PG&E Corporation
Christopher P. Johns
Senior Vice President & CFO
Citi Power Gas and Utilities Conference
June 5 and 6, 2008, Washington, DC
Exhibit 99
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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:
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 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;
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;
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;
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;
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;
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;
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;
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
Forward-Looking Statements
3
8% CAGR in EPS
PCG: Investment Case
§ PCG offers competitive growth in a constructive
regulatory environment with an attractive valuation:
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
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PG&E Vision
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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
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Delivering on Financial Objectives
§ Invest in needed infrastructure
§ Ensure adequate liquidity
§ Meet EPS targets
§ Generate strong cash flow
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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
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
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2007
Base
Forecast
Rate Base
Forecast
Rate Base
Growth
(+9% to 10%)
Add’l CapEx
(+1 to 3%)
New Shares
(-3% to- 5%)
$2.70-
$2.80
$2.80
8% CAGR
2007- 2011
8%
10%
6%
2007
Guidance {
Guidance {
Range
% CAGR
2007-2011
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$ 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
$1,200
$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
Program, additional generation and gas pipeline investments, and BC Transmission
$3.7 B
$3.6B
$3.3 B
$3.3 B
$3.0 B
$3.2 B
$3.0 B
$3.4 B
Prior Forecast Levels
Capital Expenditure Outlook
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• 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.
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
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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 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
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* 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
11/06
Billing IT infrastructure
live 2Q 2007
Live AMI billing
12/07
SmartMeterTM
Upgrade Filing
12/07
12/07
Demand Response
Interval Billing Live
05/08
05/08
Upgrade technology
installation 4Q 08
Deployment (incl.upgrade)
complete 1Q 2012
SmartMeterTM Program Progress
§ Over 550,000 meters installed
§ 270,000 meters being read electronically
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Cornerstone Improvement Program
§ Proposed $2.3 B/ 6-yr. System Upgrade
§ Key to electric distribution system reliability
improvements
improvements
§ Supporting distribution automation
§ Preparing for the grid of the future
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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
tracking and follow up to minimize surprises and ensure planned results
Improved Operational Planning
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§ 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
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Innovative EE and DR programs
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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
2011
§ 2006-2008 Program effectiveness phase (“net-to-gross
issues”) to be finalized by CPUC summer 2008
issues”) to be finalized by CPUC summer 2008
§ Program goals for 2009-2011 to be finalized second half of
2008
2008
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Financing Needs 2008-2011 (in $MM)
* Excludes cash from Energy Recovery Bond and Rate Recovery Bond revenues
Cash Flow and Equity Needs
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Dividend Policy
§ Dividend Policy Objectives:
§ Flexibility
§ Sustainability
§ Comparability
§ Target payout ratio range of 50% - 70%
§ Growth balanced with funding for additional
investment opportunities
investment opportunities
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Financial Assumptions 2008-2011
§ Capital expenditure base forecast reflects projects that
are highly likely or already approved
are highly likely or already approved
§ CPUC authorized ROE is 11.35% and Utility earns at
least 12% at FERC on projected rate base
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
operational efficiencies consistent with earnings targets
§ Resolution of FERC generator claims in 2009-2011
results in financing needs
results in financing needs
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Key Financial Takeaways
§ Delivering on Near-term EPS Guidance and 8%
CAGR
CAGR
§ Investing in Attractive Rate Base Opportunities
§ Utilizing Operating Efficiencies, Incentive Earnings
and Leverage Effectively
and Leverage Effectively
§ Delivering Strong Cash Flow and Liquidity
§ Sustaining a Comparable Dividend
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Notes
Appendix
Citi Power and Gas Utilities Conference
June 5 and 6, 2008
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JD Power Rankings
2007 Higher than 2006
2007 Higher than 2006
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§ 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
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Gateway Generating Station
§ More than 50% complete
§ >1,000,000 hours with no injury
§ On budget, on time
§ Begins operations 1Q 2009
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Colusa
657 MW
Gateway
530 MW
Humboldt
163 MW
New Generation: Colusa & Humboldt
§ Project Status:
§ Colusa: CEC permits received;
construction imminent
construction imminent
§ Humboldt: Slight delays in
permitting, construction
expected to begin by end of year
permitting, construction
expected to begin by end of year
§ Strategy for execution mirrors
successes at Gateway
successes at Gateway
§ Experienced project teams in
place
place
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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 | |
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
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Operational Changes and Efficiencies in
Current Operating Plan
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
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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
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Business Line | Gross Plant* 12/31/2007 | Net Plant* 12/31/2007 | Estimated Useful Lives |
Generation | $2.2 | $1.9 | 4 to 37 years |
Electric Distribution | $16.1 | $9.8 | 16 to 58 years |
Electric Transmission | $4.7 | $3.1 | 40 to 70 years |
Gas Distribution | $5.2 | $2.8 | 24 to 52 years |
Gas Transportation | $3.1 | $2.1 | 25 to 45 years |
Gas Storage | $0.1 | $0.1 | 25 to 48 years |
Other | $3.8 | $2.5 | 5 to 43 years |
Total | $35.2 | $22.3 |
Historical Plant by Line of Business (in $B)
*The Utility’s composite depreciation rate was approximately 3.28%, 3.09%, and 3.28% in 2007, 2006 and 2005 respectively
Utility Net Plant
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* 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.
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
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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
Guidance Range
EPS Guidance -Reg G Reconciliation