The State of Demand Response in California Ahmad Faruqui, Ph.D. Principal June 13, 2007

2 Privileged and Confidential Prepared at the Request of Counsel The top 1 percent of the hours account for more than 10 percent of the peak load in the state

3 Privileged and Confidential Prepared at the Request of Counsel California Faces a Deficit in its Demand Response Policy

4 Privileged and Confidential Prepared at the Request of Counsel Utility price-responsive programs are expected to fall short of this year’s goal of 5 percent 2007 Expected Peak Demand (MW) Peak Reduction (MW) Reduction as % of Peak PG&E19, % SCE23, % SDG&E4, % Total47,0141,0572.2% Total Anticipated DR from Price Responsive Programs (2007) Sources: IOU Reports on Interruptible Load Programs and Demand Response Programs for January 2007; CEC, “Staff Forecast of 2007 Peak Demand,” June 2006

5 Privileged and Confidential Prepared at the Request of Counsel However, interruptible programs are expected to provide an additional 3.4 percent of peak demand reduction 2007 Expected Peak Demand (MW) Peak Reduction (MW) Reduction as % of Peak PG&E19, % SCE23,1241,2045.2% SDG&E4, % Total47,0141,6133.4% Total Anticipated DR from Interruptible Programs (2007) Sources: IOU Reports on Interruptible Load Programs and Demand Response Programs for January 2007; CEC, “Staff Forecast of 2007 Peak Demand,” June 2006

6 Privileged and Confidential Prepared at the Request of Counsel Price-based programs empower customers to choose the level of risk that best suits them Flat Rate TOU RTP CPP-F Consumer Risk Supplier Risk Seasonal Rate CPP-V VPP

7 Privileged and Confidential Prepared at the Request of Counsel How much additional DR can California achieve from price-responsive programs? Technical potential ► Measures the outcome if all customers used the best available DR technology Economic potential ► Measures the outcome if all customers used a cost- effective combination of technologies Market potential ► Measures the outcome if a cost-effective combination of technologies is accepted by a reasonable number of customers in the market place

8 Privileged and Confidential Prepared at the Request of Counsel The technical potential for DR in California is around 25 percent of peak demand Assumptions Full statewide deployment of AMI 100% participation Peak demand allocation by sector ► 41% residential, 41% commercial, 18% industrial All residential customers use gateway system ► 43% peak demand reduction per customer All commercial and industrial customers use Automated DR ► 13% peak demand reduction per customer Technical potential = 25% peak demand reduction

9 Privileged and Confidential Prepared at the Request of Counsel The economic potential for DR is around 12 percent of peak demand Customers use a cost-effective mix of enabling technologies Residential 10% have gateway system 20% have smart thermostat 70% have no enabling technology 19% weighted average peak demand reduction Commercial 10% have Automated DR 30% have smart thermostat 60% have no enabling technology 7% weighted average peak demand reduction Industrial 40% have Automated DR 60% have no enabling technology 9% weighted average peak demand reduction Economic potential = 12 percent peak demand reduction

10 Privileged and Confidential Prepared at the Request of Counsel The market potential for DR is around 5 percent of peak demand Customers use same cost-effective mix of enabling technologies 40% participation rate in all sectors ► Falls between 20% estimate for opt-in rate and 80% estimate for opt-out rate Market potential = 5 percent peak demand reduction

11 Privileged and Confidential Prepared at the Request of Counsel A 5 percent peak demand reduction would provide three types of benefit Avoided generation capacity cost ► Over 3,000 MW of avoided peak demand, or 50 combustion turbines ► Cost of new capacity = $52/kW-year ► $200 million in avoided costs per year Avoided electricity generation cost ► Reduced electricity generation during peak ► $20 million in avoided costs per year* Avoided transmission & distribution capacity cost ► 10% of avoided generation capacity and energy costs ► $20 million in avoided costs per year *Using relationship observed in a recent PJM analysis of demand response

12 Privileged and Confidential Prepared at the Request of Counsel Even a 5 percent peak demand reduction would save $240 million per year or $3 billion over 20 years Annual Financial Benefits of 5% Peak Demand Reduction

13 Privileged and Confidential Prepared at the Request of Counsel Stakeholder interviews identified 14 barriers to the achievement of the state’s DR potential 1.Assembly Bill 1X (rate freeze on first two tiers) 2.Lack of AMI penetration for customers < 200 kW (being remedied) 3.Lack of cost-effective enabling technology 4.Lack of consumer interest 5.Ineffective program design 6.Utility fear of not recovering costs 7.Fear of customer backlash 8.Confusion with energy efficiency programs 9.Concerns about adverse environmental impacts 10.Lack of retail competition 11.Low capacity and energy prices 12.No recent blackouts 13.Complicated state-federal coordination issues 14.Lack of a wholesale power market

14 Privileged and Confidential Prepared at the Request of Counsel The barriers can be grouped into two areas Dynamic pricing ► Develop better and more innovative rate designs ► Resolve AB 1X complications ► Develop realistic goals for DR ► Modify existing cost-benefit methodologies for demand-side programs ► Educate customers about the benefits of time-varying and dynamic rates Technology ► Install AMI ► Equip customers with enabling technologies ► Design rates with understanding of response that customers are able to provide

