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

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


50 50 MW - $38/MWhMW - $38/MWh

100 100 MW - $15/MWhMW - $15/MWh


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


100 MW100 MW$15$15


100 MW100 MW$20$20


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


• 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


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


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


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


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


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


165 MW

165 MW




Outages / Deratings


Price Change $348

7171

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



5000 10000 15000 20000 25000

-2000

-1000

0

1000

2000

Price ($)

MWh

RTRT2

$1275.55

$1500.00

7373


75 MW

111 MW




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


690 MW




Outages / Deratings


Price Change

690 MW

$2000

7777

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



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


1210 MW




Outages / Deratings


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


165 MW




Outages / Deratings


Price Change

1210 MW$169.63

165 MW

36 MW75 MW

690 MW

90 MW54 MW-636 MW574 MW

8282

The ENDThe END

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