SmartMeter Program Update- Operational Benefits Realization -

Jim Meadows, Program Director

August 2007

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About Pacific Gas and Electric Company

► Energy Services to 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 the California Public Utilities Commission (CPUC).

► Incorporated in 1905

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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

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Customers► Receive usage information to 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

Smartmeter Program Has A Range Of Benefits

► 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

PG&E

► Supports the CPUC’s price-responsive tariff requirements

CPUC/State

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ISTS O&M $191M

FieldDeployment

$1,299M

ISTSDeployment

$189M

Meter Reading

Operations

Costs*

Meters

Networks

Installations

IT Systems

System Integration

Project Management

O&M

Demand Response

Benefits*

Smartmeter Program Will Pay For Itself

Remote turn on / off

Outage detection

Service restoration

Avoided dispatches / truck rolls

Call volume reductions

Records exception reductions

Complex billing

Capacity planning

Costs < Benefits

90% of costs

► 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

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53%

12%

12%

7%

5%

4%3% 2%2%

Meter Reading Savings

Other Employee-Related Costs

Billing Benefits

Remote Turn-on & Shut-off

Metering Operations

Outage Restoration

Avoid Dispatch (Power is On)

Reduction in Call Volumes

Other (gas and electric T&D capacityplanning, EON retirement)

90% Of Smartmeter Program Costs Covered By Operational Benefits

Total annual benefit from operations (at full deployment) = $160.5 Million

Breakdown of Operational Benefits By Benefit Area

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Activated Meter Commitment to CPUC

Savings Per Activated Meter Electric $ Gas $

  Meter Reader $ (0.8235) $ (0.8223)

  severance   -   -

  Other Employee Related Costs $ (0.1706) $ (0.1705)

  Remote Electric Shut-off Benefits $ (0.1429) $ -

  Avoided TOU Meter Maintenance $ (0.1155) $ -

  Cash Flow on Summary Bills $ (0.0927) $ (0.0225)

  Exceptions Processing $ (0.0809) $ -

  Avoided Dispatch Where Power is On $ (0.0794) $ -

  Significant Outage Restoration-Capital $ (0.0764) $ -

  Significant Outage Restoration-Expense $ (0.0578) $ -

  Lower customer Call Volumes $ (0.0515) $ -

  Deferred Meter Testing $ (0.0445) $ -

  Improved TOU Rate Changes $ (0.0190) $ -

  Momentary Outage Detection $ (0.0106) $ -

  Load Research Capital Savings $ (0.0069) $ (0.0071)

  T&D Capital Savings (gas) $ - $ (0.0143)

  TOTAL Savings/Meter/Month: $ (1.7722) $ (1.0366)

Once meters are activated, we pay either $1.77 or $1.04 to the SM balancing account each month.

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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

Meters are activated in batches, by virtual route string

Once a meter is activated, actual meter reading benefits begin to accrue

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Activated Meters Lifecycle

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

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

Network installed with serial diversification

Endpoints installed with serial diversification

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

Meter/NetworkInstalled

SM Enabled

SM Read

QA / Anchor Billed

Meters Eligible For Activation

CompletedRoutes

Virtual RouteString

BenefitsRealizations

Customer accounts on 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

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Meter Routes Progress

Bakersfield (TC) Maximum Complete by Serial (7/20/07)

83%

72%

88%

65%

79%

98%96%

83%

88%92%

72%

62% 64%

98%

88%

62% 64%66% 67%

61%

98%

77%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

B 81

C 25

D 74

F 30

G 81

H 01

J 11

K 19

L 67

M 05

N 41

P 40

Q 32

R 06

S 83

T 90

V 74

W 58

X 77

Y 30

Z 03

Avg[1]

Serial

Perc

en

t C

om

ple

te

[1] = ( 10,055 / 13,111 ). 31,263 total meters enabled = 3.1 ratio.

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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 a balancing 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

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In The Future, The Smartmeter Program Could Enable The Following Potential Capabilities

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

Customers

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)

PG&E

Energy resource planning

Data for ISO system control

Load control programs

Demand response programs

CPUC/State