Historical Nodal Pricing AnalysisAnalysis on nodal pricing was requested by Day Ahead Market Working Group This work also supports the Minister of Energy’s 1999 directive to the

Market Evolution ProgramJanuary 2004

Historical Nodal PricingAnalysis

Market Operations Standing Committee 2

Presentation Highlights

§ The Day Ahead Market Working Group has indicated that thereis insufficient data, analysis or understanding at this time forstakeholders to support a recommendation on nodal pricing§ Historical results for generators for the study period

• Average Market Clearing Price is $54/MWh• Average nodal price would have been $72/MWh

§ Historical results for load customers for the study period• Average uniform price including uplifts for CMSC and losses

is $55/MWh• Average nodal price would have been $72/MWh

§ Historical results for load customers for the study period includingthe effect of existing rebates

• Average uniform price including uplifts for CMSC and lossesis $48/MWh

• Average nodal price would have been $55/MWh


Presentation Highlights

§ Average nodal prices calculated assume no changes in biddingbehaviour§ Uniform prices do not accurately reflect the demand-supply

balance of the market§ Nodal prices are more reflective of system and market conditions§ Future prices cannot be predicted - participants may change

bidding behaviour in response to any market changes


Ongoing Efforts

§ Nodal pricing has been considered for the Day Ahead Market(DAM) by the DAM Working Group as the design approach toprice locational differences due to congestion and losses• DAM Working Group has also asked to consider other designs

§ Analysis of historical prices has shown that locational differencesaccount for a small portion of the difference between the averageuniform price (HOEP) and the weighted average nodal price• Other aspects of the price calculations have a more significant

impact (i.e. impact of ramp rates, calculation of demand, etc)§ We are continuing work along the following paths

• Further investigate the sources of the differences betweenuniform and nodal prices

• Evaluate whether the sources of price differences continue tobe appropriate for Ontario’s market

• Report to stakeholders on the results of these efforts


Agenda

BackgroundHistorical Nodal Pricing AnalysisSummary


What is Nodal Pricing?

§ Nodal Pricing is a method of determining prices in which marketclearing prices are calculated for a number of locations on thetransmission grid called nodes• Each node represents a physical location on the transmission

system including generators and loads

§ The price at each node represents the locational value of energy,which includes the cost of the energy and the cost of delivering it(i.e. losses and congestion)

§ Nodal prices are determined by calculating the incremental costof serving one additional MW of load at each location subject tosystem constraints (i.e. transmission limits, ramp rates ofresources, contingency analysis)


Why Was This Study Done?

§ Analysis on nodal pricing was requested by Day Ahead MarketWorking Group

§ This work also supports the Minister of Energy’s 1999 directive tothe IMO to undertake a review of the impact of congestion pricing

§ The IMO is continually investigating mechanisms to increase theefficiency of spot market pricing - nodal pricing is one suchmechanism

§ Historical nodal pricing data was used for this analysis


Objective and Scope

What do we want to achieve?§ To provide market stakeholders with a summary of historical

nodal and uniform pricing data

What is included in this study?§ Total pricing comparison - to consistently compare uniform and

nodal prices and show how these prices have varied over time§ Spatial analysis - to show how nodal prices have varied across

Ontario

Predicting future prices is not within the scope of this study


Future Prices Cannot be Predicted

Why?§ Market Participant bidding behaviour not captured in this analysis§ Bidding behaviour will change with any change in pricing

methodology§ Any other market changes introduced going forward will also

impact energy price§ Only historical nodal pricing data is analysed


Review of Current Pricing Scheme

NodalPrices

Currently calculated for informational purposes only

IMOMarket Participants

UnconstrainedCalculation

• ignores physical limitations

MarketSchedule

UniformPrice

ConstrainedCalculation

• considers physical limitations

DispatchSchedule

Bids/Offers Bids /

Offers

Dispatchableresources

produce or consume MWs

Uniform price of energy

CMSC


Nodal Pricing Scheme

NodalPrices

Nodal price of energy

IMOMarket Participants

UnconstrainedCalculation

• ignores physical limitations

MarketSchedule

UniformPrice

ConstrainedCalculation

• considers physical limitations

DispatchSchedule

Bids/Offers Bids /

Offers

Dispatchableresources

produce or consume MWs

Disappears with nodal pricing

CMSC


Data

What data is used?§ Study spans period from October 4, ‘02 to December 31, ‘03§ No data available during market suspension August 14-22, ‘03§ Incorrect publication of nodal prices prior to October 4, ‘02

