The Ontario Electricity Market 1 Year in
The Ontario Electricity Market 1 Year in
Richard Penn
Mgr - Market Assessment
The IMO
AgendaAgenda
• Introduction - brief overview
• Market Design
• Issues Identified in the MSP reports
• Introduction - brief overview
• Market Design
• Issues Identified in the MSP reports
33
IMOIMO
www.theimo.com
44
The IMO Web - Today’s marketThe IMO Web - Today’s market
55
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
66
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
www.theimo.comwww.theimo.com
The Energy MarketStatistics
The Energy MarketStatistics
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 1 58.42 $/Mw-hr
Average Weighted energy price since May 1 62.50 $/Mw-hr
Minimum Hourly Price was 7.84 $/Mw-hr
Maximum Hourly Price was 1036.80 $/Mw-hr
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 1 58.42 $/Mw-hr
Average Weighted energy price since May 1 62.50 $/Mw-hr
Minimum Hourly Price was 7.84 $/Mw-hr
Maximum Hourly Price was 1036.80 $/Mw-hr
Some Facts
The Ontario Demand for the first year of the market is about 156 Tw-hr
Close to 10 B$ has been settled through the IAM markets
More than 136,000 Settlement Statements will have been issued by April 30, 2003
100% of Settlement Statements issued on time, so far
99.6% of Settlement Statements issued to date were error free
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, 2003
100% of Settlement Statements issued on time, so far
99.6% of Settlement Statements issued to date were error free
1111
Average HOEP for May to April 2003
$-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
Month
$/M
w-h
r Average Off Peak HOEP
Average On Peak HOEP
Average HOEP
1212
Surrounding Spot Market Prices May 2002 to April 2003 ($CDN per MWh)Preliminary
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
IMO NY Zone OH ISO New England PJM Western Hub
Market
$C/M
w-h
r
May 2002 to April 2003 ($CDN per MWh)
1313
Daily Natural Gas PricesMay 1'st to April 1, 2003
0
5
10
15
20
25
30
Delivery Date
Hen
ry H
ub
Sp
ot
Pri
ce (
$ C
dn
/MM
Btu
)
The Energy MarketThe Energy Market
1515
Simple Energy Spot Market
Energy SuppliersEnergy
PurchasersOffers Bids
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)
1616
The Present MarketThe Present Market
EnergyEnergyOperatingOperatingReserveReserve
Real-timeReal-time
IMO - Administered MarketsIMO - Administered MarketsIMO - Administered MarketsIMO - Administered Markets
TransmissionTransmissionRightsRights
FinancialFinancial PhysicalPhysical
AncillaryAncillaryServicesServices
ProcurementProcurement
1717
Who Can Participate in the Markets
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
1818
ParticipantsParticipantsOutsideOutsideOntarioOntario
Direct LargeDirect LargeCustomerCustomer
Who Can Participate?Who Can Participate?
DistributorDistributor
Embedded LargeEmbedded LargeCustomer Customer
EmbeddedEmbeddedGeneratorGenerator
GeneratorGenerator
Simplified Energy MarketSimplified Energy Market
Offers and Bids
2020
Bid and Offer BasicsBid and Offer Basics
Generators and Generators and ImportsImports
OffersOffers Loads and Loads and ExportsExports
BidsBids
IMO - IMO - AdministeredAdministered
MarketsMarkets
Real-time Real-time EnergyEnergy
2121
+MMCP
-MMCP
0
AvailableCapacity
Price
CumulativeQuantity
Composite Energy Offer CurveComposite Energy Offer Curve
