exhibit99.htm

PG&E Corporation

European Investor Meetings

June 23 - 27, 2008

This presentation contains forward-looking statements regarding management’s guidance for PG&E Corporation’s 2008 and 2009 earnings per share from operations,
targeted compound average growth rate for earnings per share from operations over the 2007-2011 outlook period, as well as management’s projections regarding
Pacific Gas and Electric Company’s (Utility) capital expenditures, rate base and rate base growth. These statements are based on current expectations which
management believes are reasonable including that the Utility’s rate base averages $18.2 billion in 2008 and $20.3 billion in 2009, that the Utility earns at least its
authorized rate of return on equity, that the Utility’s ratemaking capital structure is maintained at 52 percent equity, and that the Utility is successful in implementing its
initiatives to become more efficient and reduce costs. Actual results may differ materially. Factors that could cause actual results to differ materially include:

§ the Utility’s ability to manage capital expenditures and operating costs within authorized levels and recover costs through rates in a timely manner;

§ the outcome of regulatory proceedings, including pending and future ratemaking proceedings at the California Public Utilities Commission (CPUC) and
the Federal Energy Regulatory Commission;

§ the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and
natural gas markets;

§ the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of
terrorism, and other events or hazards on the Utility’s facilities and operations, its customers, and third parties on which the Utility relies;

§ the potential impacts of climate change on the Utility’s electricity and natural gas business;

§ changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial
market conditions, changes in technology including the development of alternative energy sources, or other reasons;

§ operating performance of the Utility’s Diablo Canyon nuclear generating facilities (Diablo Canyon), the occurrence of unplanned outages at Diablo
Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

§ whether the Utility is able to maintain the cost efficiencies it has recognized from the completed initiatives to improve its business processes and
customer service, and identify and successfully implement additional cost saving measures;

§ whether the Utility incurs substantial unanticipated expense to improve the safety and reliability of its electric and natural gas systems;

§ whether the Utility is able to achieve the CPUC’s energy efficiency targets and timely recognize any incentives the Utility may earn;

§ the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

§ the impact of changing wholesale electric or gas market rules, including the California Independent System Operator’s new rules to restructure the
California wholesale electricity market;

§ how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;

§ the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from
third parties, or through insurance recoveries;

§ the ability of PG&E Corporation and/or the Utility to access capital markets and other sources of credit in a timely manner on favorable terms;

§ the impact of environmental laws and regulations and the costs of compliance and remediation;

§ the effect of municipalization, direct access, community choice aggregation, or other forms of bypass;

§ the impact of changes in federal or state tax laws, policies or regulations; and

§ other risks and factors disclosed in PG&E Corporation’s and the Utility’s 2007 Annual Report on Form 10-K and other reports filed with the SEC.

Cautionary Language Regarding
Forward-Looking Statements

Discussion Outline

§ Overview

§ Financial Update

§ Operational Update

8% CAGR in EPS

PCG: Investment Case

§ PCG offers competitive growth in a constructive
regulatory environment with an attractive valuation:

§ $13 billion planned CapEx 2008-2011

§ 85% of CapEx approved

§ 11.45% weighted ROE on 52% equity

§ High-performing, low-carbon generation

§ Decoupled revenues

§ Sustainable dividend, growing in-line with EPS

PG&E SERVICE AREA
IN CALIFORNIA

Pacific Gas and Electric (PG&E)

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

§ 70,000 square-mile service territory

§ Four main operational units:

§ Electric and gas distribution

§ Electric transmission

§ Gas transmission

§ Electric generation

§ Forward test-year general rate case with
inflation increases

§ CPUC jurisdictional revenues decoupled
from sales

§ Pass-through of electric and gas
procurement costs

6%
Base

5%
Public
Purpose

35%
Base

54%
Electric and gas supply

2007 total revenue protected from sales fluctuations = 94%

Revenue not protected from sales fluctuations

Effect of Decoupling on Revenues

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

Rate base = net plant ± adjustments to approximate invested capital

Business Scope

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

§ Customer services (call centers, meter reading, billing)

§ 5.1 million electric and 4.3 million gas customer accounts

Primary Assets

§ $11.0 billion of rate base (2007 wtd. avg.)

