Historical Nodal Pricing Analysis. Market Evolution Program January 2004

Transcription

1 Historical Nodal Pricing Analysis Market Evolution Program January 2004

2 Presentation Highlights The Day Ahead Market Working Group has indicated that there is insufficient data, analysis or understanding at this time for stakeholders 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 including the effect of existing rebates Average uniform price including uplifts for CMSC and losses is $48/MWh Average nodal price would have been $55/MWh Market Operations Standing Committee 2

3 Presentation Highlights Average nodal prices calculated assume no changes in bidding behaviour 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 3

4 Ongoing Efforts Nodal pricing has been considered for the Day Ahead Market (DAM) by the DAM Working Group as the design approach to price 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 differences account for a small portion of the difference between the average uniform 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 between uniform and nodal prices Evaluate whether the sources of price differences continue to be appropriate for Ontario s market Report to stakeholders on the results of these efforts Market Operations Standing Committee 4

5 Agenda Background Historical Nodal Pricing Analysis Summary Market Operations Standing Committee 5

6 What is Nodal Pricing? Nodal Pricing is a method of determining prices in which market clearing prices are calculated for a number of locations on the transmission 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 cost of serving one additional MW of load at each location subject to system constraints (i.e. transmission limits, ramp rates of resources, contingency analysis) Market Operations Standing Committee 6

7 Why Was This Study Done? Analysis on nodal pricing was requested by Day Ahead Market Working Group This work also supports the Minister of Energy s 1999 directive to the IMO to undertake a review of the impact of congestion pricing The IMO is continually investigating mechanisms to increase the efficiency of spot market pricing - nodal pricing is one such mechanism Historical nodal pricing data was used for this analysis Market Operations Standing Committee 7

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 8

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 9

10 Review of Current Pricing Scheme Uniform price of energy Uniform Price Market Participants Bids/ Offers Bids / IMO Offers Unconstrained Calculation ignores physical limitations Market Schedule CMSC Constrained Calculation considers physical limitations Dispatch Schedule Dispatchable resources produce or consume MWs Nodal Prices Currently calculated for informational purposes only Market Operations Standing Committee 10

11 Nodal Pricing Scheme Disappears with nodal pricing Uniform Price Market Participants Bids/ Offers Bids / IMO Offers Unconstrained Calculation ignores physical limitations Market Schedule CMSC Constrained Calculation considers physical limitations Dispatch Schedule Dispatchable resources produce or consume MWs Nodal Prices Nodal price of energy Market Operations Standing Committee 11

12 Data What data is used? Study spans period from ober 4, to ember 31, No data available during market suspension August 14-22, Incorrect publication of nodal prices prior to ober 4, Aggregation The hourly average of prices and schedules are used to be consistent with how Hourly Ontario Energy Price (HOEP) is calculated Market Operations Standing Committee 12

13 Agenda Background Historical Nodal Pricing Analysis Total Price Comparison Summary Market Operations Standing Committee 13

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 losses and CMSC Some explanation of these price differences Market Operations Standing Committee 14

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 15

16 Nodal Total Pricing What we need to determine? The total price paid by load customers under nodal pricing would be Load-Weighted Average However we do not have the necessary data to calculate the load-weighted average But if we assume that internal FTRs and loss residuals are allocated to load customers, the total price paid by load customers under nodal pricing would be the Generator- Weighted Average price (FTRs + Loss Residuals) = (Load-Wtd Avg) - (Gen-Wtd Avg) (Gen-Wtd Avg) = (Load-Wtd Avg) - (FTRs + Loss Residuals) Other uplifts including IOG and OR are common to both uniform and nodal pricing schemes Market Operations Standing Committee 16

17 Total Price Comparison Nodal (Gen-Wtd Avg) Average - $72.46 $/MWh HOEP + CMSC + Losses Average - $ Jan Feb Mar Apr May Jun Jul Aug Sep Month Uniform (HOEP+CMSC+Losses) Nodal (Gen-Wtd Avg) Market Operations Standing Committee 17

18 Total Price Components HOEP Average - $53.56 CMSC Uplift Average - $0.80 Losses Uplift Average - $1.06 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month HOEP CMSC Uplift Losses Uplift Market Operations Standing Committee 18

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 19

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 to transmission constraints Nodal prices properly reflect the demand-supply balance Constrained calculation determines the schedule of resources that can be delivered while considering constraints of the transmission system Market Operations Standing Committee 20