2222
Composite Energy Bid CurveComposite Energy Bid Curve
+MMCP
-MMCP
0
AvailableCapacity
Price
CumulativeQuantity
2323
Market Clearing PriceMarket Clearing Price
Market Clearing Price
Price
SupplyDemand
MCP
Quantity
Determining Market PriceDetermining Market Price
2525
Market Design PrinciplesMarket 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
2626
Setting the Market Clearing Price - An Example
Setting the Market Clearing Price - An Example
Generator 3Generator 3
50 MW - $25/MWh50 MW - $25/MWh
Generator 1Generator 1
50 50 MW - $38/MWhMW - $38/MWh
100 100 MW - $15/MWhMW - $15/MWh
Generator 2Generator 2
50 MW - $20/MWh50 MW - $20/MWh
2727
Offers Are Selected Economically
Offers Are Selected Economically
100 MW100 MW
50 MW50 MW
50 MW50 MW
50 MW50 MW
$15 / MWh$15 / MWh
$20 / MWh$20 / MWh
$25 / MWh$25 / MWh
$38 / MWh$38 / MWh
Generator 1Generator 1 Generator 2Generator 2 Generator 3Generator 3
12:0012:00 13:0013:00 14:0014:00 15:0015:00 16:0016:00 17:0017:00 18:0018:00 19:0019:00
QuantityQuantity
TimeTime
20:0020:00
2828
50 MW50 MW
100 MW100 MW
150 MW150 MW
200 MW200 MW
$15 / MWh$15 / MWh
$20 / MWh$20 / MWh
$25 / MWh$25 / MWh
$38 / MWh$38 / MWh
12:0012:00 13:0013:00 14:0014:00 15:0015:00 16:0016:00 17:0017:00 18:0018:00 19:0019:00
QuantityQuantity
TimeTime
Generator 1Generator 1 Generator 2Generator 2 Generator 3Generator 3
20:0020:00
Offers and DemandOffers and Demand
250 MW250 MW
2929
100 MW
50 MW
50 MW
50 MW
$15 / MWh$15 / MWh
$20 / MWh$20 / MWh
$25 / MWh$25 / MWh
$38 / MWh$38 / MWh
16:00 16:05 16:10 16:15 16:30 16:35 16:40 16:45
Quantity
Time
17:00
Generator 1 Generator 2 Generator 3
16:20 16:25 16:50 16:55
Offers and Demand - 5 Minute IntervalsOffers and Demand - 5 Minute Intervals
25 25 25 25 25 25 25 38MCP
$ / MWh 38 38 38 38
3030
July 2002 Offer StackJuly 2002 Offer Stack
3131
Comparison of a July to an October Domestic Offer CurveComparison of a July to an October Domestic Offer Curve
Difference is due to Outages
Now it Gets ComplicatedIn the Ontario Design there are actually two
schedules for each generator
Now it Gets ComplicatedIn 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
3333
MCP - Copper Plate
Requirement is 190 MW
• Gen 1: 100 MW• Gen 2: 90 MW• Gen 3: does not run
• MCP $20
Generator 1
100 MW$15
Generator 2
100 MW$20
Generator 3
100 MW$25
Load
190 MW
Region 2Region 1
Notransmission
line limit
3434
The IMO Web - Today’s marketThe IMO Web - Today’s market
3535
Physical Limitations• Bid/Offer selection must
result in system flows within system’s physical limitations
• Increases the cost of power to ensure reliability
• 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 YorkEast
East-West Tie
Flow North/Flow South
BLIPQFW
Quebec South
New York Niagara
FETT
Manitoba
3636
Transmission CongestionTransmission Congestion
Requirement is Requirement is 190 MW190 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 MCP $20 determined from Unconstrained
ScheduleSchedule
Generator 1Generator 1
100 MW100 MW$15$15
Generator 2Generator 2
100 MW100 MW$20$20
Generator 3Generator 3
100 MW100 MW$25$25
LoadLoad
190 MW190 MW
Region 2Region 2Region 1Region 1
150 MW150 MWtransmissiontransmission
line limitline limit
3737
Unconstrained vs ConstrainedReminder
Unconstrained vs ConstrainedReminder
• Unconstrained schedule determines prices
