DR issues in California discussed last year in March

1. DR issues in California discussed last year in March • Historical DR in California: some background issues • Twenty years of programs/tariffs I/C and AC cycling (mostly) • Loads in California • Interruptible contracts for many years • The Vision of DR in California • Current MW “available” from DR • Efforts to promote DR • Various tariffs are available • CPUC seems inclined to make CPP mandatory for all customers this summer, excluding those on interruptible contracts • Statewide Pricing Pilot • Business Cases for Automated Metering Infrastructure • Filings on March 15 • Valuing DR in different time frames (long-term, day-ahead, real time, etc.)

2. A year later • The attempt to implement price sensitive DR has moved more slowly than some would like • Rate Design and rate offerings in California • Large customers • DR funding • A settlement has been reached but not yet approved by CPUC • Advanced Metering Infrastructure continues thru the CPUC review process for PG&E • Standard method of evaluating DR cost effectiveness • Has been deferred to a different proceeding • An update of Standard Practices Manual • Demand Response Research Center • Programmable Communicating Thermostats – incorporating into California Building Standards in 2008 • Workshops currently underway • And relationship of all of this to Resource Adequacy Requirement at the CPUC

3. DR Policy • Joint Proceeding – CEC and CPUC (R.02-06-001) • Peevey, Rosenfeld and McPeak • Working Group 2 > 200 kW • All have interval meters and TOU tariff • 26 MW on CPP tariff • Working Group 3, Residential and Small Commercial • 2,500 customers in a Statewide Pricing Pilot (SPP) • Utility Business Plans for Automated Meter Infrastructure • In preliminary filings, PG&E and Sempra appear favorable toward AMI; SCE disinclined • Early Goal for Price Sensitive Demand Response • ~ 1% per year = 5% 5 years after t=0

4. Vision – Customer Choice • If economic, customers should have a choice of the following rates: • Residential and Small Commercial (< 200 kW) • Default: Critical Peak Pricing • Options: Time Of Use • Large Customers (200 kW to 1 MW) • Default: Critical Peak Pricing • Options: Time Of Use, Real Time Pricing • Very Large Customers (> 1 MW) • Default: Real Time Pricing • Options: Time Of Use, Critical Peak Pricing • Early Goal for Price Sensitive Demand Response • ~ 1% per year or ~ 4% of 45 GW or 1,800 MW by 2006

5. Large Customers and Price Sensitive Demand • Demand Bidding and Critical Peak Pricing have been offered to all large customers for the last two summers • However, these are not very popular • ~ 30 MW for CPP • ~ 100 MW for Demand Bidding • The CPUC is considering making CPP the default tariff for large customers, possibly after the summer of 2006. A decision is expected within a month or two.

6. DR funding levels and estimated enrollment • Settlement is before the CPUC • Sets three year funding levels for DR at: • PG&E $109 million • SCE $101 million • SDG&E $53 million • With expected enrollment by 2008 (based on utility filings) • PG&E 876 MW • SCE 1,911 MW • SDG&E 384 MW • Many different programs/tariffs • In 2006, about 1,800 MW of response will be available but most of this is not considered “price sensitive demand response” • The 5% goal likely will be reconsidered

7. Advanced Metering Infrastructure • PG&E proposes to install new electronic meters with communication for all customers • CPUC in the process of reviewing this application • Hearings are on-going • Of specific interest might be: • Tariff structure (voluntary and a rider on existing tariffs) • Expected response to CPP tariff (enrollment and response) • How to value such response (avoided cost, value of combustion turbine) • SDG&E expected to file AMI application within a few months

8. More Generally: CPUC and DR • By April 3, 2006, CPUC staff shall prepare a set of draft protocols for estimating load impacts from DR • coordinated with R.01-08-028, and R.04-04-003, • The draft should address whether the load impacts of all types of demand response programs (e.g., bidding programs, time-differentiated tariffs, reliability programs, interruptible tariffs) should be measured by the protocols. The draft protocols should include • a list of data that must be collected on energy use or customer load profiles, • program capital and operating costs, and incremental customer costs, including comfort changes or customer costs during curtailments. • Staff shall propose a rulemaking or recommend an alternative procedural approach for Commission consideration no later than six months after the draft protocols are circulated.

9. Programmable Communicating Thermostats • Could respond in an automated manner to price or system emergency signals • For emergencies, response could not be overridden • With exceptions for certain customers • Current Thinking about the PCT • One PCT for all of CA (US) • Retail purchased at hardware stores • Consumer owned, installed, maintained • Common signaling throughout California • Works with any minimum AMI system • Signals synched with AMI resolution • Compatible with legacy technologies • However, at a recent workshop considerable concern was raised • Especially, regarding communication infrastructure • Either one or two way communication capabilities • Who controls the signal, be if either price or emergency

10. Demand Response Research Center • 2 Research Opportunity Notices were issued and contracts let • Establish the Value of Demand Response • Develop an Integrated Efficiency / Demand Response Framework • Demand Response Rates and Program Design • Reports are in; some additional work forthcoming next month • http://drrc.lbl.gov/

11. Resource Procurement and DR • CPUC will require all load serving entities to contract in advance to meet 115% to 117% of monthly peak load • DR can count if it meets certain requirements • Available for at least 48 hours during a summer • However, if a 2 hour response (possibly air conditioning cyclers) could only count to a maximum of 0.89% of monthly peak • Still figuring out who how to coordinate who determines when these are used (the CAISO or the load serving entity, for example) • Non-dispatchable DR simply reduces demand forecast • Some effort expected to develop a forward capacity market • Some debate about how the requirement will impact energy market prices