TEAC21

1. TEAC21 Thursday, May 6, 2004 Sheraton Hotel Springfield, Massachusetts

2. TEAC21 Agenda • Welcoming Remarks • Load Response Program 2004 • Load Response Penetration Study • SWCT RFP Results • Resource Adequacy Results • Interregional Planning Update • Economic Assessment Review methodology Results

3. TEAC22 - June 2nd • TEAC23 - June 25th • FDWG's Elec. & Gas Wholesale Initiative Project May 14th • Cold Snap Issues

4. Making the Business Case for Demand Response Henry YoshimuraISO New England

5. Agenda • What is Demand Response? • How do the Demand Response programs work? • What’s New for 2004? • Making the Business Case or What’s in it for me?

6. What is Demand Response? • Customers reducing their electricity consumption in response to either: • High Wholesale Electricity Prices or • SystemReliabilityEvents • Customers being paid for performance based on wholesale market prices.

7. Program Types • Reliability (Demand) Programs: • Customers respond to System Reliability Conditions as determined by the ISO New England Control Room • Price Programs: • Customers respond to Wholesale Spot Prices as determined by the Market.

8. Real-Time Demand Response

9. Example 1: Scrap Metal Processor • Demand Program • August 15, 2003 • Suspended Operation within 30-Minutes Notice • Promised: • 2.5 MW per Hour • Delivered (Avg): • 1.94 MW per Hour • Energy Payment: • $9,700

10. Example 2: Industrial Gas Producer • Demand Program • August 15, 2003 • Suspended Operation within 30-Minutes Notice • Promised: • 19 MW per Hour • Delivered (Avg): • 15.4 MW per Hour • Energy Payment: • $127,000

11. Real-Time Price Response

12. Example 3: Pharmaceutical Company • Price Response Program • Participated in thirty (30) event days from March through December 2003 • Total of 239 hours of Demand Reduction • Average Demand Reduction: 1.3 MW • Average Payment Rate: $0.104/kWh • Total Energy Payment: $34,000

13. Metering Options • Internet Based Communication System (IBCS) • 5-Minute Usage Data, Event Notification, Internet Access to Usage and Performance data • Financial subsidies available from ISO-NE • Low Tech and Super Low Tech Option: • Hourly data sent to ISO NE either every day or within 3 months of an event. • Customized Metering Plans: • Data from EMS or sub-metering systems • Statistical sampling allowed • Flexibility: Monitor kW, operating times, on/off status, etc.

14. Estimating Demand Reduction Adjusted Baseline Actual Usage Baseline (Average of 5 prior non-event business days)

15. New for 2004 Annual Audit • All programs will be activated at least once per year as a test. • Customers will be paid for the Audit Event • Only ISO New England will know the difference between an Audit Event and a Real Event.

16. New for 2004 Metering Subsidies for Smaller Facilities • $/kW Basis • Minimum 25kW per Site • Maximums Apply • Smaller Sites must be Aggregated to achieve 100 kW

17. New for 2004 5-Day Initial Baseline • Initial Baseline reduced from 10 business days to 5 business days. • Customers eligible to participate within 5 business days of the start of ISO New England receiving their hourly data. • Customers must have an hourly meter installed before they are eligible to participate.

18. New for 2004 Locational Installed Capacity (ICAP) • Currently one capacity market (ICAP) for all of New England • Same ICAP price from Northeast Maine to Southwest Connecticut. • Summer 2004 - Different ICAP values by Load Zone. • Resources located in congested Load Zones may receive higher ICAP payments.

19. Building the Business Case

20. Program Benefits: Paid to Get in Shape! • Short-Term • Paid for Performance • Minimum Payment $0.10 to $0.50/kWh • Paid for Availability* • $/kW per Month based on ICAP Market, Utility Program or Resource RFP • Long-Term • Better Load Shape = Better Retail Price * Demand Programs Only

21. Program Costs • Fixed Costs • Advanced Metering (Required) • Subsidies are available to cover 50% to 100% of the cost. • Controls and Equipment Upgrades (Optional) • Variable Costs • Internal and External Labor • Fuel and O&M • Lost Opportunity • What would I have earned had I not shut down manufacturing for 4 hours? • Did sales go down because I dimmed the overhead lights?

22. Integrated Energy Management Energy Efficiency Demand Response Supply Management

23. Integrated Energy Management • Energy Efficiency – Managing energy consumption. • Supply Management – Managing the supplier relationship and risk. • Demand Response – Managing load shape.

24. Supply Management and Demand Response • Yesterday: Prices set by the Regulator. Customers had little interest in the wholesale markets. • Today: Prices set by the Supplier and Customer. Customers have the option of being connected with the wholesale markets

25. Supply Management and Demand Response – Customer’s Perspective • It’s all about risk management! The price a customer pays for electricity is based on: • The customer’s credit • The customer’s timing (when they decide to shop for a supplier) • The customer’s load shape (how much electricity they use each hour of the day)

26. Customer’s Perspective (Continued) • Customers who can not control when they use electricity transfer risk to their supplier. • The supplier must assume the risk that at any point in time the customer can increase their consumption without any consideration for the supplier’s wholesale costs. • Higher risk translates into a higher retail price.

