Powerpoint Presentation

PG&E Corporation: Customer Focused, Value Driven

Investor Meetings

June 23 – July 7, 2006

This presentation contains forward-looking statements regarding management's guidance for PG&E Corporation's 2006 and 2007 earnings per share rom operations, capital expenditures, Pacific Gas and Electric Company’s (Utility) rate base and rate base growth, anticipated costs and benefits from Transformation initiatives, anticipated electric resources, and targeted average annual growth rate for earnings per share from operations, over the 2006-2010 period. These statements are based on current expectations and various assumptions which management believes are reasonable, including that substantial capital investments are made in Utility business over the 2006-2010 period and that the Utility earns an authorized return on equity of 11.35%. These statements and assumptions are necessarily subject to various risks and uncertainties the realization or resolution of which are outside of management's control. Actual results may differ materially. Factors that could cause actual results to differ materially include:

•

Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility’s ability to earn its authorized rate of return;

•

How the Utility manages its responsibility to procure electric capacity and energy for its customers;

•

The adequacy and price of natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the natural gas market for its

customers;

•

The operation of the Utility’s Diablo Canyon nuclear power plant, which could cause the Utility to incur potentially significant environmental costs and

capital expenditures, and the extent to which the Utility is able to timely increase its spent nuclear fuel storage capacity at Diablo Canyon;

•

Whether the Utility is able to recognize the anticipated cost benefits and savings to result from its efforts to improve customer service through

implementation of specific initiatives to streamline business processes and deploy new technology;

•

The outcome of proceedings pending at the Federal Energy Regulatory Commission and the California Public Utilities Commission (CPUC),

including the Utility’s 2007 General Rate Case and the CPUC’s pending investigation into the Utility’s billing and collection practices;

•

How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC’s decisions permitting the

establishment of holding companies for the California investor-owned electric utilities, and the outcome of the CPUC's new rulemaking proceeding
concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates;

•

The impact of the recently adopted Energy Policy Act of 2005 and future legislative or regulatory actions or policies affecting the energy industry;

•

Increased municipalization and other forms of bypass in the Utility’s service territory; and

•

Other factors discussed in PG&E Corporation's and Pacific Gas and Electric Company’s SEC reports.

Cautionary Statement Regarding Forward-Looking Information

Objectives for Today’s Discussion

•

Update PG&E's long-term business prospects, opportunities, and risks, within the context of our long-term business priorities

•

Provide an understanding of our Transformation effort and its impact in defining the furure of PG&E

•

Articulate how PG&E's investment opportunities and customer-centric operational goals translate to shareholder value

•

Communicate the commitment to deliver on that plan

PG&E Corporation: A Value Opportunity

•

A wholly regulated utility offering a stable platform for growth

Stability: • minimum authorized equity ratio: 52%

• minimum authorized ROE: 11.22%

• pass-through for procurement costs

• balancing account for sales variability

Regulated growth: • utility infrastructure investments

• solid rate base growth

• strong cash flow

Electric and gas distribution customers	5 MM electric 4.2 MM gas
Electric transmission circuits	18,616 miles
Gas transmission backbone	6,128 miles
Electric generation capacity	6,420 MW

Pacific Gas and Electric Company (PG&E)

•

2005 marked the 100^th anniversary of PG&E

•

Provides energy to nearly 1 in 20 people in the U.S.

•

70,000 square-mile service territory

Business Priorities 2006-2010

Advance business transformation

Provide attractive shareholder returns

Increase investment in utility infrastructure

Implement an effective energy procurement plan

Improve reputation through more effective communications

Evaluate the evolving industry and related investment opportunities

We act with integrity and communicate honestly and openly.

We are passionate about meeting our customers’ needs

and delivering for our shareholders.

We are accountable for all of our own actions: these include

safety, protecting the environment, and supporting our communities.

We work together as a team and are committed to excellence and innovation.

We respect each other and celebrate our diversity.

