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March 12-13, 2014 | Markets Committee

March 12-13, 2014 | Markets Committee. Catherine McDonough . cmcdonough@iso-ne.com | 413-535-4027. Strengthen Incentive for Load to participate in the Day-Ahead Energy Market(‘DAEM’). NCPC Cost Allocation: Phase 1 . Outline . Summary of Problem/Concern Summary of Proposed Action

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March 12-13, 2014 | Markets Committee

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  1. March 12-13, 2014 | Markets Committee Catherine McDonough cmcdonough@iso-ne.com | 413-535-4027 Strengthen Incentive for Load to participate in the Day-Ahead Energy Market(‘DAEM’) NCPC Cost Allocation: Phase 1

  2. Outline • Summary of Problem/Concern • Summary of Proposed Action • Expected Benefits of NCPC Cost Allocation Phase 1 • Response to Participant Questions • Proposed Tariff Language • Next Steps • Appendix : Material Already Posted at Prior MC Meetings

  3. Summary of Problem/Concern • Real-time Load Obligation (‘RTLO’) is generally greater than the amount of load cleared in the DAEM • 91% of peak-hour real-time load generally clears in the DAEM • About 70% of DA/RT load deviations are negative (RT>DA) • Virtual transactions--especially Decrements – down since 2010/2011 • ISO frequently needs to commit more units in Resource Adequacy Analysis (‘RAA’) or in Real Time to meet load that does not clear in the DAEM • Reduces efficiency of the unit commitment and dispatch process • Later notice can make it more challenging for generators to start and to procure fuel-especially during winter months—which reduces the time available for ISO System Operators to devise alternative plan

  4. Proposed Action: NCPC Cost Allocation Phase 1 • Allocate RT 1st Contingency NCPC charges associated with positive real-time load deviations (RT< DA) to participants based on their real-time load obligation (‘RTLO’) • No change in how RT 1st Contingency NCPC charges are allocated to negative load deviations or to other NCPC deviations • No change in how NCPC deviations are calculated • RTLO excludes DARD pumping load & load from non-pumping DARDs that follow dispatch Note: Broader changes to NCPC Cost Allocation method may be proposed as part of Phase 2 (discussions to begin 2015)

  5. Expected Benefits of Phase 1 • Strengthen incentive for load (exports, load, decrements) to participate in DAEM so that more load clears DAEM • Raise efficiency and timeliness of unit commitment • Reduce challenges associated with procuring gas and starting units in real time. • Allow more time for operators to identify & re-solve issues • Improve real-time price formation/lower NCPC costs • Complements other changes the ISO has proposed • Can be in place before winter (2014/15)

  6. Response to Participant Questions • What percent of load bids do not clear in the DAEM? A: Less than 1-2% on average of price sensitive and fixed price load bids (excluding decrement bids) do not clear in the DAEM • Why not measure DA/RT load deviations relative to DAEM “bid-in” instead of “cleared load” to not penalize participants who bid expected load in the DAEM using price-sensitive load bids? A: 1) Not really an issue since less than 1-2% of load bids do not clear. 2) Changing the definition of a load deviation in this way creates an incentive for participants to submit zero-price load bids in the DAEM. This would not increase the percent of RTLO that clears in the DAEM

  7. Response to Participant Questions (continued) • Could the under-bidding of RTLO in the DAEM be due to the ISO’s load forecast? A: The ISO’s daily peak load forecast posted prior to close of the DAEM bidding window is slightly above 100% on average, • Is it optional for participants to bid load in the DAEM ? A: Yes. The ISO simply wants to strengthen the incentive for participants to exercise this option because it helps to lower system costs and improve reliability with the new energy mix that characterizes the current generation fleet.