• Constrained schedule determines dispatch instructions
• Any differences between unconstrained and constrained schedule creates potential for CMSC
• Unconstrained schedule determines prices
• Constrained schedule determines dispatch instructions
• Any differences between unconstrained and constrained schedule creates potential for CMSC
3838
Constrained Payments for the 1’st Year of the Market
Constrained Payments for the 1’st Year of the Market
• Constrained on Payments = about 75M$
• Constrained Off Payments = about 132 M$
• Constrained on Payments = about 75M$
• Constrained Off Payments = about 132 M$
3939
The Actual Constrained Schedule takes into account
The Actual Constrained Schedule takes into account
- Available Transmission
- Transmission Limits
- Losses
- Generator Capabilities such as Ramp rates
-Actual generator Output
4040
FN/FS
TECCLAN/CLAS
MIS
S(E
CC
T)E
E-W
-TR
-E
LK
HD
(EC
CT
)E
TE
K
TE
M
KA
O
FETT
QFW
BLIP
P502X+A8K/A9K
DES JOACHIMS
MOOSE RIVERBASIN 230kV
LENNOX230
MAD
CHENAUX
CHATS 230
St. L 23
0
St. L
115
CENTRAL
ESSA
ALLANBURG
LAMBTON
Lakehead115 kV Area
LOWERNOTCH
West ofFETT
North ofFN/FS
EAST
NORTHEAST
West ofBLIP
East ofQFW
GLP
LITTLELONG
KAPUSKASING
Purchasethrough
Michigan &Nigara interfaces
The Reserve Area Bubble Diagram
Operating ReserveOperating Reserve
4242
Now it Gets More complicatedNow 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
4343
Operating ReserveOperating 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
4444
Operating ReserveOperating 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)
4545
Offer Basics - Operating Reserve Markets
Offer Basics - Operating Reserve Markets
Energy Energy SuppliersSuppliers
Energy Energy PurchasersPurchasers
OROROffersOffers
OROROffersOffers
IMO - IMO - AdministeredAdministered
MarketsMarkets
Operating Operating ReserveReserve
Classes of OR MarketsClasses of OR Markets• 10 min spinning10 min spinning• 10 min non-spinning10 min non-spinning• 30 min30 min
Offer Offer
Operating Reserve amount Operating Reserve amount and price offered for each hour and price offered for each hour of the dispatch dayof the dispatch day
4646
Optimization ObjectiveOptimization Objective
Value of ElectricityValue of Electricityproducedproduced
……as indicated by as indicated by Energy demand from Energy demand from
non-dispatchable non-dispatchable loads and Energy bidsloads and Energy bids
--Cost toCost to
produce Electricityproduce Electricity
……as indicated by as indicated by offers to supply offers to supply
Energy & Operating Energy & Operating ReserveReserve
== Economic gain Economic gain from tradefrom trade
Algorithm maximizes Algorithm maximizes economic gain from trade economic gain from trade for all market participantsfor all market participants
Interjurisdictional TradeInterjurisdictional Trade
4848
Further ComplicationsInterjurisdictional TradeFurther 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)
4949
Interjurisdictional TradeInterjurisdictional 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
5050
Interjurisdictional TradeInterjurisdictional Trade
Minnesota
Quebec (8)
Manitoba
New YorkMichigan
5151
Boundary Entities and Boundary Entity Resources
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
5252
Types of Interjurisdictional Trade?Types of Interjurisdictional Trade?
