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April 8, 2014 | Markets Committee PowerPoint Presentation
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April 8, 2014 | Markets Committee

April 8, 2014 | Markets Committee

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April 8, 2014 | Markets Committee

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  1. April 8, 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 Proposal/Key Driver • Reallocate Charges Based on ‘Beneficiary Pays Principle’ • Proposal is Narrowly focused on Load Participants • Response to Participant Questions/Concerns • Proposed Tariff Language • Next Steps • Appendix : Material Posted at Prior MC Meetings

  3. Summary of Proposal/Key Driver • Exclude positive load deviations (DA>RT) from NCPC charges to strengthen the incentive for load (exports, load, decrements) to participate in DAEM so that more units will be committed Day-Ahead • Driver: Committing more units Day-Ahead improves reliability • Improves the ability and willingness for cleared generation to acquire/schedule fuel • Ensures operational readiness of units to meet their expected schedule • Narrow scope can be implemented before winter (2014/15) and provides better signals to market than existing cost allocation

  4. Reallocate Charges Based on ‘Beneficiary Pays’ • Allocate excluded RT 1st Contingency NCPC charges to load based their pro-rata share of Real-time Load Obligation(‘RTLO’) • Why? • All load benefits from having resources scheduled to ensure the reliable operation of the system regardless of whether load is cleared DAEM. Allocating a portion of the real time NCPC costs to RTLO is based on the ‘beneficiary pays principle’

  5. Proposal is Narrowly Focused on Load Participants Narrow scope of this solution can be implemented prior to next winter and will incrementally improve the reliability of the system relative to the current cost allocation method. Phase 1 proposes no change in how NCPC costs are allocated to any other NCPC deviations (negative load, generation, increments or import deviations) The ISO continues to work through a more comprehensive cost causation analysis related to real time NCPC and is expected to begin discussions with stakeholders late 2014/ early 2015

  6. RESPONSE TO PARTICIPANT QUESTIONS/CONCERNS

  7. Response to Participant Question/Concern: #1 • How does the Phase 1 proposal improve the incentives for a participant who is currently bidding its RTLO with 100% accuracy in the DAEM? A: With Phase 1 in place, this participant will be charged for a portion of RT 1st Contingency NCPC credits based on the ‘beneficiary pays principle.’ The participant still has an incentive to bid their RTLO in the DAEM; otherwise they will assume an added NCPC charge for negative load deviations.

  8. Response to Participant Question/Concern: #2 • Would a participant that currently clears its expected RTLO in the DAEM be worse off with this proposal? A: As shown in the following examples, participants who bid their expected RTLO into the DAEM (equal number of positive and negative load deviations) can lower their NCPC charges under the Phase 1 proposal.

  9. Example: Participants who bid expected RTLO in the DAEM can benefit from Phase 1 • Assumptions: Same as Base Case (See Slide 31) except Participant A has the same number of positive (7) and negative load deviations (-7) • Implication: RT 1st Contingency NCPC charges to Participant A are lower when their pro-rata share of positive load deviations is greater than their pro-rata share of RTLO .

  10. Example: Participants who bid expected RTLO in the DAEM can benefit from Phase 1 • Assumptions: Same as Base Case (See Slide 31) except that Participant A has a lower RTLO (60 MW), lower total NCPC deviations (6) with an equal number of positive and negative load deviations. We also further that Participant B has an equal number of positive (7) and negative load deviations (-7). • Implication: RT 1st Contingency NCPC charges to Participant A and B are lower when their pro-rata share of positive load deviations is greater than their pro-rata share of RTLO .

  11. Response to Participant Question/Concern: #3 • Several participants expressed concern that the Phase 1 proposal will cause RTLO to consistently over clear in the DAEM. A: Market forces will prevent this outcome. Phase 1 creates an incentive for participants clear their expected load in the DAEM. The proposed allocation of NCPC costs creates an incentive for individual participants to err on the side of over-clearing load in the DAEM. But the downward real-time price impact from any systematic over-clearing will curb the incentive for participants to systematically over clear load in the DAEM. The participation of virtual transactions will also prevent load from consistently over-clearing in the DAEM.

  12. Response to Participant Question/Concern: #4 • Some participants expressed concern that strengthening the incentive for load to bid in the DAEM will offset part of the expected financial gain from their strategy to purchase a portion of their RTLO in real-time • A: This is exactly the point. By strengthening the incentive to clear load in the DAEM, the Phase 1 proposal will help to improve reliability by reducing the fuel-procurement and operational challenges.

  13. Proposed Tariff Language

  14. 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

  15. 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 that would otherwise be allocated to positive Real-Time Load Obligation Deviations for a day are insteadallocated 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 (1) DARD pumping load and (2) with load from non-pumping DARDs that are following Dispatch Instructions. For purposes of this determination, • i) 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 • ii) 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. * Proposed changes based on discussion at last MC meeting are shown in red

  16. 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

  17. Appendix A Materials Presented at Previous MC Meetings

  18. Background

  19. 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

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

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

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

  23. Problem/Concern

  24. 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

  25. Participants tend to under-clear load in DAEM

  26. Real Time Load Exceeds Load Cleared in DAEM

  27. Proposed Solution

  28. 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)

  29. 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

  30. 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.

  31. 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

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

  33. 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

  34. 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

  35. Scenario Analysis

  36. 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

  37. 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

  38. 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

  39. 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 .

  40. Market analysis

  41. 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

  42. RT 1st Contingency NCPC charge rates

  43. Historical Daily Averages 2012-2013

  44. Response to Participant Questions

  45. 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

  46. 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.