Historical Nodal Pricing AnalysisAnalysis on nodal pricing was requested by Day Ahead Market Working...
Transcript of Historical Nodal Pricing AnalysisAnalysis on nodal pricing was requested by Day Ahead Market Working...
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
Market Operations Standing Committee 3
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
Market Operations Standing Committee 4
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
Market Operations Standing Committee 5
Agenda
BackgroundHistorical Nodal Pricing AnalysisSummary
Market Operations Standing Committee 6
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)
Market Operations Standing Committee 7
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
Market Operations Standing Committee 8
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
Market Operations Standing Committee 9
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
Market Operations Standing Committee 10
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
Market Operations Standing Committee 11
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
Market Operations Standing Committee 12
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
Market Operations Standing Committee 13
Agenda
BackgroundHistorical Nodal Pricing Analysis§ Total Price Comparison
Summary
Market Operations Standing Committee 14
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
Market Operations Standing Committee 15
Uniform Total Pricing
What we need to determine?§ Total price paid by load customers under uniform pricing
HOEP + CMSC Uplift + Losses Uplift
Market Operations Standing Committee 16
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)
Market Operations Standing Committee 17
Total Price Comparison
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Month
$/M
Wh
Uniform (HOEP+CMSC+Losses) Nodal (Gen-Wtd Avg)
Nodal (Gen-Wtd Avg) Average - $72.46
HOEP + CMSC + Losses Average - $55.42
Market Operations Standing Committee 18
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$/M
Wh
HOEP CMSC Uplift Losses Uplift
Total Price Components
HOEP Average - $53.56
CMSC Uplift Average - $0.80
Losses Uplift Average - $1.06
Market Operations Standing Committee 19
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
Market Operations Standing Committee 20
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
Market Operations Standing Committee 21
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
Market Operations Standing Committee 22
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
Market Operations Standing Committee 23
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
Market Operations Standing Committee 24
Total Price Comparison With Existing Rebates Applied
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$/M
Wh
Uniform (HOEP+CMSC+Losses) Nodal (Gen-Wtd Avg)
Nodal (Gen-Wtd Avg) Average - $55
HOEP + CMSC + Losses Average - $48
Market Operations Standing Committee 25
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
Market Operations Standing Committee 26
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 $77
Market Operations Standing Committee 27
Discussion on Prices
Why have prices been volatile?§ System is dispatched by optimizing over the next 5-minute
dispatch (myopic dispatch)§ Multi-Interval Optimization (MIO) should lessen real-time market
volatility
Comment on Richview reference bus nodal price§ May be used as proxy for the generator-weighted average nodal
price§ Any studies based on Richview nodal prices are valid and over-
state the generator-weighted average nodal price
Market Operations Standing Committee 28
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$/M
Wh
HOEP Richview
HOEP vs.. Hourly Richview Nodal Price Since Market Opening
Richview Average - $81
HOEP Average - $53
Market Operations Standing Committee 29
Agenda
BackgroundHistorical Nodal Pricing Analysis§ Spatial AnalysisSummary
Market Operations Standing Committee 30
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
Market Operations Standing Committee 31
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
Market Operations Standing Committee 32
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
Market Operations Standing Committee 33
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
Market Operations Standing Committee 34
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
QuebecInterconnection
(Radial)
QuebecInterconnection
(Radial)
TEC
FIO
Average nodal price paid by load $72Average nodal price with rebates $55Average uniform price $55Average uniform price with rebates $48
Market Operations Standing Committee 35
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
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
$100
QuebecInterconnection
(Radial)
QuebecInterconnection
(Radial)
TEC
FIO
Average nodal price paid by load $93Average nodal price with rebates $65Average uniform price $69Average uniform price with rebates $53
Market Operations Standing Committee 36
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
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
$59
QuebecInterconnection
(Radial)
QuebecInterconnection
(Radial)
TEC
FIO
Average nodal price paid by load $55Average nodal price with rebates $47Average uniform price $44Average uniform price with rebates $41
Market Operations Standing Committee 37
Congestion and Losses
§ Congestion• Between adjacent zones
§ Marginal Losses• Relative to Richview reference bus
Market Operations Standing Committee 38
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
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$77.96
QuebecInterconnection
(Radial)
QuebecInterconnection
(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
Market Operations Standing Committee 39
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
Market Operations Standing Committee 40
Agenda
BackgroundHistorical Nodal Pricing AnalysisSummary
Market Operations Standing Committee 41
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
Market Operations Standing Committee 42
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
Market Operations Standing Committee 43
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
Market Operations Standing Committee 44
Supplementary Information
Explanation of CalculationsAverage On-Peak and Off-Peak PricesRepresentative Average Nodal Prices For Each Zone
Market Operations Standing Committee 45
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)
Market Operations Standing Committee 46
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 −
Market Operations Standing Committee 47
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
(FTRs + Loss Residuals) = (Load-Wtd Avg) - (Gen-Wtd Avg)
Market Operations Standing Committee 48
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)
Market Operations Standing Committee 49
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
Market Operations Standing Committee 50
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
Market Operations Standing Committee 51
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
Market Operations Standing Committee 52
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
Market Operations Standing Committee 53
Aggregation of Zones for Oct ‘02 - Mar ‘03 Calculations
Northwest Northeast
EssaBruce
West
Niagara
Southwest Toronto East
QFW
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
QuebecInterconnection
(Radial)
QuebecInterconnection
(Radial)
TEC
FIO
Z1 Z2
Z3Z4
Market Operations Standing Committee 54
Aggregation of Zones for April - Dec ‘03 Calculations
Northwest Northeast
EssaBruce
West
Niagara
Southwest Toronto East
QFW
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
QuebecInterconnection
(Radial)
QuebecInterconnection
(Radial)
TEC
FIO
Z2Z1
Z3
Z4
Z5
Z6
Z7
Z8
Market Operations Standing Committee 55
Internal FTRs and Loss Residuals
§ 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.
(FTRs + Loss Residuals) = (Load-Wtd Avg) - (Gen-Wtd Avg)
ZnZ2Z1
ZnZnZ2Z2Z1Z1
DDDPDPDPD
++++++
K
K
ZnZ2Z1
ZnZnZ2Z2Z1Z1
GGGPGPGPG
++++++
K
K
Market Operations Standing Committee 56
Internal FTRs and Loss Residuals
§ 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 =
Market Operations Standing Committee 57
Supplementary Information
Explanation of CalculationsAverage On-Peak and Off-Peak PricesRepresentative Average Nodal Prices For Each Zone
Market Operations Standing Committee 58
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Month
$/M
Wh
HOEP Gen-Wtd Avg
Average Prices Paid to GeneratorsHOEP Average - $54
Gen-Wtd Avg Average - $72
Market Operations Standing Committee 59
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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
Gen-Wtd Avg Average - $93
Market Operations Standing Committee 60
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
Gen-Wtd Avg Average - $55
Market Operations Standing Committee 61
Supplementary Information
Explanation of CalculationsAverage On-Peak and Off-Peak PricesRepresentative Average Nodal Prices For Each Zone
Market Operations Standing Committee 62
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
Market Operations Standing Committee 63
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
Market Operations Standing Committee 64
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
Market Operations Standing Committee 65
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
Market Operations Standing Committee 66
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
Market Operations Standing Committee 67
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
Market Operations Standing Committee 68
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
Market Operations Standing Committee 69
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
Market Operations Standing Committee 70
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
Market Operations Standing Committee 71
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
Market Operations Standing Committee 72
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
Market Operations Standing Committee 73
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