Spinning Reserve GFA Distribution Rate Questions? 357

359 Real-Time Supplemental Reserve Cost Distribution Amount (RT_ASM_SUPP_DIST) 358

360 RT_ASM_SUPP_DIST - Purpose Supplemental Reserve Cost Distribution Amount (RT_ASM_SUPP_DIST) Represents the allocation of the total cost of procurement of Supplemental Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve Market by the AO percent share of Load in a Reserve Zone Calculated hourly by taking the sum of: The Hourly Supplemental Reserve Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Supplemental Reserve Distribution Rate, and The Hourly Supplemental Reserve GFA Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Supplemental Reserve GFA Distribution Rate Who gets the charge/credit? Payments are funded by AOs in a Reserve Zone through the RT_ASM_SUPP Charge Type Where does it go? Asset Owners that own Resources with cleared Supplemental Reserve 359

361 RT_ASM_SUPP_DIST Hierarchy *In order to conserve space, determinants for the ASM_SUPP_DIST_RATE ZN and ASM_SUPP_GFA_DIST_RATE ZN calculations are not shown. These rates are given on an AO s Real-Time statement and the calculations will be discussed later. 360

362 RT_ASM_SUPP_DIST - Formula *RT_ASM_SUPP_DIST = H x ( *ASM_SUPP_DIST_VOL [( AO-ZN AO-ZN ) *ASM_SUPP_DIST_RATE ZN + ( x ) *RT_ASM_SUPP_GFA_ SELLER_DIST_VOL AO-ZN *ASM_SUPP_GFA_ DIST_RATE ZN 361

363 RT_ASM_SUPP_DIST - Formula Hourly Supplemental Reserve Distribution Volume (MWh) *ASM_SUPP_DIST_VOL AO-ZN *ASM_SUPP_DIST_RATE ZN = Σ CN ( ASM_SUPP_DIST_VOL CN x PCT_CPN_IN_ZN ) = = IF ASM_SUPP_DIST_EXEMPT = N THEN [ MAX (RT_BLL_MTR CN, 0 ) - { Σ Transactions (RT_GFACO Buyer x PRE_888_SUPP ) } + { Σ Transactions RT_PHYS Buyer } ] ELSE 0 Hourly Supplemental Reserve Distribution Rate ($/MWh) Σ CN [ { ( ( DA_SUPP_VOL CN x DA_SUPP_MCP CN ) + ( RTN_SUPP_VOL CN x RT_SUPP_MCP CN ) - ( RT_ASM_SUPP_GFA_SELLER_DIST_VOL CN x ASM_SUPP_GFA_DIST_RATE ZN ) ) x PCT_CPN_IN_ZN } / ( ASM_SUPP_DIST_VOL CN x PCT_CPN_IN_ZN ) ] *RT_ASM_SUPP_GFA_ SELLER_DIST_VOL AO-ZN *ASM_SUPP_GFA_ DIST_RATE ZN = = Hourly Supplemental Reserve GFA Distribution Volume (MWh) Σ CN ( RT_ASM_SUPP_GFA_SELLER_DIST_VOL CN x PCT_CPN_IN_ZN ) = IF ASM_SUPP_DIST_EXEMPT = N THEN { Σ Transactions (RT_GFACO Seller x PRE_888_SUPP ) } ELSE 0 Hourly Supplemental Reserve GFA Distribution Rate ($/MWh) Σ CN [ { ( ( DA_SUPP_VOL CN x DA_SUPP_MCP CN ) + ( RTN_SUPP_VOL CN x RT_SUPP_MCP CN ) ) x PCT_CPN_IN_ZN } / ( ( RT_ASM_SUPP_GFA_SELLER_DIST_VOL CN + ASM_SUPP_DIST_VOL CN ) x PCT_CPN_IN_ZN ) ] 362

364 RT_ASM_SUPP_DIST Load Scenario 1 Load Serving Entity participating in the Real-Time Energy and Operating Reserve Market Total asset withdrawal volume at the CPNode is 100 MW Moved 12 MW from its Generator A to its Load with a GFACO schedule Carved-Out Grandfathered Agreement cover the Supplemental Reserve service required of the Asset Owner Applicable rates have been provided by the MISO What is the charge/credit for RT_ASM_SUPP_DIST? Load Asset Volume HE *RT_BLL_MTR *RT_GFACO Buyer *PRE_888 _SPIN *PCT_CPN_ IN_ZN *ASM_SUPP_ DIST_RATE ZN *ASM_SUPP_GFA _DIST_RATE ZN N (0) 100% $0.047 $

365 RT_ASM_SUPP_DIST Intermediate Calculations Determinant Formula ASM_SUPP_DIST_VOL CN = IF ASM_SUPP_DIST_EXEMPT = N THEN [ MAX (RT_BLL_MTR CN, 0 ) - { Σ Transactions (RT_GFACO Buyer x PRE_888_SUPP ) } + { Σ Transactions RT_PHYS Buyer } ] ELSE = IF ASM_SUPP_DIST_EXEMPT = N THEN [ MAX ( 100, 0 ) - { Σ Transactions ( 12 x 1 ) } + {Σ Transactions 0 } ] ELSE 0 RT_ASM_SUPP_GFA_SELLER_ = IF ASM_SUPP_DIST_EXEMPT = N THEN { Σ Transactions (RT_GFACO Seller x DIST_VOL CN PRE_888_SUPP ) } ELSE 0 0 = IF ASM_SUPP_DIST_EXEMPT = N THEN { ΣTransactions (12 x 1 ) } ELSE 0 Determinant Formula *ASM_SUPP_DIST_VOL AO-ZN = Σ CN ( ASM_SUPP_DIST_VOL CN x PCT_CPN_IN_ZN ) 100 = ΣCN ( 100 x 100% ) *RT_ASM_SUPP_GFA_ SELLER_DIST_VOL AO-ZN = Σ CN ( RT_ASM_SUPP_GFA_SELLER_DIST_VOL CN x PCT_CPN_IN_ZN ) 0 = ΣCN ( 12 x 100% ) 364