21 Demand Differences Demand for the constrained calculation is estimated before the interval for which resources are dispatched Demand for the unconstrained calculation is measured after the interval Market Operations Standing Committee 21

22 Ramp Rate Constraints Unconstrained calculation uses artificial (12x) ramp rate to determine HOEP Constrained calculation uses actual (1x) ramp rates to dispatch the system and calculate nodal prices Market Operations Standing Committee 22

23 Pricing Transitional Mechanisms With a change in pricing methodology, transitional mechanisms are 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) would ultimately depend on the pricing model for load customers For the purposes of this analysis we have applied the BPPR to both uniform and nodal total price to see the impact on the price differences Market Operations Standing Committee 23

24 Total Price Comparison With Existing Rebates Applied $/MWh Nodal (Gen-Wtd Avg) Average - $ HOEP + CMSC + Losses Average - $48 0 Jan Feb Mar Apr May Jun Jul Aug Sep Month Uniform (HOEP+CMSC+Losses) Nodal (Gen-Wtd Avg) Market Operations Standing Committee 24

25 Internal FTRs and Loss Residuals Example Node 1 Price = $50 G1 Capacity = 120MW G1 Dispatch = 100MW Load = 50MW Flow and Limit = 50MW Paid to generators = 50x x50 = $8000 Paid by load = 50x x100 = $8500 FTRs = = $500 Node 2 Price = $60 G2 Capacity = 60MW G2 Dispatch = 50MW Load = 100MW Under nodal pricing, internal Financial Transmission Rights (FTRs) and loss residuals could be allocated to market participants 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 be available for distribution as internal FTRs and loss residuals Market Operations Standing Committee 25

26 Price Volatility Hourly Ontario Energy Price (no rebates) Hourly Gen-Wtd Nodal Average (no rebates) Hourly Richview Nodal Price Average for $54 $72 $75 Standard deviation for $35 $72 $77 Market Operations Standing Committee 26

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 overstate the generator-weighted average nodal price Market Operations Standing Committee 27

28 HOEP vs.. Hourly Richview Nodal Price Since Market Opening $/MWh Richview Average - $ HOEP Average - $53 0 May Jun Jul Aug Sep Jan Feb Mar Apr May Jun Jul Aug Sep Month HOEP Richview Market Operations Standing Committee 28

29 Agenda Background Historical Nodal Pricing Analysis Spatial Analysis Summary Market Operations Standing Committee 29

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 30

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 31

32 Selection of Representative Nodal Prices NORTHWEST Lake Superior MICHIGAN Wawa Sault Ste. Marie Mattagami River NORTHEAST Lake Huron BRUCE Timmins Moose River Abitibi River Orangeville SOUTHWEST London Sarnia MANITOBA James Bay Lake Timiskaming Sudbury North Bay Lake Nipissing Georgian Bay Owen Sound Kitchener MINNESOTA Red Lake Trout Lake Lake St. Joseph Lac Seul Sioux Lookout the Lake Woods of NORTHWEST Fort Frances ESSA Lake Simcoe Barrie Peterborough Belleville Lake Nipigon QUEBEC OTTAWA Ottawa Kingston Albany River Geraldton Thunder Bay Lake Superior CANADA UNITED STATES EAST Brockville Ottawa River TORONTO CANADA Toronto Lake Ontario UNITED STATES Hamilton NEW YORK Niagara Falls NIAGARA Manitouwadge Wawa St Lawrence River How are representative nodal prices chosen? For many zones, variability of prices within a zone is low and one nodal price is considered as representative For the Northwest and Northeast, prices of 3 nodes and estimated weights based on load are chosen to best represent the expanse of these zones WEST Chatham CANADA Lake Erie Windsor UNITED STATES Market Operations Standing Committee 32

