®
Goldman Sachs
Power and Utility Conference
August 12, 2010
Power and Utility Conference
August 12, 2010
PG&E
Corporation
Exhibit 99
This presentation contains management’s guidance for PG&E Corporation’s 2010 and 2011 earnings per share from operations. These statements and
projections, as well as the underlying assumptions, are forward-looking statements that are based on current expectations which management believes are
reasonable. These statements and assumptions are necessarily subject to various risks and uncertainties, the realization or resolution of which may be outside
of management's control. Actual results may differ materially. Factors that could cause actual results to differ materially include:
projections, as well as the underlying assumptions, are forward-looking statements that are based on current expectations which management believes are
reasonable. These statements and assumptions are necessarily subject to various risks and uncertainties, the realization or resolution of which may be outside
of management's control. Actual results may differ materially. Factors that could cause actual results to differ materially include:
• the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels;
• the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;
• the adequacy and price of electricity and natural gas supplies and whether the new day-ahead, hour-ahead, and realtime wholesale electricity markets
established by the California Independent System Operator (“CAISO”) will continue to function effectively, the extent to which the Utility can manage and respond
to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;
established by the California Independent System Operator (“CAISO”) will continue to function effectively, the extent to which the Utility can manage and respond
to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;
• explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, and similar events that may occur while operating
and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce
generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the
imposition of civil, criminal, or regulatory fines or penalties on the Utility;
and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce
generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the
imposition of civil, criminal, or regulatory fines or penalties on the Utility;
• the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer
demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which
the Utility relies;
demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which
the Utility relies;
• the potential impacts of climate change on the Utility’s electricity and natural gas businesses;
• 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 that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or
other reasons;
conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or
other reasons;
• the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon, the availability of nuclear fuel, the outcome of the Utility’s
application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies
with respect to the storage of spent nuclear fuel, security, safety, or other matters associated with the operations at Diablo Canyon;
application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies
with respect to the storage of spent nuclear fuel, security, safety, or other matters associated with the operations at Diablo Canyon;
• whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking
mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;
mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;
• the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
• whether the Utility can successfully implement its program to install advanced meters for its electric and natural gas customers and integrate the new meters
with its customer billing and other systems, the outcome of the independent investigation ordered by the CPUC and the California Legislature into customer
concerns about the new meters, and the ability of the Utility to implement various rate changes including “dynamic pricing” by offering electric rates that can
vary with the customer’s time of use and are more closely aligned with wholesale electricity prices;
with its customer billing and other systems, the outcome of the independent investigation ordered by the CPUC and the California Legislature into customer
concerns about the new meters, and the ability of the Utility to implement various rate changes including “dynamic pricing” by offering electric rates that can
vary with the customer’s time of use and are more closely aligned with wholesale electricity prices;
• how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the
extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;
extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;
• the outcome of litigation, including litigation involving the application of various California wage and hour laws, and 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 insurance, or from other third parties;
the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, or from other third parties;
• the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;
• the impact of environmental laws and regulations and the costs of compliance and remediation;
• the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels
of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which
permits cities and counties to purchase and sell electricity for their local residents and businesses;
of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which
permits cities and counties to purchase and sell electricity for their local residents and businesses;
• the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations; and
• other factors and risks discussed in PG&E Corporation and Pacific Gas and Electric Company’s 2009 Annual Report on Form 10-K and other reports filed with
the Securities and Exchange Commission.
the Securities and Exchange Commission.
