May 6-7, 2014| mc meeting

1. May 6-7, 2014| mc meeting Henry Yoshimura Christopher Parent Email: hyoshimura @iso-ne.com cparent @iso-ne.com Demand Response Model, Baseline & Measurement, Energy Market Full Integration of Demand Response Resources into the Energy and Reserves Markets

2. Full Integration of Demand Response Resources into Energy and Reserve Markets • The ISO plans to fully integrate Demand Response Resources into the energy and reserve markets on June 1, 2017 • The proposed market design is generally consistent with the September 26th, 2013 whitepaper describing how Demand Response Resources will be able to provide Real-Time Reserves and participate in the Forward Reserve Market • Project schedule and scope was introduced at the April 2014 Markets Committee meeting • The plan is the have the market rules voted upon by the Markets Committee in September 2014 so that the rules are in place before February 2015 (i.e., FCA 9)

3. Two major design changes were required to allow demand response to provide reserves • Establishing a common dispatch model for demand response that does not require a separate generation asset to model Net Supply in the energy market • This change provides the “platform” which will allow reserves to properly be accounted on demand response. • This change will require conforming changes to the Forward Capacity Market, Energy Market and Baseline rules for demand response • Establishing rules for how demand response provides reserves • These changes establish the rules for how demand response will provide reserves in real-time and participate in the Forward Reserve Market • These changes will require changes to the Forward Capacity Market rules for demand response as well

4. Today’s discussion is focused on the Energy Market, Real-Time Reserves and Baseline & Measurement • The focus of the discussion today will be on the Demand Response Model, Baseline and Measurement and Energy Market and Real-Time Reserves • The Forward Reserve Market, Forward Capacity Market and reserve auditing rule changes will be discussed at subsequent meetings • All changes discussed with the stakeholders will be tied back to the two major design drivers: • Common Dispatch Model • Common Dispatch Model Overview • Effect on Day-Ahead & Real-Time Energy Market Settlement • Adding Capability to Provide Reserves • Dispatch Zone/Reserve Zone Registration Rule • Additional Reserve Related Offer Parameters • Consumption Forecast • Real-Time Reserve Designation and Settlement • Telemetry Requirements for 10-minute reserves

5. Common Dispatch Model Common Dispatch Model Overview Effect on Day-Ahead & Real-Time Energy Market Settlement

6. Net Supply Generator Model in the Current Rules • A single facility that can reduce demand and provide Net Supply at the same Retail Delivery Point (RDP) is modeled as two assets: a Demand Response Asset (DRA) and a Net Supply Generator Asset (NSGA) • Total energy provided is 7 MW (5 MW demand reduction, 2 MW of Net Supply) • To produce Net Supply, the demand at the facility must be reduced first

7. Issues with the Net Supply Generator Model • The NSGA is available to provide energy only after the demand has been reduced on the DRA • If offered as separate 30-minute resources, the DRA and NSGA may each be designated to provide TMOR • However, if the DRA takes 30 minutes to produce demand reduction, the NSGA cannot produce its Net Supply within the same 30 minutes • Since there is no mechanism enforce the dependency between the DRA and NSGA, the TMOR provided by this facility is overestimated • Even if priced above the DRA, there is a possibility that the NSGA would be dispatched before the DRA • The dispatch solution co-optimizes energy and reserves subject to security constraints, not the dependency between the DRA and NSGA • To avoid this outcome, the NSGA would need to be declared unavailable until the DRA had been dispatched • If unavailable, however, the NSGA cannot provide reserves

8. Common Dispatch Model recognizes the dependency between the Net Supply & Demand Reduction • Common dispatch model more accurately accounts for energy and reserves, and is simpler to administer • Requires only a single asset (a DRA) at the RDP to model both consumption and Net Supply • The Demand Reduction Offer will cover the entire range of demand reduction and Net Supply produced by the facility

9. Effect on Day-Ahead & Real-Time Energy Market Settlement

10. Implications on the Application of Distribution Losses in the Energy Market • Demand Reduction Offers do not specify the amount of Net Supply that would be provided if the DRR is dispatched • Avoided distribution losses would be applied to demand reductions when determining the performance of a DRR; however, avoided distribution losses would not be applied to Net Supply • Market Participants must account for the difference in the treatment of distribution losses between demand reductions and Net Supply when formulating their Demand Reduction Offers