33 Representative Nodal Prices Northeast CANYON-LT.AG weighting NPIROQFALLS-LT.AG weighting NORTHWEST Mattagami River Moose River MANITOBA Abitibi River James Bay Red Lake Trout Lake Lake St. Joseph Lac Seul Sioux Lookout the Lake Woods of NORTHWEST Fort Frances Lake Nipigon Albany River Geraldton Manitouwadge Northwest ATIKOKAN-LT.G1 0.3 weighting PINEPORTAGE-LT.AG weighting ANDREWS-LT.G1 0.3 weighting Lake Superior Wawa NORTHEAST Timmins MINNESOTA Lake Timiskaming Thunder Bay Lake Superior CANADA UNITED STATES QUEBEC Wawa THUNDERBAY-LT.G3 0.5 weighting Essa DESJOACHIMS-LT.AG12 Bruce BRUCE-LT.G5 Southwest NANTICOKE-LT.G5 MICHIGAN Sault Ste. Marie Lake Huron BRUCE Sudbury North Bay Lake Nipissing Georgian Bay Owen Sound Orangeville Kitchener SOUTHWEST London Sarnia ESSA Lake Simcoe Barrie EAST Peterborough Belleville OTTAWA Ottawa Kingston Brockville Ottawa River St Lawrence River TORONTO CANADA Toronto Lake Ontario UNITED STATES Hamilton NEW YORK Niagara Falls NIAGARA Ottawa TAOHSC-LT.AG2012 East SAUNDERS-LT.AG1234 Toronto DARLINGTON-LT.G1 West LAMBTON-LT.G1 WEST Chatham CANADA Lake Erie Windsor UNITED STATES Niagara BECK2-LT.AG1718 Market Operations Standing Committee 33

34 Average Nodal Prices Paid to Generators ( - ) Manitoba (PAR Controlled) Northwest $50 EWTE EWTW Northeast $63 Quebec (Radial) Minnesota (PAR Controlled) FS FN Bruce $73 Essa $72 Ottawa $78 Quebec (Radial) FABC CLAS CLAN FIO BLIP NBLIP FETT Michigan (Partial PAR Controlled) West $72 Average nodal price paid by load $72 Average nodal price with rebates $55 Southwest $74 Average uniform price $55 Average uniform price with rebates $48 QFW New York (Free Flowing) Niagara $76 Toronto $75 TEC East $74 Quebec (Radial) New York (PAR Controlled) Market Operations Standing Committee 34

35 Average On-Peak Nodal Prices Paid to Generators ( - ) Manitoba (PAR Controlled) Northwest $59 EWTE EWTW Northeast $76 Quebec (Radial) Minnesota (PAR Controlled) FS FN Bruce $95 Essa $91 Ottawa $100 Quebec (Radial) FABC CLAS CLAN FIO BLIP NBLIP FETT Michigan (Partial PAR Controlled) West $94 Average nodal price paid by load $93 Average nodal price with rebates $65 Southwest $95 Average uniform price $69 Average uniform price with rebates $53 QFW New York (Free Flowing) Niagara $98 Toronto $97 TEC East $95 Quebec (Radial) New York (PAR Controlled) Market Operations Standing Committee 35

36 Average Off-Peak Nodal Prices Paid to Generators ( - ) Manitoba (PAR Controlled) Northwest $43 EWTE EWTW Northeast $52 Quebec (Radial) Minnesota (PAR Controlled) FS FN Bruce $56 Essa $57 Ottawa $59 Quebec (Radial) FABC CLAS CLAN FIO BLIP NBLIP FETT Michigan (Partial PAR Controlled) West $54 Average nodal price paid by load $55 Average nodal price with rebates $47 Southwest $56 Average uniform price $44 Average uniform price with rebates $41 QFW New York (Free Flowing) Niagara $57 Toronto $57 TEC East $56 Quebec (Radial) New York (PAR Controlled) Market Operations Standing Committee 36

37 Congestion and Losses Congestion Between adjacent zones Marginal Losses Relative to Richview reference bus Market Operations Standing Committee 37

38 Average Congestion and Losses ( - ) $3.42 Manitoba (PAR Controlled) Northwest $50.20 EWTE EWTW Northeast $63.24 Quebec (Radial) Minnesota (PAR Controlled) $9.62 FS FN $2.09 $7.14 $2.10 $0.95 Michigan (Partial PAR Controlled) Bruce $73.35 FABC West $72.20 BLIP NBLIP Marginal losses relative to Richview reference bus Congestion between adjacent zones and direction of flow $0.43 $1.38 $2.83 $0.73 Southwest $73.65 QFW $0.48 $1.50 $2.32 $3.50 $1.50 $0.28 New York (Free Flowing) FETT Niagara $75.63 Essa $72.47 CLAS CLAN Toronto $75.43 $2.04 $5.00 TEC $0. $1.53 Ottawa $77.96 FIO East $73.90 Quebec (Radial) $0.19 Quebec (Radial) New York (PAR Controlled) $3.87 Market Operations Standing Committee 38