The

leading
utility in the
United States

Delighted Energized Rewarded

customers employees shareholders

Our values

Operational excellence

Transformation

Our strategies

Our goals

Our vision

Strategic Direction

Satisfied

Regulators

Rewarded

Shareholders

Delighted

Customers

OUR VISION

The leading utility
in the United States

The Virtuous Circle

Operational

Excellence

Understand the

Customer

Technology/

Innovation

•

Standardization prevails

•

Relentless focus on efficiency

•

Responsive to customer expectations

•

Deliver new products and services

•

Use of technology to drive operational excellence

•

Innovation to lower cost and satisfy customers

Transformation Vision

Implementation

& Operational
Handover

Build/

Test

Detailed

Design

Preliminary

Design
& Analysis

Strategy/

Roadmap

Planned deployment of initiatives:

•

2005: 20 initiatives were fully or partially deployed

•

2006: 33 other initiatives will be fully or partially deployed

Transformation Phases

Today (Manual)

Future (Automated)

New Residential Service

–

Developer prepares electronic application for new service

–

Single system entry of project information

–

Central job estimation with specialized team focusing on

subdivisions

New Residential Service

–

Developer completes paper application for new service

–

Multiple groups record and track project

–

Local estimation of project

Outage Management

–

Customer notifies the utility of a problem

–

Troubleman assesses scope of outage

–

Customized construction information prepared

Outage Management

–

Utility systems immediately locate a problem

–

Troubleman uses on-line records to prepare job

information and specify material required for repair

Work and Resource Management

–

Integrated systems mobilize the right resources, at the

right capacity

–

Electronic job information provided to work crews

–

Prepackaged material delivered on time to job site

–

Work crew updates records remotely

–

Supervisor is in the field to coach and assist crews

Work and Resource Management

–

Supervisor schedules crews and assembles job

information for crews

–

Paper job packages provided to work crews

–

Work crew gathers needed materials

–

Manual updates to multiple systems

•

Improve

infrastructure

•

Deploy new

technology

•

Revamp

business
processes

•

Instill a

competitive,
customer-fo
cused mindset

Transformation Enhancing Performance - Examples

Anticipated Transformation Net Costs and Benefits

Net Cost Range

Net Benefit Range

	2005 EOY Actual	2006 Q1 Actual	2006 Q1 Target	2006 EOY Target
Overall customer satisfaction surveys)	94.0	94.5	94.0	96.0
Timely bills (% billed within 35 days)	99.38%	99.53%	99.53%	99.51%
Estimate of outage restoration time accuracy (% accurate)	47%	64%	50%	50%
System Average Interruption Duration Index (yearly minutes per customer)	178.7	67.6	46.0	166.0
System Average Interruption Frequency Index (yearly interruptions per customer)	1.34	0.43	0.33	1.31
(composite of owned generation and procured energy availability) Energy availability ¹	n/a	2.0	1.7	1.5
Telephone service level (% answered within 20 seconds)	75%	76%	73%	76%
Expense per customer ² ($ cost of operations per customer)	$278	$75	$74	$283
Diablo Canyon performance index ³ (composite of plant performance metrics)	94.7	95.2	94.9	94.0
Employee Premier Survey index ⁴ (composite of employee satisfaction Premier survey metrics)	64%	n/a	n/a	68%
Lost workday case rate (lost workday case rate per 100 employees)	1.04	0.47	0.45	0.88

(1) Metric is first applicable in 2006. (2) The reconciliation of non-GAAP cost of operations to operating and maintenance expense can be found in the Appendix and at www.pge-corp.com.

(3) 2005 results have been restated to maintain consistency with the actual and target values based on the recently revised industry calculation methodology. (4) Based on an annual survey.

Operational Performance Metrics

* Reg G reconciliation to GAAP for 2005 EPS from Operations and 2006 and 2007 EPS Guidance available in Appendix and at www.pge-corp.com

Operating EPS Assumptions ($MM)

2006 2007

Rate Base                           $15,900     $17,400
Equity Ratio                            52%          52%
Authorized ROE                    11.35%      11.35%
Carrying Cost Credit               ($66)          ($52)
Holding Company Interest        ($16)          ($16)

EPS Guidance

•

EPS from Operations*: 2006 guidance of $2.40-$2.50 per share

2007 guidance of $2.65-$2.75 per share

Source: Zacks Investment Research, Inc. survey of analyst estimates (June 20, 2006)

EPS Growth

•

EPS from operations growth targeted to average approximately 7.5% annually 2006-2010

•

Actual growth rate will depend on infrastructure investments

PG&E Corporation has consistently outperformed S&P 500 and Dow Jones Utility Indices