Aggregation§ The hourly average of prices and schedules are used to be

consistent with how Hourly Ontario Energy Price (HOEP) iscalculated


Agenda

BackgroundHistorical Nodal Pricing Analysis§ Total Price Comparison

Summary


Total Price Comparison

What do we want to show?§ What would the difference be between the uniform and nodal

prices paid for energy taking into account the uplifts for lossesand CMSC§ Some explanation of these price differences


Uniform Total Pricing

What we need to determine?§ Total price paid by load customers under uniform pricing

HOEP + CMSC Uplift + Losses Uplift


Nodal Total Pricing

What we need to determine?§ The total price paid by load customers under nodal pricing would

be

§ However we do not have the necessary data to calculate theload-weighted average

• But if we assume that internal FTRs and loss residuals areallocated to load customers, the total price paid by loadcustomers under nodal pricing would be the Generator-Weighted Average price

§ Other uplifts including IOG and OR are common to both uniformand nodal pricing schemes

Load-Weighted Average

(FTRs + Loss Residuals) = (Load-Wtd Avg) - (Gen-Wtd Avg)

(Gen-Wtd Avg) = (Load-Wtd Avg) - (FTRs + Loss Residuals)


Total Price Comparison

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Uniform (HOEP+CMSC+Losses) Nodal (Gen-Wtd Avg)

Nodal (Gen-Wtd Avg) Average - $72.46

HOEP + CMSC + Losses Average - $55.42


0

10

20

30

40

50

60

70

80

90

100

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

HOEP CMSC Uplift Losses Uplift

Total Price Components

HOEP Average - $53.56

CMSC Uplift Average - $0.80

Losses Uplift Average - $1.06


Factors Accounting for Price Differences

Why are uniform and nodal prices different?§ HOEP is determined from the output of the unconstrained

algorithm which ignores physical limitations of grid§ Constrained algorithm considers physical limitations of grid when

dispatching resources and calculating nodal prices

Specific factors accounting for price differences§ Regional demand-supply balance§ Demand differences§ Ramp rate requirements


Demand-Supply Balance

§ HOEP does not accurately reflect the demand-supply balance• Unconstrained calculation has access to larger resource

stack than constrained calculation, e.g.– Operating reserve in NW Ontario that is available but

can’t be delivered– Full capability of quick-start units and partially

dispatched units that can’t be delivered due totransmission constraints

§ Nodal prices properly reflect the demand-supply balance• Constrained calculation determines the schedule of

resources that can be delivered while consideringconstraints of the transmission system


Demand Differences

§ Demand for the constrained calculation is estimated before theinterval for which resources are dispatched§ Demand for the unconstrained calculation is measured after the

interval


Ramp Rate Constraints

§ Unconstrained calculation uses artificial (12x) ramp rate todetermine HOEP§ Constrained calculation uses actual (1x) ramp rates to dispatch

the system and calculate nodal prices


Pricing Transitional Mechanisms

§ With a change in pricing methodology, transitional mechanismsare needed to help customers adjust§ The IMO supports transitional mechanisms to facilitate a change

from uniform pricing to nodal pricing• If an Ontario-weighted average nodal price were to be paid by

load customers, the existing Business Protection Plan Rebate(BPPR) could be one example of a transitional mechanism

• However, the appropriate transitional mechanism(s) wouldultimately depend on the pricing model for load customers

• For the purposes of this analysis we have applied the BPPRto both uniform and nodal total price to see the impact on theprice differences


Total Price Comparison With Existing Rebates Applied

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Uniform (HOEP+CMSC+Losses) Nodal (Gen-Wtd Avg)

Nodal (Gen-Wtd Avg) Average - $55

HOEP + CMSC + Losses Average - $48


Internal FTRs and Loss Residuals

§ Under nodal pricing, internal Financial Transmission Rights(FTRs) and loss residuals could be allocated to marketparticipants§ Our best estimate of the pool of FTRs and loss residuals is

approximately $1/MWh• Approximations used since we don’t currently have all necessary

historical data to make a more accurate determination§ Based on the Ontario annual consumption of 150TWh (and no

change in bidding behaviour), an estimate of $150M would beavailable for distribution as internal FTRs and loss residuals

