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GRAPHIC
  PG&E Corporation and Pacific Gas and Electric Company

2013 Annual Report

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Financial Highlights

  1

Comparison of Five-Year Cumulative Total Shareholder Return

 
2

Selected Financial Data

 
3

Management's Discussion and Analysis

 
4

PG&E Corporation and Pacific Gas and Electric Company Consolidated Financial Statements

 
44

Notes to the Consolidated Financial Statements

 
56

Quarterly Consolidated Financial Data

 
105

Management's Report on Internal Control Over Financial Reporting

 
106

PG&E Corporation and Pacific Gas and Electric Company Boards of Directors

 
109

Officers of PG&E Corporation and Pacific Gas and Electric Company

 
109

Shareholder Information

 
111

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GLOSSARY

        The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2013 Annual Report   PG&E Corporation's and Pacific Gas and Electric Company's
combined Annual Report on Form 10-K for the year ended
December 31, 2013, including the information incorporated by
reference into the report
AFUDC   Allowance for Funds Used During Construction
ALJ   administrative law judge
ARO   Asset retirement obligation
ASU   accounting standards update
CAISO   California Independent System Operator
CARB   California Air Resources Board
CPUC   California Public Utilities Commission
CRRs   congestion revenue rights
EPA   Environmental Protection Agency
EPS   earnings per common share
FERC   Federal Energy Regulatory Commission
GAAP   generally accepted accounting principles
GHG   greenhouse gas
GRC   general rate case
GT&S   gas transmission and storage
IRS   Internal Revenue Service
LTIP   long term incentive plan
MGP   manufactured gas plant
NEIL   Nuclear Electric Insurance Limited
NRC   Nuclear Regulatory Commission
ORA   Officer of Ratepayer Advocates
OSC   CPUC Order to Show Cause
PSEP   pipeline safety enhancement plan
QF(s)   Qualified facilities
Regional Board   California Regional Water Quality Control Board, Lahontan Region
REITS   Global real estate investment trust
RSU(s)   restricted stock unit
ROE   return on equity
SEC   U.S. Securities and Exchange Commission
SED   Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD
TO   transmission owner
TURN   The Utility Reform Network
Utility   Pacific Gas and Electric Company
VIE(s)   variable interest entity(ies)

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FINANCIAL HIGHLIGHTS(1)

PG&E Corporation

(unaudited, in millions, except share and per share amounts)
  2013   2012  

Operating revenues

  $ 15,598   $ 15,040  
           

Income available for common shareholders

             

Earnings from operations(2)

    1,210     1,367  

Items impacting comparability(3)

    (396 )   (551 )
           

Reported consolidated income available for common shareholders

    814     816  
           

Income per common share, diluted

             

Earnings from operations(2)

    2.72     3.22  

Items impacting comparability(3)

    (0.89 )   (1.30 )
           

Reported consolidated net earnings per common share, diluted

    1.83     1.92  
           

Dividends declared per common share

    1.82     1.82  
           

Total assets at December 31,

  $ 55,605   $ 52,449  
           

Number of common shares outstanding at December 31,

    456,670,424     430,718,293  
           

(1)
This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company. PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.
(2)
"Earnings from operations" is not calculated in accordance with GAAP and excludes items impacting comparability as described in Note (3) below.
(3)
"Items impacting comparability" are those items that management believes do not reflect the normal course of operations.

PG&E Corporation's earnings from operations for 2013 and 2012 exclude net costs of $645 million and $812 million, pre-tax, that the Utility incurred in connection with natural gas matters that are not recoverable through rates, as shown in the table below. These amounts included pipeline-related expenses to validate safe operating pressures and perform other activities in accordance with the Utility's PSEP, costs to identify and remove encroachments from the Utility's transmission pipeline rights-of-way and perform other gas-related work. Costs incurred also included charges for disallowed PSEP capital expenditures, fines related to natural gas enforcement matters, and increases in the accrual for third-party claims arising from the San Bruno accident on September 9, 2010 that were partially offset by insurance recoveries. Costs for 2012 also included a contribution to the City of San Bruno to support the community's recovery efforts after the accident.

(pre-tax)
  2013   2012  

Pipeline-related expenses

  $ 387   $ 477  

Disallowed capital

    196     353  

Accrued fines

    22     17  

Third-party liability claims

    110     80  

Insurance recoveries

    (70 )   (185 )

Contribution to City of San Bruno

        70  
           

Total natural gas matters

  $ 645   $ 812  
           
           

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        PG&E Corporation common stock is traded on the New York Stock Exchange. The official New York Stock Exchange symbol for PG&E Corporation is "PCG."


COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL SHAREHOLDER RETURN(1)

        This graph compares the cumulative total return on PG&E Corporation common stock (equal to dividends plus stock price appreciation) during the past five fiscal years with that of the Standard & Poor's 500 Stock Index and the Dow Jones Utilities Index.

GRAPHIC


(1)
Assumes $100 invested on December 31, 2008 in PG&E Corporation common stock, the Standard & Poor's 500 Stock Index, and the Dow Jones Utilities Index, and assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns.

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SELECTED FINANCIAL DATA

(in millions, except per share amounts)
  2013   2012   2011   2010   2009  

PG&E Corporation

                               

For the Year

                               

Operating revenues

  $ 15,598   $ 15,040   $ 14,956   $ 13,841   $ 13,399  

Operating income

    1,762     1,693     1,942     2,308     2,299  

Income from continuing operations

    828     830     858     1,113     1,234  

Earnings per common share from continuing operations, basic

    1.83     1.92     2.10     2.86     3.25  

Earnings per common share from continuing operations, diluted

    1.83     1.92     2.10     2.82     3.20  

Dividends declared per common share(1)

    1.82     1.82     1.82     1.82     1.68  

At Year-End

                               

Common stock price per share

  $ 40.28   $ 40.18   $ 41.22   $ 47.84   $ 44.65  

Total assets

    55,605     52,449     49,750     46,025     42,945  

Long-term debt (excluding current portion)

    12,717     12,517     11,766     10,906     10,381  

Capital lease obligations (excluding current portion)(2)

    90     113     212     248     282  

Energy recovery bonds (excluding current portion)(3)

                423     827  

Pacific Gas and Electric Company

                               

For the Year

                               

Operating revenues

  $ 15,593   $ 15,035   $ 14,951   $ 13,840   $ 13,399  

Operating income

    1,790     1,695     1,944     2,314     2,302  

Income available for common stock

    852     797     831     1,107     1,236  

At Year-End

                               

Total assets

    55,049     51,923     49,242     45,679     42,709  

Long-term debt (excluding current portion)

    12,717     12,167     11,417     10,557     10,033  

Capital lease obligations (excluding current portion)(2)

    90     113     212     248     282  

Energy recovery bonds (excluding current portion)(3)

                423     827  

(1)
Information about the frequency and amount of dividends and restrictions on the payment of dividends is set forth in "Liquidity and Financial Resources—Dividends" within "Management's Discussion and Analysis of Financial Condition and Results of Operations," and in PG&E Corporation's Consolidated Statements of Equity, the Utility's Consolidated Statements of Shareholders' Equity, and Note 5 of the Notes to the Consolidated Financial Statements.
(2)
The capital lease obligations amounts are included in noncurrent liabilities—other in PG&E Corporation's and the Utility's Consolidated Balance Sheets.
(3)
The energy recovery bonds matured in December 2012.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

OVERVIEW

        PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility's electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility's electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility's nuclear generation facilities. The Utility also is subject to the jurisdiction of other federal, state, and local governmental agencies.

        Before setting rates, the CPUC and the FERC conduct proceedings to determine the annual amount of revenue that the Utility is authorized to collect from its customers to recover its reasonable operating and capital costs (depreciation, tax, and financing expenses) of providing utility services. The primary CPUC proceedings are the GRC and the GT&S rate case which generally occur every few years and result in revenue requirements that are set for multi-year periods. The CPUC also periodically conducts a cost of capital proceeding, where it determines the capital structure the Utility must maintain (i.e., the relative weightings of common equity, long-term debt, and preferred equity) and authorizes the Utility to earn a specific rate of return on each capital component, including equity. The authorized revenue requirements the CPUC sets in the GRC and GT&S rate cases are set at levels to provide the Utility an opportunity to earn its authorized rates of return on its "rate base"—the Utility's net investment in facilities, equipment, and other property used or useful in providing utility service to its customers. The primary FERC proceeding is the electric TO rate case which generally occurs on an annual basis. The rate of return for the Utility's FERC jurisdictional assets is embedded in revenues authorized in the TO rate cases.

        The Utility's ability to recover its GRC revenue requirements does not depend on the volume of the Utility's sales of electricity and natural gas services. This decoupling of revenues and sales eliminates volatility in the revenues earned by the Utility due to fluctuations in customer demand. The Utility's ability to recover a portion of its GT&S revenue requirements depends on the volume of natural gas transported as well as the use of its storage facilities. The Utility's ability to recover its electric transmission-related revenue requirements depends on the volume of electricity sales.

        The Utility's revenue requirements are set based on forecast costs. Differences in the amount or timing between forecast costs and actual costs can occur for numerous reasons, including unanticipated costs related to storms, outages, catastrophic events, or to comply with new legislation, regulations, or orders; or third-party claims that are not recoverable through insurance. Generally, differences between actual costs and forecast costs could affect the Utility's ability to earn its authorized return (referred to as "activities impacting earnings" below). However, for certain core operating costs, such as costs associated with pension and other employee benefits, the Utility is authorized to track the difference between actual amounts and forecast amounts and recover or refund the difference through rates (referred to as "cost recovery activities" below). The Utility also collects additional revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose programs, such as demand response and customer energy efficiency. Therefore, although the timing and amount of these costs can impact the Utility's revenue, these costs generally do not impact net income (included in "cost recovery activities" below).

        There may be some types of costs that the CPUC has determined will not be recoverable through rates or for which the Utility does not seek recovery, such as certain pipeline-related costs and fines associated with the Utility's natural gas transmission system. The CPUC could also disallow recovery of costs that it finds were not prudently or reasonably incurred. The timing and amount of the unrecoverable or disallowed costs can materially impact the Utility's revenue and net income, as described more fully below.

        This is a combined annual report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities. PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility's Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. This combined Management's Discussion and Analysis of Financial Condition and Results of Operations

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of PG&E Corporation and the Utility should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in this annual report.

Summary of Changes in Net Income and Earnings per Share

        PG&E Corporation's net income available for common shareholders for 2013 was $814 million, or $1.83 per share, as compared to $816 million, or $1.92 per share, for 2012. Operating results have continued to be materially affected by costs the Utility has incurred to improve the safety and reliability of its natural gas operations that are not recoverable through rates. These unrecovered costs have increased the Utility's equity needs which PG&E Corporation has funded through equity issuances that have materially diluted PG&E Corporation's EPS.

        The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation's income available for common shareholders and EPS for the year ended December 31, 2013 compared to the prior year. (See "Results of Operations" and "Natural Gas Matters" below for additional information.)

(in millions, except per share amounts)
  Earnings   EPS
(Diluted)
 

Income Available for Common Shareholders—2012

  $ 816   $ 1.92  

Natural gas matters(1)

    96     0.27  

Growth in rate base earnings(2)

    87     0.19  

Environmental-related costs(3)

    59     0.14  

Reduction in authorized cost of capital(4)

    (166 )   (0.37 )

Impact of capital spending over authorized(5)

    (24 )   (0.06 )

Uneconomic project and lease termination(6)

    (11 )   (0.03 )

Gas transmission revenues

    (9 )   (0.02 )

Increase in shares outstanding(7)

        (0.15 )

Other

    (34 )   (0.06 )
           

Income Available for Common Shareholders—2013

  $ 814   $ 1.83  
           
           

(1)
The Utility incurred net costs and capital charges related to natural gas matters of $645 million and $812 million, pre-tax, during 2013 and 2012, respectively. These amounts are not recoverable through rates. See "Operating and Maintenance" below.
(2)
Represents the impact of the increase in rate base as authorized in various rate cases during 2013 as compared to 2012.
(3)
Environmental-related costs were lower in 2013 compared to 2012 when the Utility incurred a significant charge for environmental remediation associated with the Hinkley natural gas compressor site.
(4)
Reflects the lower cost of capital authorized in the 2013 Cost of Capital proceeding. The CPUC authorized the Utility to earn a ROE of 10.40% (compared to 11.35% previously authorized) and adjusted its cost of debt beginning on January 1, 2013.
(5)
Represents the incremental interest and depreciation expense associated with capital expenditures that exceed the current authorized levels.
(6)
Represents the expenses incurred in 2013 for terminated projects and leases, compared to 2012.
(7)
Represents the impact of a higher number of weighted average shares outstanding during 2013, compared to 2012. PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility's capital structure and fund operations, including expenses related to natural gas matters. This has no dollar impact on earnings.

Key Factors Affecting Results of Operations, Financial Condition, and Cash Flows

        PG&E Corporation and the Utility believe that their future results of operations, financial condition, and cash flows will be materially affected by several factors, including the timing and outcome of CPUC ratemaking proceedings, the ultimate amount of costs the Utility will continue to incur to improve the safety and reliability of its natural gas operations, the outcome of the pending investigations that commenced following the San Bruno accident including the ultimate amount of fines the Utility will be required to pay, and the timing and amount of the Utility's financing needs.

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        For more information about the factors and risks that could affect PG&E Corporation's and the Utility's future results of operations, financial condition, and cash flows, or that could cause future results to differ from historical results, see the section entitled "Risk Factors" below. In addition, this 2013 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management's judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. See the section entitled "Cautionary Language Regarding Forward Looking Statements" below for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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RESULTS OF OPERATIONS

PG&E Corporation

        The consolidated results of operations consist primarily of balances related to the Utility, which are discussed below. The table below provides a summary of consolidated net income (loss) for 2013, 2012 and 2011:

(in millions)
  2013   2012   2011  

Consolidated Total

  $ 814   $ 816   $ 844  

PG&E Corporation

    (38 )   19     13  

Utility

    852     797     831  

        PG&E Corporation's net income consists primarily of operating and maintenance expense, interest expense on long-term debt, other income from investments, and income taxes. In 2013, PG&E Corporation's operating results were primarily impacted by an impairment loss resulting from investments unrelated to PG&E Corporation's core operations with no similar activity in 2012 and by an increase in charitable contributions. There were no material changes to PG&E Corporation's operating results in 2012 compared to 2011.