39 Congestion and Losses Nodal price differences across Ontario are a function of both congestion and losses - with losses contributing more to the price differences Highest occurrence of congestion along East-West Transfer interfaces Losses are greatest between Northwest and Northeast Market Operations Standing Committee 39

40 Agenda Background Historical Nodal Pricing Analysis Summary Market Operations Standing Committee 40

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 and load Market Operations Standing Committee 41

42 Summary Average 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 study period 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 behaviour Transitional mechanisms are recommended for a change from uniform to nodal pricing Market Operations Standing Committee 42

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 curve Nodal price differences across Ontario Are due to both congestion and losses - with losses as a larger contributing factor Internal FTRs and Loss Residuals The estimated value is $150M annually Market Operations Standing Committee 43

44 Supplementary Information Explanation of Calculations Average On-Peak and Off-Peak Prices Representative Average Nodal Prices For Each Zone Market Operations Standing Committee 44

45 Total Price Paid Under Uniform Pricing HOEP + CMSC uplift + Losses uplift (- Rebates if applied) 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 (Demand - weighted) HOEP $38 2 Market Operations Standing Committee 45

46 Total Price Paid Under Nodal Pricing Nodal Price - (Rebates if applied) Nodal prices already include components of losses and congestion Rebates (if applied) - the same BPPR formula is used Nodal Price $38 2 Market Operations Standing Committee 46

47 Nodal Prices An indication of what load would pay is the Load-Weighted Average 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 be allocated back to market participants (FTRs + Loss Residuals) = (Load-Wtd Avg) - (Gen-Wtd Avg) For the purposes of this analysis, we assume that loads are allocated the internal FTRs and loss residuals Market Operations Standing Committee 47

48 Total Price Paid Under Nodal Pricing Recall that total price paid by loads under nodal pricing is Which can be expressed as Nodal Price - (Rebates if applied) (Load-Wtd Avg) - (Rebates if applied) If internal FTRs and loss residuals are allocated back to loads, the total price paid by loads under nodal pricing is (Gen-Wtd Avg) - (Rebates if applied) Market Operations Standing Committee 48

49 Ontario Generator-Weighted Average Price An indication of what generators would get paid Used in total pricing comparisons Calculated by G1P 1 + G2P G + G G i is the MW dispatched for generator i P i is the nodal price for generator i 1 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 average calculation K+ GNP K+ G On the system-wide basis, excluding the scheduled imports for this calculation has a small impact N Market Operations Standing Committee 49 N

50 Ontario Load-Weighted Average An indication of what loads would pay Calculated by L i is the energy consumed by load i P i is the nodal price for load i Cannot be calculated L P L2P L + L Do not have associated nodal price for each load point 1 Use the Ontario demand-weighted average as an estimate instead K+ L K+ L For this study, the Ontario demand-weighed average is only used in the calculation of FTRs and loss residuals N N P N Market Operations Standing Committee 50

51 Ontario Demand-Weighted Average An estimation of what loads would pay Calculated by D Z1 PZ1 D + DZ2P + D Z1 Z2 + K+ D + K+ D Z2 D Zi is the total demand in zone Zi P Zi is the representative nodal price for zone Zi Zn Zn P Zn Zone 1 Total generation = G Z1 Net flows = F Z1 Total demand, D Z1 = G Z1 + F Z1 Zone 2 Total generation = G Z2 Net flows = F Z2 Zone n Total generation = G Zn Net flows = F Zn Total demand, D Zn = G Zn + F Zn Total demand, D Z2 = G Z2 + F Z2 Market Operations Standing Committee 51

52 Approximations in Calculating the Ontario Demand Weighted Average Some flow data was not readily available to calculate the demand for each of the 10 zones Some zones were aggregated to calculate the Ontario demandweighted average From ober - March demand was aggregated into 4 zones From April - ember demand was aggregated in 8 zones Market Operations Standing Committee 52

53 Aggregation of Zones for - Mar Calculations Manitoba (PAR Controlled) Northwest Z1 EWTE EWTW Northeast Z2 Quebec (Radial) Minnesota (PAR Controlled) FS FN Bruce FABC Z3 Z4 Essa Ottawa Quebec (Radial) CLAS CLAN FIO BLIP NBLIP FETT West Southwest Toronto East Michigan (Partial PAR Controlled) QFW Niagara TEC Quebec (Radial) New York (PAR Controlled) New York (Free Flowing) Market Operations Standing Committee 53

