®
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;
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
2
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
3
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
4
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 100th anniversary of PG&E
•
Provides energy to nearly 1 in 20 people in the U.S.
•
70,000 square-mile service territory
5
Business Priorities 2006-2010
1.
Advance business transformation
2.
Provide attractive shareholder returns
3.
Increase investment in utility infrastructure
4.
Implement an effective energy procurement plan
5.
Improve reputation through more effective communications
6.
Evaluate the evolving industry and related investment opportunities
6
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
utility in the
United States
Delighted Energized Rewarded
customers employees shareholders
Our values
Operational excellence
Transformation
Our strategies
Our goals
Our vision
Strategic Direction
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Satisfied
Regulators
Rewarded
Shareholders
Delighted
Customers
OUR VISION
The leading utility
in the United States
in the United States
The Virtuous Circle
8
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
9
Implementation
& Operational
Handover
Handover
Build/
Test
Detailed
Design
Preliminary
Design
& Analysis
& 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
10
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
processes
•
Instill a
competitive,
customer-fo
cused mindset
customer-fo
cused mindset
Transformation Enhancing Performance - Examples
11
Anticipated Transformation Net Costs and Benefits
Net Cost Range
Net Benefit Range
12
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 | $283 |
Diablo Canyon performance index 3 (composite of plant performance metrics) | 94.7 | 95.2 | 94.9 | 94.0 |
Employee Premier Survey index 4 (composite of employee satisfaction Premier survey metrics) | 64% | n/a | n/a | 68% |
Lost workday case rate (lost workday case rate per 100 employees) | 1.04 | 0.47 | 0.45 | 0.88 |
(1) Metric is first applicable in 2006. (2) The reconciliation of non-GAAP cost of operations to operating and maintenance expense can be found in the Appendix and at www.pge-corp.com.
(3) 2005 results have been restated to maintain consistency with the actual and target values based on the recently revised industry calculation methodology. (4) Based on an annual survey.
Operational Performance Metrics
13
* Reg G reconciliation to GAAP for 2005 EPS from Operations and 2006 and 2007 EPS Guidance available in Appendix and at www.pge-corp.com
Operating EPS Assumptions ($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)
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
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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
15
PG&E Corporation has consistently outperformed S&P 500 and Dow Jones Utility Indices
Long Term
Stock Price Performance
and
YTD 2006
16
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
17
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
18
* 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.
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
19
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
20
Energy Procurement Overview
•
Procurement plan intended to meet customer need for reliable
energy in an environmentally-responsible and cost-effective
manner
manner
•
Energy efficiency and renewables are highest priority in
California “loading order”
•
Offers solicited for short, intermediate and long-term resources
21
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.
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
22
| * | 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
23
Effective Communications
•
Strengthening communications with our stakeholders:
–
Employees
–
Customers
–
Policymakers
–
Investors
24
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
25
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
26
Appendix
•
Reg G Reconciliation / Financial Profile
•
Company Overview and Definitions
27
| * | 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.
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
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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 | $2.75 |
| * Earnings per share from operations is a non-GAAP measure. This non-GAAP measure is used because it allows investors to compare the core underlying financial performance from one period to another, exclusive of items that do not reflect the normal course of operations. | ||
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| * | Total expense per customer is a non-GAAP measure. This non-GAAP measure is used because it is an indicator of |
overall efficiency and productivity in delivering energy to PG&E customers.
Cost of Operations - Reg G Reconciliation
The reconciliation of non-GAAP cost of operations to Operating and Maintenance Expense is:
30
Estimated Average Deferred Tax Balances and Carrying Cost Credit Impacts ($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
31
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.
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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
33
(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
34
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
35
•
6,128 miles of backbone transportation import
capacity of 2.0 BCF/day Canadian gas,
1.1 BCF/day Southwest 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
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
36
Helms
Pumped
Storage
Storage
Humboldt
Diablo Canyon
Nuclear Plant
Conventional
Hydroelectric
facilities
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
37
Gas Customers: 4.2MM
Electric Customers: 5MM
Customer Profiles by Usage
38
Electric Sales Outlook
Electric sales growth forecasted to average 1.2% during 2006-2010
39
Gas Sales Outlook
Gas sales growth forecasted to average 1.1% during 2006-2010
40
| * | 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*
41
Comparative Energy Procurement Costs
42
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
43
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
44
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.
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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.
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.
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