PG&E
Corporation
®
Morgan Stanley Utilities Conference
March 11-12, 2010
March 11-12, 2010
Exhibit 99
2
2
This presentation contains management’s guidance for PG&E Corporation’s 2010 and 2011 earnings per share from operations, projections of Pacific Gas and
Electric Company’s (Utility) capital expenditures, construction work in progress (CWIP), rate base and rate base growth, and projections of PG&E
Corporation’s and the Utility’s financing needs. 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:
Electric Company’s (Utility) capital expenditures, construction work in progress (CWIP), rate base and rate base growth, and projections of PG&E
Corporation’s and the Utility’s financing needs. 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:
• the Utility’s ability to 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 the ability of the Utility to manage and respond to the volatility of the electricity and
natural gas markets, including the ability of the Utility and its counterparties to post or return collateral;
natural gas markets, including 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 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;
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, including the development of alternative technologies that enable customers to increase their reliance on self-
generation, or other reasons;
market conditions, changes in technology, including 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 with respect to the storage of spent
nuclear fuel, security, safety or other matters associated with the operations at Diablo Canyon;
Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations with respect to the storage of spent
nuclear fuel, security, safety or other matters associated with the operations at Diablo Canyon;
• whether the Utility can maintain the cost savings it has recognized from operating efficiencies it has achieved and identify and successfully implement
additional sustainable cost-saving measures;
additional sustainable cost-saving measures;
• whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms;
• the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
• whether the new wholesale electricity markets in California will continue to function effectively and whether the Utility can successfully implement “dynamic
pricing” for its electricity customers;
pricing” for its electricity customers;
• 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
insurance, or from other third parties;
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 effect of municipalization, direct access, community choice aggregation, or other forms of bypass;
• 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’s and the Utility’s 2008 Annual Report on Form 10-K and other reports filed with the Securities and
Exchange Commission.
Exchange Commission.
Cautionary Language Regarding
Forward-Looking Statements
Forward-Looking Statements
3
PCG: Key Takeaways
We have a solid strategy
- customer focus
- excellence in operations
- strong regulatory relations
- environmentally responsible
- community oriented
We execute on our strategy
- a proven management team
- delivering consistent solid results
for our customers and shareholders
4
2009 Report Card
** Measured by OSHA Recordable Injuries
$3.21
$3.9 B
2.38 cases
$33.4 MM
Earnings from Operations*
Capital Expenditures
15% Reduction in Injuries**
Energy Efficiency Incentives
On Time, On Budget Execution
$3.15 - $3.25 per share
$3.6 to $3.7 B
2.76 cases / 200,000 hours
$0 to $30 MM
SmartMeterTM
Gateway Generating Station
Nuclear Projects
New Gas Fired Facilities
(on line in 2010)
Our Plan
Our Results
* Reg G reconciliation to GAAP for 2009 EPS from Operations available in Appendix and at www.pge-corp.com
5
PG&E is sensitive to customer needs
- Proposing plan to restructure residential
tiers
tiers
- Making customers aware of options
to tiered rates
to tiered rates
- Managing revenue changes to keep
average rates flat in 2011
average rates flat in 2011
Customer Environment
6
Electric Rates
7
Source: Edison Electric Institute, Statistical Yearbook, Year 2008
Residential Bills
8
CPUC and Regulation
“No matter how one looks at it,
California will have to make
significant investments in
transmission and power plants, be
they conventional or renewable, to
meet the demands of a growing
population and economy.”
California will have to make
significant investments in
transmission and power plants, be
they conventional or renewable, to
meet the demands of a growing
population and economy.”
(President Peevey, June 23, 2009)
“We want to actually work with the
people of the state of California, and
the utilities and the sources of
capital, to effect this multi-decade
transformation…”
people of the state of California, and
the utilities and the sources of
capital, to effect this multi-decade
transformation…”
(Commissioner Bohn, Feb 4, 2010)
“We have a need for critical
infrastructure. It is crucial that
California continue to invest in critical
infrastructure, not only in order to
augment our portfolio of preferred
resources, but also enhance reliability
and help grow the economy”
infrastructure. It is crucial that
California continue to invest in critical
infrastructure, not only in order to
augment our portfolio of preferred
resources, but also enhance reliability
and help grow the economy”
(Commissioner Simon, Dec 17, 2009)
9
Under a new governor, what changes?