54 Aggregation of Zones for April - Calculations Manitoba (PAR Controlled) Northwest Z1 EWTE EWTW Northeast Z2 Quebec (Radial) Minnesota (PAR Controlled) FS FN Z7 Bruce Z3 Essa Ottawa Quebec (Radial) FABC BLIP NBLIP Z5 FETT CLAS CLAN FIO Z8 West Southwest Toronto East Michigan (Partial PAR Controlled) Z4 QFW Niagara Z6 TEC Quebec (Radial) New York (PAR Controlled) New York (Free Flowing) Market Operations Standing Committee 54

55 Internal FTRs and Loss Residuals Estimated by (FTRs + Loss Residuals) = (Load-Wtd Avg) - (Gen-Wtd Avg) Since we estimate what loads pay in a zonal manner, i.e. D Z1 PZ1 D + DZ2P + D Z1 Z2 + K+ D + K+ D Z2 We shall also calculate what generators are paid in a zonal manner to estimate available internal FTRs and loss residuals, i.e. G Z1 PZ1 + GZ2P G + G Z1 Z2 Z2 Zn + K+ G + K+ G Zn Zn Zn P P Zn Zn Market Operations Standing Committee 55

56 Internal FTRs and Loss Residuals So, internal FTRs and loss residuals are estimated by (FTRs + Loss Residuals) = (Demand-Wtd Avg) - (Gen-Wtd Avg) FTRs + Loss Residuals = D Z1 PZ1 + DZ2P D + D Z1 Z2 + K+ D + K+ D Z2 Zn Zn P Zn - G Z1 PZ1 + GZ2P G + G Z1 Z2 + K+ G + K+ G Z2 Zn Zn P Zn This estimate calculated is based on available historical data Market Operations Standing Committee 56

57 Supplementary Information Explanation of Calculations Average On-Peak and Off-Peak Prices Representative Average Nodal Prices For Each Zone Market Operations Standing Committee 57

58 Average Prices Paid to Generators 160 HOEP Average - $ Gen-Wtd Avg Average - $ $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month HOEP Gen-Wtd Avg Market Operations Standing Committee 58

59 Average On-Peak Prices Paid to Generators 160 HOEP Average - $ Gen-Wtd Avg Average - $ $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month HOEP Gen-Wtd Avg Market Operations Standing Committee 59

60 Average Off-Peak Prices Paid to Generators 160 HOEP Average - $ Gen-Wtd Avg Average - $ $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month HOEP Gen-Wtd Avg Market Operations Standing Committee 60

61 Supplementary Information Explanation of Calculations Average On-Peak and Off-Peak Prices Representative Average Nodal Prices For Each Zone Market Operations Standing Committee 61

62 Northwest Average Nodal Price Paid to Generators 140 Average - $ Std Dev - $ $/M W h Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 62

63 Northwest Average Nodal Price Paid to Generators $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Atikokan Pine Portage Thunderbay Market Operations Standing Committee 63

64 Northeast Average Nodal Price Paid to Generators 140 Average - $ Std Dev - $ $/M W h Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 64

65 Northeast Average Nodal Price Paid to Generators $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Canyon Iroquois Falls Andrews Market Operations Standing Committee 65

66 Essa Average Nodal Price Paid to Generators Average - $72 Std Dev - $79 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 66

67 Toronto Average Nodal Price Paid to Generators Average - $75 Std Dev - $75 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 67

68 Ottawa Average Nodal Price Paid to Generators Average - $78 Std Dev - $66 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 68

69 Bruce Average Nodal Price Paid to Generators Average - $73 Std Dev - $67 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 69

70 Niagara Average Nodal Price Paid to Generators Average - $76 Std Dev - $79 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 70

71 West Average Nodal Price Paid to Generators Average - $72 Std Dev - $78 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 71

72 East Average Nodal Price Paid to Generators Average - $74 Std Dev - $77 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 72

73 Southwest Average Nodal Price Paid to Generators Average - $74 Std Dev - $75 $/MWh Jan Feb Mar Apr May Jun Jul Aug Sep Month Market Operations Standing Committee 73