Long Term

Stock Price Performance

and

YTD 2006

Dividend Policy

•

Objectives

–

Flexibility

–

Sustainability

–

Comparability

•

Dividend payout ratio range of 50-70%. Current payout in the low 50s and expected to grow roughly in line with EPS growth rate

•

Growth balanced with funding for additional investment opportunities

Capital expenditures average $2.5B for years 2006-2010:

($BN)

2.5 2.8 2.6 2.4 2.2

Capital Expenditure Outlook

Distribution

Generation

Electric Transmission

Gas Transmission

CC8

SmartMeter™(AMI)

Common Plant

* 2006-2010 rate base is not adjusted for the impact of the carrying cost credit that primarily results from the second series of the

Energy Recovery Bonds. Earnings will be reduced by an amount equal to the deferred tax balance associated with the regulatory
asset, multiplied by the utility's equity ratio and by its equity return. The carrying cost credit declines to zero when the taxes are fully
paid in 2012.

Rate Base Growth

Potential Additional Capital Expenditures

Potential additional capital expenditures related to the following possible projects are not included in the capital expenditure projections:

•

657 MW utility-owned generation submitted to the CPUC for

approval as part of the long-term procurement plan

•

Electric transmission system upgrades and expansion (e.g., Sea

Breeze, Tehachapi)

•

Gas transmission system upgrades and expansion

Energy Procurement Overview

•

Procurement plan intended to meet customer need for reliable

energy in an environmentally-responsible and cost-effective
manner

•

Energy efficiency and renewables are highest priority in

California “loading order”

•

Offers solicited for short, intermediate and long-term resources

The parties’ material obligations under these agreements are conditioned upon CPUC approval of the agreements and applicable ratemaking

mechanisms. The agreement related to the Calpine Hayward project is a letter of intent to execute a Power Purchase Agreement (PPA). The
execution of the PPA is subject to certain financial conditions, including that the associated Calpine entity emerge from bankruptcy or transfer the
project site to a bankruptcy remote entity. If these conditions are not satisfied by October 2006, the letter of intent will terminate.

Capital expenditures for the utility-owned generation are estimated to be in the range of $900 – 1,100 per KW.

Executed Agreements Pursuant to Long-Term RFO

*	Approximately 20% of total retail sales expected to be eligible renewable

resources coming from utility-owned, QF, Irrigation District, and other sources.

**	Includes 150MW Humboldt Bay repowering and utility-owned renewables.

***	May include utility-owned resources.

*	Approximately 12% of total retail sales are supplied by eligible renewable resources coming from utility-owned, QF, Irrigation District, and other sources.

Long-Term Electric Resources

Effective Communications

•

Strengthening communications with our stakeholders:

–

Employees

–

Customers

–

Policymakers

–

Investors

Evaluating the Evolving Industry

•

Trends:

–

Recent industry consolidation

–

PUHCA reform

–

Restructuring

–

Renewed M&A dialogue

•

Monitoring M&A and investment activity

•

Primary focus is on developing good momentum in Transformation

Conclusion

•

PCG: a value opportunity with stability and solid growth prospects

–

$12.5B of capital expenditures through 2010

–

Rate base more than $20B by 2010

–

Strong cash flow

•

A focus on operational excellence

–

Transforming operations to provide better, faster and more cost effective service

Appendix

•

Reg G Reconciliation / Financial Profile

•

Company Overview and Definitions

*	Earnings per share from operations is a non-GAAP measure. This non-GAAP measure is used because it allows

investors to compare the core underlying financial performance from one period to another, exclusive of items that
do not reflect the normal course of operations.

2005 EPS - Reg G Reconciliation

2005 EPS on an Earnings from Operations Basis $2.34

Items Impacting Comparability:

Incremental interest costs related to generator disputed claims from Chapter 11 proceedings (0.01)

Prior year’s portion of the gain associated with AEAP settlement 0.24

Costs of chromium litigation settlement and accruals for unresolved claims (0.23)

Gain from tax adjustments related to NEGT 0.03

2005 EPS on a GAAP Basis $2.37

EPS Guidance - Reg G Reconciliation

2006	Low	High
EPS Guidance on an Earnings from Operations Basis*	$2.40	$2.50
Estimated Items Impacting Comparability	0.00	0.00
EPS Guidance on a GAAP Basis	$2.40	$2.50

2007	Low	High
EPS Guidance on an Earnings from Operations Basis*	$2.65	$2.75
Estimated Items Impacting Comparability	0.00	0.00
EPS Guidance on a GAAP Basis	$2.65	$2.75

* Earnings per share from operations is a non-GAAP measure. This non-GAAP measure is used because it allows investors to compare the core underlying financial performance from one period to another, exclusive of items that do not reflect the normal course of operations.