11. Day-Ahead Energy Market Day-Ahead Settlement Payment: DAMScheduled X LMPDA x (1 + AADLoss) Where: LMPDA is Day-Ahead LMP at Dispatch Zone or Node, and AADLoss is Average Avoided Distribution Loss • ISO cannot readily determine the amount of Net Supply included in any particular Price/Quantity pair of a Demand Reduction Offer • All cleared offers will be treated as a demand reduction

12. Real-Time Energy Market [(RTEMReduction Delivered X (1 + AADLoss) + RTEMNet Supply ) – (DAMScheduled X (1 + AADLoss)] X LMPRT Where: LMPRT is RTEM LMP at Dispatch Zone or Node, and AADLoss is Average Avoided Distribution Loss • If DAM scheduled for the hour > energy delivered in RTEM, then the DRR is charged the difference at LMPRT • If DAM scheduled for the hour ≤ energy delivered in RTEM, then the DRR is paid the difference at LMPRT • Settlement includes gross-up for avoided losses on demand reductions but not on Net Supply

13. Providing reserves Dispatch Zone/Reserve Zone Registration Rule Additional Reserve Related Offer Parameters Consumption Forecast Real-Time Reserve Designation and Settlement Telemetry Requirements for 10-minute reserves

14. Additional Registration Rules are Required for Proper Accounting of Local Reserves • Most DRRs are aggregations of assets within a Dispatch Zone • Because the current Dispatch Zones and Reserve Zones do not align in all cases, it is possible for a Dispatch Zone to span more than one Reserve Zone • e.g., the Western CT Dispatch Zone spans SWCT & CT Reserve Zones. • To resolve potential mismatches between Dispatch Zones and Reserve Zones, a DRR (and all of its assets) must be registered in the same Dispatch Zone and Reserve Zone • This will allow Demand Response Resources to have their reserves properly counted to meet the Reserve Zone requirements

15. Additional Reserve Related Offer Parameters

16. Current Parameters of DRR Demand Reduction Offers * Different values can be offered for each hour.

17. Additional Demand Reduction Offer parameters are required for demand response to provide reserves • Both of these parameters can be offered hourly into the Day-Ahead Energy Market and redeclared hourly throughout the operating day

18. Consumption Forecast

19. Need for a Real-Time Consumption Forecast • To allow DRRs to provide reserves, a better short-term forecast of a DRR’s energy consumption in real-time is needed • To determine reserve sufficiency, the ISO forecasts throughout the Operating Day the availability of resources to provide additional energy within 10- or 30-minutes • To accurately forecast the amount of reserves available from a DRR, the ISO needs to adjust a DRR’s forecast consumption to better reflect its actual consumption throughout the Operating Day • The present method for adjusting the Demand Response Baseline is: • Once a day, only when the DRR is dispatched, and after the Operating Day is over, which is inadequate for reserve designation purposes

20. Concept for a Real-Time Consumption Forecast Adjustment • To forecast a DRR’s ability to provide reserves in real time and to determine its real-time performance in response to a Dispatch Instruction, its consumption would be forecasted using historical interval meter data and adjusted throughout the Operating Day using 5-minute real-time telemetry data: • The initial estimated consumption forecast would be computed using the method presently in Section III.8B for the Demand Response Baseline • Real-time telemetry data received during the Operating Day would be used to adjust the consumption forecast at various points throughout the Operating Day • The adjustment procedure would be performed more frequently and would be based on telemetry data from intervals closer to real time

21. Factors for a Real-Time Forecast Adjustment Dispatch Day Duration is how many intervals are used in the adjustment Proximity is how close to “Now” is the last interval that will be used in the adjustment NOW “NOW” is when the calculation is to be performed to forecast future consumption • Proximity: the first historical interval from the time of the calculation that will be used in the adjustment. A shorter proximity means that more recent data is used in the calculation. The current method has a 30-minute proximity – the adjustment is calculated using data from intervals that end 30 minutes in advance of the calculation. • Frequency: the number of times during the Operating Day the adjustment is computed. The current methodology is once a day, and only if the DRR is dispatched by the ISO (and is done after the Operating Day). • Duration: the number of intervals over which calculated baseline and real-time telemetry load are compared to determine the adjustment. The current method has a two hour (24 five-minute intervals) duration