Utility

        The table below details certain items from the Utility's accompanying Consolidated Statements of Income for 2013, 2012, and 2011. The presentation below separately identifies activities that impact earnings and cost recovery activities that do not impact earnings.

        Activities that impact earnings (net income) primarily include revenues authorized by the CPUC and FERC in the various rate cases that are designed to recover the Utility's costs to own and operate its assets and provide it with an opportunity to earn its authorized rate of return on its rate base. Expenses that impact earnings include costs in excess of amounts authorized and costs for which the Utility does not seek recovery. (See "Utility Activities Impacting Earnings" below.) Activities that do not impact earnings include revenues collected to recover certain costs that the Utility is authorized to pass on to customers, including costs to purchase electricity and natural gas, as well as costs to fund public purpose programs. They also include revenues authorized in various rate cases that are designated for a specific purpose such as the payment of pension costs. (See "Utility Cost Recovery Activities" below.)

 
  2013   2012   2011  
(in millions)
  Earning
Activities
  Cost
Recovery
Activities
  Total
Utility
  Earning
Activities
  Cost
Recovery
Activities
  Total
Utility
  Earning
Activities
  Cost
Recovery
Activities
  Total
Utility
 

Electric operating revenues

  $ 6,465   $ 6,024   $ 12,489   $ 6,414   $ 5,600   $ 12,014   $ 6,150   $ 5,451   $ 11,601  

Natural gas operating revenues

    1,776     1,328     3,104     1,772     1,249     3,021     1,696     1,654     3,350  
                                       

Total operating revenues

    8,241     7,352     15,593     8,186     6,849     15,035     7,846     7,105     14,951  
                                       

Cost of electricity

        5,016     5,016         4,162     4,162         4,016     4,016  

Cost of natural gas

        968     968         861     861         1,317     1,317  

Operating and maintenance

    4,374     1,368     5,742     4,563     1,482     6,045     4,087     1,372     5,459  

Depreciation, amortization, and decommissioning

    2,077         2,077     1,928     344     2,272     1,815     400     2,215  
                                       

Total operating expenses

    6,451     7,352     13,803     6,491     6,849     13,340     5,902     7,105     13,007  
                                       

Operating income

    1,790         1,790     1,695         1,695     1,944         1,944  

Interest income(1)

                8                 6                 5  

Interest expense(1)

                (690 )               (680 )               (677 )

Other income, net(1)

                84                 88                 53  
                                                   

Income before income taxes

                1,192                 1,109                 1,325  

Income tax provision(1)

                326                 298                 480  
                                                   

Net income

                866                 811                 845  

Preferred stock dividend requirement

                14                 14                 14  
                                                   

Income Available for Common Stock

              $ 852               $ 797               $ 831  
                                                   
                                                   

(1)
Items represent activities that impact earnings for 2013, 2012, and 2011.

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Utility Activities Impacting Earnings

        The following discussion presents the Utility's operating results for activities impacting earnings for 2013, 2012, and 2011.

Operating Revenues

        The Utility's electric and natural gas operating revenues increased by $55 million, or 1%, in 2013 compared to 2012, primarily due to an increase of $294 million as authorized in various rate cases, partially offset by a decrease in revenues of $196 million as a result of the lower return authorized in the 2013 Cost of Capital proceeding.

        The Utility's electric and natural gas operating revenues increased by $340 million, or 4%, in 2012 compared to 2011 primarily due to an increase in revenues authorized in various rate cases and increases in natural gas storage revenues.

Operating and Maintenance

        The Utility's operating and maintenance expenses decreased by $189 million, or 4%, in 2013 compared to 2012, primarily due to decreases of $167 million for net costs incurred in connection with natural gas matters (see table below) and $88 million for environmental remediation costs associated with a significant charge in 2012 for the Hinkley natural gas compressor station site. These costs were partially offset by increases in other expenses that were not material. In each of 2013 and 2012, the Utility incurred expenses that were approximately $250 million higher than the level of authorized revenue requirements to improve the safety and reliability of its operations that will not be recovered in rates.

        The Utility's operating and maintenance expenses increased by $476 million, or 12%, in 2012 compared to 2011, primarily due to costs incurred to improve the safety and reliability of electric and natural gas operations that were approximately $250 million higher than amounts assumed under the 2011 rate cases. The remaining increase was primarily attributable to an increase of $73 million for net costs incurred in connection with natural gas matters (see table below), and a $56 million charge related to employee operational performance incentives.

        The following table provides a summary of the Utility's costs associated with natural gas matters that are not recoverable through rates:

(in millions)
  2013   2012   2011  

Pipeline-related expenses(1)(2)

  $ 387   $ 477   $ 483  

Disallowed capital

    196     353      

Accrued fines

    22     17     200  

Third-party liability claims

    110     80     155  

Insurance recoveries

    (70 )   (185 )   (99 )

Contribution to City of San Bruno

        70      
               

Total natural gas matters

  $ 645   $ 812   $ 739  
               
               

(1)
Includes $137 million, $268 million, and $331 million for work performed under the Utility's PSEP in 2013, 2012, and 2011, respectively.
(2)
The decrease for 2013 reflects amounts that were authorized for recovery in the CPUC's PSEP December 2012 decision as well as lower legal and other expenses in 2013.

        Pipeline-related expenses include costs to validate safe operating pressures, conduct strength testing, and perform other work associated with the Utility's PSEP; costs related to the Utility's multi-year effort to identify and remove encroachments (e.g. building structures and vegetation overgrowth) from transmission pipeline rights-of-way, and costs to improve the integrity of transmission pipelines and to perform other gas-related work; and legal and other expenses. In 2013, the Utility completed its "centerline" mapping survey of its entire gas transmission system to locate, mark, and map the center of all transmission pipelines. The Utility recorded charges of $196 million and $353 million in 2013 and 2012, respectively, for PSEP capital costs that are expected to exceed the amount to be recovered. The additional charge in 2013 primarily reflects a change in project portfolio involving higher unit costs to replace pipelines than originally forecast. (See "Natural Gas Matters—Disallowed Capital Costs" below.)

        The Utility recorded charges of $22 million and $17 million in 2013 and 2012, respectively, for fines imposed on the Utility by the CPUC and SED in connection with various self-reported violations and other enforcement matters. The Utility accrued $200 million in 2011 as the minimum amount of fines deemed probable that the Utility will pay

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to the State General Fund in connection with the three pending CPUC investigations. (See "Natural Gas Matters—Pending CPUC Investigations" below.)

        The Utility has settled the claims of substantially all of the remaining plaintiffs who sought compensation for personal injury, property damage, and other relief, following the San Bruno accident. The Utility has recorded cumulative charges of $565 million for third-party claims related to the San Bruno accident, reflecting its best estimate of probable loss. These costs were partially offset by cumulative insurance recoveries of $354 million. Although the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal expenses of $86 million) will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Depreciation, Amortization, and Decommissioning

        The Utility's depreciation, amortization, and decommissioning expenses increased by $149 million, or 8%, in 2013 compared to 2012, and by $113 million, or 6%, in 2012 compared to 2011, primarily due to the impact of capital additions.

Interest Income, Interest Expense, and Other Income, Net

        There were no material changes to interest income, interest expense, and other income, net for the periods presented.

Income Tax Provision

        The Utility's income tax provision increased by $28 million, or 9%, in 2013 compared to 2012. The effective tax rates were 27% in both 2013 and 2012.

        The Utility's income tax provision decreased by $182 million, or 38%, in 2012 compared to 2011. The effective tax rates were 27% and 36% for 2012 and 2011, respectively. The effective tax rate decreased primarily due to lower state and federal taxes for non-tax deductible penalties related to natural gas matters.

        The differences between the Utility's income taxes and amounts calculated by applying the federal statutory rate to income before income tax expense for continuing operations for 2013, 2012, and 2011 were as follows:

 
  2013   2012   2011  

Federal statutory income tax rate

    35.0 %   35.0 %   35.0 %

Increase (decrease) in income tax rate resulting from:

                   

State income tax (net of federal benefit)

    (2.2 )   (3.0 )   1.6  

Effect of regulatory treatment of fixed asset differences

    (3.8 )   (3.9 )   (4.2 )

Tax credits

    (0.4 )   (0.6 )   (0.5 )

Benefit of loss carryback

    (1.0 )   (0.4 )   (2.1 )

Non deductible penalties

    0.7     0.5     6.3  

Other, net

    (0.9 )   (0.8 )   0.1  
               

Effective tax rate

    27.4 %   26.8 %   36.2 %
               
               

Utility Cost Recovery Activities

Cost of Electricity

        The Utility's cost of electricity includes the costs of power purchased from third parties, transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, and realized gains and losses on price risk management activities. (See Note 9 of the Notes to the Consolidated Financial Statements.) The volume of power purchased by the Utility is driven by customer demand, the availability of the Utility's own generation facilities, and the cost effectiveness of each source of electricity. Additionally, the cost of electricity is impacted by the higher cost of procuring renewable energy as the Utility increases the amount of its renewable

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energy deliveries to comply with California legislative and regulatory requirements, and by costs associated with complying with California's GHG laws.

(in millions)
  2013   2012   2011  

Cost of purchased power

  $ 4,696   $ 3,873   $ 3,719  

Fuel used in own generation facilities

    320     289     297  
               

Total cost of electricity

  $ 5,016   $ 4,162   $ 4,016  
               
               

Average cost of purchased power per kWh

  $ 0.094   $ 0.079   $ 0.089  
               

Total purchased power (in millions of kWh)

    49,941     48,933     41,958  
               

Cost of Gas

        The Utility's cost of natural gas includes the costs of procurement, storage, transportation of natural gas and realized gains and losses on price risk management activities. (See Note 9 of the Notes to the Consolidated Financial Statements.) The Utility's future cost of natural gas will be affected by the market price of natural gas, changes in the cost of storage and transportation, changes in customer demand, and by costs associated with complying with California's GHG laws.

(in millions)
  2013   2012   2011  

Cost of natural gas sold

  $ 807   $ 676   $ 1,136  

Transportation cost of natural gas sold

    161     185     181  
               

Total cost of natural gas

  $ 968   $ 861   $ 1,317  
               
               

Average cost per Mcf of natural gas sold

  $ 3.54   $ 2.91   $ 4.49  
               

Total natural gas sold (in millions of Mcf)(1)

    228     232     253  
               

(1)
One thousand cubic feet

Operating Expenses

        The Utility's operating expenses also include certain recoverable costs that the Utility is required to incur as part of its operations and include public purpose programs, pension, and other continuous business expenses. Additionally, operating expenses in 2012 and 2011 include the amortization of energy recovery bonds regulatory asset which fully amortized in 2012. If the Utility were to spend over authorized amounts, these expenses could have an impact to earnings.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

        The Utility's ability to fund operations and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility's operating cash and short-term debt fluctuate as a result of seasonal load, volatility in energy commodity costs, collateral requirements related to price risk management activities, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and long-term financings, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. The CPUC authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The Utility has short-term borrowing authority of $4.0 billion, including $500 million that is restricted to certain contingencies.

        PG&E Corporation's ability to fund operations, make scheduled principal and interest payments, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, and pay dividends primarily depends on PG&E Corporation's access to the capital and credit markets and the level of cash distributions received from the Utility. PG&E Corporation's equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation's stock issuances used to fund Utility equity needs attributable to unrecoverable costs and penalties have had and will continue to have a dilutive effective on PG&E Corporation's EPS. PG&E Corporation also may use draws under its revolving credit facility or issuances under its commercial paper program to occasionally fund equity contributions on an interim basis.

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        PG&E Corporation and the Utility have $889 million of long-term debt maturing within the next 6 months. PG&E Corporation and the Utility plan to repay this debt with capital market financings.

        Further, given the Utility's significant ongoing capital expenditures, the Utility will continue to need equity contributions from PG&E Corporation to maintain its authorized capital structure. The Utility's future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters, incremental work to improve safety and reliability of electric and gas operations in excess of authorized revenue requirements, and environmental remediation costs. The Utility's equity needs would also increase to the extent it is required to pay fines or penalties in connection with pending investigations. (See "Natural Gas Matters" below.)

        PG&E Corporation's and the Utility's credit ratings may be affected by the ultimate outcome of the pending investigations related to natural gas matters and the San Bruno accident. PG&E Corporation's and the Utility's credit ratings may affect their access to the credit and capital markets and their respective financing costs in those markets. Credit rating downgrades may increase the cost of short-term borrowing, including PG&E Corporation's and the Utility's commercial paper, as well as the costs associated with their respective credit facilities, and long-term debt.

        PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. The following table summarizes PG&E Corporation's and the Utility's cash positions:

 
  December 31,  
(in millions)
  2013   2012  

PG&E Corporation

  $ 231   $ 207  

Utility

    65     194  
           

Total consolidated cash and cash equivalents

  $ 296   $ 401  
           
           

        In addition to these cash and cash equivalents, PG&E Corporation and the Utility hold restricted cash that primarily consists of cash held in escrow pending the resolution of the remaining disputed claims that were filed in the Utility's reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code. (See Note 12 of the Notes to the Consolidated Financial Statements.)

Revolving Credit Facilities and Commercial Paper Programs

        In April 2013, PG&E Corporation and the Utility amended and restated their revolving credit facilities to extend their termination dates from May 31, 2016 to April 1, 2018. These agreements contain substantially similar terms as the original 2011 credit agreements.

        In January 2014, PG&E Corporation established a new commercial paper program, the borrowings of which will be used primarily to cover fluctuations in cash flow requirements. PG&E Corporation will treat the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

        The following table summarizes PG&E Corporation's and the Utility's outstanding borrowings under their revolving credit facilities and the Utility's commercial paper program at December 31, 2013:

(in millions)
  Termination
Date
  Facility
Limit
  Letters of
Credit
Outstanding
  Borrowings   Commercial
Paper
  Facility
Availability
 

PG&E Corporation

  April 2018   $ 300 (1) $   $ 260   $   $ 40  

Utility

  April 2018     3,000 (2)   79         914 (3)   2,007 (3)
                           

Total revolving credit facilities

      $ 3,300   $ 79   $ 260   $ 914   $ 2,047  
                           
                           

(1)
Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(2)
Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(3)
The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

        For 2013, the average outstanding borrowings under PG&E Corporation's revolving credit facility were $214 million and the maximum outstanding balance during the year was $260 million. For 2013, the Utility's average

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outstanding commercial paper balance was $542 million and the maximum outstanding balance during the year was $1.1 billion. The Utility did not borrow under its credit facility in 2013.

