The Ontario Electricity Market 1 Year in Richard Penn Mgr - Market Assessment The IMO Richard Penn Mgr - Market Assessment The IMO

Agenda Introduction - brief overview Market Design Issues Identified in the MSP reports Introduction - brief overview Market Design Issues Identified in the MSP reports

3 IMO

4 The IMO Web - Today’s market

5 The IMO - As Operator of Reliable System We balance generation to meet constantly changing demand for electricity: Monitor conditions on IMO-controlled grid Schedule production from suppliers Maintain reliability to industry standards

6 The IMO - As Impartial Market Administrator We ensure accountability: Authorize/register participants Run commercial activities of market We ensure equal, unbiased access: Provide historical and forecast performance data Monitor conduct of participants – fair competition, level playing field

The Energy Market Statistics

Ontario has set a new Peak Demand of 25,414 Mw Aug 13, 2002 Ontario has set a new Monthly Energy Consumption of 14,500 Gw-hrs Imports at times totaled over 4000 Mw an hour Average energy price since May $/Mw-hr Average Weighted energy price since May $/Mw-hr Minimum Hourly Price was 7.84 $/Mw-hr Maximum Hourly Price was $/Mw-hr Some Facts

The Ontario Demand for the first year of the market is about 156 Tw-hr Close to 10 B$ has been settled through the IAM markets More than 136,000 Settlement Statements will have been issued by April 30, % of Settlement Statements issued on time, so far 99.6% of Settlement Statements issued to date were error free

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The Energy Market

15 Simple Energy Spot Market Energy Suppliers Energy Purchasers OffersBids IMO - Administered Markets Real-time Energy Offer Energy amount and price offered for each hour of the dispatch day, for each dispatchable supply facility Bid Energy amount and price required for each hour of the dispatch day, by each dispatchable load facility The market clears where the offer and bid curves intersect. This determines the: market clearing quantity and market clearing price (MCP)

16 The Present Market Energy OperatingReserve Real-time IMO - Administered Markets TransmissionRights FinancialPhysical AncillaryServices Procurement

17 Who Can Participate in the Markets Anyone can apply to become a registered market participant Anyone who wishes to inject energy into, or withdraw energy from the IMO- controlled grid MUST become a Market Participant Anyone can apply to become a registered market participant Anyone who wishes to inject energy into, or withdraw energy from the IMO- controlled grid MUST become a Market Participant

18 ParticipantsOutsideOntario Direct Large Customer Who Can Participate? Distributor Embedded Large Customer Embedded Generator Generator

Simplified Energy Market Offers and Bids

20 Bid and Offer Basics Generators and Imports Offers Loads and Exports Bids IMO - Administered Markets Markets Real-timeEnergy

21 Composite Energy Offer Curve

22 Composite Energy Bid Curve

23 Market Clearing Price Price Supply Demand MCP Quantity

Determining Market Price

25 Market Design Principles The price of energy at each time and place should reflect the marginal cost of producing or not consuming one more unit of energy (at that time and place) Dispatchable market participants should be compensated for the effects of constraints The price of energy at each time and place should reflect the marginal cost of producing or not consuming one more unit of energy (at that time and place) Dispatchable market participants should be compensated for the effects of constraints

26 Setting the Market Clearing Price - An Example Generator 3 50 MW - $25/MWh Generator 1 50 MW - $38/MWh 100 MW - $15/MWh 100 MW - $15/MWh Generator 2 50 MW - $20/MWh

27 Offers Are Selected Economically 100 MW 50 MW $15 / MWh $20 / MWh $25 / MWh $38 / MWh Generator 1 Generator 2 Generator 3 12:0013:0014:0015:0016:0017:0018:0019:00 Quantity Time 20:00

28 50 MW 100 MW 150 MW 200 MW $15 / MWh $20 / MWh $25 / MWh $38 / MWh 12:0013:0014:0015:0016:0017:0018:0019:00 Quantity Time Generator 1 Generator 2 Generator 3 20:00 Offers and Demand 250 MW

MW 50 MW $15 / MWh $20 / MWh $25 / MWh $38 / MWh 16:0016:0516:1016:1516:3016:3516:4016:45 Quantity Time 17:00 Generator 1Generator 2Generator 3 16:2016:2516:5016:55 Offers and Demand - 5 Minute Intervals MCP $ / MWh 38

30 July 2002 Offer Stack

31 Comparison of a July to an October Domestic Offer Curve Difference is due to Outages

Now it Gets Complicated In the Ontario Design there are actually two schedules for each generator The Unconstrained schedule determines a uniform Market Clearing price ( MCP) and assumes Ontario is a copper plate where all generation can flow to all loads The Constrained schedule which determines the actual dispatched output for each generator to meet the physical limitations of the Transmission System The difference is schedules can result in a Constrained Payment

