1. Kathleen King, Ph.D. Vice President SMART METERING WEST COAST 2007 CONFERENCE, Los Angeles, California August 21, 2007 The Importance of Demand Response to Electricity Markets

2. 1 Topics 1.Demand response is critical to the success of restructured power markets 2.But we didn’t include demand response in the design of restructured power markets!

3. 2 Topics 1.Demand response is critical to the success of restructured power markets Divestiture Markets Retail Markets Restructuring Demand Response

4. 3 The Impetus for Restructuring Was Lower Costs  Commissions in states with high electricity rates believed that competition might lead to better investment decisions and lower prices

5. 4 Restructuring Required Divestiture  Restructuring required separation of generation, retail supply and T&D –Divestiture –Separate corporate entities Impact of Divestiture on Generation Ownership (New England Capability) Nonutility Utility 25,000 20,000 15,000 10,000 5,000 0 888990919293949596979899 Year Megawatts Source: http://www.eia.doe.gov/cneaf/electricity/page/fact_sheets/restructuring.html

6. 5 Divestiture Was Key to Development of Markets  Prior to divestiture, each utility’s generation was used to supply its own customers  Divestiture created the need for generators and retail suppliers to transact through markets

7. 6 Markets Start with Spot Markets  Spot markets –Efficient production decisions –Efficient consumption decisions  Requires both wholesale and retail markets with demand response

8. 7 Designing a Market with Demand Response Has Consequences  Customers make choices… –About their consumption level –About managing their risk of future prices  Exposes customers to cost of consumption Source: Bloomberg. Palo Verde On-Peak Spot Prices 0 100 200 300 400 500 600 1/97 7/97 1/98 7/98 1/997/991/007/001/017/011/02 7/02 1/037/031/04 7/04 1/05 7/05 1/06 7/06 1/07 7/07 $/MWh

9. 8 Spot Markets Are the Foundation of Other Markets  Customer choices create foundation for other markets –Invest in DR technology –Hedge against price volatility  Risk markets signal value of capacity  Investment decisions affect future spot markets Markets for Investment Risk Markets Markets for DR Technology Retail and Wholesale Spot Markets

10. 9 Topics 1.Demand response is critical to the success of restructured power markets 2.But we didn’t include demand response in the design of restructured power markets! –The consequences –Why we didn’t –Why we should in the future

11. 10 Retail Markets Were Not Truly Deregulated

12. 11 Retail Markets Were Not Truly Deregulated

13. 12 Without Deregulated Retail Markets, Other Markets Have Suffered Markets for Investment Risk Markets Markets for DR Technology Retail and Wholesale Spot Markets

14. 13 Failure to Deregulate Retail Markets Contributed to “Lightening Rod” Events  California market events of 2000-01  Financial distress of the merchant energy industry  Calls for re-regulation

15. 14 Failure to Deregulate Retail Markets Contributed to “Lightening Rod” Events  Financial distress of the merchant energy industry –Short positions + price spikes of 1998 and 1999  Losses  View that assets needed as backstop  Overinvestment  Collapsing spark spreads  Financial distress Cinergy Prices (Spot, On Peak) 1996 through 2000 0 500 1,000 1,500 2,000 2,500 Jan- 96 Jul- 96 Jan- 97 Jul- 97 Jan- 98 Jul- 98 Jan- 99 Jul- 99 Jan- 00 Jul- 00 $/MWh Source: Bloomberg.  California market events of 2000-01

16. 15 Failure to Deregulate Retail Markets Contributed to “Lightening Rod” Events  Calls for re-regulation –Multi-year below-market rate freezes –Fuel price increases  California market events of 2000-01  Financial distress of the merchant energy industry

17. 16  The result: –Retail rate increases as rate freezes end Failure to Deregulate Retail Markets Contributed to “Lightening Rod” Events DC: Pepco:12% residential rate increase (RFP for ~550 MW) MA: NSTAR:34% residential rate increase (RFP for ~1,500 MW) CT: CL&P:22% residential rate increase (RFP for ~5,500 MW) NJ: PSE&G:12% residential rate increase (Auction for ~5,500 MW) MD: BG&E:72% (Phase-in) residential rate increase (RFP for ~8,000 MW) DE: Delmarva:59% (Phase-in) residential rate increase (RFP for ~850 MW)