ExportExport
ImportImport
Wheel-ThroughWheel-Through
5353
OntarioOntario New YorkNew YorkNYNY
IntertieIntertieZoneZone
External MarketExternal Market (New York Example)(New York Example)IMO-Administered MarketsIMO-Administered Markets
Export of Energy From OntarioExport of Energy From Ontario
MWs Exported MWs Exported from Ontariofrom Ontario
MWs Imported to MWs Imported to New YorkNew York
5454
OntarioOntario New YorkNew YorkNYNY
IntertieIntertieZoneZone
External MarketExternal Market (New York Example)(New York Example)IMO-Administered MarketsIMO-Administered Markets
Import of Energy Into OntarioImport of Energy Into Ontario
MWs Imported to MWs Imported to OntarioOntario
MWs Exported MWs Exported from New Yorkfrom New York
5555
Quick SummaryQuick Summary
5656
Ontario’s Wholesale Electricity Market
Ontario’s Wholesale Electricity Market
DistributorsDistributors
RetailersRetailers
WholesaleWholesaleConsumersConsumers
WholesaleWholesaleSellersSellers
GeneratorsGenerators
SuppliersSuppliers PurchasersPurchasers
IMO - IMO - AdministeredAdministered
MarketsMarkets
TransmittersTransmitters
Transactions / InformationTransactions / Information
ElectricityElectricity
Energy MarketEnergy Market
MCP calculatedMCP calculated
OffersOffers BidsBids
$$ $$
SettlementsSettlements BillingBilling
ScheduleSchedule& Dispatch& Dispatch
ScheduleSchedule& Dispatch& Dispatch
5757
Where is the Market Evolving ToWhere is the Market Evolving To
5858
Anticipated Evolution to the MarketAnticipated Evolution to the Market
AncillaryAncillaryServicesServices
EnergyEnergyOperatingOperatingReserveReserve
ProcurementProcurement
Real-timeReal-time
PhysicalPhysical
IMO - Administered MarketsIMO - Administered MarketsIMO - Administered MarketsIMO - Administered Markets
Day Ahead EnergyDay Ahead EnergyForwardForward
Hour Hour Ahead Ahead
DispatchaDispatchable Loadble Load
TransmissionTransmissionRightsRights
FinancialFinancial
5959
The MSP ReportsThe MSP Reports
http://www.theimo.com/imoweb/marketSurveil/mspReports.asp
6060
From the 1’st MSP ReportFrom 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
6161
From the 2’nd MSP ReportFrom 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
From Pre-dispatch to Real-time: An Hour in the Life of the
Market
6363
Purpose of Case StudyPurpose 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
6464
The Inter-relationship of the “Factors”The Inter-relationship of the “Factors”
Failed Transactions Self-Scheduler Error
Forecast vs Actual Demand
Impact on Supply Adequacy
Outages / Deratings
Sum of these Factors can lead to an OR Reduction
Price Change
6565
Background FactsBackground Facts
• Pre-dispatch• Energy price - $950.66
• 10 N - $868.74
• 10S - $878.14
• 30R - $868.73
• Demand - 24,679 MWh
• Pre-dispatch• Energy price - $950.66
• 10 N - $868.74
• 10S - $878.14
• 30R - $868.73
• Demand - 24,679 MWh
• Real-time• HOEP - $132.51
• Hourly IOG - $62.78
• Interval 4 • Energy price - $169.63
• 10 N - $0.99
• 10S - $10.29
• 30R - $0.10
• Interval 4 demand - 24,514 MWh
• Real-time• HOEP - $132.51
• Hourly IOG - $62.78
• Interval 4 • Energy price - $169.63
• 10 N - $0.99
• 10S - $10.29
• 30R - $0.10
• Interval 4 demand - 24,514 MWh
6666
Treatment of Net ImportsTreatment of Net Imports• Imports and exports are scheduled for real-time delivery in the
one-hour ahead pre-dispatch.• Imports and exports can set the price in pre-dispatch
• In real-time, the schedules of selected imports and exports are fixed and placed at the bottom of the offer curve.
• Imports and exports cannot set the price in real-time
• Real-time offer curve is steeper than pre-dispatch offer curve around forecast of demand.
• In sample hour 3,494 MWh imports selected and 304 MWh of exports selected.
• Imports and exports are scheduled for real-time delivery in the one-hour ahead pre-dispatch.
• Imports and exports can set the price in pre-dispatch
• In real-time, the schedules of selected imports and exports are fixed and placed at the bottom of the offer curve.
• Imports and exports cannot set the price in real-time
• Real-time offer curve is steeper than pre-dispatch offer curve around forecast of demand.
• In sample hour 3,494 MWh imports selected and 304 MWh of exports selected.
