1. Demand Resources: Challenges and New Initiatives for ISO New England Henry Yoshimura, ISO New England NEW DEMAND RESPONSE PRODUCTS IN ELECTRICITY MARKETS Cornell University January 17, 2011

2. Demand Resources in New England Overall Goal: –Integrate Demand Resources into capacity, energy, and ancillary services markets in an efficient manner Today: –Demand Resources can sell load reduction capability in the Forward Capacity Market and receive payments comparable to generation resources About 2,300 MW of Demand Resources in FCM today Almost 3,300 MW of Demand Resources expected by 2013 –ISO-NE has invested in metering and communication infrastructure to integrate demand response resource information into the systems that monitor the electricity grid and dispatches resources –Opportunities for customers to purchase electricity at wholesale energy prices and participate in Ancillary Services Markets 2

3. Demand Resources Growing in New England FCM  2010/11–2013/14: Total DR cleared in FCAs 1–4 (New and Existing); Real-Time Emergency Generation capped at 600 MW. Enrollment in ISO programs prior to start of FCM 3

4. Challenges to the Integration of Demand Resources into Wholesale Markets Competing business models –A supply of generation –A consumer of generation Economic issues –Compensation and price formation –Baseline –Cost allocation Structural issues –Legal issues – conflicts in policy and jurisdiction –Lack of linkage between retail rates and wholesale prices –Lack of advanced metering infrastructure in the retail space –Lack of enabling technology DRAFT 4

5. Achieving Price Responsive Demand Through Dynamic Retail Pricing Price-Responsive Demand (PRD) means customers change their electricity use in response to time-varying wholesale prices Over time, PRD: –Improves economic efficiency of wholesale market –Lowers average prices and total customer bills –Promotes customer choice –Stimulates investment in smart grid technologies such as advanced metering, load control, load shifting, and energy storage technologies 5

6. AMI Penetration by Region as of 2008 New England States included in NPCC *From Graph II-3, “FERC 2008 Assessment of Demand Response and Advanced Metering.” Includes US data only. 6

7. Efforts to Integrate Demand Resources into the Energy and Ancillary Services Markets October 2008, ISO started a region-wide stakeholder process to determine the best way to encourage more Price- Responsive Demand (PRD) in the Energy Market –Over the past 2 years there have been many stakeholder meetings on this topic –Strong disagreement expressed on the issue of compensation Demand response: is it supply or demand? March 2010, FERC issued Notice of Proposed Rule Making –FERC’s goal is to establish a national policy on the appropriate payment rate for demand response participating in energy markets –Final order pending 7

8. FERC NOPR on Demand Response Compensation, March 2010 The FERC proposed that demand response reducing electricity consumption from expected levels in response to price signals should be paid, in all hours, the market price for energy – i.e., the full LMP – for such reductions This raises a host of issues: –Economic efficiency –Competitive/comparability issues –Legal (entitlement) –Baseline estimation –Cost allocation Does not fully reward economic load shifting (e.g., energy storage) or off-peak usage (e.g., plug-in electric vehicles) © 2010 ISO New England Inc. 8

9. New Initiatives: Revising the Capacity Cost Allocation Method

10. Present Capacity Cost Allocation Method Market Participants pay the cost associated with the Installed Capacity Requirement (“ICR”) based on their share of total consumption in the single hour of the annual system coincident peak from the previous year –System peak only known after the fact –Difficult to make the case for retail products that promote PRD Analysis by the ISO shows that reducing loads in just the peak hour has little effect on ICR –Poor linkage between consumption and cost ICR is a function of LOLPs across many hours, which is a function of the peak load forecast distribution and expected supply availability 10

11. Findings From Analyses Conducted by the ISO Reducing daily peaks in the eight-week period during the months of July and August has the greatest impact on ICR –More recent analysis by the ISO in response to feedback showed that the impact of reducing peak loads on the 15 highest load days in July and August was largely the same as reducing peak loads on all business days in July and August Reduced consumption during a six-hour period between 12:00 and 18:00 on summer non-holiday weekday afternoons has the greatest impact on loss of load probabilities and ICR –Accommodates significant load reduction without creating new peaks at the border of the period Periodic review is needed, especially if customer response becomes strong over time Research suggests that retail customers are willing and able to actively reduce load for up to 20 days without causing “customer fatigue” 11

12. ICR is a Function of Observed Peak Loads from Week-to-Week and Year-to-Year 12

13. Effect on ICR From Reductions Only During Peak Days, July 1 st through Aug 31 st, for 5 years 13 Reducing consumption during the top 15 peak days in July/August had a similar impact as reducing consumption on all 40 business days in July/August

14. Redefining the Daily Peak Period 14 A six-hour window captures the full impact of a 5% load reduction

15. Elements of a Revised Approach 1.Allocate costs based on a load’s share of total system consumption during multiple hours that affect the ICR most directly 2.Specify the hours to be used in determining Peak Contribution values before the start of each Capability Year –Periodic analysis conducted to determine if the hours or the period need to change in future years 3.Bill capacity costs using new capacity allocators as soon as the numbers are available rather than waiting until the following year –Load-serving entities have indicated that this change will present challenges given the current retail contracting cycle 15

16. New Initiatives: Real-Time Energy and Reserves Pilot Program

17. Background: Demand Response Reserves Pilot Program (“DRRP”) DRRP ran from October 2006 to May 2010 DRRP objectives: –Test the ability of smaller demand response resources to respond to ISO dispatch instructions in a manner similar to resources providing Operating Reserve –Performance was assessed by measuring how quickly and consistently participating assets were able to reduce load relative to the quantity of interruptible capacity enrolled in the DRRP Results of the DRRP evaluation study by KEMA Consulting was presented to the Markets Committee on December 8, 2010 17

18. Total DR Performance (From KEMA Study) 18

19. Observations and Conclusions From the Demand Response Reserves Pilot Participation was limited – pilot never reached 50 MW (average participation was 26.4 MW per session) Response to dispatch instructions was statistically significant, but highly variable On average, certain demand response asset groupings substantially under-performed while others substantially over-performed The drivers of under- or over-performance are not completely clear at this time These results indicate that further research and development is needed for demand response to become a dispatchable energy and reserve resource 19

20. Design and Implement a Real-Time Energy and Reserves Pilot Program Overall Goal: Improve the reliability and efficiency of the bulk power system by presenting an opportunity for alternative resources to provide energy and reserve products to the wholesale market –Alternative resources include installed measures (i.e., equipment, systems, services, practices and/or strategies) that are otherwise not able to participate in energy or reserve markets as a supply-side resource 20

21. How Could the New Pilot Improve Upon the Old Pilot? Old DRR PilotNew RTER Pilot Reserves onlyCould include energy and reserves Participating assets consisted of individual facilities Participating assets could consist of aggregations of facilities Random dispatchDispatch could be priced-based No offer curve – Market Participants provided a single load reduction quantity per asset Market Participant could submit an offer curve consisting of multiple load reduction increments per asset ISO calculated baseline forecastMarket Participant could submit the baseline forecast Dispatch instruction was “reduce load at this time” Dispatch instruction could be “consume this amount at this time” Payment based on the difference between actual load and the baseline Payment could be based on ability to follow dispatch instructions