        The revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under PG&E Corporation's and the Utility's senior note indentures, mergers, sales of all or substantially all of PG&E Corporation's and the Utility's assets, and other fundamental changes. In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. PG&E Corporation's revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. At December 31, 2013, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

2013 Financings

Utility

        The following table summarizes long-term debt issuances in 2013:

(in millions)
  Issue Date   Amount  

Senior Notes

           

3.25%, due 2023

  June 14   $ 375  

4.60%, due 2043

  June 14     375  

3.85%, due 2023

  November 12     300  

5.125%, due 2043

  November 12     500  
           

Total debt issuances in 2013

      $ 1,550  
           
           

        The net proceeds from the issuance of Utility senior notes in 2013 were used to fund maturing debt, to repurchase and extinguish $461 million principal amount, net of $15 million of premiums and $6 million of accrued interest, of the Utility's outstanding 4.80% Senior Notes due March 1, 2014, fund capital expenditures, and for general corporate purposes.

        The Utility also received cash contributions of $1.1 billion from PG&E Corporation during 2013 to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC.

PG&E Corporation

        In May 2013, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $400 million. As of December 31, 2013, PG&E Corporation had sold common stock having an aggregate gross sales price of $395 million and had the ability to issue an additional $5 million of its common stock under this agreement. During 2013, PG&E Corporation paid commissions of $3 million under this agreement. PG&E Corporation terminated this agreement in January 2014 and intends to enter into a new equity distribution agreement providing for the sale of PG&E Corporation's common stock having an aggregate gross sales price of $500 million.

        During 2013, PG&E Corporation issued 26 million shares of its common stock for aggregate net cash proceeds of $1,045 million in the following transactions:

        The proceeds from these sales were used for general corporate purposes, including the infusion of equity into the Utility. For the year ended December 31, 2013, PG&E Corporation made equity contributions to the Utility of $1.1 billion. PG&E Corporation forecasts that it will need to continue to issue additional common stock to fund the Utility's equity needs.

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Dividends

        The Board of Directors of PG&E Corporation and the Utility have each adopted a common stock dividend policy that is designed to meet the following three objectives:

        Each Board of Directors retains authority to change the common stock dividend rate at any time, especially if unexpected events occur that would change its view as to the prudent level of cash conservation. No dividend is payable unless and until declared by the applicable Board of Directors. In addition, before declaring a dividend, the CPUC requires that the PG&E Corporation Board of Directors give first priority to the Utility's capital requirements, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner. The Boards of Directors must also consider the CPUC requirement that the Utility maintain, on average, its CPUC-authorized capital structure including a 52% equity component.

        The Board of Directors of PG&E Corporation declared dividends of $0.455 per share for each of the quarters of 2013, 2012, and 2011, for annual dividends of $1.82 per share.

        The following table summarizes PG&E Corporation's and the Utility's dividends paid:

(in millions)
  2013   2012   2011  

PG&E Corporation:

                   

Common stock dividends paid

  $ 782   $ 746   $ 704  

Common stock dividends reinvested in Dividend Reinvestment and Stock Purchase Plan

    22     22     24  

Utility:

                   

Common stock dividends paid

  $ 716   $ 716   $ 716  

Preferred stock dividends paid

    14     14     14  

        In December 2013, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $208 million, of which $202 million was paid in January 2014 to shareholders of record on December 31, 2013.

        In December 2013, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable in February 2014, to shareholders of record on January 31, 2014.

        As the Utility focuses on improving the safety and reliability of its natural gas and electric operations, and subject to the outcome of the matters described under "Natural Gas Matters" below, PG&E Corporation expects that its Board will continue to maintain the current quarterly common stock dividend.

Utility

Operating Activities

        The Utility's cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.

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        The Utility's cash flows from operating activities for 2013, 2012, and 2011 were as follows:

(in millions)
  2013   2012   2011  

Net income

  $ 866   $ 811   $ 845  

Adjustments to reconcile net income to net cash provided by operating activities:

                   

Depreciation, amortization, and decommissioning          

    2,077     2,272     2,215  

Allowance for equity funds used during construction

    (101 )   (107 )   (87 )

Deferred income taxes and tax credits, net

    1,103     684     582  

PSEP disallowed capital expenditures

    196     353      

Other

    299     236     289  

Effect of changes in operating assets and liabilities:

                   

Accounts receivable

    (152 )   (40 )   (227 )

Inventories

    (10 )   (24 )   (63 )

Accounts payable

    99     (26 )   51  

Income taxes receivable/payable

    (377 )   (50 )   (192 )

Other current assets and liabilities

    (404 )   272     36  

Regulatory assets, liabilities, and balancing accounts, net

    (202 )   291     (100 )

Other noncurrent assets and liabilities

    22     256     414  
               

Net cash provided by operating activities

  $ 3,416   $ 4,928   $ 3,763  
               
               

        During 2013, net cash provided by operating activities decreased by $1.5 billion as compared to 2012 when the Utility collected $460 million from customers related to the energy recovery bonds which matured at the end of 2012. In addition, in 2013, the amount of cash collateral returned to the Utility by third parties was $243 million lower than in 2012, the settlement payments the Utility received from the U.S Treasury related to the Utility's spent nuclear fuel disposal costs was $221 million lower, net of legal fees, than the Utility received in 2012, and the Utility's tax payments were $236 million higher than in 2012. The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections.

        During 2012, net cash provided by operating activities increased by $1.2 billion compared to 2011 when the Utility's net collateral payments were $352 million higher. Also, in 2012, the Utility received settlement payments of $250 million, net of legal fees, from the U.S. Treasury related to the Utility's spent nuclear fuel disposal costs and made tax payments that were $224 million lower than in 2011. The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections.

        Future cash flow from operating activities will be affected by various factors, including:

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Investing Activities

        The Utility's investing activities primarily consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. The amount and timing of the Utility's capital expenditures is affected by many factors such as the occurrence of storms and other events causing outages or damages to the Utility's infrastructure. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility's nuclear generation facilities.

        The Utility's cash flows from investing activities for 2013, 2012, and 2011 were as follows:

(in millions)
  2013   2012   2011  

Capital expenditures

  $ (5,207 ) $ (4,624 ) $ (4,038 )

Decrease in restricted cash

    29     50     200  

Proceeds from sales and maturities of nuclear decommissioning trust investments

    1,619     1,133     1,928  

Purchases of nuclear decommissioning trust investments

    (1,604 )   (1,189 )   (1,963 )

Other

    21     16     14  
               

Net cash used in investing activities

  $ (5,142 ) $ (4,614 ) $ (3,859 )
               
               

        Net cash used in investing activities increased by $528 million in 2013 compared to 2012. This increase was due to an increase of $583 million in capital expenditures, partially offset by net proceeds associated with sales of nuclear decommissioning trust investments in 2013 as compared to net purchases of nuclear decommissioning trust investments in 2012.

        Net cash used in investing activities increased by $755 million in 2012 compared to 2011. This increase was primarily due to an increase of $586 million in capital expenditures and a reduction in restricted cash released for resolved Chapter 11 disputed claims of $150 million.

        Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility forecasts that it will incur between $5 billion and $6 billion in capital expenditures for 2014. Most of the Utility's revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO, and GT&S rate cases. The Utility's ability to invest in its electric and natural gas systems and develop new generation facilities is subject to many risks, including risks related to securing adequate and reasonably priced financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards.

Financing Activities

        The Utility's cash flows from financing activities for 2013, 2012, and 2011 were as follows:

(in millions)
  2013   2012   2011  

Borrowings under revolving credit facilities

  $   $   $ 208  

Repayments under revolving credit facilities

            (208 )

Net issuances (repayments) of commercial paper, net of discount of $2 in 2013, $3 in 2012, and $4 in 2011

    542     (1,021 )   782  

Proceeds from issuance of short-term debt

            250  

Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $18 in 2013, $13 in 2012, and $8 in 2011

    1,532     1,137     792  

Short-term debt matured

        (250 )   (250 )

Long-term debt matured or repurchased

    (861 )   (50 )   (700 )

Energy recovery bonds matured

        (423 )   (404 )

Preferred stock dividends paid

    (14 )   (14 )   (14 )

Common stock dividends paid

    (716 )   (716 )   (716 )

Equity contribution

    1,140     885     555  

Other

    (26 )   28     54  
               

Net cash provided by (used in) financing activities

  $ 1,597   $ (424 ) $ 349  
               
               

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        In 2013, net cash provided by financing activities increased by $2.0 billion compared to the same period in 2012. In 2012, net cash provided by financing activities decreased by $773 million compared to 2011. Cash provided by or used in financing activities is driven by the Utility's financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

        PG&E Corporation affiliates hold four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that are considered VIEs. Under these agreements, PG&E Corporation has made cumulative lease payments and investment contributions of $362 million and received $275 million in benefits and customer payments from 2010 to 2013. PG&E Corporation has no material remaining commitment to fund these agreements. Lease payments, investment contributions, benefits, and customer payments received are included in cash flows from operating and investing activities within the Consolidated Statements of Cash Flows.

        In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the years ended December 31, 2013, 2012, and 2011: dividend payments, common stock issuances, borrowings and repayments under its revolving credit facility, and transactions between PG&E Corporation and the Utility.

CONTRACTUAL COMMITMENTS

        The following table provides information about PG&E Corporation's and the Utility's contractual commitments at December 31, 2013:

 
  Payment due by period  
(in millions)
  Less Than
1 Year
  1 - 3 Years   3 - 5 Years   More Than
5 Years
  Total  

Contractual Commitments:

                               

Utility

                               

Long-term debt(1):

                               

Fixed rate obligations

  $ 1,181   $ 1,258   $ 2,718   $ 18,708   $ 23,865  

Variable rate obligations

    2     326     651     211     1,190  

Purchase obligations(2):

                               

Power purchase agreements:

                               

Qualifying facilities

    913     1,294     856     1,614     4,677  

Renewable energy (other than QF)

    1,906     4,211     4,066     30,242     40,425  

Other power purchase agreements

    829     1,492     1,324     2,984     6,629  

Natural gas supply, transportation, and storage

    727     348     216     756     2,047  

Nuclear fuel agreements

    145     308     280     647     1,380  

Pension and other benefits(3)

    398     796     796     398     2,388  

Capital lease obligations(2)

    27     46     30     8     111  

Operating leases(2)

    42     71     51     193     357  

Preferred dividends(4)

    14     28     28         70  

PG&E Corporation

                               

Long-term debt(1):

                               

Fixed rate obligations

    355                 355  
                       

Total

    6,539     10,178     11,016     55,761     83,494  
                       
                       

(1)
Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2013 and outstanding principal for each instrument with the terms ending at each instrument's maturity. (See Note 4 of the Notes to the Consolidated Financial Statements.)
(2)
See Note 14 of the Notes to the Consolidated Financial Statements.

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(3)
See Note 11 of the Notes to the Consolidated Financial Statements. Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the amount shown in the column entitled "more than 5 years" represents only 1 year of contributions for the Utility's pension and other benefit plans.
(4)
Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed period of five years.

        The contractual commitments table above excludes potential payments associated with unrecognized tax positions. Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amounts and periods of future payments to major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject to examination are discussed in Note 8 of the Notes to the Consolidated Financial Statements.

NATURAL GAS MATTERS

        Since the San Bruno accident, PG&E Corporation and the Utility have incurred total cumulative charges of approximately $2.5 billion related to natural gas matters that are not recoverable through rates, as shown in the following table:

(in millions)
  2013   2012   2011   2010   Total  

Pipeline-related expenses(1)

  $ 387   $ 477   $ 483   $ 63   $ 1,410  

Disallowed capital(2)

    196     353             549  

Accrued fines(3)

    22     17     200         239  

Third-party liability claims(4)

    110     80     155     220     565  

Insurance recoveries(4)

    (70 )   (185 )   (99 )       (354 )

Contribution(5)

        70             70  
                       

Total natural gas matters

  $ 645   $ 812   $ 739   $ 283   $ 2,479  
                       
                       

(1)
Cumulative expenses through December 31, 2013 include PSEP-related expenses of $736 million and other gas safety-related work of $348 million.
(2)
See "Disallowed Capital Costs" below.
(3)
See "Pending CPUC Investigations" and "Other Enforcement Matters" below.
(4)
The Utility has settled substantially all of the third-party liability claims related to the San Bruno accident. See "Operating and Maintenance" above and "Note 14 of the Consolidated Financial Statements" below.
(5)
On March 12, 2012, the Utility and the City of San Bruno entered into an agreement under which the Utility contributed $70 million to support the city and the community's recovery efforts.

Pending CPUC Investigations

        There are three CPUC investigative enforcement proceedings pending against the Utility that relate to (1) the Utility's safety recordkeeping for its natural gas transmission system, (2) the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility's pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident.

        The SED has issued investigative reports and briefs in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations. In July 2013, the SED recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, allocated as follows: (1) $300 million as a fine to the State General Fund, (2) $435 million for a portion of costs related to the Utility's PSEP that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future costs. (See "Disallowed Capital Costs" below.) If the SED's penalty recommendation is adopted, the Utility estimates that its total unrecovered costs and fines related to natural gas transmission operations would be about $4.5 billion. Other parties, including the City of San Bruno, TURN, the CPUC's ORA, and the City and County of San Francisco, have recommended total penalties of at least $2.25 billion, including fines payable to the State General Fund of differing amounts.

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        The ALJs who oversee the investigations are expected to issue one or more presiding officers' decisions to address the violations that they have determined the Utility committed and to impose penalties. It is uncertain when the decisions will be issued. Based on the CPUC's rules, the presiding officer's decisions would become the final decisions of the CPUC 30 days after issuance unless the Utility or another party filed an appeal with the CPUC, or a CPUC commissioner requested that the CPUC review the decision, within such time. If an appeal or review request is filed, other parties would have 15 days to provide comments but the CPUC could act before considering any comments.