Impact of Election
10
10
Capital Expenditure Outlook
Low Case $4.0B
High Case $4.6B
Low Case $3.2B
High Case $5.3B
2009
2010
2011
Low
High
$3.9B
Cap Ex Forecast ($B)
Actual
Low
High
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CapEx Forecast 2010
Capital Expenditure Forecast ($MM)*
* Excludes tax equity investment outside of the Utility
12
CapEx Forecast 2011
Capital Expenditure Forecast ($MM)
13
Rate Base and CWIP
2009 Actual
2010
2011
Rate Base
Low Case $21.4B
High Case $21.3B
Low Case $21.4B
High Case $21.3B
Rate Base
Low Case $24.0B
High Case $24.4B
Low Case $24.0B
High Case $24.4B
Weighted Average Rate Base*
and Construction Work in Progress ($B)
and Construction Work in Progress ($B)
Low
High
Low
High
Construction Work
In Progress (CWIP)
In Progress (CWIP)
$21.6B
Rate Base + CWIP
Low Case $23.7B
High Case $23.6B
Low Case $23.7B
High Case $23.6B
Rate Base
Rate Base + CWIP
Low Case $25.7B
High Case $26.7B
Low Case $25.7B
High Case $26.7B
* Projected 2010-2011 rate base is not adjusted for the impact of the carrying cost credit that results from the second series of the
Energy Recovery Bonds (see Appendix for this impact). 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.
Energy Recovery Bonds (see Appendix for this impact). 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.
Rate Base: $19.8B
Rate Base + CWIP: $21.6B
Rate Base + CWIP: $21.6B
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Energy Efficiency Incentives
Incentive Awards
(pre-tax dollars $MM)
(pre-tax dollars $MM)
$33.4 MM
$41.5 MM
2008
Actual
2009
Actual
2010
2011
High
Low Case $0 MM
High Case $20 MM
Low Case $0 MM
High Case $30 MM
High
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Impact to Cash Flow from Tax
Low Case $0 MM
High Case $400 MM*
Low Case $(10) MM
High Case $340 MM
2010
2011
* Estimate of 2010 bonus depreciation impact, but amount could vary based on actual capital additions
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2011
EPS Guidance
$3.85
2008
Actual
Actual
2010
$2.95
$3.65
Low
High
Low
High
$3.50
$3.35
Earnings per Share from Operations*
Earnings per Share from Operations*
2009
Actual
Actual
$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
in Appendix and at www.pge-corp.com
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Sustainable, comparable dividend
Payout ratio range of 50% - 70%
Dividend growth in line with EPS growth
Dividend Policy
$1.44
$1.68
$1.56
$1.82
$1.32
Annualized Dividends per Share
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Cash Flow and Equity Needs
401k / DRIP
forecasted to
provide
forecasted to
provide
$100 to $200 MM
per year
per year
(in $MM)
**
**
** The high case scenario reflects bonus depreciation in 2010 of approximately $400MM. If bonus
depreciation is not extended, the high case for equity needs in 2010 and 2011 would be $325MM
and
$1080MM, respectively.
depreciation is not extended, the high case for equity needs in 2010 and 2011 would be $325MM
and
$1080MM, respectively.
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GUIDANCE REFLECTS:
Capital expenditures consistent with low and high case
ranges
ranges
Utility earns ROE of at least 11.35%
Ratemaking capital structure maintained at 52% equity
CEE incentives and tax cash flow consistent with high
and low case ranges
and low case ranges
Resolution of FERC generator claims in 2011 results in
financing needs partially in 2011 (low case) or entirely in
2012 and beyond (high case)
financing needs partially in 2011 (low case) or entirely in
2012 and beyond (high case)
Financial Assumptions: 2010-2011
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PCG Investment Case
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
®
Appendix
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• 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 generation
Pacific Gas and Electric Company
(PG&E)
(PG&E)
PG&E SERVICE AREA
IN CALIFORNIA
IN CALIFORNIA
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PG&E Financial Highlights
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Electric and Gas Distribution
(1) Authorized revenues = operating costs + (rate of return ´ 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 |
• $12.4 billion of rate base (2009 wtd. avg.) |
Regulation |
• California state regulation (CPUC) • Cost of service ratemaking: General Rate Case (1) |
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Midway
Los Banos
Moss Landing
Diablo Canyon
Gates
Dixon
Malin
Round Mt
Vaca
Electric Transmission
Business Scope |
• Wholesale electric transmission services (construction, maintenance) • Operation by CA Independent System Operator |
Primary Assets |
• $3.1 billion of rate base (2009 wtd. avg.) |
Regulation |
• Federal regulation (FERC) • Cost of service ratemaking: Transmission Owner Rate Case • Revenues vary with system load |
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Natural Gas 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 (2009 wtd. avg.) |