33 MCP - Copper Plate Requirement is 190 MW Gen 1: 100 MW Gen 2: 90 MW Gen 3: does not run MCP $20 Generator MW $15 Generator MW $20 Generator MW $25 Load 190 MW Region 2Region 1 No transmission line limit

34 The IMO Web - Today’s market

35 Physical Limitations Bid/Offer selection must result in system flows within system’s physical limitations Increases the cost of power to ensure reliability Michigan Minnesota Quebec North New York East East-West Tie Flow North/ Flow South BLIP QFW Quebec South New York Niagara FETT Manitoba

36 Transmission Congestion Requirement is 190 MW Gen 1: 100 MWGen 1: 100 MW Gen 2: 50 MWGen 2: 50 MW Gen 3: 40 MWGen 3: 40 MW MCP $20 determined from Unconstrained ScheduleMCP $20 determined from Unconstrained Schedule Generator MW $15 Generator MW $20 Generator MW $25 Load 190 MW Region 2 Region MW transmission line limit

37 Unconstrained vs Constrained Reminder Unconstrained schedule determines prices Constrained schedule determines dispatch instructions Any differences between unconstrained and constrained schedule creates potential for CMSC Unconstrained schedule determines prices Constrained schedule determines dispatch instructions Any differences between unconstrained and constrained schedule creates potential for CMSC

38 Constrained Payments for the 1’st Year of the Market Constrained on Payments = about 75M$ Constrained Off Payments = about 132 M$ Constrained on Payments = about 75M$ Constrained Off Payments = about 132 M$

39 The Actual Constrained Schedule takes into account - Available Transmission - Transmission Limits - Losses - Generator Capabilities such as Ramp rates -Actual generator Output

40 The Reserve Area Bubble Diagram

Operating Reserve

42 Now it Gets More complicated Algorithm simultaneously solves for energy and three classes of OR whether a generator is in the energy market or is “switched” to the OR market they are held whole to their operating profit. Requirement for OR determined by IMO, based on industry standards Algorithm simultaneously solves for energy and three classes of OR whether a generator is in the energy market or is “switched” to the OR market they are held whole to their operating profit. Requirement for OR determined by IMO, based on industry standards

43 Operating Reserve Three classes of Operating Reserve 10 minute spinning - 25% of the largest single contingency 10 minute non-spinning - 75% of the largest single contingency 30 minute - 1/2 of the second largest contingency Three classes of Operating Reserve 10 minute spinning - 25% of the largest single contingency 10 minute non-spinning - 75% of the largest single contingency 30 minute - 1/2 of the second largest contingency

44 Operating Reserve Who can offer OR? Dispatchable Loads Dispatchable Generators Importers and Exporters ( Injections / Off-takes) Who can offer OR? Dispatchable Loads Dispatchable Generators Importers and Exporters ( Injections / Off-takes)

45 Offer Basics - Operating Reserve Markets Energy Suppliers Energy Purchasers OR Offers IMO - Administered Markets Markets Operating Reserve Classes of OR Markets 10 min spinning10 min spinning 10 min non-spinning10 min non-spinning 30 min30 min Offer Operating Reserve amount and price offered for each hour of the dispatch day

46 Optimization Objective Value of Electricity produced …as indicated by Energy demand from non-dispatchable loads and Energy bids - Cost to produce Electricity …as indicated by offers to supply Energy & Operating Reserve = Economic gain from trade Algorithm maximizes economic gain from trade for all market participants

Interjurisdictional Trade

48 Further Complications Interjurisdictional Trade Similar to trade by resources inside Ontario Everyone must bid and offer to be scheduled Scheduling is independent of any bilateral contracts No physical transmission rights Uplifts apply to exports (some exceptions) Similar to trade by resources inside Ontario Everyone must bid and offer to be scheduled Scheduling is independent of any bilateral contracts No physical transmission rights Uplifts apply to exports (some exceptions)

49 Interjurisdictional Trade Some differences from resources in Ontario Zonal pricing Scheduled hourly Bid and offer from Boundary Entity Resources Some differences from resources in Ontario Zonal pricing Scheduled hourly Bid and offer from Boundary Entity Resources

