About Pacific Gas and Electric Company

1. SmartMeter Program Update- Operational Benefits Realization - Jim Meadows, Program DirectorAugust 2007

2. About Pacific Gas and Electric Company • Energy Servicesto about 15 M People • 5.0 M Electric Customer Accounts • 4.1 M Natural Gas Customer Accts • 70,000 Square Miles • ~20,000 Employees • Regulated by theCalifornia Public Utilities Commission (CPUC). • Incorporated in 1905

3. The PG&E SmartMeter program: • will deploy a system for automated meter reading – hourly meter reads for electric, and daily meter reads for gas • includes two separate systems: a power line carrier system for electric and a radio frequency system for gas • involves an upgrade to both gas and electric meters – approximately 10 Million meters will be upgraded • will be deployed over a five year period. An initial, paced deployment began in Bakersfield in November, 2006. Deployment efforts are scheduled to conclude in late 2011 • will introduce additional capabilities over time, including outage management and remote connect/disconnect • will enable the introduction of demand-response rates for residential and small business customers

4. Customers • Receive usage informationto better understand and manage their bills, and be able to participate in future energy efficiency and demand response programs • Experience less inconvenience and intrusion by no longer needing to unlock gates and tie up dogs for monthly meter reads • Reduction in the causes of delayed, inaccurate and estimated bills • Experience faster outage detection and restoration times • Opportunity to turn service on and off remotely • PG&E • Reduced operating costs • Reduced peak loads when customers shift to non-peak energy use and when they conserve (demand response) • Lower procurement costs resulting from reduced peak load and enhanced load modeling • Improved customer satisfaction stemming from enhanced customer service capability • Improved billing efficiency • Improved outage management • Reduced energy theft • CPUC/State • Supports the CPUC’s price-responsive tariff requirements Smartmeter Program Has A Range Of Benefits

5. Costs < Benefits 90% of costs SmartmeterProgram Will Pay For Itself Costs* Benefits* Remote turn on / off Outage detection Service restoration Avoided dispatches / truck rolls Call volume reductions Records exception reductions Complex billing Capacity planning Demand Response O&M Operations ISTS Deployment $189M Meters Networks Installations IT Systems System Integration Project Management ISTS O&M $191M Field Deployment $1,299M Meter Reading • The SmartMeter program has a positive business case: Projected benefits exceed projected costs over a 20 year program life • Operational efficiencies (including meter reading savings) cover 90% of program costs • Demand response benefits (i.e. procurement cost savings)cover approximately 10% of program costs and promise to provide additional benefits in excess of costs * 20 year Present Value of Revenue Requirement

6. 90% Of Smartmeter Program Costs Covered By Operational Benefits Breakdown of Operational Benefits By Benefit Area Total annual benefit from operations (at full deployment) = $160.5 Million

7. Activated Meter Commitment to CPUC • Once meters are activated, we pay either $1.77 or $1.04 to the SM balancing account each month.

8. Meters are activated in batches, by virtual route string Once a meter is activated, actual meter reading benefits begin to accrue An “Activated” Meter Has Several Characteristics • Installed: the endpoint equipment (meter for electric, module for gas) has been placed on customer premises • Readable: the SmartMeter system communicates with the endpoint equipment • Billable: the billing system can use interval data collected through SmartMeter to bill the customer • Part of a virtual meter reader route string: the meter reader can be re-deployed when the virtual route string is removed from the manual meter reading workload

9. Activated Meters Lifecycle Meter/Network Installed SM Enabled SM Read QA / Anchor Billed Meters Eligible For Activation Completed Routes Virtual Route String Benefits Realizations • Network installed with serial diversification • Endpoints installed with serial diversification • Updates to billing system • Customer account changed to “SM enabled” • Meters become searched in SM system • Billing system performs validation • Electric meters take longer to search in than gas meters • Customer account changes to “SM read” • Last manual meter read • Visual inspection to QA SM installs • Customer billed on manually collected anchor reads • Service plan transition from manual meter reading route to SM route • Customer accountson a SM route are part of a pool of meters eligible for activation • A “complete” route is an manual meter reading route with zero meters • Can create a completed route with limited number of meters (Excludables, UTCs, other meters out of scope) via either “closed routes” benefits functionality or manual re-routing • Consists of manual meter reading routes with zero meters (i.e. completed routes) • One completed route for each serial • Captured in reports • Meters are activated • Committed to the CPUC for benefits associated with activated meters, by writing monthly checks utilizing SM balancing account ($1.77 each electric meter, $1.04 each gas meter) • Release meter readers

10. Meter Routes Progress

11. Benefits Realization For Meter Reading • Meter reading benefits account for the bulk for program benefits - 53% of SmartMeter operational (i.e. non demand response) benefits; 46% of total benefits • Benefits are booked in abalancing account as soon as the meter is “activated” – PG&E cuts a check to the balancing account • Meter reading benefits can only be realized once a meters on a virtual route string are activated or transferred to a different route • Virtual route string = routes with different serials • Meters are activated only after they are: installed, readable, billed, part of a completed virtual route string • PG&E fine tunes installation activity to complete virtual route strings as soon as possible

12. Customers • PG&E • CPUC/State • Real time energy usage data to premise from meter • Building automation • Home energy/bill management tools and systems • Smart thermostat (programmable communicating thermostat – PCT) • Appliance control and monitoring • In-home displays • Direct load control (air conditioner, water heater, pool pump, etc.) • CPP and other demand response programs and rates • Targeted regional/area TOU programs • Smart thermostat control (programmable communicating thermostat – PCT) • Distribution planning • Distribution voltage management • Gas system planning • Pre-pay metering • Distribution fault detectors • Capacitor bank controls • Transformer load monitoring • Meter health monitoring • Preventive line maintenance data (momentary) • Identification of facility performance or customer usage anomalies • System load forecasting and settlement • Enhanced outage data management • Energy load research program flexibility • Gas distribution maintenance (e.g. cathodic protection monitoring) • Energy resource planning • Data for ISO system control • Load control programs • Demand response programs In The Future, The Smartmeter Program Could Enable The Following Potential Capabilities