Node 1Price = $50G1 Capacity = 120MWG1 Dispatch = 100MWLoad = 50MW

Flow and Limit = 50MW

Paid to generators = 50x100 + 60x50 = $8000Paid by load = 50x50 + 60x100 = $8500FTRs = 8500 - 8000 = $500

Example

Node 2Price = $60G2 Capacity = 60MWG2 Dispatch = 50MWLoad = 100MW


Price Volatility

Hourly OntarioEnergy Price (norebates)

Hourly Gen-WtdNodal Average (norebates)

Hourly RichviewNodal Price

Average for Oct ’02– Dec ‘03 $54 $72 $75

Standard deviationfor Oct ’02 – Dec ‘03 $35 $72 $77


Discussion on Prices

Why have prices been volatile?§ System is dispatched by optimizing over the next 5-minute

dispatch (myopic dispatch)§ Multi-Interval Optimization (MIO) should lessen real-time market

volatility

Comment on Richview reference bus nodal price§ May be used as proxy for the generator-weighted average nodal

price§ Any studies based on Richview nodal prices are valid and over-

state the generator-weighted average nodal price


0

20

40

60

80

100

120

140

160

May02

Jun02

Jul02

Aug02

Sep02

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

HOEP Richview

HOEP vs.. Hourly Richview Nodal Price Since Market Opening

Richview Average - $81

HOEP Average - $53


Agenda

BackgroundHistorical Nodal Pricing Analysis§ Spatial AnalysisSummary


Spatial Analysis

What do we want to show?§ How indicative prices vary across Ontario§ Averages of representative nodal prices§ On- and off-peak average nodal prices§ Impact of congestion and relative losses


How Nodal Prices Vary Across Ontario

Ontario is divided into 10 transmission zones§ Same 10 zones identified in IMOs 18-month and 10-year outlook

forecast documents§ For each zone, either one nodal price or a set of weighted nodal

prices is chosen as the indicative price for that zone§ Price differences between indicative prices in these zones

indicate areas of congestion and relative losses


Selection of Representative Nodal Prices

How are representative nodalprices chosen?§ For many zones, variability of

prices within a zone is lowand one nodal price isconsidered as representative§ For the Northwest and

Northeast, prices of 3 nodesand estimated weights basedon load are chosen to bestrepresent the expanse ofthese zones