        At December 31, 2013, the Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable that the Utility will pay to the State General Fund. The Utility is unable to make a better estimate due to the many variables that could affect the final outcome, including how the total number and duration of violations will be determined; how the various penalty recommendations made by the SED and other parties will be considered; how the financial and tax impact of unrecoverable costs the Utility has incurred, and will continue to incur, to improve the safety and reliability of its pipeline system will be considered; whether the Utility's costs to perform any required remedial actions will be considered; and how the CPUC will respond to public pressure. Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows. The CPUC may impose fines on the Utility that are materially higher than the amount accrued and may disallow PSEP costs that were previously authorized for recovery or other future costs. Disallowed capital investments would be charged to net income in the period in which the CPUC orders such a disallowance. See "Disallowed Capital Costs" below. Future disallowed expense and capital costs would be charged to net income in the period incurred.

Other CPUC Enforcement Matters

        PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses that may be incurred in connection with the following matters.

        Gas Safety Citation Program.    The Utility and other California gas corporations are required to provide notice to the SED of any self-identified or self-corrected violations of certain state and federal regulations that relate to the safety of their natural gas facilities and operating practices. The SED is authorized to issue citations and impose fines for self-identified or self-corrected violations and for violations that the SED identifies through its periodic audits of the Utility's operations or otherwise. The SED can exercise its discretion in determining whether to impose fines and the amount of such fines, or whether to take other enforcement action, based on the totality of the circumstances. The SED can consider such factors as the severity of the safety risk associated with each violation; the number and duration of the violations; whether the violation was self-reported, and whether corrective actions were taken. In January 2012, the SED imposed fines of $16.8 million on the Utility for self-reported failure to perform certain leak surveys and in 2013 the SED imposed fines ranging from $50,000 to $8.1 million for self-reported violations. The Utility has filed over 50 self-reports with the SED, plus additional follow-up reports, that the SED has not yet addressed. The SED is expected to impose fines or take enforcement action with respect to some of these self-reports.

        Natural Gas Transmission Pipeline Rights-of-Way.    In 2012, the Utility notified the CPUC and the SED that it is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments (such as building structures and vegetation overgrowth) from pipeline rights-of-way over a multi-year period. The SED could impose fines on the Utility or take other enforcement action in connection with this matter.

        Orders to Show Cause.    In August 2013, the CPUC issued two OSCs related to a document submitted by the Utility on July 3, 2013 as "errata" to correct information about some segments in Lines 101 and 147 (two of the Utility's natural gas transmission pipelines that serve the San Francisco peninsula) that had been previously provided to the CPUC in October 2011 to allow the Utility to restore operating pressure on these pipelines. On December 19, 2013, the CPUC issued a decision to impose fines of approximately $14 million on the Utility in connection with the errata submission, finding that the Utility violated CPUC rules that prohibit any person from misleading the CPUC. The Utility recorded this amount as an expense for 2013. On January 23, 2014, the Utility filed an application for the rehearing of this decision, arguing that it is erroneous in several respects. It is uncertain when the CPUC will issue a decision on the other OSC that directed the Utility to show cause why all orders issued by the CPUC to authorize increased operating pressure on the Utility's gas transmission pipelines should not be immediately suspended pending competent demonstration that the Utility's natural gas system records are reliable. Briefing on this OSC was completed on January 31, 2014.

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Disallowed Capital Costs

        In 2011, the CPUC ordered all natural gas operators in California to submit proposed plans to modernize and upgrade their natural gas transmission systems as well as associated cost forecasts and ratemaking proposals. In December 2012, the CPUC approved most of the projects proposed in the Utility's PSEP application that was filed in August 2011, but disallowed the Utility's request for rate recovery of a significant portion of costs the Utility forecasted it would incur through 2014. In October 2013, the Utility updated its PSEP application to present the results of its completed search and review of records relating to validation of operating pressure for all of the approximately 6,750 miles of the Utility's natural gas transmission pipelines. The Utility requested that the CPUC approve changes to the scope and prioritization of PSEP work, including deferring some projects to after 2014 and accelerating other projects, and that the CPUC adjust authorized revenue requirements to reflect these changes. The Utility has requested that the CPUC issue a final decision by August 2014.

        As of December 31, 2013, the Utility has recorded cumulative charges of $549 million for PSEP capital costs that are expected to exceed the amount to be recovered. The Utility has requested that the CPUC authorize capital costs of $766 million under the PSEP, reflecting the proposed changes in the PSEP update application. Of this amount, approximately $280 million is recorded in Property, Plant, and Equipment on the Consolidated Balance Sheets at December 31, 2013. The Utility could record additional charges to the extent PSEP capital costs are higher than currently expected, or if additional capital costs are disallowed by the CPUC. The Utility's ability to recover PSEP capital costs also could be affected by the final decisions to be issued in the CPUC's pending investigations discussed above.

Criminal Investigation

        In June 2011, the U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office began an investigation of the San Bruno accident and indicated that the Utility is a target of the investigation. Although the San Mateo County District Attorney's Office has publicly indicated that it will not pursue state criminal charges, the U.S. Department of Justice may still bring criminal charges, including charges based on claims that the Utility violated the federal Pipeline Safety Act, against PG&E Corporation or the Utility. It is uncertain whether any criminal charges will be brought against any of PG&E Corporation's or the Utility's current or former employees. The Utility is continuing to cooperate with federal investigators. A criminal charge or finding would further harm the Utility's reputation. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with any civil or criminal penalties that could be imposed and such penalties could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows. In addition, the Utility's business or operations could be negatively affected by any remedial measures that the Utility may undertake, such as operating its natural gas transmission business subject to the supervision and oversight of an independent monitor.

Third-party Liability Claims

        See Note 14 of the Notes to the Consolidated Financial Statements.

Class Action Complaint

        On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. The plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of California state law. The plaintiffs seek restitution and disgorgement, as well as compensatory and punitive damages.

        PG&E Corporation and the Utility contest the plaintiffs' allegations. On May 23, 2013, the court granted PG&E Corporation's and the Utility's request to dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs' allegations. The plaintiffs have appealed the court's ruling to the California Court of Appeal. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses, if any, that may be incurred in connection with this matter if the lower court's ruling is reversed.

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Other Pending Lawsuits and Claims

        At December 31, 2013, there were also four purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The plaintiffs for three of these lawsuits have filed a consolidated complaint with the San Mateo County Superior Court. The court has lifted the stay on these proceedings for the limited purpose of allowing the parties to exchange information and discuss possible resolution. A case management conference is scheduled for April 18, 2014. The remaining purported shareholder derivative lawsuit, filed in the U.S. District Court for the Northern District of California, remains stayed.

        In February 2011, the Board of Directors of PG&E Corporation authorized PG&E Corporation to reject a demand made by another shareholder that the Board of Directors (1) institute an independent investigation of the San Bruno accident and related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including Board of Directors members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The Board of Directors also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board of Directors deems such investigation or litigation appropriate.

        PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.

REGULATORY MATTERS

        The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of these and other proceedings may affect PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

2014 General Rate Case

        On November 15, 2012, the Utility filed its 2014 GRC application with the CPUC. In the Utility's GRC, the CPUC will determine the revenue requirements that the Utility is authorized to collect through rates from 2014 through 2016 to recover anticipated costs associated with electric generation operations and electric and natural gas distribution operations. The Utility has requested that the CPUC authorize a total revenue requirement of $7.8 billion for 2014, representing an increase of approximately $1.16 billion over the comparable authorized revenues for 2013. The Utility also has requested that the CPUC authorize attrition increases in 2015 and 2016 of $436 million and $486 million, respectively. The requested increase is intended to allow the Utility to recover the costs it forecasts it will incur to continue making improvements to the safety and reliability of its operations.

        The CPUC's ORA recommended that the Utility's 2014 revenue requirements be reduced by $125 million from amounts authorized in 2013, approximately $1.29 billion lower than the Utility's current forecast. The ORA also has recommended attrition increases of $169 million for 2015 and $160 million for 2016. The ORA's recommendations reflected reductions across all operations represented in the GRC. Twelve other parties, including TURN, also submitted recommendations in the 2014 GRC.

        A proposed decision is anticipated in the first quarter of 2014. Although it is uncertain when the CPUC will issue a final decision, any approved revenue requirement changes will be effective as of January 1, 2014.

2015 Gas Transmission and Storage Rate Case

        On December 19, 2013, the Utility filed its 2015 GT&S rate case application (covering 2015 through 2017) requesting the CPUC approve a total annual revenue requirement of $1.29 billion for anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2015. This is an increase of $555 million over the Utility's authorized revenue requirements of $731 million for 2014, which includes revenue requirements approved by the CPUC for both GT&S and PSEP. The Utility's forecasts for the 2015 GT&S rate case period are consistent with state law, which requires gas corporations to develop a plan to identify and minimize hazards and systemic risk for public and employee safety. The forecasts include the continuation of work begun in the Utility's PSEP, such as testing pipelines to verify safe operating pressures, replacing older pipelines, installing more valves, and inspecting the interior of more pipelines.

        The Utility requested that the CPUC authorize the Utility's forecast of its 2015 weighted average rate base for its gas transmission and storage business of $3.56 billion, which includes the capital spend above authorized levels for the prior rate case period. The Utility also requested additional revenue requirement increases of $61 million in 2016

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and $168 million in 2017 for increasing capital expenditures and the associated growth in rate base, as well as increasing costs of labor, materials, and other expenses. The Utility also has proposed eliminating the current mechanism that subjects a portion of the Utility's transportation-only revenue requirement to market risk, replacing it with two-way balancing accounts to allow the Utility to record differences between billed revenues and the Utility's authorized revenue requirements. Any over-collections would be returned to customers and any under-collections would be paid by customers, with no additional risk or benefit for shareholders.

        The Utility has not requested rate recovery for certain costs it forecasts it will incur during 2015 through 2017. These forecast costs include costs related to the Utility's multi-year effort to identify and remove encroachments from gas transmission pipeline rights-of-way, approximately $75 million over the three year period to pressure test pipelines placed into service after 1961, and approximately $75 million of remedial costs associated with the Utility's pipeline corrosion control program over the three year period.

        The Utility has requested that the CPUC issue a final decision by the end of 2014 so that any authorized revenue requirement adjustments can become effective on January 1, 2015. If the CPUC has not yet issued a final decision, then, in accordance with the CPUC's decision in the Utility's last GT&S rate case, there will be an automatic 2% increase in rates on January 1, 2015 that will remain in effect until the CPUC issues a final decision in the 2015 GT&S rate case. Given the significant revenue requirement increase the Utility has requested, the Utility plans to ask the CPUC for an order to make any authorized revenue requirement changes effective on January 1, 2015, in the event that the CPUC issues its final decision after that date.

        The Utility's continued use of regulatory accounting under GAAP (which enables it to account for the effects of regulation, including recording regulatory assets and liabilities) for gas transmission and storage service depends on its ability to recover its cost of service. If the Utility were unable to continue using regulatory accounting under GAAP, there would bedifferences in the timing of expense (or gain) recognition that could materially affect the Utility's future financial results.

Electric Transmission Owner Rate Cases

        On January 17, 2014, the FERC approved the settlement of the Utility's TO rate case that was filed in September 2012. Under the settlement the Utility's annual retail revenue requirement was increased from $934 million to $1,017 million effective as of May 1, 2013. The Utility has collected revenues between May 1 and September 30, 2013 at the higher as-filed rates requested in the Utility's application. The Utility will refund to customers the difference between revenues collected at the higher as-filed rates and the rates set in the FERC-approved settlement agreement.

        On September 24, 2013, the FERC accepted the Utility's TO rate case that the Utility filed on July 24, 2013, making the proposed rates effective October 1, 2013, subject to refund, pending a final decision by the FERC. The Utility requested a retail revenue requirement of $1,072 million and an ROE of 10.9%. The proposed rates represent a $55 million increase to the annual revenue requirement set in the FERC-approved settlement agreement described in the preceding paragraph. Hearings are currently being held in abeyance while settlement discussions are held.

Oakley Generation Facility

        In December 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California. The CPUC authorized the Utility to recover the purchase price through rates. The CPUC's denial of various applications for rehearing that had been filed with respect to its December 2012 decision was appealed to the California Court of Appeal. On February 5, 2014, the California Court of Appeal issued a ruling that annulled the CPUC's decision after the court determined that the evidence presented did not support a finding of need for the Oakley facility. The Utility is reviewing the court's decision.

Diablo Canyon Nuclear Power Plant

        In 2009, the Utility filed an application with the NRC to renew the operating licenses for the two operating units at Diablo Canyon. (The current licenses expire in 2024 and 2025.) In May 2011, after an earthquake and resulting tsunami that caused significant damage to the Fukushima-Dai-ichi nuclear facilities in Japan, the NRC granted the Utility's request to delay processing the Utility's application while certain advanced seismic studies were completed by the Utility. The Utility is currently assessing the data from recently completed advanced seismic studies along with other available seismic data. The Utility will not make any decisions about whether to request that the NRC resume

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processing the license renewal application until this assessment is completed and provided to the NRC. The Utility anticipates that it will complete its assessment by June 2014. In order for the NRC to issue renewed operating licenses, the California Coastal Commission must determine that license renewal is consistent with federal and state coastal laws. The disposition of the Utility's relicensing application also will be affected by the terms and timing of the NRC's "waste confidence" decision regarding the environmental impacts of the storage of spent nuclear fuel. The NRC has stated that it will not take action in licensing or re-licensing proceedings until it issues a new "waste confidence decision." (See "Risk Factors" below.)

        The CPUC is considering the Utility's December 2012 application to recover estimated costs to decommission the Utility's nuclear facilities at Diablo Canyon and the retired nuclear facility Humboldt Bay Power Plant Unit 3. The Utility files an application with the CPUC every three years requesting approval of the Utility's estimated decommissioning costs and authorization to recover those costs through rates. The CPUC bifurcated the proceeding to allow for the decommissioning cost estimate associated with Humboldt Bay to be addressed first and all other matters (including the Diablo Canyon decommissioning cost estimate and all rate-related issues) to be addressed in a second phase. On January 28, 2014, the assigned ALJ issued a proposed decision in the first phase that would authorize $679 million to complete the decommissioning at Humboldt Bay, approximately $48 million lower than the amount requested by the Utility. The Utility anticipates that the CPUC will issue a final decision in the first quarter of 2014. In the second phase, TURN has recommended that the CPUC adopt a decommissioning cost estimate for Diablo Canyon that is approximately $1.1 billion lower than the Utility's estimate of approximately $2.8 billion. The Utility anticipates the CPUC will issue a proposed decision in the second phase during the second quarter of 2014. (See the discussion of the 2012 Nuclear Decommissioning Cost Triennial Proceeding in Note 2 of the Notes to the Consolidated Financial Statements.)