Regulation

§ California state regulation (CPUC)

§ Cost of service ratemaking (1)

Electric And Gas Distribution

Midway

Los Banos

Moss Landing

Diablo Canyon

Gates

Dixon

Malin

Round Mt

Tesia

Vaca

Business Scope

§ Wholesale electric transmission services (construction, maintenance)

§ Operation by CA Independent System Operator

Primary Assets

§ $2.6 billion of rate base (2007 wtd. avg.)

Regulation

§ Federal Regulation (FERC)

§ Cost of Service Ratemaking

§ Revenues vary with system load

Electric Transmission

Business Scope

§ Natural gas transportation, storage, parking and lending services

§ Customers: PG&E natural gas distribution and electric generation

businesses, industrial customers, California electric generators

Primary Assets

§ $1.5 billion of rate base (2007 wtd. avg.)

Regulation

§ California state regulation (CPUC)

§ Incentive ratemaking framework (“Gas Accord”)

§ Revenues vary with throughput

Natural Gas Transmission

Business Scope

§ Electricity and ancillary services from owned and controlled resources

§ Energy procurement program

Primary Assets

§ $1.7 billion of rate base (2007 wtd. avg.)

§ Diablo Canyon nuclear power plant (2,240 MW)

§ Largest privately owned hydro system (3,896 MW)

§ Funded nuclear plant decommissioning trusts of $1.8 billion

Regulation

§ Cost of service ratemaking for utility-owned generation

§ Pass through of power procurement costs

Electric Procurement & Owned Generation

PG&E Vision

2008 Business Priorities

§ Deliver on Financial Objectives

§ Focus on Customer Service and Satisfaction

§ Identify and Capture Operating Efficiencies

§ Ensure Workforce Readiness and Alignment

§ Improve System Reliability

Delivering on Financial Objectives

§ Invest in needed infrastructure

§ Ensure adequate liquidity

§ Meet EPS targets

§ Generate strong cash flow

EPS from Operations*

* Reg G reconciliation to GAAP for 2007 EPS from Operations, and 2008 and 2009 EPS Guidance available in Appendix and at
www.pgecorp.com

Confirming EPS Guidance

§ EPS from Operations Guidance:

§ 2008 guidance of $2.90-$3.00 per share

§ 2009 guidance of $3.15-$3.25 per share

§ 8% targeted CAGR 2007-2011

2007

Base
Forecast
Rate Base

Growth

(+9% to 10%)

Add’l CapEx

(+1 to 3%)

New Shares

(-3% to- 5%)

$2.70-
$2.80

8% CAGR

2007- 2011

10%

2007
Guidance {

Range

% CAGR

2007-2011

$ MM

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

Common Plant

$260

$230

$200

$250

SmartMeter Program

$260

$330

$260

$220

Gas Transmission

$230

$200

$175

$200

Electric Transmission

$550

$580

$660

$750

Generation

$1,100

$750

$530

$260

Distribution

$1,300

$1,200

$1,350

2008

2009

2010

2011

Projects not included in forecasts include: SmartMeterTM Upgrade, Cornerstone Improvement
Program, additional generation and gas pipeline investments, and BC Transmission

$3.7 B

$3.6B

$3.3 B

$3.0 B

$3.2 B

$3.0 B

$3.4 B

Prior Forecast Levels*

* Prior forecast issued December 21, 2007

Capital Expenditure Outlook

• Projected 2008-2011 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 Energy Recovery Bonds regulatory
asset, multiplied by the Utility's equity ratio and by its equity return. This rate base offset carrying cost declines to zero when the taxes are fully paid
in 2012.

**Prior forecast issued December 21, 2007

Rate Base Growth

Additional CapEx

Proposed Projects Above 2008-2011 Base CapEx Forecast

§ SmartMeterTM Program Upgrade

§ $460 MM capital total/ $300 MM capital 2008-2011

§ Approval expected by year-end 2008

§ Cornerstone Improvement Program (Enhanced Reliability Investment)

§ $800 MM capital 2008-2011

§ $1.5 B capital investment beyond 2011

§ CPUC action requested by 1/1/2009

§ BC Transmission

§ Recovery of development costs approved by FERC

§ Working on multi-utility partnership for development of the project

§ $5+ B potential, with PG&E’s share at 1/3 to 1/2

§ New Generation

§ Prior RFO shortfalls

§ RFO for 2006-2016 period issued April 2008 for 800 - 1200 MW

§ Renewable investment opportunities

§ Pacific Connector LNG Pipeline

§ ~$50 MM capital 2008-2011

§ FERC approval expected by year end

* 2008 to 2011 estimates are based on forecasted construction schedules and additional contracted resources