22. Analysis of Real-Time Forecast Adjustment • ISO engaged DNV GL (aka KEMA) to assist in analyzing accuracy of the resulting adjusted forecasts for different adjustment factors • DNV GL analyzed the accuracy of different combinations of proximities and durations (including the current ISO adjustment method) • Proximities of 3 to 7 intervals • Duration of 3 to 24 intervals • Adjusted forecasts were analyzed for each day type (non-holiday weekdays, Saturdays, and Sunday/Holidays)

23. Real-Time Forecast Adjustment Method • The calculated adjustment is added to the forecast (which could increase or decrease the forecast) in future intervals to provide an estimate of expected consumption • Notification, startup and interruption intervals are excluded from the calculation. During these intervals, the most recent adjustment, calculated prior to the notification period, is added to the forecast • Following the end of an interruption, the scheduled adjustment recalculations resume

24. Real-Time Forecast Adjustment Method (cont.) • Generally, the results of the DNV GL analysis showed real-time adjustments perform better than the current ISO adjustment when: • Proximity is closer and duration is shorter, and • The adjustment is recalculated frequently throughout the Operating Day rather than only once a day • In addition to the results of the DNV GL analysis, the ISO considered data latency, calculation time, and how quickly information must be available to provide adequate situational awareness in developing a proposal • The ISO is recommending a real-time forecast adjustment with a proximity of 3 intervals, a duration of 3 intervals, which is scheduled to be calculated and applied at a frequency of every 15 minutes* * The adjustment calculation is not performed during notification, startup and interruption intervals and data from such intervals are not included in the adjustment calculation.

25. Real-Time Reserve Designation and Settlement

26. Demand Response Resources have similar states to generators • The table below outlines how the generator concepts of on-line and off-line are equivalent to Demand Response Resource concepts

27. Demand Response Resources, similar to generation, can also be considered fast start • To be a Fast Start Resource, the ISO must meet the following criteria: • Minimum Reduction Time does not exceed one hour; • Minimum Time Between Reductions does not exceed one hour; • Demand Response Resource Start-Up Time plus Demand Response Resource Notification Time does not exceed 30 minutes; • Personnel available to respond to dispatch or has automatic remote interruption capability; • Is dispatched using a CFE connected RTU to the DDE; and • Has satisfied its Minimum Time Between Reductions.

28. DRR are able to be designated for ten-minute and thirty minute reserves in real-time • For a DRR to be designated to provide TMSR, it must: • Not have any dispatchable behind-the-meter generators (excluding RTEGs) and; • Be committed and received a Dispatch Instruction to reduce demand between its Minimum Reduction and Maximum Reduction, or • Not be committed, meet the fast start criteria and have an audited and offered Claim 10 • For a DRR to be designated to provide TMNSR, it must: • Have a dispatchable behind-the-meter generators (excluding RTEGs) and; • Not be committed, meet the fast start criteria and have an audited and offered Claim 10, or • Be committed and received a Dispatch Instruction to reduce demand between its Minimum Reduction and Maximum Reduction • For a DRR to be designated to provide TMOR, it must have capability beyond what has been designated as ten-minute reserves and either: • Be committed and received a Dispatch Instruction to reduce demand between its Minimum Reduction and Maximum Reduction, or • Not be committed, meet the fast start criteria and have an audited and offered Claim30

29. Amount of reserves designated is constrained based upon what the DRR is capable of delivering • The forecasted consumption, audited Claim 10/Claim 30, Maximum Reduction, offered Claim 10/30, Demand Response Resource Ramp Rate all constrain the amount of reserves that can be designated in real-time • For DRR that are committed and receiving a Dispatch Instruction, the amount of reserves that can be designated is further constrained based upon where the resource is being dispatched for energy

30. Conceptual Reserve Example 1 • For the DRR that is not committed • Assume no Net Supply • Recall that offer parameters should not include Average Avoided Distribution Loss (AADLoss) • AADLoss adjustment is performed within dispatch software TMORDESIGNATED = MIN (Maximum Reduction , Claim30) X (1 + AADLoss) SETTLEMENT: TMORDESIGNATED X RTRCP Where: RTRCP is Real-Time Reserve Clearing Price