  8. Proposed Tariff Language • III.F.3.1.2 * • (g)All remaining NCPC costs for the Real-Time Energy Market are allocated and charged to Market Participants based on their pro rata daily share of the sum of the absolute values of a Market Participant’s (i) Real-Time Load Obligation Deviations in MWhs during that Operating Day, subject to the additional charge requirement specified in (h) below; (ii) generation deviations for Pool-Scheduled Resources not following Dispatch Instructions, Self-Scheduled Resources with dispatch able increments above their Self-Scheduled amounts not following Dispatch Instructions, and Self-Scheduled Resources not following their Day-Ahead Self-Scheduled amounts other than those Self-Scheduled Resources that are following Dispatch Instructions, including External Resources, in MWhs during the Operating Day; and (iii) deviations from the Day-Ahead Energy Market for External Transaction purchases in MWhs during the Operating Day. The Real-Time deviations calculation is specified in greater detail in Section III.F.3.2. * Proposed changes to implement Phase 1 shown in blue on top of the revised tariff language that clarifies the existing method to allocate NCPC Costs

  9. Proposed Tariff Language (continued) • III.F.3.1.2 • (h) Of the NCPC costs allocated to Real-Time Load Obligation Deviations under (g) above, the total NCPC costs for the Real-Time Energy Market associated with positive Real-Time Load Obligation Deviations for a day are allocated and charged to Market Participants based on their pro-rata share of Real-Time Load Obligation for the day, excluding Real-Time Load Obligation associated with Dispatch able Asset Related Demand Resource operation that are following Dispatch Instructions. For purposes of this determination, • a) the positive Real-Time Load Obligation Deviation for a day is equal to the sum of the positive hourly Real-Time Load Obligation Deviations in the day; and • b) Real-Time Load Obligation Deviation is positive in an hour if the Day-Ahead Load Obligation over all Locations in the hour is greater than the Real-Time Load Obligation over all Locations in the hour.

  10. Proposal Summary and Next Steps Exclude positive load deviations from NCPC charges to strengthen the incentive for load to participate in the day-ahead energy market Proposed changes targeted for implementation with Offer Flexibility Changes in Q4 2014

  11. Appendix A Materials Already Presented at Previous MC Meetings

  12. Background

  13. Current Allocation Approach for RT NCPC Costs NCPC credits are paid when real time energy market revenue is not sufficient to recover the cost associated with an accepted supply offer • * For more detailed description of how these costs are allocated reference Schedule 2 of the OATT

  14. Historical Allocation of Real-Time NCPC Costs • All values in Millions $ • * Includes data from January through October 2013

  15. Real-time NCPC Deviations Used to Allocate real-time 1st Contingency NCPC Costs

  16. Historical Allocation of Real-time 1st Contingency NCPC costs • All values in Millions $ • * Includes data from January through October 2013

  17. Problem/Concern

  18. Summary of Problem/Concern • Real-time Load Obligation (‘RTLO’) is generally greater than the amount of load cleared in the DAEM • 91% of peak-hour real-time load generally clears in the DAEM • About 70% of DA/RT load deviations are negative (RT>DA) • Virtual transactions--especially Decrements – down since 2010/2011 • ISO frequently needs to commit more units in Resource Adequacy Analysis (‘RAA’) or in Real Time to meet load that does not clear in the DAEM • Reduces efficiency of the unit commitment and dispatch process • Later notice can make it more challenging for generators to start and to procure fuel-especially during winter months—which reduces the time available for ISO System Operators to devise alternative plan

  19. Participants tend to under-clear load in DAEM

  20. Real Time Load Exceeds Load Cleared in DAEM

  21. Proposed Solution

  22. Proposed Solution: Modify NCPC Cost Allocation Phase 1 • Allocate RT 1st Contingency NCPC charges associated with positive real-time load deviations to participants based on their real-time load obligation (‘RTLO’)* • No change in how we allocate RT 1st Contingency NCPC charges to negative load deviations or other NCPC deviations • No change in how we calculate NCPC deviations • RTLO excludes DARD pumping load & load from non-pumping DARDs that follow dispatch • Expected Benefits • Stronger incentive for load (exports, load, decrements) to participate in DAEM • Addresses concerns regarding the reduction in virtual transactions • Complements other changes the ISO has proposed • Can be in place for Winter (2014/15) • Comprehensive review of the current method used to allocate NCPC costs may result in broader set of changes in Phase 2 (discussions to begin in 2015)

  23. RT 1st Contingency NCPC Cost Allocation Current Method • NCPC deviation charge rate (daily) = RT 1st Contingency NCPC charges (daily) / Total NCPC deviations (daily) • RT 1st Contingency NCPC charges (participant, daily) = NCPC deviation charge rate (daily) x NCPC deviations (participant, daily) Note: All NCPC deviations are charged the same ($/MW) rate

  24. Example : Current MethodBase Case * *Base Case assumes that all Load Participants have the same load deviations and RTLO MWs. We relax these assumptions in the examples shown in the Appendix A.