50 Interjurisdictional Trade Minnesota Quebec (8) Manitoba New York Michigan

51 Boundary Entities and Boundary Entity Resources MP acts as a Boundary Entity Place bids and offers from Boundary Entities Resources Participant must navigate other jurisdictions, supply NERC tag, have NEB permit (for export to US) this can lead to failed transactions MP acts as a Boundary Entity Place bids and offers from Boundary Entities Resources Participant must navigate other jurisdictions, supply NERC tag, have NEB permit (for export to US) this can lead to failed transactions

52 Types of Interjurisdictional Trade? Export Import Wheel-Through

53 Ontario New York NYIntertieZone External Market (New York Example) IMO-Administered Markets Export of Energy From Ontario MWs Exported from Ontario MWs Imported to New York

54 Ontario New York NYIntertieZone External Market (New York Example) IMO-Administered Markets Import of Energy Into Ontario MWs Imported to Ontario MWs Exported from New York

55 Quick Summary

56 Ontario’s Wholesale Electricity Market Distributors Retailers WholesaleConsumers WholesaleSellers Generators Suppliers Purchasers IMO - Administered Markets Markets Transmitters Transactions / Information Electricity Energy Market MCP calculated OffersBids $ $SettlementsBilling Schedule & Dispatch Schedule

57 Where is the Market Evolving To

58 Anticipated Evolution to the Market AncillaryServices Energy OperatingReserve Procurement Real-time Physical IMO - Administered Markets Day Ahead Energy Forward Hour Ahead Dispatcha ble Load TransmissionRights Financial

59 The MSP Reports

60 From the 1’st MSP Report Serious Capacity problem in Ontario Structure is not yet conducive to effective competition Implications of Out of Market Control Actions Transmission Co-ordination is an issue Demand Responsiveness is an issue No inappropriate behavior Serious Capacity problem in Ontario Structure is not yet conducive to effective competition Implications of Out of Market Control Actions Transmission Co-ordination is an issue Demand Responsiveness is an issue No inappropriate behavior

61 From the 2’nd MSP Report Nothing Abnormal about outage programs by generators, but it contributed to a shortage in supply No inappropriate behavior, anomalous events can be explained satisfactorily Price responsiveness of load can have a significant impact upon price and examples of that have occurred in the past summer Non-intuitive Price Outcomes continues to be an issue Nothing Abnormal about outage programs by generators, but it contributed to a shortage in supply No inappropriate behavior, anomalous events can be explained satisfactorily Price responsiveness of load can have a significant impact upon price and examples of that have occurred in the past summer Non-intuitive Price Outcomes continues to be an issue

From Pre-dispatch to Real-time: An Hour in the Life of the Market

63 Purpose of Case Study Provides graphical illustration of the factors contributing to the three key pricing issues. Uses actual data for a representative hour in July to isolate the pricing implications of: different treatment of imports/exports in pre-dispatch vs. real-time differences between pre-dispatch demand forecast and real-time demand new “market contingencies” such as self-scheduling deviations and failed intertie transactions Outages and derates Reduction of market-based operating reserve requirements Provides graphical illustration of the factors contributing to the three key pricing issues. Uses actual data for a representative hour in July to isolate the pricing implications of: different treatment of imports/exports in pre-dispatch vs. real-time differences between pre-dispatch demand forecast and real-time demand new “market contingencies” such as self-scheduling deviations and failed intertie transactions Outages and derates Reduction of market-based operating reserve requirements

64 The Inter-relationship of the “Factors” Failed TransactionsSelf-Scheduler Error Forecast vs Actual Demand Impact on Supply Adequacy Outages / Deratings Sum of these Factors can lead to an OR Reduction Price Change

65 Background Facts Pre-dispatch Energy price - $ N - $ S - $ R - $ Demand - 24,679 MWh Pre-dispatch Energy price - $ N - $ S - $ R - $ Demand - 24,679 MWh Real-time HOEP - $ Hourly IOG - $62.78 Interval 4 Energy price - $ N - $ S - $ R - $0.10 Interval 4 demand - 24,514 MWh

66 Treatment of Net Imports Imports and exports are scheduled for real-time delivery in the one-hour ahead pre-dispatch. Imports and exports can set the price in pre-dispatch In real-time, the schedules of selected imports and exports are fixed and placed at the bottom of the offer curve. Imports and exports cannot set the price in real-time Real-time offer curve is steeper than pre-dispatch offer curve around forecast of demand. In sample hour 3,494 MWh imports selected and 304 MWh of exports selected. Imports and exports are scheduled for real-time delivery in the one-hour ahead pre-dispatch. Imports and exports can set the price in pre-dispatch In real-time, the schedules of selected imports and exports are fixed and placed at the bottom of the offer curve. Imports and exports cannot set the price in real-time Real-time offer curve is steeper than pre-dispatch offer curve around forecast of demand. In sample hour 3,494 MWh imports selected and 304 MWh of exports selected.