6767
Treatment of Net ImportsTreatment of Net Imports
0 5000 10000 15000 20000 25000
-2000
-1000
0
1000
2000
Price ($)
MWh
PDRT
Pre-dispatch Demand plus
OR Requirement
Net Imports
$950.66
$1275.55
6868
Sensitivity to Demand ForecastSensitivity to Demand Forecast• One demand value used to establish pre-dispatch
schedules and price
• Forecast hourly peak demand
• Real-time interval by interval demand will always be different
• When real-time offer curve is steep, modest differences in demand can cause large price differences
• In sample hour, interval 4, demand difference was 165 MWh
• One demand value used to establish pre-dispatch schedules and price
• Forecast hourly peak demand
• Real-time interval by interval demand will always be different
• When real-time offer curve is steep, modest differences in demand can cause large price differences
• In sample hour, interval 4, demand difference was 165 MWh
6969
Sensitivity to Demand ForecastSensitivity to Demand Forecast
0 5000 10000 15000 20000 25000
-2000
-1000
0
1000
2000
Price ($)
MWh
PDRT
$1275.55
$348
Real-time Demand plus
OR Requirement
7070
The Inter-relationship of the “Factors”The Inter-relationship of the “Factors”
165 MW
165 MW
Failed Transactions Self-Scheduler Error
Forecast vs Actual Demand
Impact on Supply Adequacy
Outages / Deratings
Sum of these Factors can lead to an OR Reduction
Price Change $348
7171
New Market Contingencies Failed Transactions and Self-Scheduling
New Market Contingencies Failed Transactions and Self-Scheduling
• Failed net imports or under forecast of self-scheduling production cause the real-time offer curve to shift to the left.• less supply causes upward pressure on price
• In sample hour, interval 4, 75 MWh of net imports had failed (275 MWh of imports and 200 MWh of exports).
• In sample hour, interval 4, 36 MWh under forecast of self-scheduling generation.
• Failed net imports or under forecast of self-scheduling production cause the real-time offer curve to shift to the left.• less supply causes upward pressure on price
• In sample hour, interval 4, 75 MWh of net imports had failed (275 MWh of imports and 200 MWh of exports).
• In sample hour, interval 4, 36 MWh under forecast of self-scheduling generation.
7272
New Market Contingencies Failed Transactions and Self-Scheduling
New Market Contingencies Failed Transactions and Self-Scheduling
5000 10000 15000 20000 25000
-2000
-1000
0
1000
2000
Price ($)
MWh
RTRT2
$1275.55
$1500.00
7373
The Inter-relationship of the “Factors”The Inter-relationship of the “Factors”
75 MW
111 MW
Failed Transactions Self-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
$1500
7474
Outages and DeratesOutages and Derates
• Outages or derates that occur after the final pre-dispatch remove supply from the real-time offer curve.• places upward pressure on the price
• In sample hour, interval 4, 690 MWh had been lost due to forced outage or derates
• Outages caused the unconstrained sequence to be short operating reserve.
• Outages or derates that occur after the final pre-dispatch remove supply from the real-time offer curve.• places upward pressure on the price
• In sample hour, interval 4, 690 MWh had been lost due to forced outage or derates
• Outages caused the unconstrained sequence to be short operating reserve.
7575
Outages and DeratesOutages and Derates
5000 10000 15000 20000 25000
-2000
-1000
0
1000
2000
Price ($)
MWh
RTRT2
$1275.55
7676
The Inter-relationship of the “Factors”The Inter-relationship of the “Factors”
690 MW
Failed Transactions Self-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
7777
Reduction in Market-Based Operating Reserve Requirement
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
7878
Reduction in Market-Based Operating Reserve Requirement
Reduction in Market-Based Operating Reserve Requirement
5 0 0 0 1 0 0 0 0 1 5 0 0 0 2 0 0 0 0 2 5 0 0 0- 2 0 0 0- 1 0 0 001 0 0 02 0 0 0P r i c e ( $ ) M W h R TR T 2
5000 10000 15000 20000 25000
-2000
-1000
0
1000
2000
Price ($)
MWh
RTRT2
$1275.55
$136.23
Reduce OR requirement by
1210 MWh
7979
The Inter-relationship of the “Factors”The Inter-relationship of the “Factors”
1210 MW
Failed Transactions Self-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$136.23
8080
Effect of All FactorsEffect of All Factors
0 5000 10000 15000 20000 25000 30000
-2000
-1000
0
1000
2000
Price ($)
MWh
PDRT2
$950.66
$169.63
8181
The Inter-relationship of the “Factors”The Inter-relationship of the “Factors”
165 MW
Failed Transactions Self-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$169.63
165 MW
36 MW75 MW
690 MW
90 MW54 MW-636 MW574 MW
8282
The ENDThe END