ENVIRONMENTAL MATTERS

        The Utility's operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of the Utility's activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See "Risk Factors" below.)

Remediation

        The Utility is required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. (See Note 14 of the Notes to the Consolidated Financial Statements.)

Hinkley Site

        The Utility's remediation and abatement efforts at the Hinkley natural gas compressor site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. The Regional Board has certified a final environmental report evaluating the Utility's proposed remedial methods to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The Regional Board is expected to issue the final project permits and a final clean-up order in phases through 2014 and into 2015. As the permits and order are issued, the Utility will obtain additional clarity on the total costs associated with the final remedy and related activities. The Utility has implemented interim remediation measures to reduce the mass of the chromium plume, monitor and control movement of the plume, and provided replacement water to affected residents. (See Note 14 of the Notes to the Consolidated Financial Statements for additional information.) At December 31, 2013, $190 million was accrued in the Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, the extent of the chromium plume boundary, and adoption of a final drinking water standard by the State of California. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows.

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Topock Site

        The Utility's remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. The Utility expects to submit its final remedial design plan in 2014 for approval to begin construction of an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River. At December 31, 2013, $264 million was accrued in the Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Topock site. Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility's required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows.

Climate Change

        A report issued in 2012 by the U.S. EPA entitled, "Climate Change Indicators in the United States, 2012" states that the increase of GHG emissions in the atmosphere is changing the fundamental measures of climate in the United States, including rising temperatures, shifting snow and rainfall patterns, and more extreme climate events. (See "Risk Factors" below.) Although no comprehensive federal legislation has been enacted to address the reduction of GHG emissions, the California legislature has taken action to address climate change.

        California Assembly Bill 32 requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. The CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce AB 32. The CARB has approved various regulations to implement AB 32, including a state-wide, comprehensive "cap and trade" program that sets gradually declining limits (or "caps") on the amount of GHGs that may be emitted by the major sources of GHG emissions. During each year of the program, the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHGs emissions allowed for that year. The cap and trade program's first two-year compliance period, which began January 1, 2013, applies to the electricity generation and large industrial sectors. The next three-year compliance period, from January 1, 2015 through December 31, 2017, will expand to include the natural gas supply and transportation sectors, effectively covering all the capped sectors until 2020. During each year of the program, the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHGs emissions allowed for that year. Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties or exchanges in the market for trading GHG allowances. The CARB is allocating a fixed number of allowances (which will decrease each year) for free to regulated electric distribution utilities, including the Utility, for the benefit of their electricity customers. The utilities are required to consign their electricity-related allowances for auction by the CARB. The CPUC has ordered the utilities to allocate their electricity-related auction revenues among certain classes of their customers. Although the CPUC has previously authorized the utilities to recover their electricity-related GHG compliance costs through rates, the recovery of these costs has been temporarily deferred until May 2014. In addition, the CARB may allocate a number of allowances for free to natural gas suppliers, including the Utility, for the benefit of the Utility's natural gas customers. The Utility has filed requests at the CPUC for authority to recover the natural gas supplier-related compliance costs from natural gas customers on an annual basis effective January 1, 2015.

        The Utility expects all costs and revenues associated with GHG cap-and-trade to be passed through to customers.

Clean Water Act

        The EPA published draft regulations in April 2011 to implement the requirements of the federal Clean Water Act that requires cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, to reflect the best technology available to minimize adverse environmental impacts. In June 2012, the EPA proposed changes to these draft regulations which, if adopted, would provide more flexibility in complying with some of the requirements. It is currently uncertain when the EPA will issue final regulations.

        At the state level, the California Water Board has adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%. The California Water Board has appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at nuclear power plants, including Diablo Canyon. The committee's consultant is expected to submit a final report to the

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California Water Board in 2014. If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Even if the Utility is not required to install cooling towers, it could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility's Diablo Canyon operations must be in compliance with the California Water Board's policy by December 31, 2024.

OFF-BALANCE SHEET ARRANGEMENTS

        PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 2 (PG&E Corporation's tax equity financing agreements) and Note 14 of the Notes to the Consolidated Financial Statements (the Utility's commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

        The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and storage; emissions allowances, other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as "price risk" and "interest rate risk." The Utility is also exposed to "credit risk," the risk that counterparties fail to perform their contractual obligations.

        The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility's risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

Commodity Price Risk

        The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings. Such fluctuations, however, may impact cash flows. The Utility's natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

        The Utility's natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to price and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility sells most of its capacity based on the volume of gas that the Utility's customers actually ship, which exposes the Utility to volumetric risk.

        The Utility uses value-at-risk to measure its shareholders' exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services that could impact revenues due to changes in market prices and customer demand. The Utility's value-at-risk calculated under the methodology described above was approximately $14 million and $13 million at December 31, 2013 and 2012, respectively. During the 12 months ended December 31, 2013, the Utility's approximate high, low, and average values-at-risk were $14 million, $9 million and $12 million, respectively. During 2012, the value-at-risk amounts were $13 million, $10 million and $12 million, respectively. (See Note 9 of the Notes to the Consolidated Financial Statements for further discussion of price risk management activities.)

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Interest Rate Risk

        Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2013 and December 31, 2012, if interest rates changed by 1% for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the impact on net income over the next 12 months would be $11 million and $7 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Energy Procurement Credit Risk

        The Utility conducts business with counterparties mainly in the energy industry, including the CAISO market, other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.

        The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as "Credit Collateral" in the table below). Credit collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Credit collateral or performance assurance may be required from counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.

        The following table summarizes the Utility's credit risk exposure to its counterparties as of December 31, 2013 and December 31, 2012:

(in millions)
  Gross Credit
Exposure
Before Credit
Collateral(1)
  Credit
Collateral
  Net Credit
Exposure(2)
  Number of
Wholesale
Customers or
Counterparties
>10%
  Net Credit
Exposure to
Wholesale
Customers or
Counterparties
>10%
 

December 31, 2013

  $ 87   $ (9 ) $ 78     2     34  

December 31, 2012

  $ 94   $ (9 ) $ 85     2     62  

(1)
Gross credit exposure equals mark-to-market value on physically and financially settled contracts, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
(2)
Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit posted by counterparties and held by the Utility). For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES

        The preparation of Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.

Regulatory Accounting

        The Utility's rates are primarily set by the CPUC and the FERC and are designed to recover the cost of providing service. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are expected to be recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In

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addition, the Utility records regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other reduction of net allowable costs be given to customers over future periods.

        Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility's regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. The CPUC has not denied the recovery of any material costs previously recognized by the Utility as regulatory assets for the periods 2011 through 2013.

        If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. At December 31, 2013, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $6.5 billion and regulatory liabilities (including current balancing accounts payable) of $6.8 billion.

        In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures under construction (or recently completed expenditures) will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility records a provision based on the lower end of the range of possible losses to the extent there is a high degree of uncertainty in the Utility's forecast of capital project costs. The Utility's capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. As discussed above in "Natural Gas Matters—Disallowed Capital Costs" and Note 14 of the Notes to the Consolidated Financial Statements, the Utility recorded charges of $196 million and $353 million in 2013 and 2012, respectively, for PSEP capital costs that are expected to exceed the amount to be recovered. The additional charge in 2013 primarily reflects changes in the project portfolio involving higher costs to replace pipelines than originally forecast. Management will continue to periodically assess its PSEP capital costs and the related CPUC regulatory proceedings, and further charges could be required in future periods.

Loss Contingencies

Environmental Remediation Liabilities

        The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former MGP sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

        The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has begun a program related to certain former MGP sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility's liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

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        When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort.

        At December 31, 2013 and 2012, the Utility's accruals for undiscounted gross environmental liabilities were $900 million and $910 million, respectively. The Utility's undiscounted future costs could increase to as much as $1.7 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.

Legal and Regulatory Matters

        PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are subject to claims or named as parties in lawsuits. In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the minimum amount, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses (or reasonably possible losses in excess of the amounts accrued), are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing the amount of such losses, PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs. (See "Natural Gas Matters" and "Legal and Regulatory Contingencies" in Note 14 of the Notes to the Consolidated Financial Statements.)

Asset Retirement Obligations

        PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. A legal obligation can arise from an existing or enacted law, statute, or ordinance; a written or oral contract; or under the legal doctrine of promissory estoppel.

        At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process.

        Most of PG&E Corporation's and the Utility's AROs relate to the Utility's obligation to decommission its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission assets. The Utility estimates its obligation for the future decommissioning of its nuclear generation facilities and certain fossil fuel-fired generation facilities. In December 2012, the Utility submitted an updated estimate of the cost to decommission its nuclear facilities to the CPUC. The estimated undiscounted cost to decommission the Utility's nuclear power plants increased by $1.4 billion in 2012 due to higher spent nuclear fuel disposal costs and an increase in the scope of work. To estimate the liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. (See Note 2 of the Notes to the Consolidated Financial Statements.)

        Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. For example, a premature shutdown of the nuclear facilities at Diablo Canyon would increase the likelihood of an earlier start to decommissioning and cause an increase in the ARO. Additionally, if the inflation adjustment increased 25 basis points, the amount of the ARO would increase by approximately 4.21%. Similarly, an increase in

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the discount rate by 25 basis points would decrease the amount of the ARO by 5.24%. At December 31, 2013, the Utility's recorded ARO for the estimated cost of retiring these long-lived assets was $3.5 billion.

Pension and Other Postretirement Benefit Plans

        PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.

        The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses.

        PG&E Corporation and the Utility recognize the funded status of their respective plans on their respective Consolidated Balance Sheets with an offsetting entry to accumulated other comprehensive income (loss); or, to the extent that the cost of the plans are recoverable in utility rates, to regulatory assets and liabilities, resulting in no impact to their respective Consolidated Statements of Income.

        Pension and other benefit expense is based on the differences between actuarial assumptions and actual plan results and is deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery from customers. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability for a portion of the credit balance in accumulated other comprehensive income. (See Note 3 of the Notes to the Consolidated Financial Statements.)

        PG&E Corporation and the Utility review recent cost trends and projected future trends in establishing health care cost trend rates. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation's plans, the assumed health care cost trend rate for 2013 is 8%, gradually decreasing to the ultimate trend rate of 5% in 2020 and beyond.

        Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed-income returns were projected based on real maturity and credit spreads added to a long-term inflation rate. Equity returns were estimated based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation. For the Utility's defined benefit pension plan, the assumed return of 6.5% compares to a ten-year actual return of 8.7%.

        The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 494 Aa-grade non-callable bonds at December 31, 2013. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

        The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:

(in millions)
  Increase (Decrease) in
Assumption
  Increase in 2013
Pension
Costs
  Increase in Projected
Benefit Obligation at
December 31, 2013
 

Discount rate

    (0.50 )% $ 122   $ 1,041  

Rate of return on plan assets

    (0.50 )%   60      

Rate of increase in compensation

    0.50 %   60     246  

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        The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:

(in millions)
  Increase
(Decrease) in
Assumption
  Increase in 2013
Other Postretirement
Benefit Costs
  Increase in Accumulated
Benefit Obligation at
December 31, 2013
 

Health care cost trend rate

    0.50 % $ 7   $ 43  

Discount rate

    (0.50 )%   7     104  

Rate of return on plan assets

    (0.50 )%   9      

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

        This 2013 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management's judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations; forecasts of costs the Utility will incur to make safety and reliability improvements, including natural gas transmission costs that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as "assume," "expect," "intend," "forecast," "plan," "project," "believe," "estimate," "predict," "anticipate," "may," "should," "would," "could," "potential" and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

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        For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future financial condition, results of operations, and cash flows, see "Risk Factors" below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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RISK FACTORS

PG&E Corporation's and the Utility's reputations have been significantly affected by the negative publicity about the San Bruno accident, the related investigations and civil litigation, the Utility's noncompliance with certain natural gas regulations, and the fines imposed on the Utility for noncompliance with these regulations and for violation of certain CPUC rules. Their reputations may be further adversely affected by publicity regarding developments in the pending CPUC and criminal investigations, and by future investigations or other regulatory or governmental proceedings or action that may be commenced. In addition, the Utility's electricity and natural gas operations generally are subject to continuous public scrutiny and criticism that could lead to further reputational harm. Additional reputational harm or the inability of PG&E Corporation and the Utility to restore their reputations may further affect their financial conditions, results of operations and cash flows.

        The reputations of PG&E Corporation and the Utility have seriously suffered as a result of the extensive media coverage of the San Bruno accident, the investigative findings from the NTSB and the CPUC's independent review panel that placed the blame for the accident primarily on the Utility, the ensuing civil litigation, the criminal investigation, and the CPUC investigations that were commenced to determine whether the Utility violated any laws, rules, regulations or orders relating to safety recordkeeping, pipeline installation, integrity management, or other operational practices. (See "Natural Gas Matters" above.) PG&E Corporation and the Utility anticipate that there will be additional media coverage of future developments in the pending investigations, especially after the final outcomes are determined.

        In addition, there could be additional negative publicity as the SED takes action with respect to numerous reports the Utility has submitted to notify the SED about the Utility's noncompliance with certain natural gas regulations. In January 2012, the SED imposed fines of $16.8 million on the Utility for self-reported failure to perform certain leak surveys and in 2013 the SED imposed fines ranging from $50,000 to $8.1 million for self-reported violations. The SED may impose additional fines based on other self-reported violations. The media also has published reports about two orders to show cause that were issued by the CPUC in August 2013 regarding a filing the Utility submitted in July 2013 to correct certain factual errors made in documents submitted in October 2011 that provided support for an order to restore operating pressure on certain pipelines. In December 2013, the Utility was fined $14.4 million for violating a CPUC rule prohibiting misleading disclosures to the CPUC.

        The Utility's reputation can also be affected by media coverage of highly debated public policy issues such as those relating to the Utility's nuclear generation operations and nuclear decommissioning activities; environmental remediation or permitting activities; the accuracy, privacy, and safety of the Utility's information, operating, and billing systems; and the future development of the state-mandated California High Speed Rail project through the Utility's service territory. Media coverage of outages, vandalism, physical attacks on the Utility's facilities (such as the attack on the Metcalf electric substation), gas leaks, accidents causing injury or death, or other operational events, as well as concerns about the risks of terrorist acts, climate change, earthquakes, or a nuclear accident, can also negatively affect the Utility's reputation. These public policy debates and operational concerns have often led to additional adverse media coverage and could later result in investigations or other action by regulators, legislators and law enforcement officials or in lawsuits.