Year-end 2008 target: 1.3 million meters installed

2007 2008 2009 2010 2011 2012

1st meter

installed
11/06

Billing IT infrastructure

live 2Q 2007

Live AMI billing

12/07

SmartMeterTM

Upgrade Filing
12/07

Demand Response

Interval Billing Live
05/08

Upgrade technology

installation 4Q 08

Deployment (incl.upgrade)

complete 1Q 2012

SmartMeterTM Program Progress

§ > 550,000 meters installed

§ 270,000 meters being read electronically

§ CPUC decision on SmartMeterTM Upgrade expected by 12/08

Cornerstone Improvement Program

§ Proposed $2.3 B/ 6-yr. System Upgrade

§ Key to electric distribution system reliability
improvements

§ Supporting distribution automation

§ Preparing for the grid of the future

Current-state	Performance Value
Multi-year operating plan	§ Rigorous comprehensive process § Both tactical and strategic view
Business Reviews	§ Real-time decisions § Sr. management dialogue and engagement
Project governance	§ Holistic approach § Multi-functional business case reviews, approvals and follow up
Efficiency Fund	§ Current year funds invested for future year benefits

All current-state processes include integrated analysis with disciplined
tracking and follow up to minimize surprises and ensure planned results

Improved Operational Planning

§ Strategic Sourcing

§ IT, Telecom, and consulting ($1.4 B in annual spend)

§ Contract extensions ($1.2 B in annual spend)

§ Labor Productivity

§ Timekeeping and reporting process

§ Asset Management

§ Fleet Management ($200 M in annual spend)

§ Real Estate Optimization ($100 M in annual spend)

§ Inventory Management ($150 M in asset value)

§ Cash Cycle Management ($50 M in annual spend)

Identifying Operational Efficiencies

Energy Efficiency Incentives

§ Guidance assumes:

§ $90 - $130 MM in Energy Efficiency Incentives 2008-2011

§ 2 years in 2008, 1 year in 2009, hold-back in 2010, 2 years in
2011

§ 2006-2008 Program effectiveness phase (“net-to-gross
issues”) to be finalized by CPUC summer 2008

§ Program goals for 2009-2011 to be finalized second half of
2008

Financing Needs 2008-2011 (in $MM)

* Excludes cash from Energy Recovery Bond and Rate Recovery Bond revenues

Cash Flow and Equity Needs

$ per Share

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

2005

2006

2007

Dividends per Common Share

EPS from Operations*

$2.34

$2.57

$2.78

$1.23

$1.32

$1.44

Dividend Policy

§ Dividend Policy Objectives:

§ Flexibility

§ Sustainability

§ Comparability

§ Target payout ratio range of
50% - 70%

§ Growth balanced with funding
for additional
investment opportunities

Financial Assumptions 2008-2011

§ Capital expenditure base forecast reflects projects that
are highly likely or already approved

§ CPUC authorized ROE is 11.35% and Utility earns at
least 12% at FERC on projected rate base

§ Ratemaking capital structure maintained at 52% equity

§ Additional capital expenditures, CEE incentives, and
operational efficiencies consistent with earnings targets

§ Resolution of FERC generator claims in 2009-2011
results in financing needs

Key Financial Takeaways

§ Delivering on Near-term EPS Guidance and 8%
CAGR

§ Investing in Attractive Rate Base Opportunities

§ Utilizing Operating Efficiencies, Incentive Earnings
and Leverage Effectively

§ Delivering Strong Cash Flow and Liquidity

§ Sustaining a Comparable Dividend

Notes

Agricultural

Electric Customers

(86,179 GWh delivered)

Gas Customers

(869 Bcf delivered)

Industrial
69%

Commercial
8%

Residential
23%

Industrial
18%

Commercial
40%

Residential
36%

Agricultural
& Other

2007 Customer Profiles - % by Sales

Electric Customers

Gas Customers

Note: * Residential data released in July (Electric) and September (Gas); Business data released in February (Electric) and March (Gas)