Regulation |
• California state regulation (CPUC) • Incentive ratemaking framework: Gas Transmission & Storage Rate Case • Revenues vary with throughput |
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Electric Procurement & Owned Generation
Business Scope |
• Electricity and ancillary services from owned and controlled resources • Energy procurement program |
Primary Assets |
• $2.8 billion of rate base (2009 wtd. avg.) • Diablo Canyon Nuclear Power Plant (2,240 MW) • Gateway Generating Station (530 MW) • Largest privately owned hydro system (3,896 MW) • Funded nuclear plant decommissioning trusts of $2.0 billion |
Regulation |
• California state regulation (CPUC) • Cost of service ratemaking for utility-owned generation: General Rate Case • Pass through of power procurement costs |
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Humboldt Generating Station
(in construction)
(in construction)
Colusa Generating Station
(in construction)
(in construction)
Conventional Hydroelectric facilities
Gateway Generating Station
Helms Pumped Storage
PG&E Generation in California
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2009 Customer Profiles - % of Sales
Electric Customers
Gas Customers
(822 Bcf delivered)
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Existing Resource Mix
2009 Total Sources of Electric Energy
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RPS Contracts Signed Since 2002
Over 6,000 MW in RPS Contracts
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Greenhouse Gas Emissions
Total 2008 Greenhouse Gas Emissions by
Source Category
(Total 27.1 million metric tons CO2-e (2))
Source Category
(Total 27.1 million metric tons CO2-e (2))
Benchmarking Greenhouse Gas
Emissions for Delivered Electricity
(Pounds of CO2 per MWh)
Emissions for Delivered Electricity
(Pounds of CO2 per MWh)
U.S. Average (1)
1,329
California’s Average 724
2008 641
2007 636
2006 456
2005 489
2004 566
2003 620
(1) Source: U.S. Environmental Protection Agency eGRID 2007
Version 1.1 (updated December 2008 and based on 2005 data).
Version 1.1 (updated December 2008 and based on 2005 data).
(2) PG&E’s emissions rates for delivered electricity were independently verified and registered with the California Climate Action Registry.
Given that a portion of the electricity that PG&E delivers comes from unspecified generation sources, the company’s total emissions,
and associated emissions rates may vary from registered figures.
Given that a portion of the electricity that PG&E delivers comes from unspecified generation sources, the company’s total emissions,
and associated emissions rates may vary from registered figures.
PG&E (2)
33
Key Regulatory Proceedings
34
Cost of Capital
52% Equity Level · 11.35% ROE · Adj ustment Mechanism
• Decided separately from General Rate Case
• Current terms in place until 2013
• Triggers change to ROE if average Moody’s Utility (A or Baa) bond yield index over
a 12 month period moves up or down by 100 basis points over benchmarks.
a 12 month period moves up or down by 100 basis points over benchmarks.
• 12 month period is October through the following September
(i.e. October 2009 through September 2010).
(i.e. October 2009 through September 2010).
Mechanism
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2011 General Rate Case
Docket # A. 09-12-020
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
$1.048 billion 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
useful lives
• replacement of aging generation infrastructure, hydro relicensing
requirements
requirements
• replacement of aging fleet, buildings and IT systems
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Filing includes a flexible attrition mechanism adjusting for:
• labor cost adjustments
• materials and services adjustments
• capital related adjustments
• other adjustments, such as changes in franchise, payroll or other taxes
Attrition revenues are currently forecasted to be $275M and
$343M in 2012 and 2013
$343M in 2012 and 2013
Items not included in the 2011 GRC:
• SmartMeterTM and SmartMeterTM Upgrade programs
• Cornerstone, PV Filing and Manzana
Jan - July*
June - July
August
Nov
Discovery
Hearings
Opening/
Reply Briefs
Reply Briefs
Proposed
Decision
Decision
* Dates are approximate and subject to approval by ALJ
New Rates
in Effect
in Effect
Jan 1 2011
2011 General Rate Case
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Docket # ER09-1521-000
Sets revenue requirements for PG&E’s Electric Transmission
business in 2010-2011
business in 2010-2011
Revenue Requirement Request: $946 million
$800M Capital Expenditures
Adds additional transmission capacity and performance of
maintenance and replacement work on our substations
improving overall reliability of our system
maintenance and replacement work on our substations
improving overall reliability of our system
Final decision expected in Q3 2010
FERC TO12 Filing
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2011 Gas Transmission and