QUEBEC

Orangeville

Lake SimcoeBarrie

LakeSuperior

MooseRiver

James Bay

Sault Ste. Marie

Lake Timiskaming

Sudbury North Bay

LondonSarnia

Chatham CANADA

UNITED STATESLake Erie

Niagara Falls

Kitchener

Lake Huron

Georgian Bay Ottawa

Ottawa River

KingstonBelleville

Peterborough

Lake OntarioCANADA

UNITED STATES

Abitibi River

Mattagami River

TimminsMINNESOTA

Red LakeLake St. Joseph Albany River

Trout Lake

Lac SeulSioux Lookout

Lake ofthe Woods LakeNipigon

UNITED STATES

Manitouwadge

GeraldtonFortFrances

Wawa

LakeSuperiorCANADA

Lake Nipissing

OwenSound BrockvilleSt L

awren

ce River

Thunder Bay

MICHIGAN

NEW YORK

Toronto

Hamilton

Windsor

EAST

OTTAWA

ESSA

SOUTHWEST

WEST

BRUCE

NORTHEAST

NORTHWEST

Wawa

NORTHWEST

NIAGARA

MA

NIT

OBA

TORONTO


Representative Nodal Prices

QUEBEC

Orangeville

Lake SimcoeBarrie

LakeSuperior

MooseRiver

James Bay

Sault Ste. Marie

Lake Timiskaming

Sudbury North Bay

LondonSarnia

Chatham CANADA

UNITED STATESLake Erie

Niagara Falls

Kitchener

Lake Huron

Georgian Bay Ottawa

Ottawa River

KingstonBelleville

Peterborough

Lake OntarioCANADA

UNITED STATES

Abitibi River

Mattagami River

TimminsMINNESOTA

Red LakeLake St. Joseph Albany River

Trout Lake

Lac SeulSioux Lookout

Lake ofthe Woods LakeNipigon

UNITED STATES

Manitouwadge

GeraldtonFortFrances

Wawa

LakeSuperiorCANADA

Lake Nipissing

OwenSound BrockvilleSt L

awren

ce River

Thunder Bay

MICHIGAN

NEW YORK

Toronto

Hamilton

Windsor

EAST

OTTAWA

ESSA

SOUTHWEST

WEST

BRUCE

NORTHEAST

NORTHWEST

Wawa

NORTHWEST

NIAGARA

MA

NIT

OBA

TORONTO

BruceBRUCE-LT.G5

NortheastCANYON-LT.AG1450.5 weighting

ANDREWS-LT.G10.3 weighting

OttawaTAOHSC-LT.AG2012

EastSAUNDERS-LT.AG1234

NiagaraBECK2-LT.AG1718

NorthwestATIKOKAN-LT.G1

0.3 weighting

PINEPORTAGE-LT.AG120.2 weighting

THUNDERBAY-LT.G30.5 weighting

SouthwestNANTICOKE-LT.G5

TorontoDARLINGTON-LT.G1

EssaDESJOACHIMS-LT.AG12

WestLAMBTON-LT.G1

NPIROQFALLS-LT.AG1230.2 weighting


Average Nodal Prices Paid to Generators (Oct ‘02 - Dec ‘03)

Northwest

$50Northeast

$63

Essa

$72Bruce

$73

West

$72

Niagara

$76

Southwest

$74Toronto

$75East

$74QFW

QuebecInterconnection

(Radial)

New YorkInterconnection

(PAR Controlled)

New YorkInterconnection(Free Flowing)

MichiganInterconnection

(Partial PARControlled)

ManitobaInterconnection

(PAR Controlled)

MinnesotaInterconnection

(PAR Controlled)

EWTE

EWTW

FNFS

CLA

N

CLA

S

FETT

FABC

NBLIPBLIP

Ottawa

$78


(Radial)


(Radial)

TEC

FIO

Average nodal price paid by load $72Average nodal price with rebates $55Average uniform price $55Average uniform price with rebates $48


Average On-Peak Nodal Prices Paid to Generators(Oct ‘02 - Dec ‘03)

Northwest

$59Northeast

$76

Essa

$91Bruce

$95

West

$94

Niagara$98

Southwest

$95Toronto

$97East

$95QFW


(Radial)


(PAR Controlled)





(PAR Controlled)


(PAR Controlled)

EWTE

EWTW

FNFS

CLA

N

CLA

S

FETT

FABC

NBLIPBLIP

Ottawa

$100


(Radial)


(Radial)

TEC

FIO



Average Off-Peak Nodal Prices Paid to Generators(Oct ‘02 - Dec ‘03)

Northwest

$43Northeast

$52

Essa

$57Bruce

$56

West

$54

Niagara

$57

Southwest

$56Toronto

$57East

$56QFW


(Radial)


(PAR Controlled)





(PAR Controlled)


(PAR Controlled)

EWTE

EWTW

FNFS

CLA

N

CLA

S

FETT

FABC

NBLIPBLIP

Ottawa

$59


(Radial)


(Radial)

TEC

FIO



Congestion and Losses

§ Congestion• Between adjacent zones

§ Marginal Losses• Relative to Richview reference bus


Average Congestion and Losses (Oct ‘02 - Dec ‘03)

Northwest$50.20

Northeast$63.24

Essa$72.47

Bruce$73.35

West$72.20

Niagara$75.63

Southwest$73.65

Toronto$75.43

East$73.90

QFW


(Radial)


(PAR Controlled)





(PAR Controlled)


(PAR Controlled)

EWTE

EWTW

FNFS

CLA

N

CLA

S

FETT

FABC

NBLIPBLIP

Ottawa$77.96


(Radial)


(Radial)