Bottom

Quartile

3rd

Quartile

2nd

Quartile

Top

Quartile

Residential*

Overall Customer

Satisfaction Index

2006

2007

2006

2007

Bottom

Quartile

3rd

Quartile

2nd

Quartile

Top

Quartile

Business

Overall Customer

Satisfaction Index

2006

2007

2006

2007

2008

Rank:

2/55

Rank:

51/76

Rank:

43/76

Rank:

5/56

Rank:

20/56

Rank:

46/51

Rank:

4/38

Rank:

11/37

Rank:

2/40

Rank:

11/56

J.D. Power

Customer Satisfaction Performance

Preferred Loading Order

§ PG&E’s resource investment strategy is aligned with
California’s Energy Action Plans:

§ Energy Efficiency

§ Demand Response

§ Renewable Resources

§ Distributed Generation

§ Conventional Resources

Innovative EE and DR programs

The Best Year Ever in Energy Efficiency Innovation

2007 Energy Efficiency Successes

§ PG&E set a personal best in terms of the highest gross savings we’ve ever
achieved

§ Prevented more than 1 million tons of CO2 emissions

§ Equivalent to taking 150,000 cars off the road for one year

§ Saved enough energy to power 225,000 homes for one year

§ Saved enough natural gas to heat 50,000 homes for one year

§ Delivered more than $500 million in societal net benefits to PG&E
customers

§ Received over 30 national awards and recognitions for 2007 programs - the
most for any year in our 31 years of doing energy efficiency

§ ENERGY STAR® Partner of the Year

§ ENERGY STAR® HOMES Outstanding Achievement Award

§ 12 programs recognized as Exemplary by American Council for an Energy-Efficient Economy
(ACEEE)

Today

Near-Term

Future

• Home Area
Network Energy
Management

• PHEV
SmartCharge™

• Vehicle to Grid

• Distributed storage
and generation

• SmartMeters™

• Electric Field Vehicles

Innovating for the Future:
Smart Energy Web

Year Signed	Project	Max GWh/yr	Technology
2006	Military Pass Rd.	840	Geothermal
2006	HFI Silvan	142	Biomass
2006	Liberty Biofuels	70	Biofuels
2006	Bottle Rock USRG	385	Geothermal
2006	IAE Truckhaven	366	Geothermal
2006	Global Common - Chowchilla	72	2006
2006	Global Common - El Nido	72	Biomass
2006	Newberry	840	Geothermal
2006	Calpine Geysers	922	Geothermal
2006	Tunnel Hydro	2.1	Hydro
2006	Buckeye Hydro	1.4	Hydro
2006	Eden Vale Dairy	1.3	Biogas
2006	Microgy	TBD	Biogas
2006	Bio_Energy LLC	TBD	Biogas
2006	Palco	36	Biomass

Year Signed	Project	Max GWh/yr	Technology
2007	Solel	1388	Solar Thermal
2007	PPM-Klondike	265	Wind
2007	CalRenew	9	PV
2007	Green Volts	5	PV
2007	enXco	509	Wind
2007	Ausra	388	Solar Thermal
2007	White Creek	148	Wind
2007	Finavera Renewables	4	Wave
2008	BrightSource	1230	Solar Thermal
2008	San Joaquin Solar	700	Solar Thermal- Biofuel Hybrid

* Based on contracts signed through August 2007

1) Average delivered energy over multiple years: pre-RPS baseline

Over 21% of Projected 2010 Load Currently Signed*

Renewable Contracts Signed

§ Steam Generator Replacement

§ $700 MM approved capital investment

§ Unit 2 replacement completed in 69 days

§ Unit 1 replacement scheduled for early 2009

Diablo Steam Generator Replacement

Gateway Generating Station

§ More than 50% complete

§>1,000,000 hours with no injury

§ On budget, on time

§ Begins operations 1Q 2009

Colusa

657 MW/$670 MM

Gateway

530 MW/ $370 MM

Humboldt

163 MW/ $240 MM

New Generation: Colusa & Humboldt

§ Project Status:

§ Colusa: CEC permits received;
construction imminent

§ Humboldt: Slight delays in
permitting, construction
expected to begin by end of year

§ Strategy for execution mirrors
successes at Gateway

§ Experienced project teams in
place

Renewable RFO

§ PG&E issued its annual Renewable RFO in March 2008

§ Objective to sign an additional 1-2%

§ Offers due by June, followed by CPUC review

Long-Term Plan 2006 Cycle

§ PG&E issued its RFO in April, 2008

§ PG&E was authorized to procure 800-1200 MW of operationally flexible
resources by 2015