        The outcome of pending ratemaking proceedings, such as the GRC and the GT&S rate case, also could affect PG&E Corporation's and the Utility's reputations, with unfavorable regulatory outcomes having a negative reputational effect. Alternatively, PG&E Corporation's or the Utility's unfavorable reputation could have a negative influence on the regulatory decision-making process.

        Investors may question management's ability to repair the reputational harm that PG&E Corporation and the Utility have suffered, resulting in an adverse impact on the market price of PG&E Corporation common stock. The issuance of common stock by PG&E Corporation to fund the Utility's unrecovered costs has materially diluted PG&E Corporation's EPS. Additional share issuances following a declining stock price would cause further dilution. The extent to which PG&E Corporation's and the Utility's reputations can be restored will depend, in part, on the success of the Utility's efforts to improve the safety and reliability of the natural gas system as planned in the Utility's PSEP, whether they can implement the remaining recommendations made by the CPUC's independent review panel and the NTSB, and whether they are able to adequately show regulators, legislators, law enforcement officials, city officials, the media and the public that they have done so. If PG&E Corporation and the Utility are unable to repair their reputations, their financial conditions, results of operations and cash flows may continue to be negatively affected.

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PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially affected by the ultimate outcome of the CPUC investigations; the ultimate amount of gas transmission costs that the Utility does not recover through rates; and the ultimate outcome of the criminal investigation, including the amount of penalties imposed and the cost to implement any required action.

        As discussed above in the section entitled "Natural Gas Matters—Pending CPUC Investigations and Enforcement Matters," the SED has recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, consisting of a $300 million fine payable to the State General Fund and $1.95 billion of non-recoverable costs. If the SED's penalty recommendation is adopted by the CPUC, the Utility estimates that its total unrecovered costs and fines related to natural gas transmission operations would be about $4.5 billion and the Utility would incur material charges in addition to the charges already incurred for the probable fines of $200 million and unrecoverable natural gas transmission costs. Such charges would materially affect PG&E Corporation's and the Utility's financial condition and results of operations and could negatively affect the availability, amount, and timing of future debt and equity issuances by PG&E Corporation and the Utility. Future developments in the criminal investigation arising from the San Bruno accident also could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows. (See the sections entitled "Criminal Investigation" under the heading "Natural Gas Matters.")

PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows have been materially affected by costs incurred by the Utility to perform work under the PSEP, to undertake other pipeline-related work, and to improve the safety and reliability of its natural gas and electricity operations. The Utility forecasts that it will incur a material amount of unrecoverable natural gas transmission costs in 2014. The Utility's ability to recover natural gas transmission costs in 2015 through 2017 primarily will be determined by the outcome of the Utility's 2015 GT&S rate case.

        In December 2012, the CPUC approved most of the Utility's proposed scope and timing of projects to be completed under the Utility's PSEP through 2014, but the CPUC disallowed the Utility's request for rate recovery of a significant portion of forecasted capital costs and expenses. In October 2013, the Utility filed an update application, as ordered by the CPUC, to reflect changes in the scope and priority of projects resulting from the Utility's completed search and review of records related to pipeline pressure validation and other information, including updated cost forecasts. At December 31, 2013, the Utility had recorded cumulative charges of $549 million for PSEP capital costs that the Utility expects will exceed the adopted cost amounts. (See "Natural Gas Matters" above.) The Utility could record additional charges for disallowed costs if the CPUC does not approve the Utility's request to adjust revenue requirements or if cost forecasts increase. The Utility also forecasts it will incur costs during 2014 that it will not recover through rates, including costs to identify and remove encroachments from gas transmission pipeline rights-of-way, to pressure test pipelines placed into service after January 1, 1956, consistent with the CPUC's disallowance of such costs in the PSEP decision, and remedial costs associated with the Utility's pipeline corrosion control program.

        The Utility's ability to recover its natural gas transmission and storage costs in 2015, 2016, and 2017, will be determined by whether the CPUC approves the Utility's GT&S rate case application. (See "Regulatory Matters" above.) PG&E Corporation's and the Utility's financial condition and results of operations could be materially affected if the CPUC does not approve the Utility's request or if actual costs exceed the capital and expense amounts that the CPUC may authorize. The Utility has not requested rate recovery for certain costs it forecasts it will incur during 2015 through 2017, including costs to identify and remove encroachments from gas transmission pipeline rights-of-way, to pressure test certain pipelines, and to take remedial measures to address pipeline corrosion. Actual costs to perform this work could materially exceed forecasts and negatively affect PG&E Corporation's and the Utility's results of operations. The Utility's ability to recover natural gas transmission costs also could be affected by the final decisions to be issued in the CPUC's pending investigations discussed above.

PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows will be affected by their ability to continue accessing the capital markets and by the terms of debt and equity financings.

        The Utility relies on access to capital and credit markets as significant sources of liquidity to fund capital expenditures, pay principal and interest on its debt, provide collateral to support its natural gas and electricity procurement hedging contracts, and fund other operations requirements that are not satisfied by operating cash flows. See the discussion of the Utility's future financing needs above in "Liquidity and Financial Resources." The Utility's financing needs would increase if the Utility were required to incur unrecoverable costs and pay fines as a result of the outcome of the pending investigations discussed in "Natural Gas Matters" above. Such financing may become more difficult to obtain, especially if the ultimate outcome of the investigations affected the Utility's credit

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ratings. As the Utility has incurred costs it has been unable to recover through rates, it has relied on equity contributions from PG&E Corporation to maintain the 52% equity component of its CPUC-authorized capital structure. The Utility's equity needs could increase materially depending on the ultimate outcome of the pending investigations and the amount of natural gas and transmission costs it is unable to recover through rates.

        PG&E Corporation relies on independent access to the capital and credit markets to fund its operations, make capital expenditures, and contribute equity to the Utility as needed to maintain the Utility's CPUC-authorized capital structure, if funds received from the Utility (in the form of dividends or share repurchases) are insufficient to meet such needs. Since the San Bruno accident, PG&E Corporation has issued a material amount of equity to fund its equity contributions to the Utility. PG&E Corporation forecasts that it will need to issue additional material amounts of equity in 2014 as the Utility continues to incur costs that it cannot recover through rates. If the Utility is required to pay penalties in an amount that exceeds the amount already accrued, the Utility may need further equity contributions that PG&E Corporation may need to fund through additional dilutive share issuances. PG&E Corporation also may be required to access the capital markets to fund equity contributions to the Utility following the Utility's issuance of long-term debt to maintain the Utility's capital structure. PG&E Corporation primarily has relied on the public sale of its common stock to raise the funds it contributes to meet the Utility's equity needs. The market price of PG&E Corporation common stock could decline materially depending on the outcome of the investigations and the amount and timing of future share issuances. Declines in the stock price could increase the dilutive effect of future stock issuances and make it more difficult or expensive for PG&E Corporation to complete future equity offerings.

        PG&E Corporation's and the Utility's ability to access the capital and credit markets and the costs and terms of available financing depend on many factors, including the ultimate outcome of the pending investigations, the outcome of pending ratemaking proceedings, changes in their credit ratings, changes in the federal or state regulatory environment affecting energy companies generally or PG&E Corporation and the Utility in particular, the overall health of the energy industry, volatility in electricity or natural gas prices, and general economic and financial market conditions. If PG&E Corporation's or the Utility's credit ratings were downgraded to below investment grade, their ability to access the capital and credit markets would be negatively affected and could result in higher borrowing costs, fewer financing options, including reduced access to the commercial paper market, additional collateral posting requirements, which in turn could affect liquidity and lead to an increased financing need.

        If the Utility were unable to access the capital markets, it could be required to decrease or suspend dividends to PG&E Corporation. PG&E Corporation also would need to consider its alternatives, such as contributing capital to the Utility, to enable the Utility to fulfill its obligation to serve. To maintain PG&E Corporation's dividend level in these circumstances, PG&E Corporation would be further required to access the capital or credit markets. PG&E Corporation may need to decrease or discontinue its common stock dividend if it is unable to access the capital or credit markets on reasonable terms.

PG&E Corporation's and the Utility's financial condition depends upon the Utility's ability to recover its operating expenses and its electricity and natural gas procurement costs and to earn a reasonable rate of return on capital investments, in a timely manner from the Utility's customers through regulated rates.

        The Utility's ability to recover its costs and earn its authorized rate of return can be affected by many factors, including the time lag between when costs are incurred and when those costs are recovered in customers' rates and differences between the forecast or authorized costs embedded in rates (which are set on a prospective basis) and the amount of actual costs incurred. (See "Regulatory Matters—2014 General Rate Case" above.) The CPUC or the FERC may not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. For example, the CPUC has prohibited the Utility from recovering a material portion of costs that the Utility has already incurred, and will continue to incur, as it performs work under the PSEP, in part, because the CPUC found that such costs were incurred as a result of imprudent management. The CPUC may order the Utility to propose cost-sharing methods for certain costs or the Utility may decide for other reasons not to seek recovery of certain costs. In either case, the Utility would incur costs that are not recovered through rates. (See "Natural Gas Matters" above.)

        Further, to serve its customers in a safe and reliable manner, the Utility may be required to incur expenses before the CPUC approves the recovery of such costs. The Utility is generally unable to recover costs incurred before CPUC authorization is obtained, unless the CPUC authorizes the Utility to track costs for potential future recovery. For example, the Utility requested that the CPUC allow the Utility to track costs incurred in 2012 under the PSEP before the CPUC approved the plan. The CPUC did not address the Utility's request and as a result the

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Utility was unable to recover costs incurred before the effective date of the decision, December 20, 2012. The Utility's failure to recover these and other pipeline-related costs has materially affected PG&E Corporation's and the Utility's financial condition, results of operations and cash flows.

        Changes in laws and regulations or changes in the political and regulatory environment also may have an adverse effect on the Utility's ability to timely recover its costs and earn its authorized rate of return. In addition, the Utility may be required to incur substantial costs to comply with new state laws or to implement new state policies before the Utility is assured of cost recovery. For example, the state-mandated development of the California High Speed Rail Project through the Utility's service territory will require the relocation of some of the Utility's electric and gas facilities, new electric facilities, and significant expansion and upgrade to the Utility's electric system. Although the CPUC has begun a proceeding to address cost allocation and cost recovery issues, the Utility may incur costs before the issues are settled, for example, to obtain environmental permits. Further, fluctuating commodity prices also could affect the Utility's ability to timely recover its costs and earn its authorized rate of return. Although current law and regulatory mechanisms permit the Utility to pass through its costs to procure electricity and natural gas to customers in rates, a significant and sustained rise in commodity prices, caused by costs associated with new renewable energy resources and California's new cap-and-trade program and other factors, could create overall rate pressures that make it more difficult for the Utility to recover its costs. This pressure could increase as the Utility continues to collect authorized rates to support public purpose programs, such as energy efficiency programs, and low-income rate subsidies, and to fund customer incentive programs.

        The Utility's ability to recover its costs also may be affected by the economy and the economy's corresponding impact on the Utility's customers. For example, a sustained downturn or sluggishness in the economy could reduce the Utility's sales to industrial and commercial customers. Although the Utility generally recovers its costs through rates, regardless of sales volume, rate pressures increase when the costs are borne by a smaller sales base. A portion of the Utility's revenues depends on the level of customer demand for the Utility's natural gas transportation services which can fluctuate based on economic conditions, the price of natural gas, and other factors. In the GT&S rate case application, the Utility has proposed that this revenue mechanism be eliminated beginning on January 1, 2015 but it is uncertain whether the request will be granted.

        The Utility's failure to recover its operating expenses, including electricity and natural gas procurement costs in a timely manner through rates could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

The Utility's ability to procure electricity to meet customer demand at reasonable prices and recover procurement-related costs timely may be affected by increasing renewable energy requirements, the continuing functioning of the wholesale electricity market in California, and the expanded cap-and-trade market.

        The Utility meets customer demand for electricity from a variety of sources, including electricity generated from the Utility's own generation facilities, electricity provided by third parties under power purchase agreements, and purchases on the wholesale electricity market. The Utility must manage these sources using the commercial and CPUC regulatory principles of "least cost dispatch."

        Following competitive requests for offers from third parties, the Utility enters into power purchase agreements, including contracts to purchase renewable energy, in compliance with a CPUC-approved long-term procurement plan. These agreements become binding obligations of the Utility after the CPUC approves the agreements and authorizes the Utility to recover contract costs through rates. There is a risk that the contractual prices the Utility is required to pay will become uneconomic in the future for a variety of reasons, including developments in alternative energy technology, increased self-generation by customers, an increase in distributed generation, and lower customer demand due to economic conditions or the loss of the Utility's customers to other generation providers. In particular, as the market for renewable energy develops in response to California's renewable energy requirements, there is a risk that the Utility's contractual commitments could result in procurement costs that are higher than the market price of renewable energy. This could create a further risk that, despite original CPUC approval of the contracts, the CPUC would disallow contract costs in the future if the CPUC determines that the costs are unreasonably above market. In addition, the CPUC could disallow procurement costs if the CPUC determined that the Utility incurred procurement costs that were not in compliance with its CPUC-approved procurement plan, or that the Utility did not prudently administer the power purchase agreements that were executed in compliance with the plan. The Utility also could incur liability under its contracts to procure electricity from conventional and renewable generation resources if such resources are physically curtailed by the CAISO during periods of over-generation when generation resources scheduled with the CAISO exceed customer load. The costs incurred by the Utility under these circumstances would be subject to reasonableness review by the CPUC and could be disallowed.