*	Total expense per customer is a non-GAAP measure. This non-GAAP measure is used because it is an indicator of

overall efficiency and productivity in delivering energy to PG&E customers.

Cost of Operations - Reg G Reconciliation

The reconciliation of non-GAAP cost of operations to Operating and Maintenance Expense is:

Estimated Average Deferred Tax Balances and Carrying Cost Credit Impacts ($MM)

* Rate Reduction Bonds are fully retired at the end of 2007.

Estimated carrying cost credits assume a utility equity ratio of 52% and ROE at 11.35%.

	2006	2007	2008	2009	2010	2011	2012
Rate Reduction Bond and Energy Recovery Bond Average Deferred Tax Balance	$1,125	$878	$683	$542	$396	$242	$82
Estimated Carrying Cost Credit *	($66)	($52)	($40)	($32)	($23)	($14)	($5)

Carrying Cost Credit Impacts

Credit Profile

•

Current Ratings

–

Utility issuer rating: BBB (S&P) and Baa1 (Moody’s)

–

Utility unsecured debt: BBB (S&P) and Baa1 (Moody’s)

•

Average Metrics (2006-2010)*

–

S&P Business Profile Rating: 5

–

Total Debt to capitalization (EOY): 53.5%

–

Funds from Operations Cash Interest Coverage: 5.1x

–

Funds from Operations to Average Total Debt: 25%

* Metrics include debt equivalents for long-term power purchase contracts.

Pacific Gas and Electric Company (PG&E)

•

Authorized rate of return: 11.35%

•

Projected 2006 rate base: $15.9B

•

Adjustment mechanisms for sales levels and procurement cost differences from revenue requirements

–

Balancing accounts to track over- and under-collections

•

2005 rate base levels:

–

Electric and gas distribution - $9.9B

–

Electric transmission - $2.0B

–

Natural gas transmission - $1.5B

–

Electric procurement and owned generation - $1.7B

(1) Authorized revenues = operating costs + (rate of return x rate base)

Rate base = net plant ± adjustments to approximate invested capital

Electric & Gas Distribution

Business Scope

•

Retail electricity and natural gas distribution service (construction, operations & maintenance)

•

Customer services (call centers, meter reading, billing)

•

5 million electric and 4.2 million gas customer accounts

•

Service territory covers 70,000 square miles and 47 counties

Primary Assets

•

$9.9 billion of rate base (2005 wtd. avg.)

Revenues/Margins

•

Cost of service ratemaking ⁽¹⁾

•

Formulaic attrition revenue increases (through 2006)

•

Revenues stabilized by sales balancing accounts

Existing

500 kV

18,616 circuit miles of

electric transmission lines

Electric Transmission

Business Scope

•

Wholesale electric transmission services (construction,

maintenance)

•

Operation by CA Independent System Operator

Primary Assets

•

$2.0 billion of rate base (2005 wtd. avg.)

Revenues/Margins

•

Cost of service ratemaking under FERC

•

Significant growth in rate base

•

Revenues vary with system load

•

6,128 miles of backbone transportation import

capacity of 2.0 BCF/day Canadian gas,
1.1 BCF/day Southwest gas

•

Three storage facilities with 42.0 BCF cycle

capacity

Natural Gas Transmission

Gas Transmission Business Scope

•

Natural Gas transportation, storage, parking and

lending services

•

Customers: PG&E’s natural gas distribution and

electric generation businesses, industrial customers,
California electric generators, and marketers

Primary Assets

•

$1.5 billion of rate base (2005 wtd. avg.)

Revenues/Margins

•

Incentive ratemaking framework (Gas Accord)

•

Revenues vary with throughput

Helms

Pumped
Storage

Humboldt

Diablo Canyon

Nuclear Plant

Conventional

Hydroelectric
facilities

Electric Procurement and Owned Generation

Business Scope

•

Electricity and ancillary services from owned and controlled

resources

•

Energy procurement program

Primary Assets

•

Diablo Canyon nuclear power plant ( 2,174 MW)

•

Largest privately owned hydro system (3,896 MW)

•

$1.7 billion rate base (2005 wtd. avg.)