§ Offers are due by the end of July, followed by CPUC review

§ The amount will include any projects that have failed to materialize from
the 2004 RFO

2008 Request for Offer Process

New Build Energy Procurement Cost ($/MWh)

100

120

140

160

Combined Cycle

Energy Efficiency

Wind

Geothermal

Biomass

Solar & Emerging

Comparative Energy Procurement
Costs

2008 Compensation metrics	Percentage weight
Delivering on EPS Goals (Measurement of earnings from ongoing core operations)	40%
Brand Health Index (Composite of customer surveys and marketing research)	20%
Reliable Energy Delivery (Composite of various reliability metrics)	20%
Employee Engagement Survey (Measurement of employee engagement at PG&E)	10%
Safety Performance (Measurement of occupational injury or illness based on OSHA Recordables)	10%

Compensation Aligned with Business Focus

Measuring Our Performance

Notes

Appendix

European Investor Meetings

June 23 - 27, 2008

	Cumulative four-year totals (pre-tax earnings in $MM)
Need identified in December 2007 (2008-2011)	$335- $575
Potential sources identified in December 2007 to fill need:
§ Additional Rate Base Investment	$125- $175
§ CEE Program Incentives	$100- $200
§ Operational Efficiencies	$110- $200 $335- $575
Total Need	$110- $200 $335- $575

Items now identified, implemented, completed or included in operating plans:
§ CEE Program Incentives	$90- $130
§ Operational Changes and Efficiencies	$100- $140
Total items identified, implemented, completed or included in operating plans	$190- $270

Remaining four-year need (2008-2011)	$145- $305

Opportunities identified but not yet implemented to fill remaining need:
§ Additional Rate Base Investment	$200- $250
§ Operational Efficiencies	$50- $110
Total opportunities identified but not yet implemented to fill remaining need	$250- $360

Earnings Drivers Reconciliation

Operational Changes and Efficiencies in
Current Operating Plan

+ Economic Stimulus Act of 2008

+ Resolution of outstanding tax audits

+ Settlement of outstanding generator claims

- Delay in electric transmission project (C3ET)

+ Workforce reductions

+ Strategic sourcing

+ Cash cycle management

+ Inventory management

+ Fleet management

+ Real estate optimization

* Estimated carrying cost credits include only the equity portion and assume a utility equity ratio of 52% and ROE at 11.35%.

($MM)	2008	2009	2010	2011	2012
Energy Recovery Bond Average Deferred Tax Balance	$683	$542	$396	$243	$82
Estimated After-tax Carrying Cost Credit*	$(40)	$(32)	$(23)	$(14)	$(5)

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

Carrying Cost Credit Impacts

($MM)	2008	2009	2010	2011	2012
Annual ERB Amortization	$354	$369	$386	$404	$423
End-of-year ERB balance	$1,582	$1,213	$827	$423	$-

ERB Amortization Schedule

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

Current Ratings

§ Utility Corporate Credit/Issuer: BBB+ (S&P) and A3 (Moody’s)

§ Utility Senior unsecured debt: BBB+ (S&P) and A3 (Moody’s)

Average Utility Metrics (2008-2011)*

§ S&P Business Profile Rating: 5

§ Total Debt to capitalization (EOY): 55%

§ Funds from Operations Cash Interest Coverage: 5.20x

§ Funds from Operations to Average Total Debt: 22%

Credit Profile

* 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.

EPS on an Earnings from Operations Basis	$2.78
Items Impacting Comparability	0.00
EPS on a GAAP Basis	$2.78

2007

2007 EPS - Reg G Reconciliation

2008
	Low	High
EPS Guidance on an Earnings from Operations Basis* Estimated Items Impacting Comparability EPS Guidance on a GAAP Basis	$2.90 0.00 $2.90	$3.00 0.00 $3.00

2009
	Low	High
EPS Guidance on an Earnings from Operations Basis* Estimated Items Impacting Comparability EPS Guidance on a GAAP Basis	$3.15 0.00 $3.15	$3.25 0.00 $3.25
* 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.

Guidance Range

EPS Guidance -Reg G Reconciliation