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        The Utility also purchases energy through the day-ahead and real-time wholesale electricity market operated by the CAISO. The amount of electricity the Utility purchases on the wholesale market fluctuates due to a variety of factors, including, the level of electricity generated by the Utility's own generation facilities, changes in customer demand, periodic expirations or terminations of power purchase contracts, the execution of new power purchase contracts, fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract by the Utility, and the implementation of new energy efficiency and demand response programs. The market prices of electricity also fluctuate due to various factors, including the type of generation resources. Hydroelectric generation resources are generally the least expensive. As drought conditions in California and the Western U.S. persist, the market prices of electricity will generally reflect the higher cost of conventional and other resources. Although market mechanisms are designed to limit excessive prices, these market mechanisms could fail, or the related systems and software on which the market mechanisms rely may not perform as intended due to a cyber-attack or other reason, which could result in excessive market prices. For example, during the 2000 and 2001 energy crisis, the market mechanism flaws in California's newly established wholesale electricity market led to dramatically high market prices for electricity that the Utility was unable to recover through customer rates, ultimately causing the Utility to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code.

        In addition, electricity costs include the costs to comply with California's cap-and-trade regulations. Although some of these costs can be offset by revenues from the sale of emission allowances by the Utility on behalf of some classes of electricity customers, it is uncertain how the cap-and-trade market will develop in the future especially as the cap-and-trade compliance periods expand to cover other sources of GHG emissions and as other regional or federal cap-and-trade programs are adopted.

        PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially affected if the Utility is unable to recover a material portion of the costs it incurs to deliver electricity to customers.

The completion of capital investment projects is subject to substantial risks, and the timing of the Utility's capital expenditures and recovery of capital-related costs through rates, if at all, will directly affect net income.

        The Utility's ability to invest capital in its electric and natural gas businesses is subject to many risks, including risks related to obtaining regulatory approval, securing adequate and reasonably priced financing, obtaining and complying with the terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Third-party contractors on which the Utility depends to develop or construct these projects also face many of these risks. Changes in tax laws or policies, such as those relating to "bonus" depreciation, may also affect when or whether a potential project is developed. In addition, reduced forecasted demand for electricity and natural gas as a result of an economic slow-down, or other reasons, may also increase the risk that projects are deferred, abandoned, or cancelled. Some of the Utility's future capital investments may also be affected by evolving federal and state policies regarding the development of a "smart" electric transmission grid.

        In addition, differences in the amount or timing of actual capital expenditures compared to the amount and timing of forecast capital expenditures authorized to be recovered through rates, can directly affect net income. Changes in regulatory policies concerning ongoing recovery of costs for existing projects may increase risks associated with capital investment. Further, if capital expenditures are disallowed, the Utility would be required to write-off such expenses which could have a material effect on PG&E Corporation's and the Utility's financial condition and results of operations. For example, at December 31, 2013, the Utility had recorded cumulative charges of $549 million for PSEP capital costs that the CPUC has specifically disallowed and for increases in the amount of costs that the Utility forecasts will exceed the adopted cost amounts.

PG&E Corporation's and the Utility's financial results could be affected by the loss of Utility customers and decreased new customer growth due to municipalization, an increase in the number of community choice aggregators, increasing levels of "direct access," and the development and integration of self-generation and distributed generation technologies, if the CPUC fails to adjust the Utility's rates to reflect such events.

        The Utility's customers could bypass its distribution and transmission system by obtaining such services from other providers. This may result in stranded investment capital, loss of customer growth, and additional barriers to cost recovery. Forms of bypass of the Utility's electricity distribution system include construction of duplicate distribution facilities to serve specific existing or new customers. In addition, local government agencies could exercise their power of eminent domain to acquire the Utility's facilities and use the facilities to provide utility service to their local residents and businesses. The Utility may be unable to fully recover its investment in the

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distribution assets that it no longer owns. The Utility's natural gas transmission facilities could be bypassed by interstate pipeline companies that construct facilities in the Utility's markets, by customers who build pipeline connections that bypass the Utility's natural gas transmission and distribution system, or by customers who use and transport liquefied natural gas.

        Alternatively, the Utility's customers could become direct access customers who purchase electricity from alternative energy suppliers or they could become customers of governmental bodies registered as community choice aggregators to purchase and sell electricity for their residents and businesses. Although the Utility is permitted to collect a non-bypassable charge for generation-related costs incurred on behalf of these customers, or distribution, metering, or other services it continues to provide, the fee may not be sufficient for the Utility to fully recover the costs to provide these services. Furthermore, if the former customers return to receiving electricity supply from the Utility, the Utility could incur costs to meet their electricity needs that it may not be able to timely recover through rates or that it may not be able to recover at all.

        In addition, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, could put upward rate pressure on remaining customers. Also, a confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and storage a viable, cost-effective alternative to the Utility's bundled electric service which could further threaten the Utility's ability to recover its generation, transmission, and distribution investments.

        If the CPUC fails to adjust the Utility's rates to reflect the impact of changing loads, increasing self-generation and net energy metering, and the growth of distributed generation and storage, PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially adversely affected.

The operation of the Utility's electricity and natural gas generation, transmission, and distribution facilities involve significant risks which, if they materialize, can adversely affect PG&E Corporation's and the Utility's financial condition, results of operations and cash flows, and the Utility's insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event.

        The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. The Utility's service territory covers approximately 70,000 square miles in northern and central California and is composed of diverse geographic regions with varying climates, weather conditions, vegetation amounts, and population density levels, all of which create numerous operating challenges. The Utility's facilities are interconnected to the U.S. western electricity grid and numerous interstate and continental natural gas pipelines. These facilities are subject to physical attacks, including cyber-attacks that can cause local or widespread outages of electric or natural gas service, or otherwise disrupt operations, as well as cause property damage and personal injury. The Utility and other industry participants implement various security measures to monitor and protect their facilities but these security measures may not always be successful. The Utility's ability to earn its authorized rate of return depends on its ability to efficiently maintain, operate, and protect its facilities and provide electricity and natural gas services safely and reliably. The maintenance and operation of the Utility's facilities, and the facilities of third parties on which the Utility relies, involve numerous risks, including the risks discussed elsewhere in this section and those that arise from:

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        The occurrence of any of these events could affect demand for electricity or natural gas; cause unplanned outages or reduce generating output which may require the Utility to incur costs to purchase replacement power; cause damage to the Utility's assets or operations requiring the Utility to incur unplanned expenses to respond to emergencies and make repairs; damage the assets or operations of third parties on which the Utility relies; subject the Utility to claims by customers or third parties for damages to property, personal injury, or wrongful death, or subject the Utility to penalties. These costs may not be recoverable through rates or insurance. Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, the Utility may retain liability for the quality and completion of the contractor's work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders. Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. An uninsured loss could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows. Future insurance coverage may not be available at rates and on terms as favorable as the rates and terms of the Utility's current insurance coverage or may not be available at all.

The Utility's operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, cyber-attacks, physical attacks on the Utility's assets, acts of terrorism, severe weather, solar events, electromagnetic events, natural disasters, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Utility's operations and cause the Utility to incur unanticipated losses and expense.

        The operation of the Utility's extensive electricity and natural gas systems rely on evolving information and operational technology systems and network infrastructures that are becoming more complex as new technologies and systems are implemented to modernize capabilities to safely and reliably deliver gas and electric services. The Utility's business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of tasks and transactions, many of which are highly complex. The failure of the Utility's information and operational systems and networks due to a physical attack, cyber-attack or other cause could significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; damage to the Utility's assets or operations or those of third parties; and subject the Utility to claims by customers or third parties, any of which could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

        The Utility's systems, including its financial information, operational systems, advanced metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increase the risk of errors and malfunction. Any disruptions or deficiencies in existing systems, or disruptions, delays or deficiencies in the modification or implementation of new systems, could result in increased costs, the inability to track or collect revenues, the diversion of management's and employees' attention and resources, and could negatively affect the effectiveness of the companies' control environment, and/or the companies' ability to timely file required regulatory reports.

        The Utility's ability to measure customer energy usage and generate bills depends on the successful functioning of the advanced metering system. The Utility relies on third party contractors and vendors to service, support, and maintain certain proprietary functional components of the advanced metering system. If such a vendor or contractor ceased operations, if there was a contractual dispute or a failure to renew or negotiate the terms of a contract so that the Utility becomes unable to continue relying on such a third-party vendor or contractor, then the Utility could

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experience costs associated with disruption of billing and measurement operations and would incur costs as it seeks to find other replacement contractors or vendors or hire and train personnel to perform such services.

        Despite implementation of security and mitigation measures, all of the Utility's technology systems are vulnerable to disability or failures due to cyber-attacks, physical attacks on the facilities and equipment needed to operate the technology systems, viruses, human errors, acts of war or terrorism, and other events. If the Utility's information technology systems or network infrastructure were to fail, the Utility might be unable to fulfill critical business functions and serve its customers, which could have a material effect on PG&E Corporation's and the Utility's financial conditions, results of operations, and cash flows.

        In addition, in the ordinary course of its business, the Utility collects and retains sensitive information including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data can subject the Utility to penalties for violation of applicable privacy laws, subject the Utility to claims from third parties, and harm the Utility's reputation.

The Utility's success depends on the availability of the services of a qualified workforce and its ability to maintain satisfactory collective bargaining agreements which cover a substantial number of employees. PG&E Corporation's and the Utility's results may suffer if the Utility is unable to attract and retain qualified personnel and senior management talent, or if prolonged labor disruptions occur.

        The Utility's workforce is aging and many employees will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may not be successful. The Utility may be faced with a shortage of experienced and qualified personnel. The majority of the Utility's employees are covered by collective bargaining agreements with three unions. The terms of these agreements affect the Utility's labor costs. It is possible that labor disruptions could occur. In addition, it is possible that some of the remaining non-represented Utility employees will join one of these unions in the future. It is also possible that PG&E Corporation and the Utility may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the San Bruno accident. Any such occurrences could negatively impact PG&E Corporation's and the Utility's financial condition and results of operations.

The operation and decommissioning of the Utility's nuclear power plants expose it to potentially significant liabilities that it may not be able to recover from its insurance or other sources, and the Utility may incur significant capital expenditures and compliance costs that it may be unable to fully recover, adversely affecting PG&E Corporation's and the Utility's s financial conditions, results of operations, and cash flows.

        The operation of the Utility's nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to the storage, handling and disposal of spent nuclear fuel, the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. There are also significant uncertainties related to the regulatory, technological, and financial aspects of decommissioning nuclear generation plants when their licenses expire. To reduce the Utility's financial exposure to these risks, the Utility maintains insurance and manages decommissioning trusts that hold nuclear decommissioning charges collected through customer rates. However, the costs or damages the Utility may incur in connection with the operation and decommissioning of its nuclear power plants could exceed the amount of the Utility's insurance coverage and nuclear decommissioning trust assets. The Utility has insurance coverage for property damages and business interruption losses, as well as coverage for acts of terrorism at its nuclear power plants as a member of NEIL, a mutual insurer owned by utilities with nuclear facilities. NEIL provides coverage for both nuclear (meaning that nuclear material is released) and non-nuclear losses. Due to multiple large non-nuclear losses in the industry, in 2013 NEIL significantly reduced its coverage for non-nuclear losses. While the Utility is seeking alternative insurance options, efforts to obtain additional coverage may not be successful. Even if the Utility is able to obtain additional coverage, this future insurance coverage may not be available at rates and terms as favorable as the rates and terms of the Utility's current NEIL insurance coverage. If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

        In addition, as an operator of the two operating nuclear reactor units at Diablo Canyon, the Utility may be required under federal law to pay up to $255 million of liabilities arising out of each nuclear incident occurring not only at the Utility's Diablo Canyon facility but at any other nuclear power plant in the United States. (See Note 14

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of the Notes to the Consolidated Financial Statements.) The Utility's ability to continue to operate its nuclear generation facilities also is subject to the availability of adequate nuclear fuel supplies on terms that the CPUC will find reasonable.

        The NRC oversees the licensing, construction, and decommissioning of nuclear facilities and has broad authority to impose requirements relating to the maintenance and operation of nuclear facilities; the storage, handling and disposal of spent fuel; and the safety, radiological, environmental, and security aspects of nuclear facilities. The NRC has adopted regulations that are intended to protect nuclear facilities, nuclear facility employees, and the public from potential terrorist and other threats to the safety and security of nuclear operations, including threats posed by radiological sabotage or cyber-attack. The Utility incurs substantial costs to comply with these regulations. In addition, in March 2012, the NRC issued several orders to the owners of all U.S. operating nuclear reactors to implement the highest-priority recommendations issued by the NRC's task force to incorporate the lessons learned from the March 2011 earthquake and tsunami that caused significant damage to the Fukushima-Dai-ichi nuclear facilities in Japan. The NRC may issue further orders to implement the recommendations, including facility-specific orders, which could require the Utility to incur additional costs.

        In 2009, the Utility filed an application with the NRC to renew the operating licenses for the two operating units at Diablo Canyon. (See "Regulatory Matters—Diablo Canyon Nuclear Power Plant" above.) In May 2011, after the Fukushima-Dai-ichi event, the NRC granted the Utility's request to delay processing the Utility's application while certain advanced seismic studies were completed. The Utility is currently assessing the data from recently completed advanced seismic studies along with other available seismic data. The Utility will not make any decision about whether to request that the NRC to resume processing the license renewal application until this assessment is completed and provided to the NRC. The Utility anticipates that it will complete this assessment by June 2014. If the Utility does not request that the NRC resume processing the application, the current operating licenses would expire in 2024 and 2025. In any event, the NRC has stated that it will not issue final decisions in licensing or re-licensing proceedings, including the Utility's re-licensing application, until it has issued a new "waste confidence decision," as described below. In addition, the NRC would not issue renewed operating licenses for Diablo Canyon unless the California Coastal Commission determined that license renewal is consistent with federal and state coastal laws.

        In the NRC's original "waste confidence decision," the NRC found that spent nuclear fuel can be safely managed until a permanent off-site repository is established. The NRC's waste confidence decision was successfully challenged on the basis that the NRC's environmental review was deficient. The NRC has instructed its staff to develop and issue a new waste confidence decision and temporary storage rule by October 2014. It is uncertain how the new waste confidence decision and temporary storage rule would affect the Utility's decision to resume the renewal application process at the NRC or, if the application process were resumed, how the new waste confidence decision and temporary storage rule would affect the disposition of the renewal application. It is also uncertain how the new waste confidence decision and temporary storage rule would affect the Utility's nuclear generation operations during the current terms of the NRC licenses for Diablo Canyon.