Storage Rate Case
Storage Rate Case
Docket # A. 09-09-013
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
$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
Attrition revenues are currently forecasted to be $32.4M,
$30.7M, and 22.6M for 2012, 2013 and 2014
$30.7M, and 22.6M for 2012, 2013 and 2014
Final decision requested by Q4 2010
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Docket # A. 08-05-023
Sets revenue requirements aimed at improving the reliability of
PG&E’s electric distribution system
PG&E’s electric distribution system
Request: $2.0 billion capital spend
Enables installation of new substation transformers, feeders,
conductors and other equipment to add capacity and relieve
points of strain
conductors and other equipment to add capacity and relieve
points of strain
Focuses on improving reliability, while 2011 GRC maintains
current reliability levels
current reliability levels
Hearings completed in 2Q 2009 - Next Step Proposed
Decision
Cornerstone Improvement Program
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Solar PV Program
Docket # A. 09-02-019
Sets revenue requirements to develop and own 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
Request: $1.45 billion (all capital) for the Utility-owned 250MW
PD issued on 01/26/2010 proposes:
• development and installation of up to 250MW Utility owned PV facilities, ranging
in capacity from 1MW to 20MW, up to 50MW per year
in capacity from 1MW to 20MW, up to 50MW per year
• recovery of project costs through performance based pricing resulting from the
PPA portion of the program, rather than ratebase
PPA portion of the program, rather than ratebase
• approval of the 2MW PV pilot constructed at the Vaca-Dixon substation in 2010
Alternate PD on 03/02/2010 proposes:
• recovery of project costs in rate base with opportunity to earn traditional cost-
of-service return
of-service return
Next Step: Final Decision
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Manzana Wind Project
Docket # A. 09-12-002
Sets revenue requirements to acquire, own, and operate the 189 -
246MW Manzana wind project in the Tehachapi region of Southern
California
246MW Manzana wind project in the Tehachapi region of Southern
California
Request: $900 million (all capital) at 246MW capacity
Manzana Wind Project would be developed, designed and
constructed by Iberdrola Renewables, Inc.
constructed by Iberdrola Renewables, Inc.
• PG&E will make progress payments throughout construction and will take
full ownership at completion
full ownership at completion
• final size of the project will 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 Q4 2010
42
Dynamic Pricing
Docket # A. 09-02-022
Sets revenue requirements to implement peak-day pricing and
time-of-use pricing
time-of-use pricing
Request: $160 million spend in 2008-2010, approximately $110 in capital
In February, CPUC issued revised PD approving $123 million of our
request and approving default Peak Day Pricing rates beginning:
request and approving default Peak Day Pricing rates beginning:
May 1, 2010: large commercial and industrial customers
February 1, 2011: large agricultural customers
November 1, 2011: small and medium commercial and industrial
February 1, 2011: Small agriculture customers will default to Time-of-Use rates
Final decision is expected in Q1 2010
Phase II costs associated with real-time pricing
will be filed under 2011 GRC Phase II filing
will be filed under 2011 GRC Phase II filing
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Carrying Cost Credit Impacts
Estimated Average Deferred Tax Balances and
Carrying Cost Credit Impacts ($MM)
Carrying Cost Credit Impacts ($MM)
($MM) | 2010 | 2011 | 2012 |
Energy Recovery Bond Average Deferred Tax Balance | $396 | $243 | $82 |
Estimated After-tax Carrying Cost Credit* | $(23) | $(14) | $(5) |
* Estimated carrying cost credits include only the equity portion and
assume a utility equity ratio of 52% and ROE at 11.35%.
assume a utility equity ratio of 52% and ROE at 11.35%.
44
ERB Amortization Schedule
($MM) | 2010 | 2011 | 2012 |
Annual ERB Amortization | $386 | $404 | $423 |
End-of-year ERB balance | $827 | $423 | $0 |
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Credit Profile
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 (2010-2012)* |
• S&P Business Profile Rating: Excellent • Total Debt to capitalization (EOY): 55.1% • Funds from Operations Cash Interest Coverage: 5.2x • Funds from Operations to Average Total Debt: 21.4% |
* Metrics include debt equivalents for long-term power purchase contracts
46
2008 EPS - Reg G Reconciliation
* 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
EPS on an Earnings from Operations Basis* | $2.95 |
Items Impacting Comparability** | 0.68 |
EPS on a GAAP Basis | $3.63 |
2008
47
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.
48
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) Expenses related to the California Taxpayers' Right to Vote Act.