15 Privileged and Confidential Prepared at the Request of Counsel The best way to overcome these barriers may be through instituting new load management standards The Energy Commission pioneered load management standards in the late 1970s These were intended to reduce peak demand by 7 percent and enjoyed a certain amount of success The Energy Commission’s Title 20 and 24 standards have contributed half of the efficiency gain that has been observed over the past three decades

16 Privileged and Confidential Prepared at the Request of Counsel Back to the Future!

17 Privileged and Confidential Prepared at the Request of Counsel In 1978, the Energy Commission proposed four load management standards Load control standard Swimming pool filter pump standard Non-residential (commercial) standard Load management tariff standard

18 Privileged and Confidential Prepared at the Request of Counsel The impact of the load management standards Slow initial response to the standards Two workshops were held to facilitate program development in 1979 ► Load management technology ► Improving customer participation Report from Governor’s Energy Conservation Task Force reinforced need for immediate response in January 1980

19 Privileged and Confidential Prepared at the Request of Counsel The impact (concluded) Utilities responded and California survived low capacity margins of the early 1980s Two programs produced lasting impacts ► TOU rates exist for customers above 500 kW of demand (lowered to 200 kW after the Western Energy Crisis) ► Residential load control programs at some utilities

20 Privileged and Confidential Prepared at the Request of Counsel Reasons for limited success Advisory nature ► The Energy Commission does not have independent authority to enforce the standards, as it does with the appliance and building standards (Titles 20 and 24) Administrative constraints ► Programs must be approved by both commissions and today may additionally require involvement of CAISO Technological issues ► Technical challenges with the pool pump timers; required significant manual efforts by user

21 Privileged and Confidential Prepared at the Request of Counsel Reasons (concluded) Voluntary participation ► With exception of mandatory TOU rates, the standards did not require default participation Private market for DR did not exist ► Programs remained under control of utilities; little private sector involvement and innovation Cyclical nature of capacity shortages ► Eventual capacity surplus in the state shifted the focus away from load management

22 Privileged and Confidential Prepared at the Request of Counsel Load Management II

23 Privileged and Confidential Prepared at the Request of Counsel The state is now reconsidering the imposition of load management standards They are likely to be centered around three pillars Dynamic pricing standard ► Default dynamic pricing tariff for all customers Programmable Communicating Thermostat (PCT) standard ► PCTs for all residential customers Automated Demand Response standard ► Automated DR for all C&I customers

24 Privileged and Confidential Prepared at the Request of Counsel Without the standards, a 2.5% peak reduction might be achieved, representing over $1 billion in the next 20 years Assumptions Same methodology described in morning presentation Statewide deployment of AMI Voluntary (opt-in) dynamic pricing is offered by the three IOUs ► 20 percent participation rate Most customers are not equipped with enabling technologies such as PCTs Result 2.5% peak reduction Financial benefits of over $1 billion in the next 20 years

25 Privileged and Confidential Prepared at the Request of Counsel With the adoption of a dynamic pricing standard, the peak reduction could increase by 7 percentage points and benefits could rise by $4 billion Assumptions Default pricing is made the default tariff for all customer classes 80 percent of customers stay on the default tariff, 20 percent opt back to their old tariff No enabling technologies are offered to customers Result Additional 7 percent peak demand reduction Incremental financial benefits of $4 billion

26 Privileged and Confidential Prepared at the Request of Counsel The adoption of a PCT standard could increase the peak reduction by 8 percentage points and raise financial benefits by some $5 billion Assumptions The dynamic pricing standard is in place All residential customers are equipped with a PCT The average peak reduction for residential customers with a PCT is 27% Result Additional 8 percent demand reduction overall Incremental financial benefits of $5 billion

27 Privileged and Confidential Prepared at the Request of Counsel The further adoption of an Automated DR standard could increase the peak reduction by 2 percentage points and raise financial benefits by $1 billion Assumptions Dynamic pricing standard and PCT standard are in place All C&I customers are equipped with system-wide automation for managing multiple end uses The average peak demand reduction for a customer equipped with this technology is 13 percent Results Additional 2 percent peak demand reduction $1 billion in incremental financial benefits

28 Privileged and Confidential Prepared at the Request of Counsel The incremental benefit of all three is nearly an 18 percent peak demand reduction, representing an additional $10 billion in financial benefits

29 Privileged and Confidential Prepared at the Request of Counsel After adjusting the calculation of the benefits of the PCT standard, the incremental peak reduction is still over 12%, representing an additional $7 billion

30 Privileged and Confidential Prepared at the Request of Counsel Conclusions California’s earlier experience with load management standards was successful ► Stimulated discussion about ways to reduce peak load ► Produced programs that are still effective today The state has had much success with building and appliance standards Load management standards are being revisited The three strawman proposals present a compelling picture of the benefits that might be derived by pursuing the CEC’s load management standard-setting authority ► Focus on dynamic pricing and enabling technologies ► Day-ahead and day-of deployment ► Enhance the role of pricing mechanisms for managing demand and supply ► Decrease the role of cash incentives

31 Privileged and Confidential Prepared at the Request of Counsel Contact information Ahmad Faruqui, Ph. D. Principal The Brattle Group 353 Sacramento Street, Suite 1140 San Francisco, CA Voice: Fax: Cell: