Energy Payments for Demand Response Resources Dispatched in FCM – Q&A Version

1. The Demand Response Baseline – A CSP Perspective Energy Payments for Demand Response Resources Dispatched in FCM – Q&A Version Herb Healy Markets Committee, August 10-11, 2009

2. Today’s Presentation by EnerNOC • Designed to address clarification questions asked following EnerNOC’s presentation at the July 14 MC meeting • Questions are indicated on the relative charts in that presentation • Substantive changes and additions to that presentation that respond to those questions are indicated in RED • Otherwise, presentation is identical in content as July 14 version

3. Problem Statement • Under current FCM rules, active Demand Resources with a CSO that are dispatched by ISO in an FCM event do not receive energy payments • Because the PRD energy market initiative has been extended, absent this separate initiative, active Demand Response has lost its opportunity to secure energy payments for performance in the FCM come the start of the FCM in 2010

4. How Does It Work in Transition Period? • Demand Response resources that are registered, and are dispatched in reliability event, receive energy payments based on their load reduction over the event window • Payment structure: greater of RT energy price, or $500/MW-hr

5. Distinction - DALRP and FCM Energy Payments • DALRP - Economic; voluntary price response program • FCM - Capacity adequacy/ reliability; mandatory response if dispatched DALRP does provide possibility for energy payments for FCM events only if resource bids & clears in DA DALRP Events FCM Events • Exposure for FCM resources during FCM • Events • all RTEG • RTDR that does not clear in DA

6. ISO IMMU Recommendation re DR in FCM • “Product Definition And Penalties Comparable” • Except Demand Resources have no PER” • “Energy Revenues Provide An Incentive For Generation To Respond During Shortage Events” • “Recommend That DR Have An Opportunity To Earn Energy Revenues To Increase Incentives”

7. NECPUC Recommendations re DR in FCM • “…unless rules changes are made, at the end of the FCM transition period and until new approaches (either those recommended herein or others) are fully implemented, demand resources that provide capacity in the FCM will no longer receive compensation from the energy market for the value of their energy reduction. It is NECPUC’s understanding that the intent of the proposed one-year extension of the DALRP and RTLRP is to maintain the status quo until new approaches can be implemented. Consistent with this intent, NECPUC supports continuing energy market payments for demand resources that provide capacity in the FCM. That is not to say that the current energy payment regime must continue in its current form, only that some form of payments should continue until the demand response integration being considered in this process is implemented.” • NECPUC-Paper on Demand Response in; ISO Energy Mkt-06-23-2009, p.16; emphasis added

8. EnerNOC Proposal • Eligible Resources • Eligible Delivery • Energy Price • Assets with Cleared DALR Offers • Cost Allocation • Implementation • Next Steps

9. Eligible Resources • Active Demand Resources dispatched in FCM • All OP4/Action 6 or 12 events, regardless of day-of or day-ahead activation • Includes RTDR and RTEG Resources • Excludes passive Resources (On Peak and Seasonal Peak)

10. Are the energy payments based on the Asset/Resource Demand Reduction Value? I.e., would the energy paymentsinclude allowance for T&D gross-up, as will be the case for capacity payments for DR in the FCM? Eligible Delivery • Payments to be based on the load reduction dispatched by ISO-NE and actually provided.  Meaning: • Resources receive payment based on their Demand Reduction Values (DRV), not grossed up for T&D* • Consistent with DALRP which co-exists with this proposed interim approach • Resources receive payment for the lesser of dispatch instruction or actual delivered • Resources receive payment for actual energy delivered not exceeding +10% of the DRV corresponding to dispatch instructions, or the DRV for which supplemental capacity payments are paid based on the performance of the entire pool, whichever is greater. *This does not prejudice EnerNOC’s position for the correct basis for energy payments for the PRD initiative

11. Eligible Delivery For this interim payment structure, EnerNOC is not including NCPC charges for deviations surrounding FCM dispatch instructions This interim basis energy payment structure does not include the ability to bid into, clear, and set LMP prices in the DA or RT markets—it is only to secure energy payments for performance in an FCM dispatched event. EnerNOC recommends exploring the issue of NCPC charges for deviations as part of the broader PRD initiative. Will deviations exceeding ISO limitations of ± 10% from Dispatch Instructions be subject to NCPC charges? 11

12. What are the anticipated market costs associated with the EnerNOC proposal, for the interim period? Energy Price • Resources dispatched by ISO in FCM event receive RT LMP payment • Capped at the Peak Energy Rent (PER) threshold $/MWh • Lesser of RT-LMP or PER threshold, an indexed value based on a peaking unit with a 22,000 heat rate. • Preserves comparability w generators wrt PER • No minimum energy price • No threshold value for RT LMP to qualify for LMP payment. • Anticipated Earnings • $3.3 M/yr • Assumptions • 975 MW of RTDR, dispatched for 40 hrs at 33% of CSO • 875 MW of RTEG, dispatched for 4 hrs at 100% of CSO • RT LMP > PER threshold in all hrs, • PER = $200/MWh (~$9/MMBtu fuel price)