67 Treatment of Net Imports Price ($) MWh PD RT Pre-dispatch Demand plus OR Requirement Net Imports $ $

68 Sensitivity to Demand Forecast One demand value used to establish pre-dispatch schedules and price Forecast hourly peak demand Real-time interval by interval demand will always be different When real-time offer curve is steep, modest differences in demand can cause large price differences In sample hour, interval 4, demand difference was 165 MWh One demand value used to establish pre-dispatch schedules and price Forecast hourly peak demand Real-time interval by interval demand will always be different When real-time offer curve is steep, modest differences in demand can cause large price differences In sample hour, interval 4, demand difference was 165 MWh

69 Sensitivity to Demand Forecast Price ($) MWh PD RT $ $348 Real-time Demand plus OR Requirement

70 The Inter-relationship of the “Factors” 165 MW Failed TransactionsSelf-Scheduler Error Forecast vs Actual Demand Impact on Supply Adequacy Outages / Deratings Sum of these Factors can lead to an OR Reduction Price Change $348

71 New Market Contingencies Failed Transactions and Self-Scheduling Failed net imports or under forecast of self- scheduling production cause the real-time offer curve to shift to the left. less supply causes upward pressure on price In sample hour, interval 4, 75 MWh of net imports had failed (275 MWh of imports and 200 MWh of exports). In sample hour, interval 4, 36 MWh under forecast of self-scheduling generation. Failed net imports or under forecast of self- scheduling production cause the real-time offer curve to shift to the left. less supply causes upward pressure on price In sample hour, interval 4, 75 MWh of net imports had failed (275 MWh of imports and 200 MWh of exports). In sample hour, interval 4, 36 MWh under forecast of self-scheduling generation.

72 New Market Contingencies Failed Transactions and Self-Scheduling Price ($) MWh RT RT2 $ $

73 The Inter-relationship of the “Factors” 75 MW 111 MW Failed TransactionsSelf-Scheduler Error Forecast vs Actual Demand Impact on Supply Adequacy Outages / Deratings Dependent upon Sum of these Factors can lead to an OR Reduction Price Change 36 MW $1500

74 Outages and Derates Outages or derates that occur after the final pre-dispatch remove supply from the real- time offer curve. places upward pressure on the price In sample hour, interval 4, 690 MWh had been lost due to forced outage or derates Outages caused the unconstrained sequence to be short operating reserve. Outages or derates that occur after the final pre-dispatch remove supply from the real- time offer curve. places upward pressure on the price In sample hour, interval 4, 690 MWh had been lost due to forced outage or derates Outages caused the unconstrained sequence to be short operating reserve.

75 Outages and Derates Price ($) MWh RT RT2 $

76 The Inter-relationship of the “Factors” 690 MW Failed TransactionsSelf-Scheduler Error Forecast vs Actual Demand Impact on Supply Adequacy Outages / Deratings Sum of these Factors can lead to an OR Reduction Price Change 690 MW $2000

77 Reduction in Market-Based Operating Reserve Requirement Market-based operating reserve requirement reduced when IMO look-ahead tool forecast a pending shortage of operating reserve in the constrained schedule IMO satisfies NERC/NPCC requirements with “out of market” mechanisms reductions in operating reserve requirements done manually and can be “blunt” In sample hour, interval 4, total operating reserve requirements reduced by 1210 MW Market-based operating reserve requirement reduced when IMO look-ahead tool forecast a pending shortage of operating reserve in the constrained schedule IMO satisfies NERC/NPCC requirements with “out of market” mechanisms reductions in operating reserve requirements done manually and can be “blunt” In sample hour, interval 4, total operating reserve requirements reduced by 1210 MW

78 Reduction in Market-Based Operating Reserve Requirement Price ($) MWh RT RT2 $ $ Reduce OR requirement by 1210 MWh

79 The Inter-relationship of the “Factors” 1210 MW Failed TransactionsSelf-Scheduler Error Forecast vs Actual Demand Impact on Supply Adequacy Outages / Deratings Sum of these Factors can lead to an OR Reduction Price Change 1210 MW $136.23

80 Effect of All Factors Price ($) MWh PD RT2 $ $169.63

81 The Inter-relationship of the “Factors” 165 MW Failed TransactionsSelf-Scheduler Error Forecast vs Actual Demand Impact on Supply Adequacy Outages / Deratings Sum of these Factors can lead to an OR Reduction Price Change 1210 MW $ MW 36 MW 75 MW 690 MW 90 MW 54 MW -636 MW 574 MW

82 The END