27. Customer’s Perspective (Continued) • Customers who participate in a Demand Response Program can: • Manage their hourly usage, • Respond to wholesale prices or reliability events, and • Help lower their supplier’s risk. • Lower risk translates into a lower retail price.

28. Time-of-Use Rate vs. Demand Response “I’ve already shifted all the load I can!” • Time of Use (TOU) Rate Management • Routinely shifting energy use from on-peak to off-peak without impacting day-to-day business operations. Actions justified by rate tariff. • Demand Response • Temporary changes from routine day-to-day business operation during critical time periods. Actions justified by the program benefits.

29. Real-Time Pricing vs. Demand Response • Real Time Pricing • Exposed to wholesale price volatility and risk all the time. • Real-Time Price Response Program • Opportunity to respond to price volatility on a limited basis without any risk.

30. Summary of Customer Benefits • Paid for managing consumption in response to reliability or price events. • Hourly usage information that can be used to manage demand and energy charges year round. • Customers who can manage their demand may be able to negotiate lower retail electricity prices from their competitive supplier. • Help ensure the reliability of the region’s electrical grid. • Help mitigate supplier power in setting wholesale prices.

31. 2003 Customer Survey Results

32. Questions: • Who participates in Demand Response Programs? • What do they do? • Why do they participate?

33. Who participates in Demand Response Programs?

34. Demand Response Growth 400 MW (2003) 200 MW (2002)

35. ME 17.2% NEMA/ Boston 17.9% NH 52.1% 0.1% RI 0.4% SEMA CT 2.1% VT 3.8% West/Central Mass (WCMA) 6.4% Where are Demand Response Resources? • Where it’s needed most: • Southwest Connecticut and the Greater Boston Area • Where it’s most available: • Maine’s Large Industrial Consumers

36. Customers by Industry Type Service Industry (Real Estate, Recreation, Health Care, Education, Government) Retail Transportation, Communication, Utilities Manufacturing 0 5 10 15 20 25 30 35 40 45 50 Percent (%) Demand Response Price Response

37. Customer Characteristics • Price Program: 30% of the MWs, 70% of the customers • Demand Programs: 70% of the MWs, 30% of the customers • Air Conditioning and Refrigeration • 80% of Price Response Customers • 40% of Demand Response Customers • Emergency Generator • 70% of Demand Response Customers • 45% of Price Response Customers

38. Customer Characteristics (Continued) • Company Size: • Majority have less than 1,000 employees • 1/3 have less than 100 employees • Electricity represents greater than 5% of the their Total Operating Costs • Most customers spend less than 10% of their time Buying and Managing Energy

39. Customer Characteristics (Continued) • Over 90% have made investments in Energy Efficiency in the past 5 years; 50% have installed Energy Management Systems • 2/3 of Demand Response Customers have participated in either a Time-of-Use, Interruptible or Real-Time Price rate program • 2/3 of all participating customers conducted a Cost/Benefit Analysis prior to enrolling in a Demand Response Program

40. What changes do customers make to reduce electricity use?

42. Demand Reduction Methods • Lighting • Over 85% control their Interior Lighting with Wall Switches and Circuit Breakers • HVAC • 50% use their Energy Management Systems • Over 50% say they can increase Temperatures by 1 to 2 °F without effecting Processes or Occupant Comfort • Manufacturing Processes • 45% use Computer or Fully Integrated Manufacturing Controls • Emergency Generation • 40% in the Demand Programs start their Emergency Generators • 70% say they have Emergency Generators • Environmental permitting issues limit the use of most generators to “emergency conditions”

43. Why do customers participate in Demand Response Programs?

44. Payments to customers in 2003 totaled approximately $1 million

45. Load Response PotentialDave EhrlichISO New England

46. Real Time Price Demand Response Program Market Assessment Prepared for: ISO – New England Prepared by: RLW Analytics and Neenan Associates

47. The objective of this market assessment is to utilize available customer specific Demand Response data in conjunction with ISO-NE supply models and Utility customer load data to develop a Price Response Market Model (PRMM). • The PRMM will estimate the magnitude of price responsive load response, by zone, as the real time LMP changes.

49. SWCT New Resource RFP 2004-2008 Presentation to TEAC 21 Jim Platts – ISO New England May 6, 2004

50. Background • On 12/01/03 ISO New England issued an RFP for up to 300 MW of new emergency resources for SWCT 2004 – 2008 • These resources were sought to meet reliability criteria for SWCT, i.e. provide reserve to reduce the risk of load shedding • Critical area is 16 “Preferred Towns” and 38 “Other Towns”