TEC

FIO

Congestion between adjacentzones and direction of flow

Marginal losses relative toRichview reference bus

$3.42

$2.09

$0.19

$0.03

$0.43

$1.38

$0.95

$0.48

$2.04$2.32

$0.28

$2.10$0.73 $3.50

$2.83$1.53

$9.62$7.14

$1.50

$3.87$5.00

$1.50


Congestion and Losses

§ Nodal price differences across Ontario are a function of bothcongestion and losses - with losses contributing more to theprice differences§ Highest occurrence of congestion along East-West Transfer

interfaces§ Losses are greatest between Northwest and Northeast


Agenda

BackgroundHistorical Nodal Pricing AnalysisSummary


Summary

The information presented§ Over 14 months of nodal pricing data has been used for analysis§ Future prices cannot be predicted - participants may change

bidding behaviour in response to any market changes

Uniform vs.. Nodal Pricing§ Nodal pricing offer prices more transparent and reflective of

power system and market conditions§ Uniform prices do not accurately reflect the demand-supply

balance of the market§ Nodal pricing is one of several important considerations in

analysing where to site additional generation, transmission andload


SummaryAverage Prices§ For generators during the study period

• Average Market Clearing Price is $54/MWh• Average nodal price would have been $72/MWh

§ For load customers• Average uniform price including losses and congestion uplifts is

$55/MWh• Average nodal price would have been $72/MWh

§ For load customers, including the effect of existing rebates for the studyperiod

• Average uniform price including losses and congestion uplifts is$48/MWh

• Average nodal price would have been $55/MWh§ Average nodal prices calculated assume no changes in bidding

behaviourTransitional mechanisms are recommended for a change fromuniform to nodal pricing


Summary

Price Differences§ Are caused by• Accuracy in considering demand-supply balance• Demand differences in constrained and unconstrained

algorithms• Use of different ramp rates§ Are particularly sensitive when operating on the steep portion of

supply curveNodal price differences across Ontario§ Are due to both congestion and losses - with losses as a larger

contributing factorInternal FTRs and Loss Residuals§ The estimated value is $150M annually


Supplementary Information

Explanation of CalculationsAverage On-Peak and Off-Peak PricesRepresentative Average Nodal Prices For Each Zone


Total Price Paid Under Uniform Pricing

§ HOEP - average of interval MCPs§ CMSC uplift - Congestion Management Settlements Credit§ Losses uplift - estimated by the Net Energy Market Settlements

Credit (NEMSC) uplift• The dollars paid out to generators is more than the dollars

collected from loads for energy• This shortfall is an estimate for losses that loads must pay

§ Rebates (if applied) - Business Protection Plan Rebate (BPPR)calculated by

2$38HOEP weighted)-(Demand −

HOEP + CMSC uplift + Losses uplift (- Rebates if applied)


Total Price Paid Under Nodal Pricing

§ Nodal prices already include components of losses andcongestion§ Rebates (if applied) - the same BPPR formula is used

Nodal Price - (Rebates if applied)

2$38Price Nodal −


Nodal Prices

§ An indication of what load would pay is the Load-WeightedAverage Nodal Price§ An indication of what generators would be paid is the Generator-

Weighted Average Nodal Price§ Unlike uniform pricing, under nodal pricing the dollars collected

from loads is more than the dollars paid to generators§ This difference makes up the available internal Financial

Transmission Rights (FTRs) and loss residuals that can beallocated back to market participants

§ For the purposes of this analysis, we assume that loads areallocated the internal FTRs and loss residuals



Total Price Paid Under Nodal Pricing

§ Recall that total price paid by loads under nodal pricing is

§ Which can be expressed as

§ If internal FTRs and loss residuals are allocated back to loads,the total price paid by loads under nodal pricing is

Nodal Price - (Rebates if applied)

(Gen-Wtd Avg) - (Rebates if applied)

(Load-Wtd Avg) - (Rebates if applied)


Ontario Generator-Weighted Average Price

An indication of what generators would get paid§ Used in total pricing comparisons§ Calculated by

§ Gi is the MW dispatched for generator i§ Pi is the nodal price for generator i§ Scheduled imports at interties should be modelled as generators§ Data for all scheduled imports was not readily available for the

study and was not included in the generator-weighted averagecalculation• On the system-wide basis, excluding the scheduled imports

for this calculation has a small impact

N21

NN2211

GGGPGPGPG

+++++

K

K


An indication of what loads would pay§ Calculated by

§ Li is the energy consumed by load i§ Pi is the nodal price for load iCannot be calculated§ Do not have associated nodal price for each load point§ Use the Ontario demand-weighted average as an estimate

instead§ For this study, the Ontario demand-weighed average is only used

in the calculation of FTRs and loss residuals

Ontario Load-Weighted Average

N21

NN2211

LLLPLPLPL

+++++

K

K


An estimation of what loads would pay§ Calculated by

§ DZi is the total demand in zone Zi§ PZi is the representative nodal price for zone Zi

