CEC Load Management Standards Workshop March 3, Update on the CPUC’s Demand Response and Advanced Metering Proceedings Bruce Kaneshiro Energy Division California Public Utilities Commission

CEC Load Management Standards Workshop March 3, Presentation Outline DR Policy, Action Items, Accomplishments Advanced Metering Projects Rate Cases and Dynamic Pricing Demand Response Programs Enabling Technologies Integration with CAISO’s MRTU Forecasting, Measurement and Evaluation Tools

CEC Load Management Standards Workshop March 3, Overall DR Policy and Action Items  DR continues to be a high priority energy resource for the state; second only to Energy Efficiency in the Energy Action Plan’s ‘loading order’  The Energy Action Plan 2008 Update lists several key DR action items: Adopt load management standards to establish a DR infrastructure Legislative authorization for time-varying pricing for residential customers More progress on dynamic pricing rate design for all customers. Programs that utilize advanced metering, tariffs, and other automated DR infrastructure. Modify retail programs to more fully participate in the CAISO’s wholesale market structure. Develop DR load impact and cost-effectiveness protocols.

CEC Load Management Standards Workshop March 3, DR Accomplishments to Date  Advanced metering deployment is underway for PG&E and starting soon for SDG&E  Default Critical Peak Pricing (CPP) approved for SDG&E’s large C&I customers  Peak Time Rebate (PTR) program approved for SDG&E’s residential customers  First phase of integrating DR resources with CAISO operations in place for summer 2008  Existing DR programs offer a broad range of options for customers and equate to over 2,000 MWs of DR potential capacity  DR qualifies as a resource in meeting a load serving entity’s Resource Adequacy Requirement.

CEC Load Management Standards Workshop March 3, PG&E’s AMI Project  In 2006, the CPUC authorized PG&E’s AMI proposal (5.6 million electric meters and 4.5 million gas meters)  Full deployment of PG&E’s AMI system technology and network is scheduled to take 5 years ( ).  As of November 2007, PG&E has installed approximately 243,000 meters (gas and electric), mostly in Bakersfield and Sacramento.  In December 2007, PG&E filed a proposal to upgrade its AMI system: Solid state meter technology Remote connect/disconnect switches Home Area Network Gateway devices

CEC Load Management Standards Workshop March 3, SDG&E’s and SCE’s AMI Project  In 2007, the CPUC authorized SDG&E’s AMI proposal (1.4 m. electric meters, 900,000 gas meters)  SDG&E currently finalizing contracts with meter and infrastructure vendors – will seek Commission approval of the contracts this spring. Full deployment of SDG&E’s AMI is expected to be complete by 2011 (deployment expected to begin towards the end of 2008)  SCE’s AMI proposal (5.3 million electric meters) is currently under review CPUC decision on SCE’s AMI proposal is scheduled for August 2008  Proposed AMI deployment schedule: 2009 to 2012

CEC Load Management Standards Workshop March 3, Rate Cases and Dynamic Pricing  Dynamic Pricing is being developed by the CPUC in the utilities’ individual rate design proceedings  SDG&E’s General Rate Case (GRC). Following rates approved:  Default Critical Peak Pricing (CPP) for >20 kW customers  Two opt-out windows provided  Bill protection for one year  Capacity Reservation Charge option Peak Time Rebate (PTR) program for residential customers  Customer receives an incentive ($ per kWh basis) for the amount of reduction provided below the customer’s specific baseline during PTR event hours.  Customer’s baseline: historical usage, adjusted for temperature  Two-tier incentive structure: higher incentive payment for customers who install demand response technology  SCE’s GRC application will be filed in March 2008  Default CPP and PTR anticipated in SCE’s filing

CEC Load Management Standards Workshop March 3, Rate Cases and Dynamic Pricing  PG&E’s Dynamic Pricing Proceeding: Objective: to create a year-by-year strategic work plan that will direct PG&E to develop and integrate dynamic pricing rates into PG&E’s rate design for all customers by The strategic work plan should answer three questions: 1) What types of dynamic pricing tariffs should PG&E offer to its customers? 2) When should PG&E offer each type of dynamic pricing tariffs to each customer class? 3) How should the dynamic pricing tariffs be designed and integrated into PG&E’s overall rate design?