•

Funded nuclear plant decommissioning trusts of $1.6 billion

Revenues/Margins

•

Cost of service ratemaking for utility owned generation

•

Power procurement cost recovery in place

•

2,250MW of new generation to be owned/contracted by 2010

Gas Customers: 4.2MM

Electric Customers: 5MM

Customer Profiles by Usage

Electric Sales Outlook

Electric sales growth forecasted to average 1.2% during 2006-2010

Gas Sales Outlook

Gas sales growth forecasted to average 1.1% during 2006-2010

*	Approximately 12% of total retail sales are supplied by eligible renewable

resources coming from utility-owned, QF, Irrigation District, and other sources.

PG&E: Existing Resource Mix

•

Owned generation Type Net Capacity (MW)

–

Diablo Canyon Nuclear 2,174

–

Hydroelectric facilities Hydro 3,896

–

Humboldt Fossil 350

–

Total 6,420

•

2005 sources of electric energy*

Comparative Energy Procurement Costs

Current Ratemaking

•

Distribution – Next General Rate Case (GRC) applies to 2007-2009

•

Electric Transmission – Rates set at FERC through Transmission Owner cases

•

Gas Transmission and Storage – Rates set through Gas Accord framework through 2007

•

Generation – Cost-of-service ratemaking with existing generation covered through the GRC

Key Pending Regulatory Proceedings

•

Pending approval

–

PG&E SmartMeter™ (AMI) Decision expected 7/06

–

Cost of Capital Waiver Application Decision expected Q3 2006

–

2007 GRC Decision expected 12/06

–

Generation LT RFO & Humboldt Bay PP Decision expected end of 2006

•

Pending investigation

–

Billing and Collection OII Decision expected Q4 2006

•

Anticipated filings

–

Gas Transmission rates (post 2007) Filing expected late 2006

Definitions of Transformation Metrics

Overall Customer Satisfaction. PG&E measures residential and business customer satisfaction with annual industry wide surveys conducted by J.D. Power and Associates, as well as with proprietary studies using the same survey in intervening quarters. For this overall customer satisfaction measure, the four residential scores are averaged into one score and, similarly, the four business scores are averaged and then the two averages are combined with equal weighting.

Timely Bills. Customers expect timely bills. This metric measures the percentage of bills that have been issued timely to customers (within 35 days of the last scheduled meter read).

Estimated Time of Outage Restoration Accuracy. Estimated Time of Restoration measures how accurately PG&E provides outage information to customers during the early stages of an outage. The metric calculates if the first restoration estimate given to customers (the estimate is provided as a two hour window) is accurate for the majority of the initial customers interrupted.

System Average Interruption Duration Index. SAIDI represents the average outage time that each PG&E customer experiences over a one year period due to sustained outages.

System Average Interruption Frequency Index. SAIFI represents the average number of sustained outages that each PG&E customer experiences over a one year period.

Total Energy Availability. The Energy Availability measure combines two separate reliability measures, each equally weighted. One assesses whether PG&E-owned generation is available as planned and the other assesses whether PG&E has obtained adequate electric supplies for its customers, as measured by CAISO alerts.

Definitions of Transformation Metrics (continued)

Telephone Service Level. TSL measures the percent of customer calls to the contact centers that are answered within a specified number of seconds and is a measure of the responsiveness to customer calls.

Expense per Customer. The average annual cost of operations per customer includes all budget expense items, including business unit and corporate service department expenses, casualty, benefits, severance and insurance. This measurement excludes capital-related costs such as depreciation and interest, and the commodity costs of gas and electricity. The denominator is defined as the total average number of gas and
electric customer accounts for the year.

Diablo Canyon Performance Index. The Diablo Canyon Composite Performance Index is intended to provide a quantitative indication of plant performance in the areas of nuclear plant safety and reliability and plant efficiency.

Employee Opinion. The “employee index score” was created to measure overall change in employee satisfaction and engagement across the enterprise and is derived by using the overall score from the Premier survey, which is distributed to all employees on an annual basis.

Lost Workday Case Rate. This metric measures the number of non-fatal injury and illness cases that (1) satisfy OSHA requirements for recordability, (2) occur in the current year, and (3) result in at least one day away from work. The rate measures how frequently new lost workday cases occur for every 200,000 hours worked, or for approximately every 100 employees.