  25. RT 1st Contingency NCPC Cost Allocation Proposed Method (Phase 1) • RT 1st Contingency NCPC charges (participant, daily) = NCPC deviation charge rate (daily) x NCPC deviations (participant, daily) except positive NCPC load deviations (DA>RT) 2. Total RT 1st Contingency NCPC charges for RTLO =NCPC deviation charge rate (daily) x positive NCPC load deviations (daily) 3.NCPC load charge rate (daily)=Total RT 1st Contingency NCPC charges for RTLO/ Total RTLO • RT 1st Contingency NCPC load charge (participant, daily) = NCPC load charge rate (daily) x RTLO (participant, daily) *Parts of the allocation method that change with the Phase 1 proposal shown in blue

  26. Example: Proposed Method (Phase 1)Base Case NCPC deviation charge rate is the same as w/ current method: See Slide 8

  27. Example: Proposed vs. Current Method Participants whose pro-rata share of positive load deviations > pro-rata share of RTLO allocated less RT 1st Contingency NCPC charges Participants whose pro-rata share of positive load deviations < pro-rata share of RTLO allocated more RT 1st Contingency NCPC charges Impact of Phase 1 change is smaller when the difference between pro-rata shares of (+) load deviations and RTLO is smaller

  28. Summary:What does the Phase 1 Proposal change? • No change in the way Generators, Imports, Increments and Negative NCPC load deviations are charged for NCPC • Reallocates ~20% of RT 1st Contingency NCPC charges to RTLO instead of positive NCPC load deviations (DA>RT) • NCPC charges will be lower for participants whose pro-rata share of positive NCPC load deviations is greater than their share of RTLO • NCPC charges will be higher for participants whose pro-rata share of positive NCPC load deviations is less than their share of RTLO • NCPC charges for Decrements (‘DECs’) will be zero

  29. Scenario Analysis

  30. Case 1*: Neutral impact on Participants whose pro-rata share of (+) load deviations = pro-rata share of RTLO *Assumptions: Same as Base Case except Participant 3 has lower RTLO (115 vs. 130 MW ) Implication: Pro-rata share of positive load deviations = pro-rata share of RTLO for participant C; Phase 1 has no impact on RT 1st Contingency Charges for Participant C

  31. Case 2*: Decrements will have zero NCPC charges *Assumptions: Same as Base Case except Participant 3 is a cleared virtual demand bid (DEC) for 1 MW; positive load deviation = 1 MW and RTLO = 0 Implication: Participant 3 has no RT 1st Contingency NCPC charges

  32. Case 3*:Share of NCPC charges allocated to RTLO rises w/share of positive load deviations • Assumptions: Same as Base Case except Participant C has lower RTLO (115 vs. 130 MW ) and NCPC load deviations for all participants are positive • Implication: RT 1st Contingency NCPC Charges allocated based entirely on RTLO; Participants A and B pay more and Participant C pays less

  33. Case 4*: Reducing negative load deviations alone may not reduce RT 1st Contingency NCPC charges • Assumptions: Same as Base Case except Participant C has no negative load deviations ; Participant C’s load deviations = 4 instead of 14. • Implication: RT 1st Contingency NCPC charges to Participant C are higher because the pro-rata share of positive load deviations is less than their pro-rata share of RTLO .

  34. Market analysis

  35. Summary of Impacts • No change in RT 1st Contingency NCPC deviation charge rate; generators, Imports, Increments and negative NCPC load deviations will be charged the same as today • Phase 1 reallocates ~20% of RT 1st Contingency NCPC charges to RTLO instead of to positive load deviations; If positive load deviations rise over time, the share of RT 1st Contingency NCPC charges allocated to RTLO will also rise • RT 1st Contingency NCPC charges will be lower for participants whose pro-rata share of positive load deviations is greater than their pro-rata share of RTLO • RT 1st Contingency charges for Decrements (‘DECs’) will be zero because DECs create only positive load deviations and have no associated RTLO • Participants may be able to reduce RT 1st Contingency NCPC charges by bidding their expected load in the DAEM; i.e. increase the share of positive load deviations

  36. RT 1st Contingency NCPC charge rates

  37. Historical Daily Averages 2012-2013

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