CEC Load Management Standards Workshop March 3, Rate Cases and Dynamic Pricing  PG&E’s Dynamic Pricing Proceeding (con’t): Highlights from the Draft Timetable for PG&E Rate Proposals: Residential Rates:  If AB1X remains in place: default PTR w/ flat rate or opt-in TOU/CPP in 2010  Post-AB1X: default TOU-CPP with opt-out to TOU or flat rate (one year after AB1X ends) Small/Medium C&I: default TOU-CPP in 2010 with opt-out to TOU. No flat rate option Large C&I: Choice of TOU-CPP or RTP in 2010, with opt-out to TOU  In 2011, default RTP with opt-out to TOU or CPP Small/Medium Agriculture: default TOU in 2010 with opt-out to TOU or flat rate Large Agriculture: Choice of CPP or RTP in 2011, with opt-out to TOU For more details see Commissioner Chong’s Jan. 23 Ruling:

CEC Load Management Standards Workshop March 3, Demand Response Programs  Utility DR Programs are currently funded on a three-year budget cycle (’06-’09)  Utility DR portfolio has different triggers (day-of, day-ahead, emergency), incentive structures (capacity payments, energy payments or both) and operators (utility or 3 rd -party aggregator)  Enabling technologies starting to play a larger role in utility DR portfolios:  PG&E AC Cycling Program: customers may opt for the installation of Programmable Communicating Thermostat (PCT)  Auto-DR Program – showing promising results  Future DR programs will need to be aligned with CAISO wholesale market design

CEC Load Management Standards Workshop March 3, Enrolled 1 MWs in Utility Demand Response Programs July 2003July 2005Dec % DR Goal Emergency-triggered Programs 1,485 MWs1,600 MWs1,800 MWsN/A Price-Responsive Programs 0 MWs800 MWs ,125 MWs 2,500 MWs 3 [1] “Upper-bound” estimates except for the 465 MWs referenced by footnote [2]. [2] Represents actual MWs: estimate based on past performance or other methods (no formal method at this time on how to estimate actual load impacts) [3] 5% of an assumed 50,000 MWs of system peak demand – illustration purposes only For more information on CPUC staff’s proposed DR goals for 2009 and beyond see:

CEC Load Management Standards Workshop March 3, Demand Response Programs  Utilities’ DR portfolio proposals (’09-’11) are due in June 2008:  CPUC guidance to the utilities for their portfolio included:  Emphasis on alignment with CAISO MRTU framework and operation  Integration of DR and EE in customer outreach/marketing  Expansion of programs that provide enabling technology: AutoDR for example  Find ways for customers to participate in both DR incentive programs and dynamic pricing tariffs without ‘double-dipping’.  Encourages pilot programs that explore new ideas. For example, DR following intermittent load (renewables)  Criteria by which IOU’s DR portfolio will be evaluated by the CPUC  For more details see:

CEC Load Management Standards Workshop March 3, Forecasting, Measurement and Evaluation Tools  CPUC 2007 DR Rulemaking: Load Impact (LI) Protocol and a Cost- Effectiveness (CE) Protocol  LI Protocol provides data for:  Long-term planning and Resource Adequacy purposes  Day-to-day operational and procurement needs (CAISO or utility)  Settlement purposes: accurately calculate the load drop to fairly compensate DR participants  CPUC proposed decision on a LI protocol (for long-term planning purposes) is expected in the near term.  Outputs from the LI protocol are inputs (benefits) for the CE Protocol.  CPUC is considering a proposed settlement on a CE protocol in its rulemaking.  CPUC anticipates that a CE protocol will be in place to evaluate the utilities’ ’09-’11 DR portfolio proposals

CEC Load Management Standards Workshop March 3, Contact Information: Bruce Kaneshiro Supervisor, Demand Response Programs California Public Utilities Commission