1. February 11-12, 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. Overview of Presentation • Highlights • Problem/Concern • Background Data • Proposed Solution • Current Approach/Example • Proposed Approach /Example • Market Analysis • Summary of Impacts • RT 1st Contingency NCPC charge rates • Historical information • Next Steps

3. Highlights: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 NCPCP load deviations is less than their share of RTLO • NCPC charges for Decrements (‘DECs’) will be zero

4. Problem/Concern

5. Problem/Concern • 91% of peak-hour load generally clears in the DAEM; • Participants err on the side of under-clearing load in the DAEM • About 70% of DA/RT load deviations are negative (RT>DA) • Virtual transactions—especially Decrements – are down markedly since 2010/2011 • ISO frequently needs to commit more units in Reserve Adequacy Analysis (‘RAA’) or in Real-Time • Reduces efficiency of the unit commitment and dispatch process • Later notice can make it more challenging for generators to procure fuel--especially during winter months

6. Participants tend to under-clear load in DAEM

7. Peak-Hour RTLO under-clears in the DAEM

8. Proposed Solution

9. 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)

10. 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

11. 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.

12. 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

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

14. 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

15. Market analysis

16. 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

17. RT 1st Contingency NCPC charge rates

18. Historical Daily Averages 2012-2013

19. Next Steps

20. 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

21. Appendix A Scenario Analysis

22. 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

23. 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

24. 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

25. 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 .

26. Appendix B Additional material previously presented

27. 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

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

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

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