13. Energy Price The PER threshold is determined as prescribed in MR1 for FCM. That threshold will be used as the cap for energy prices paid to DR dispatched in an FCM event; i.e., DR is paid the lower of LMP or PER threshold. DR is the resource of last resort, and will MOST OFTEN be dispatched at partial resource CSO levels; as such, we will MOST OFTEN not have the opportunity to earn energy payments commensurate with our CSO. Thus, application of PER against the full CSO of each DR resource is neither fair nor comparable. No PER “cap” for DALRP energy payments during shortage hours. That would be a change to the DALRP as filed, and EnerNOC does not propose re-opening that FERC filing. Said another way, DA energy sales would not be subject to the PER threshold. Note—there is no RT opportunity without a DA commitment in the DALRP How is PER applied? Does the PER threshold only apply to energy reductions during DR FCM events; i.e., during periods that DR is dispatched in an FCM DR event, or will PER threshold apply to FCM DR assets performing in RT shortage hours due to a DALRP commitment? 13

14. Assets with Cleared DALR Offers • Consistent with current settlement structure, if an asset is dispatched in an FCM event coincident with a DALRP cleared obligation, it would receive RT LMP for only that portion of energy delivered in the FCM event that exceeds its cleared obligation in the DALRP • Ex: an asset has a DRV of 500 kW;  if asset clears a 200 kW DA obligation, and on day-of, the ISO dispatches the resource at 100%, then the first 200 kW reduction is paid at DA cleared price (DA LMP), and the remainder of the reduction is paid RT LMP.

15. Cost Allocation • LMP payment is an uplift to Real Time Load Obligation (RTLO) • Prorate across all load, based on the whole day RTLO share • This is a change in position from previous EnerNOC position – why the change? • EnerNOC recognizes the issue of appropriating costs fairly • EnerNOC believes that bifurcation of LMP costs may be most fair allocation on long term basis • E.g., LMP-G to host LSE, and G prorated to RTLO • Issue is to be vetted in the PRD initiative • As an interim approach, timing is key, and simplicity/ practicality in overall payment design trumps perfection

16. Approach to Implementation • Implement as an interim measure, while the broader PRD energy market initiative is decided and implemented • EnerNOC’s FCM energy payment structure consistent with the PRD supply-side approach • Can be implemented without prejudice to outstanding issues of PRD initiative • Implement by June, 2010 • Significantly reduced effort as compared to implementation of PRD supply-side approach • Proposing energy payments for FCM events only; not bidding and clearing in DA or RT market • No change to dispatching of DR resources • Performance in FCM events will already be tracked and assessed; no to little new effort • Settlement is only new wrinkle • Interim treatment while awaiting longer-term PRD supply-side implementation is practical approach • EnerNOC recognizes it is preferable not to create interim measures • But can’t wait to reach consensus on the PRD Design Basis Document

17. Next Steps Premise • This energy payments initiative for FCM DR resources dispatched in FCM events, AND the broader PRD initiative to continue to be in Markets Committee domain • Per position of FCMWG from July 30 meeting Next Steps • EnerNOC will consider any new clarification questions/ issues and guidance from Market Participants during today’s review • Pending above, EnerNOC will proffer red-lined Market Rule changes for Sept 8 MC meeting • EnerNOC supports from NEPOOL Counsel to draft changes

19. Backup Materials

20. What is the meaning of G? What is meant by the Host LSE? Cost Allocation - Background • G is the cost of generation included in the DR customer’s retail rate • The host LSE is the market participant responsible for the Load Asset in the ISO-NE wholesale market that includes the DR customer’s load; i.e., the entity whose Ownership Share of the Load Asset includes the DR customer’s load, per definitions in the MR1 and manuals. It is not to be confused with the Host Utility, nor the Host Participant as defined in the MR1. • Example A: Supplier X has a bilateral contract with a DR customer to provide commodity, which is a pass-through on the customer’s bill from his local distribution utility (i.e., LDC). Supplier X is the host LSE for the DR customer. • Example B: Supplier Y is providing commodity to meet the needs of LDC’s Basic Service customers, one of whom is a DR customer. Supplier Y is the host LSE for the DR customer.

21. How is the host LSE held harmless if it is allocated the portion of the cost equal to LMP - G? Cost Allocation Scenario: Customer X has 1 MW of price-responsive load reduction LSE A is Asset Load owner for Customer X in ISO energy wholesale market Assume: --RT LMP = $80/MWh --Customer X retail rate for supply (G) = $60/MWh LSEA: Pays market (LMP-G) $20 Loses customer revenue (G) $60 Total cost $80 If LSEA is long: Sells 1 MWh @ LMP $80 revenue If LSEA is short: Avoids procurement of 1 MWh @ LMP ($80) avoided expense ISO $20 (=LMP-G) $20 (=LMP-G) LSEA Customer X ($60) (=Lost revenue to LSEA from Customer X) Host LSE held harmless by DR Participation 21