Ontario Demand-Weighted Average

ZnZ2Z1

ZnZnZ2Z2Z1Z1

DDDPDPDPD

++++++

K

KZone 1Total generation = GZ1

Net flows = FZ1

Total demand, DZ1= GZ1+ FZ1

Zone 2Total generation = GZ2

Net flows = FZ2

Total demand, DZ2= GZ2+ FZ2

Zone nTotal generation = GZn

Net flows = FZn

Total demand, DZn= GZn+ FZn


Approximations in Calculating the OntarioDemand Weighted Average

§ Some flow data was not readily available to calculate thedemand for each of the 10 zones§ Some zones were aggregated to calculate the Ontario demand-

weighted average• From October ‘02 - March ‘03 demand was aggregated into 4

zones• From April ‘03 - December ‘03 demand was aggregated in 8

zones


Aggregation of Zones for Oct ‘02 - Mar ‘03 Calculations

Northwest Northeast

EssaBruce

West

Niagara

Southwest Toronto East

QFW


(Radial)


(PAR Controlled)





(PAR Controlled)


(PAR Controlled)

EWTE

EWTW

FNFS

CLA

N

CLA

S

FETT

FABC

NBLIPBLIP

Ottawa


(Radial)


(Radial)

TEC

FIO

Z1 Z2

Z3Z4


Aggregation of Zones for April - Dec ‘03 Calculations

Northwest Northeast

EssaBruce

West

Niagara

Southwest Toronto East

QFW


(Radial)


(PAR Controlled)





(PAR Controlled)


(PAR Controlled)

EWTE

EWTW

FNFS

CLA

N

CLA

S

FETT

FABC

NBLIPBLIP

Ottawa


(Radial)


(Radial)

TEC

FIO

Z2Z1

Z3

Z4

Z5

Z6

Z7

Z8



§ Estimated by

§ Since we estimate what loads pay in a zonal manner, i.e.

§ We shall also calculate what generators are paid in a zonalmanner to estimate available internal FTRs and loss residuals,i.e.


ZnZ2Z1

ZnZnZ2Z2Z1Z1

DDDPDPDPD

++++++

K

K

ZnZ2Z1

ZnZnZ2Z2Z1Z1

GGGPGPGPG

++++++

K

K



§ So, internal FTRs and loss residuals are estimated by

§ This estimate calculated is based on available historical data

ZnZ2Z1

ZnZnZ2Z2Z1Z1

DDDPDPDPD

++++++

K

K

ZnZ2Z1

ZnZnZ2Z2Z1Z1

GGGPGPGPG

++++++

K

K-

(FTRs + Loss Residuals) = (Demand-Wtd Avg) - (Gen-Wtd Avg)

FTRs +Loss Residuals =





0

20

40

60

80

100

120

140

160

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

HOEP Gen-Wtd Avg

Average Prices Paid to GeneratorsHOEP Average - $54

Gen-Wtd Avg Average - $72


0

20

40

60

80

100

120

140

160

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

HOEP Gen-Wtd Avg

Average On-Peak Prices Paid to GeneratorsHOEP Average - $67



0

20

40

60

80

100

120

140

160

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

HOEP Gen-Wtd Avg

Average Off-Peak Prices Paid to GeneratorsHOEP Average - $43






Northwest Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $50

Std Dev - $59


Northwest Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Atikokan Pine Portage Thunderbay


Northeast Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $63

Std Dev - $59


Northeast Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Canyon Iroquois Falls Andrews


Essa Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $72

Std Dev - $79


Toronto Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $75

Std Dev - $75


Ottawa Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $78

Std Dev - $66


Bruce Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $73

Std Dev - $67


Niagara Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $76

Std Dev - $79


West Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $72

Std Dev - $78


East Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $74

Std Dev - $77


Southwest Average Nodal Price Paid to Generators

0

20

40

60

80

100

120

140

Oct02

Nov02

Dec02

Jan03

Feb03

Mar03

Apr03

May03

Jun03

Jul03

Aug03

Sep03

Oct03

Nov03

Dec03

Month

$/M

Wh

Average - $74

Std Dev - $75

Documents

Historical Nodal Pricing AnalysisAnalysis on nodal pricing was requested by Day Ahead Market Working Group This work also supports the Minister of Energy’s 1999 directive to the