Cautionary Language Regarding
Forward-Looking Statements
Forward-Looking Statements
2
3
Overview Page 4
Regulatory Update Page 8
Appendix Page 18
Table of Contents
4
• Provides energy to approximately 15 million people
• 70,000 square-mile service territory
• Four main operational units:
Electric and gas distribution
Electric transmission
Natural gas transmission
Electric procurement and owned generation
Pacific Gas and Electric Company
(PG&E)
(PG&E)
PG&E SERVICE AREA
IN CALIFORNIA
IN CALIFORNIA
5
Excellent service at reasonable cost
Constructive regulatory environment
Investment in infrastructure-
providing solid, regulated growth
providing solid, regulated growth
Clean generation and world-class energy
efficiency programs
efficiency programs
Stable capital structure and return
Reliable, growing dividend
PCG Investment Case
6
Sustainable, comparable dividend
Payout ratio range of 50% - 70%
Dividend growth in line with EPS growth
Dividend Policy
7
2011
EPS Guidance
$3.85
$3.85
2008
Actual
Actual
2010
$2.95
$2.95
$3.65
$3.65
Low
Low
High
High
Low
Low
High
High
$3.50
$3.50
$3.35
$3.35
Earnings per Share from Operations*
Earnings per Share from Operations*
2009
Actual
Actual
$3.21
$3.21
* Reg G reconciliation to GAAP for 2008 and 2009 EPS from Operations, and 2010-2011 EPS Guidance
available in Appendix and at www.pge-corp.com
available in Appendix and at www.pge-corp.com
®
Regulatory Update
9
2011 General Rate Case
Sets revenue requirements for Gas and Electric Distribution
and Electric Generation businesses for 2011 - 2013
and Electric Generation businesses for 2011 - 2013
Revenue Requirement Request: $6.7B
$1.1B increase
$2.7B average capital expenditures per year
Allows for necessary investments in energy infrastructure
to deliver energy safely and reliably to customers
to deliver energy safely and reliably to customers
Key capital projects will focus on:
• replacement of gas and electric systems that are at or near the end of their
useful lives
• replacement of aging generation infrastructure, hydro relicensing
requirements
requirements
• replacement of aging fleet, buildings and IT systems
10
Also requested a flexible attrition mechanism to adjust for:
• Labor costs
• Materials and services
• Capital investments
• Changes in franchise, payroll or other taxes
Based on the requested mechanism, attrition revenues are
currently forecasted to be $275M and $343M in 2012 and 2013
currently forecasted to be $275M and $343M in 2012 and 2013
Items not included in the 2011 GRC:
• SmartMeterTM and SmartMeterTM Upgrade programs
• PV Project, Cornerstone, Manzana, Diablo Relicensing
June - July
August - September
November
Hearings
Opening and
Reply Briefs
Reply Briefs
Proposed
Decision
Decision
New Rates
in Effect
in Effect
Jan 1 2011
December
Final
Decision
2011 General Rate Case
11
2011 Gas Transmission and
Storage Rate Case
Storage Rate Case
Sets revenue requirements, rates, terms and conditions for PG&E’s
Gas Transmission and Storage services for 2011 - 2014
Gas Transmission and Storage services for 2011 - 2014
Revenue Requirement Request: $529M
$67M increase over 2010 revenue requirement
$235M Capital Expenditures
Allows for upgrades to backbone transmission, local transmission,
and storage facilities, and maintenance of equipment
and storage facilities, and maintenance of equipment
Proposed attrition mechanism similar to General Rate Case
Conference held in July resulted in a proposed, multi-party settlement
The terms are confidential until the agreement is submitted to the
CPUC for approval
CPUC for approval
Final decision requested by Q4 2010
12
Request for revenue requirements to acquire, own, and operate
the 189 - 246MW Manzana wind project in the Tehachapi region
of Southern California
the 189 - 246MW Manzana wind project in the Tehachapi region
of Southern California
Request: $900M (all capital) at 246MW capacity
Manzana Wind Project would be designed, developed, and
constructed by Iberdrola Renewables, Inc.
constructed by Iberdrola Renewables, Inc.