366 RT_ASM_SUPP_DIST Charge Type Calculation = H x ( *ASM_SUPP_DIST_VOL [( AO-ZN AO-ZN ) *ASM_SUPP_DIST_RATE ZN + ( x ) *RT_ASM_SUPP_GFA_ SELLER_DIST_VOL AO-ZN *ASM_SUPP_GFA_ DIST_RATE ZN $4.70 = H x ( 100MW AO-ZN [( ) $ ( ) 0 MW x $.055 Results in a $4.70 charge for HE 1 365

367 RT_ASM_SUPP_DIST Summary The Supplemental Reserve Cost Distribution Amount represents the allocation of the total cost of procurement of Supplemental Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve Market by the AO percent share of Load in a Reserve Zone. Calculated hourly by taking the sum of: The Hourly Supplemental Reserve Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Supplemental Reserve Distribution Rate, and The Hourly Supplemental Reserve GFA Distribution Volume for an AO in a Reserve Zone multiplied by the Hourly Supplemental Reserve GFA Distribution Rate. Questions? 366

368 Summary 367

369 Load Real Time Charges Summary Load Related Real-Time Charges Charge Type S7 Total Real-Time Asset Energy Amount Real-Time Financial Schedule Congestion Amount 2 2 Real-Time Financial Schedule Loss Amount 2 2 Real-Time Congestion Rebate on Carved-Out Grandfathered -2-2 Agreements Real-Time Losses Rebate on Carved-Out Grandfathered -2-2 Agreements Real-Time Market Administration Amount RT Schedule 24 Allocation Amount Real-Time Distribution of Losses Amount Real-Time Miscellaneous Amount Real-Time Net Inadvertent Distribution Real-Time Revenue Neutrality Uplift Amount Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount Regulation Cost Distribution Amount Spinning Reserve Cost Distribution Amount 8 8 Supplemental Reserve Cost Distribution Amount Total

370 Summary There are four main types of charges related to Load in the MISO market: Energy, Schedule, Admin and Distribution. The Settlement of a Load is best understood by getting familiar with the terminology and formulas behind each Charge Type Calculation. 369

371 Review Quiz 370

372 Load Quiz Question 1 How many Day-Ahead Settlement Charges are related to Load? c 1) 10 2) 11 3) 7 4) 9 371

373 Load Quiz Question 2 How many Real-Time Settlement Charges are related to Load? c 1) 13 2) 14 3) 12 4)

374 Load Quiz Question 3 Which volume does the Real-Time Settlement use for the Real-Time Asset Energy Charge calculation? Real-Time Billable - Actual Meter volume when it is available, otherwise the State Estimator value. Residual Load is also applied. 373

375 Load Quiz Question 4 Which is not a way to minimize the Real-Time RSG Distribution 1 Charges for a Load? 1) Submit a Day Ahead Schedule 2) Update a Load Forecast volume 3) Buy all energy in Real Time 4) Submit RSG Deviation Financial Contract before NDL 374

376 Load Quiz Question 5 When will a Load get a credit instead of a charge for the DA_ASSET_EN? 1) If the DA LMPcpnode is negative, 2) Offer the Load as generation, 3) When Financial Schedule buy is greater than Sell, 4) When the RT Billable volume is negative. 375

377 Load Quiz Question 6 What would happen if no Day-Ahead Schedule was submitted for a Load, but have actual meter volume? 1) No Day Ahead Charges 2) All Real Time Related Charges 3) Subject to Real Time LMP only 4) All the above. 376

378 Load Quiz Question 7 If there is an Emergency due to a reliability issue and an AO is directed by the MISO to shed Load, is that Load subject to the Real-Time RSG Distribution volume deviation charges? If it s an E mergency, Charges related to the Load deviation volume will be exempted, per the Tariff. 377

379 Load Quiz Question 8 Can a Load CPNode sell energy to the Real-Time Market? Certain load has Generation behind the meter and has the ability to generate more power than it consumes; therefore it can get paid for the power. 378

380 Load Quiz Question 9 Which 2 DA and RT Market Settlement charge rates don t change over the month? ADMIN (DA_ ADMIN and RT_ADMIN) SCHD_24 (DA_SCHD_24_ALC and RT_SCHD_24_ALC) 379

381 Load Quiz Question 10 How many components to Revenue Neutrality Charge Amount

382 Helpful Resources 381

383 References Settlement related documentation Posted on the MISO website ( Market Settlements Business Practices Manual 005 Market Settlements Business Practices Manual 005 Attachment A sspracticesmanuals.aspx Market Settlements helpful documents and files Frequently Asked Questions (FAQs) Documents Market Settlements Market Settlements Working Group (MSWG) Meetings Conducted monthly, generally the first Tuesday of every month 382

384 Helpful Resources Where can I learn about the MISO Market? Websites Documentation On Guiding documents Business Practices, Draft Tariff Informational documents Training presentations, Testing documentation, etc. Technical Infrastructure documents Implementation documents Technical specifications Testing information Market Registration documents Registration packet, public data Client Account Representative are assigned to each Market Participant 383

385 Reporting Issues and Submitting Questions Client Relations Call , Option 1 clientrelations@misoenergy.org marketquality@misoenergy.org hchu@misoenergy.org Network Operations Center (NOC) Call , Option 2 Report Portal, Dispatch and AGC Outages 24x7 Report other items during MISO business hours 384

386 Load Answer Key 385

387 RSG_DIST1 Training 386

388 RSG_DIST1 Training 387