18. 17 Why We Didn’t Include Demand Response  Hindsight is 20-20  Fear 1.That markets won’t work 2.That customers won’t respond 3.That there won’t be “enough” demand response

19. 18 To Each Fear, There Is an Answer Fear #1 1.That markets won’t work  Demand response is what makes markets work  Lack of demand response is key to extreme market events

20. 19 To Each Fear, There Is an Answer Fear #2 2.That customers won ’ t respond  The evidence is: Customers DO Respond

21. 20 The Evidence Is that Customers DO Respond  Economic Curtailment Programs  Critical Peak Pricing (CPP) Programs  Real-time Pricing (RTP) Programs

22. 21 Economic Curtailment Programs  DR programs enrolled over 24,900 MWs at 10 ISO/RTOs  PJM, August 2006 –DR reduced wholesale prices over $300/MWh  NYISO, August 2006 –DR reduced peak load almost 1,000 MW  ISO-NE, 2005 –About 80% of demand in DR programs shed –Real-time Price Response Program reduced load 31% of enrolled demand

23. 22 California’s CPP Pilot  2003-04 pilot, with 2500 customers, extended to 2005  Customers reduced usage, augmented by automated demand response technology  Survey: 70 to 80 percent preferred CPP rate  SCE, PG&E, SDG&E have filed CPP tariffs Event DaysNon-Event Days 2005 ADRS43%27% 2004 ADRS51%32% 2004 Pricing-Only17%12% Percentage Usage Reduction by High Consumption Customers Relative to Control Source: Rocky Mountain Institute, "Automated Demand Response System Pilot, Final Report, Vol. 2: Load Impact Results," 31 March 2006.

24. 23 Gulf Power’s CPP  Implemented in 2000 –Features advanced metering and home automation technology –8,500 participants currently  Customers reduced usage 40 to 60 percent during CPP events  Bill savings of 15 percent annually, energy savings of 3.8 percent

25. 24 RTP Programs  Earliest source of evidence that customers respond to dynamic pricing programs –England and Wales, Pacific Gas & Electric, Southern California Edison, Niagara Mohawk, Georgia Power, others  Number of programs in US has grown from 16 in 1993 to 70 in 2004

26. 25 Georgia Power’s RTP  Largest RTP program –82 percent of eligible load and 43 percent of eligible customers (2004) –Day-ahead and hour-ahead options  Largest load reduction: 750MW (1999) –About 20 percent for DA at $1.50/kWh –About 50 percent for HA at $6.50/kWh

27. 26 Illinois Residential RTP Program  Energy-Smart Pricing Plan by Community Energy Cooperative with ComEd –Over 1,400 customers by 2005 –Pass-thru of PJM prices capped at $.50/kWh –Automated notification if next-day prices over $.10/kWh  Customers did reduce demand –Up to 20 percent on average in 2003, saving 11 percent –15 percent at 2005 summer peak, 3-4 percent usage reduction –Smaller demand reduction in cool 2004 summer  Remote AC cycling in high-priced periods reduced demand  Being expanded to Ameren Illinois

28. 27 To Each Fear, There Is an Answer Fear #3 3.That there won ’ t be “ enough ” demand response  The amount of demand response needed at system peak is small  Substantial demand response is available  Advanced metering technologies and customer enabling technologies increase demand response and participation

29. 28 Why We Should Include Demand Response  DR is the foundation of markets –“Lightening rod” market outcomes without demand response  DR programs are successful –Customers DO respond –Demand response can be sufficient to ameliorate price spikes and system stress –Enabling technologies increase DR and broaden the spectrum of likely participants

30. Contact Us Kathleen King, Ph.D. Vice President NERA—Washington DC kathleen.king@nera.com 202 466 9269 © Copyright 2007 National Economic Research Associates, Inc. All rights reserved.