• PG&E proposes to make progress payments throughout construction
and take full ownership at completion
and take full ownership at completion
• Final size of the project would depend upon permitting requirements,
completion of land rights acquisition and turbine supply
completion of land rights acquisition and turbine supply
• The proposed wind facility is targeted to be operational as early as
December 2011
December 2011
Final decision is requested by the end of 2010
Manzana Wind Project
13
Sets revenue requirements for PG&E’s Electric Transmission
business in 2011
business in 2011
Revenue Requirement Request: $1.026B
Capital Expenditures: $810M
If approved, revenues would provide for additional transmission
capacity and increased maintenance and replacement work on
our substations to improve overall reliability of our system
capacity and increased maintenance and replacement work on
our substations to improve overall reliability of our system
TO13 final decision expected by Q3 2011
FERC TO13 Filing
Request Settlement
TO 10 $760.5M $718M
TO 11 $845.0M $776M
TO 12 $946.0M $875M - Approved on 7/27/10
14
Cornerstone Reliability Program
Sets revenue requirements aimed at improving the reliability of
PG&E’s electric distribution system
PG&E’s electric distribution system
Approved Final Decision (6/24/10):
• $350M in reliability focused capital investments through 2013
• CPUC provided the opportunity for additional reliability investment
in 2014 GRC and subsequent general rate cases
in 2014 GRC and subsequent general rate cases
The primary focus of the program is:
Additional substation emergency capacity
Enhanced interconnectivity and automation
Reliability investments in rural areas
Recent Decisions
15
Solar PV Program
Sets revenue requirements to develop and own up to 250MW of PV
and sign PPAs for an additional 250MW of PV over a five year period
and sign PPAs for an additional 250MW of PV over a five year period
Approved Final Decision (4/22/10):
• $1.45B (all capital) for the Utility-owned 250MW
• Authorized cost of service ratemaking treatment for the Utility-
owned portion
owned portion
• Included an incentive mechanism with 90/10 sharing between
customers and shareholders of the amount of total costs below a
certain threshold over the timeframe of project development
customers and shareholders of the amount of total costs below a
certain threshold over the timeframe of project development
Recent Decisions
16
Summer Rate Relief Program
As proposed by PG&E, the CPUC approved reducing overall rates by
$400M, a 3% decrease, effective June 1, 2010
$400M, a 3% decrease, effective June 1, 2010
For residential rates, reductions focused on highest rate tiers
• Substantially reduced rates in Tier 5 by 19.6%
and Tier 4 by 5.8%
• Moderately increased rates in Tier 3 by 1.8%
GRC Phase II filing recommends collapsing of
Tier 3, 4, and 5 into one Tier 3 rate
Tier 3, 4, and 5 into one Tier 3 rate
Recent Decisions
®
Appendix
18
Key Regulatory Proceedings
19
* 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.
compare the core underlying financial performance from one period to another, exclusive of items that do not reflect the normal
course of operations.
** Items impacting comparability reconcile earnings from operations with consolidated net income as reported in accordance with
GAAP. For the three and twelve months ended December 31, 2008, PG&E Corporation recognized $257 million of net income
resulting from a settlement of tax audits for tax years 2001 through 2004. Of this amount, $154 million was related to PG&E
Corporation’s former subsidiary, National Energy & Gas Transmission, Inc., and was recorded as income from discontinued
operations
GAAP. For the three and twelve months ended December 31, 2008, PG&E Corporation recognized $257 million of net income
resulting from a settlement of tax audits for tax years 2001 through 2004. Of this amount, $154 million was related to PG&E
Corporation’s former subsidiary, National Energy & Gas Transmission, Inc., and was recorded as income from discontinued
operations
2008 EPS - Reg G Reconciliation
20
2009 EPS - Reg G Reconciliation
(1) 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.
core underlying financial performance from one period to another, exclusive of items that do not reflect the normal course of operations.
(2) Items impacting comparability reconcile earnings from operations with consolidated net income as reported in accordance with GAAP.
(3) For the twelve months ended December 31, 2009, PG&E Corporation recognized $66 million, after-tax, for the interest and state tax
benefit associated with a federal tax refund, for 1998 and 1999.
benefit associated with a federal tax refund, for 1998 and 1999.
(5) For the twelve months ended December 31, 2009, PG&E Corporation incurred $59 million, after-tax of costs to perform accelerated
system-wide natural gas integrity surveys and associated remedial work.
system-wide natural gas integrity surveys and associated remedial work.
(4) For the twelve months ended December 31, 2009, PG&E Corporation recognized $28 million, after-tax, related to the CPUC's
authorization to recover costs previously incurred in connection with the Utility’s hydroelectric generation facilities.
authorization to recover costs previously incurred in connection with the Utility’s hydroelectric generation facilities.
(6) For the twelve months ended December 31, 2009, PG&E Corporation accrued $38 million, after-tax of severance costs related to the
elimination of approximately 2% percent of the Utility’s workforce.
elimination of approximately 2% percent of the Utility’s workforce.
21
EPS Guidance - Reg G Reconciliation
(1) 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. |
(2) Items impacting comparability reconcile earnings from operations with consolidated net income as reported in accordance with GAAP.
(3) Costs related to Proposition 16 - The Taxpayers' Right to Vote Act
(4) Reduction in the deferred tax asset corresponding to the loss of tax deductibility of Medicare Part D federal subsidies.