31. Conceptual Reserve Example 1 (cont.) • G1 is dispatched to meet all 80 MW of system load; its remaining capacity is available to provide reserves • Reserves exceed 35 MW requirement: • Fast DR designated for 26.63 MW (25 MW plus 6.5% avoided losses) • G1 is designated for 20 MW • No resource is re-dispatched to provide reserves, so opportunity cost of re-dispatch = RTRCP = $0

32. Conceptual Reserve Example 2 • For the DRR that is committed and dispatched • Assume no Net Supply • Recall that offer parameters should not include AADLoss • AADLoss adjustment is performed within dispatch software TMORDESIGNATED = MIN ( Maximum Reduction – Dispatch, Ramp Rate X 30 Minutes) X (1 + AADLoss) Where: Dispatch is the expected level of reduction SETTLEMENT: TMORDESIGNATED X RTRCP Where: RTRCP is Real-Time Reserve Clearing Price

33. Conceptual Reserve Example 2 (cont.) • If G1 is fully dispatched for energy, the reserve requirement would not be met: • Fast DR designated for 26.63 MW (25 MW plus 6.5% avoided losses) • G1 must be re-dispatched to provide the remaining requirement of 8.37 MW • G1 dispatched for 91.63 MW • Fast DR dispatched for 18.37 MW • Opportunity cost to G1 of re-dispatch = RTRCP = $150(LMP) - $90(offer) = $60

34. Telemetry Requirements for DRR providing 10-minute reserves

35. Demand response in the energy market is required to provide at least five-minute real-time telemetry • Assets associated with DRRs participating in the energy market are required to provide at least five-minute real-time telemetry • Five-minute telemetry is sufficient to determine the real-time performance and availability of a resources providing 30-minute reserves that has been activated to deliver energy

36. There is latency in five-minute telemetry due to the lag time between the end of the interval and retrieval of the data • The latency in five-minute telemetry is due to the lag time between the end of the interval and retrieval of the telemetry data

37. 5-minute telemetry does not provide adequate information for resources providing 10-minute reserves • At the time of a reportable event, the ISO has 15 minutes from the start of that event to recover area control error (“ACE”) and avoid a NERC violation • System operators must know as soon as possible if resources providing a ten-minute reserves have responded to a Dispatch Instruction when activated • If a resource does not deliver the dispatched amount of energy within 10 minutes, operations must determine whether it is necessary to dispatch another resource to recover ACE and avoid a NERC violation

38. Example: Using 5-minute data to measure 10-minute reserve performance is not adequate • At 14:12 a single interval of five-minute telemetry is available from which to calculate the DRR’s performance in the minutes since dispatch ACE must be recovered by this time

39. Example: Using 5-minute data to measure 10-minute reserve performance is not adequate • The real-time performance and capability of a DRR providing 10-minute reserves and reporting only five-minute data will be measured based on a single five-minute interval showing performance 3 minutes into the event • This is unlikely to reflect the actual performance of the DRR at the end of ten minutes • Additionally, in order to be eligible to provide reserves from a not committed state, a resource must establish its capability to provide 10- or 30-minute reserves through an audit which requires similar information to measuring the performance after a dispatch

40. More granular data is required from Demand Response Resources providing 10-minute reserves • In order to provide adequate information to measure the real-time performance and capability of DRRs providing 10-minute reserves, the ISO is recommending that these resources provide at least one-minute real-time telemetry • The MW values reported by the DDE could be instantaneous power measurement or an average power value determined from an energy measurement for the one-minute interval • Real-time telemetry at a one-minute or better granularity will be used to determine the real-time performance for audits and energy dispatch of 10-minute reserve capability • Energy settlement will continue to use five-minute revenue quality meter data

41. PROJECT SCHEDULE

42. Upcoming Schedule and Topics • June 2014: • Continue discussion on (1) Demand Response Model, (2) Baseline & Measurement, and (3) Energy Market & Real-time Reserves • Present market design changes for: (4) Forward Reserve Market • Reliability Committee: Claim10 and Claim30 Audits • July 2014: • Continue discussion on prior topics as needed • Present market design changes for: (5) Forward Capacity Market • Reliability Committee: Claim10 and Claim30 Audits • August 2014: • Review complete market rule changes • September 2014: • Vote at Reliability Committee • Vote at Markets Committee