New England Demand Response Initiative Recommendations

1. New England Demand Response Initiative Recommendations Massachusetts Electric Restructuring Roundtable Henry Yoshimura Manager, Demand Response ISO New England, Inc. Holyoke, Massachusetts November 21, 2003

2. 2003 Regional Demand Response Program Types

3. Demand Response Program Enrollment Overview • Over 400 MW (over 450 customers) enrolled in the Demand Response Program by the end of the Summer 2003 • Price Program: • 30% of the MWs, 70% of the customers • Reliability Programs: • 70% of the MWs, 30% of the customers • Over 50% in Connecticut, about 20% in the Greater Boston area • More than doubled the number of enrolled participants since Summer 2002 • 185 MW (221 customers) enrolled by the end of Summer 2002

4. DR Performance – August 15, 2003 • The blackout affecting the Northeast, Midwest, and Canada commenced around 16:15 EST on August 14, 2003 • Only 10% of New England load was affected, and most of that was restored before August 15, 2003 • During restoration efforts, a major transmission line failed in SW Connecticut • OP-4 was declared in Connecticut on August 15, 2003 • In accordance with operating procedures, demand response resources in Connecticut were called around 08:00 on August 15, 2003

5. Preliminary Observations From 08/15/2003 • Reliability Programs produced significant response • Enrolled customers in Connecticut produced a maximum response of about 130 MW • Average response was about 90 MW per hour over the period 08:00 to 18:00 • The Price Program did not produce a significant response • However, LMPs in Connecticut were low on August 15 • Day-Ahead LMPs did not exceed $94.52/MWh • Real-Time LMPs did not exceed $62.48/MWh • Floor price of $100/MWh does not appear to be a sufficient incentive for loads to respond

6. CT Zone Program Performance – 08/15/2003

7. Regional Demand Response: Detailed Program Design Issues • RDR-1: Strengthen the Real Time DR Program • Higher minimum payments • Lower entry barriers (drop $5000 participation fee) • Longer term commitment (up to 3 years) • Provide capacity payments to enrolled resources • Note: these recommendations were addressed by the FERC in Feb. and June 2003 • Current program is based on: • Energy Payment: Greater of Real Time Price or Guaranteed Minimum $0.50/kWh for 30-Minute Response and $0.35/kWh for 2-Hour Response • $500 participation fee • Programs effective through February 2006 • Capacity Payment: Monthly Installed Capacity (ICAP) credit ($/kW) based on the monthly ICAP Supply Auction clearing price

8. Regional Demand Response: Detailed Program Design Issues • RDR-2: Strengthen the Day-Ahead DR Program • Permit smaller bidding increments • Permit standing offers, don’t require daily bids • Equal bid ceilings for supply and demand-side bids • RDR-3: Develop a Price-Driven Day-Ahead program by 2004 • Note: per Nov. 13, 2003 Order, the FERC requires implementation by Mar. 31, 2005 • Current status: • Day-Ahead program design, development, testing, and implementation commenced in February 2003, but was put on hold because of resource constraints and unknown market potential • 2003 DR program evaluation includes a Day-Ahead Demand Response Market Assessment • Day-Ahead Demand Response program development has resumed

9. Financial Support for Regional DR Programs • RDR-5: Provide location-based capacity credits to DR resources • To be implemented by June 1, 2004, per Devon Order (April 25, 2003) • RDR-6: Provide adequate resources and cost recovery to DR programs • Cost recovery at wholesale level filed and approved • Potential issues with retail cost recovery

10. Financial Support for Regional DR Programs • RDR-7: Evaluate and improve DR programs • Preliminary evaluation results to be presented at our DRWG meeting on December 10, 2003 (see ISO website for more details) • Report to be filed with the FERC on or around December 31, 2003 • Demand Response Working Group • Regular meetings began in February 2003 • Meetings scheduled for the first Wednesday of every month (next meeting will be held on December 10, 2003, to accommodate presentation on DR evaluation) • Became a subgroup of the NEPOOL MC in May 2003

11. Financial Support for Regional DR Programs • RDR-8: Performance-based metering and telemetry to reduce unnecessary costs for DR • Measurement and verification (M&V) protocols developed through stakeholder process filed with the FERC in June 2003 • Current M&V protocols applicable to Real-time Profile Response Program • In December 2003, a filing will be made to expand the use of M&V protocols to be applicable to all DR Programs • Alternatives to traditional interval metering • Statistical measurement of savings • RDR-9: Ratepayer Funding to Overcome Market Barriers to and Increase Participation in DR

12. Address Market Barriers • Imperfect Knowledge • Customers need help with: • Determining their demand response potential (kW) • Understanding demand response price points ($/kWh) • Estimating the costs and benefits • Developing strategies to respond to price and/or reliability events • Implement better marketing principles that focus on program benefits instead of program features • Lack of Enabling Infrastructure • Automated systems that deliver demand response andenergy conservation functionality (i.e., controls, communication, monitoring and verification)

13. Energy Conservation Demand Response Supply Management Capitalize on Synergies • In today’s market, Demand Response should be a • component of an overall energy management • strategy, not a stand-alone product

14. EC, DR, Supply Management Synergies

15. Integrated Approach to Energy Management • Encourage the integration of demand response and energy conservation through the existing program delivery structure • Encourage the development of programs that offer financial incentives for the installation of automated technologies that deliver both demand response and energy conservation functionality • Support the use of state funding to support the integration of demand response and energy conservation into comprehensive and complementary program offerings that provide customers with greater value • Better link the wholesale and retail markets

16. Can Demand Response Provide Contingency Reserves? • Essential idea: Spinning, supplemental, and replacement reserves to meet power system contingencies can be provided by resources on the supply side or the load side • Reserves are needed to: • Balance real-time generation and load • Manage power flows across transmission facilities • Challenges for DR resources: • System operators need to control and monitor real-time status • Individual loads are small – resources need to be aggregated • Is the resource pool big enough to matter? • Can the resource be dispatched for sufficient duration? • Tradition, current rules tailored to supply-side resources

17. Load Participation in Contingency Reserves • CR-1: ISO-NE should develop markets for contingency reserves. • CR-2: Launch a market study and pilot programs to demonstrate the potential for small loads to provide contingency reserves. • CR-3: NPCC should establish technology-neutral standards for CR, open to DR as well as traditional supply standards. • CR-4: Review metering and telemetry requirements for DR resources providing contingency reserves.