        The CPUC has authority to determine the rates the Utility can collect to recover its nuclear fuel, operating, maintenance, compliance, and decommissioning costs. The Utility also could incur significant expense to comply with regulations or orders the NRC may issue in the future to impose new safety requirements, to obtain license renewal, and to comply with federal and state policies and regulations applicable to the use of cooling water intake systems at generation facilities, such as Diablo Canyon. (See "Environmental Matters" above.) The Utility expects that it would seek rate recovery of these additional costs. The outcome of these rate proceedings at the CPUC can be influenced by public and political opposition to nuclear power.

        If the Utility were unable to recover costs related to its nuclear facilities, PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially affected. The Utility may determine that it cannot comply with the new regulations or orders, including a new waste confidence decision, in a feasible and economic manner and voluntarily cease operations at Diablo Canyon. Alternatively, the NRC may order the Utility to cease its nuclear operations until it can comply with new regulations, orders, or decisions. Further, the Utility could decide not to resume the license renewal process or the Utility could fail to obtain renewed operating licenses for Diablo Canyon requiring nuclear operations to cease when the current licenses expire in 2024 and 2025.

The Utility's operations are subject to extensive environmental laws and changes in or liabilities under these laws could adversely affect PG&E Corporation's and the Utility's financial conditions, results of operations, and cash flows.

        The Utility's operations are subject to extensive federal, state, and local environmental laws, regulations, orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation

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of natural resources and wildlife. The Utility can incur significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations. These costs can be difficult to forecast because the extent of contamination may be unknown. For example, the Utility's costs to perform hydrostatic pressure tests on natural gas pipelines were higher than anticipated because the water used to perform the tests became contaminated as it traveled through the pipe and the Utility had to incur additional costs to remediate the contaminated wastewater. Further, even if the extent of contamination is known, remediation costs can be difficult to estimate due to many factors, including which remediation alternatives will be used, the applicable remediation levels, and the financial ability of other potentially responsible parties. Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations. Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions.

        The Utility has been, and may be, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. These sites, some of which the Utility no longer owns, include former manufactured gas plant sites, current and former power plant sites, former gas gathering and gas storage sites, sites where natural gas compressor stations are located, current and former substations, service center and general construction yard sites, and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. Although the Utility has liabilities for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. (See Note 14 to the Notes to the Consolidated Financial Statements for more information.)

        The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover in rates.

        Some of the Utility's environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance. The Utility's costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination have had, and may continue to have, a material effect on PG&E Corporation's and the Utility's financial conditions, results of operations, and cash flows. (See "Environmental Matters" above.)

The Utility's future operations may be affected by climate change that may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

        A report issued in 2012 by the EPA entitled, "Climate Change Indicators in the United States, 2012" states that the increase of GHG emissions in the atmosphere is changing the fundamental measures of climate in the United States, including rising temperatures, shifting snow and rainfall patterns, and more extreme climate events. In December 2009, the EPA issued a finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare. The impact of events or conditions caused by climate change could range widely, from highly localized to worldwide, and the extent to which the Utility's operations may be affected is uncertain. For example, if reduced snowpack decreases the Utility's hydroelectric generation, the Utility will need to acquire additional generation from other sources at a greater cost. In addition, if lower hydroelectric generation due to dry conditions or prolonged drought increases reliance on conventional generation resources, it may be more costly for the Utility to comply with California's renewable portfolio standard program and GHG emissions limits.

        Under certain circumstances, the events or conditions caused by climate change could result in a full or partial disruption of the ability of the Utility—or one or more of the entities on which it relies—to generate, transmit, transport, or distribute electricity or natural gas. The Utility has been studying the potential effects of climate change on the Utility's operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most significant. Events or conditions caused by climate change could have a greater impact on the Utility's operations than the Utility's studies suggest and could result in lower revenues or increased expenses, or both. If the CPUC fails to adjust the Utility's rates to reflect the impact of events or conditions caused by climate

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change, PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially affected.

The Utility is subject to fines and penalties for failure to comply with federal, state, or local statutes and regulations. Changes in the political and regulatory environment could cause federal and state statutes, regulations, rules, and orders to become more stringent and difficult to comply with, and required permits, authorizations, and licenses may be more difficult to obtain, increasing the Utility's expenses or making it more difficult for the Utility to execute its business strategy.

        The Utility must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of the CPUC, the FERC, the NRC, and other regulatory agencies relating to the aspects of its electricity and natural gas utility operations that fall within the jurisdictional authority of such agencies. In addition to the NRC requirements described above, these include meeting new renewable energy delivery requirements, resource adequacy requirements, federal electric reliability standards, customer billing, customer service, affiliate transactions, vegetation management, operating and maintenance practices, and safety and inspection practices. The Utility is subject to penalties and sanctions for failure to comply with applicable statutes, regulations, rules, tariffs, and orders.

        The CPUC can impose fines up to $50,000 per day, per violation. The CPUC has wide discretion to determine, based on the facts and circumstances, whether a single violation or multiple violations were committed and to determine the length of time a violation existed for purposes of calculating the amount of fines. The CPUC has delegated authority to the SED to levy citations and impose fines for violations of certain regulations related to the safety of natural gas facilities and utilities' natural gas operating practices. Like the CPUC, the SED has discretion to determine how to count the number of violations, but the delegated authority requires the SED to assess the maximum statutory fine per violation with discretion to adjust the amount of the fine based on the risk-level of the violation as determined by the SED. (For a discussion of pending investigations and potential enforcement proceedings, see MD&A "Natural Gas Matters" above.) A California law enacted in 2013 requires the CPUC to establish a safety enforcement program for gas facilities by July 1, 2014 and for electric facilities by January 1, 2015. The law requires the CPUC to delegate enforcement authority to the SED under these programs. The CPUC may make changes to its gas safety enforcement program to implement the new law. These programs may increase the risk that penalties will be imposed on the Utility.

        In addition, the federal Pipeline and Hazardous Materials Safety Administration has independent authority to impose fines for violation of federal pipeline safety regulations in amounts that range from $100,000 to $200,000 for an individual violation and from $1 million to $2 million for a series of violations.

        The Utility must comply with federal electric reliability standards that are set by the North American Electric Reliability Corporation and approved by the FERC. These standards relate to maintenance, training, operations, planning, vegetation management, facility ratings, and other subjects. These standards are designed to maintain the reliability of the nation's bulk power system and to protect the system against potential disruptions from cyber-attacks and physical security breaches. Regulatory authorities conduct frequent compliance audits of the Utility's operating practices. The FERC can impose fines (up to $1 million per day, per violation) for failure to comply with these mandatory electric reliability standards. As these and other standards and rules evolve, and as the wholesale electricity markets become more complex, the Utility's risk of noncompliance may increase.

        In addition, statutes, regulations, rules, tariffs, and orders, or their interpretation and application, may become more stringent and difficult to comply with in the future. If this occurs, the Utility could be exposed to increased costs to comply with the more stringent requirements or new interpretations and to potential liability for customer refunds, penalties, or other amounts. If it is determined that the Utility did not comply with applicable statutes, regulations, rules, tariffs, or orders, and the Utility is ordered to pay a material amount in customer refunds, penalties, or other amounts, PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows would be materially affected.

        The Utility also must comply with the terms of various governmental permits, authorizations, and licenses. These permits, authorizations, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, waste discharge permits and other approvals and licenses often have a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In connection with a license renewal for one or more of the Utility's hydroelectric generation facilities or assets, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the facility.

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        If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, or licenses, or if the Utility cannot recover any increased costs of complying with additional license requirements or any other associated costs in its rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations could be materially affected.

Market performance or changes in other assumptions could require PG&E Corporation and the Utility to make significant unplanned contributions to its pension plan, other postretirement benefits plans, and nuclear decommissioning trusts.

        PG&E Corporation and the Utility provide defined benefit pension plans and other postretirement benefits for eligible employees and retirees. The Utility also maintains three trusts for the purposes of providing funds to decommission its nuclear facilities. Up to approximately 60% of the plan assets and trust assets have generally been invested in equity securities, which are subject to market fluctuation. A decline in the market value may increase the funding requirements for these plans and trusts.

        The cost of providing pension and other postretirement benefits is also affected by other factors, including the assumed rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, levels of assumed interest rates, future government regulation, and prior contributions to the plans. Similarly, funding requirements for the nuclear decommissioning trusts are affected by changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements as well as changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment. Funding requirements also can be affected by the difference between the actual rate of return on plan assets and the assumed rate and by changes in the assumed rate of return. For example, changes in interest rates affect the liabilities under the plans: as interest rates decrease, the liabilities increase, potentially increasing the funding requirements.

        The Utility has recorded an asset retirement obligation related to decommissioning its nuclear facilities based on various estimates and assumptions. Changes in these estimates and assumptions can materially affect the amount of the recorded asset retirement obligation. (See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of the increase in the recorded asset retirement obligation to reflect increased estimated decommissioning costs.)

        The CPUC has authorized the Utility to recover forecasted costs to fund pension and postretirement plan contributions and nuclear decommissioning through rates. If the Utility is required to make significant unplanned contributions to fund the pension and postretirement plans and nuclear decommissioning trusts and is unable to recover such contributions in rates, the contributions would negatively affect PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

        Other Utility obligations, such as its workers' compensation obligations, are not separately earmarked for recovery through rates. Therefore, increases in the Utility's workers' compensation liabilities and other unfunded liabilities also can negatively affect net income.

PG&E Corporation's and the Utility's financial statements reflect various estimates, assumptions, and values and are prepared in accordance with applicable accounting rules, standards, policies, guidance, and interpretations, including those related to regulatory assets and liabilities. Changes to these estimates, assumptions, values, and accounting rules, or changes in the application of these rules, could materially affect PG&E Corporation's and the Utility's financial condition or results of operations.

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of revenues, expenses, assets, and liabilities, and the disclosure of contingencies. (See the discussion under Notes 1 and 2 of the Notes to the Consolidated Financial Statements and "Critical Accounting Policies" above.) If the information on which the estimates and assumptions are based proves to be incorrect or incomplete, if future events do not occur as anticipated, or if there are changes in applicable accounting guidance, policies, or interpretation, management's estimates and assumptions will change as appropriate. A change in management's estimates or assumptions, or the recognition of actual losses that differ from the amount of estimated losses, could have a material impact on PG&E Corporation's and the Utility's financial condition or results of operations.

        As a regulated entity, the Utility's rates are designed to recover the costs of providing service. The Utility's continued use of regulatory accounting (which enables it to account for the effects of regulation, including recording regulatory assets and liabilities) depends on its ability to recover its cost of service. (See Note 3 of the Notes to the

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Consolidated Financial Statements.) Since the San Bruno accident, the Utility has recorded cumulative charges of approximately $2.5 billion related to its natural gas operations that are not recoverable through rates. (See "Natural Gas Matters" above.) To the extent that rates, including rates in the 2015 GT&S rate case, are not set at a level that allows the Utility to recover the cost of providing service and a reasonable return on its investment in future periods, the Utility may be required to discontinue the application of regulatory accounting for portions of its operations. If that occurs, the related regulatory assets and liabilities would be charged against income in the period in which that determination was made and could have a material impact on PG&E Corporation's and the Utility's future financial condition and results of operations. In addition, if regulatory accounting did not apply, the Utility's future financial results could become more volatile under GAAP accounting as compared to historical financial results under regulatory accounting due to the differences in the timing of expense (or gain) recognition under GAAP accounting as compared to regulatory accounting.

As a holding company, PG&E Corporation depends on cash distributions and reimbursements from the Utility to meet its debt service and other financial obligations and to pay dividends on its common stock.

        PG&E Corporation is a holding company with no revenue generating operations of its own. PG&E Corporation's ability to pay interest on its outstanding debt, the principal at maturity, and to pay dividends on its common stock, as well as satisfy its other financial obligations, primarily depends on the earnings and cash flows of the Utility and the ability of the Utility to distribute cash to PG&E Corporation (in the form of dividends and share repurchases) and reimburse PG&E Corporation for the Utility's share of applicable expenses. Before it can distribute cash to PG&E Corporation, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and meet its obligations to employees and creditors. The Utility's ability to pay common stock dividends is constrained by regulatory requirements, including that the Utility maintain its authorized capital structure with an average 52% equity component. PG&E Corporation's and the Utility's ability to pay dividends also could be affected by financial covenants contained in their respective credit agreements that require each company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. If the Utility is not able to make distributions to PG&E Corporation or to reimburse PG&E Corporation, PG&E Corporation's ability to meet its own obligations could be impaired and its ability to pay dividends could be restricted. (Also see the discussion of financing risks above.)

PG&E Corporation could be required to contribute capital to the Utility or be denied distributions from the Utility to the extent required by the CPUC's determination of the Utility's financial condition.

        The CPUC imposed certain conditions when it approved the original formation of a holding company for the Utility, including an obligation by PG&E Corporation's Board of Directors to give "first priority" to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC later issued decisions adopting an expansive interpretation of PG&E Corporation's obligations under this condition, including the requirement that PG&E Corporation "infuse the Utility with all types of capital necessary for the Utility to fulfill its obligation to serve." The Utility's financial condition will be affected by the amount of costs the Utility incurs that it does not recover through rates (whether such non-recovery is because actual costs exceed authorized or forecast costs, the Utility did not seek authorization to recover certain costs, or the CPUC prohibited the Utility from recovering certain costs), the amount of third-party losses it is unable to recover through insurance, and the amount of penalties the Utility incurs in connection with the pending investigations and future citations for self-reported violations. After considering these impacts, the CPUC's interpretation of PG&E Corporation's obligation under the first priority condition could require PG&E Corporation to infuse the Utility with significant capital in the future or could prevent distributions from the Utility to PG&E Corporation, or both, any of which could materially restrict PG&E Corporation's ability to pay principal and interest on its outstanding debt or pay its common stock dividend, meet other obligations, or execute its business strategy. Further, laws or regulations could be enacted or adopted in the future that could impose additional financial or other restrictions or requirements pertaining to transactions between a holding company and its regulated subsidiaries.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

 
  Year ended December 31,  
 
  2013   2012   2011  

Operating Revenues

                   

Electric

  $ 12,494   $ 12,019   $ 11,606  

Natural gas

    3,104     3,021     3,350  
               

Total operating revenues

    15,598     15,040     14,956  
               

Operating Expenses

                   

Cost of electricity

    5,016     4,162     4,016  

Cost of natural gas

    968     861     1,317  

Operating and maintenance

    5,775     6,052     5,466  

Depreciation, amortization, and decommissioning          

    2,077     2,272     2,215  
               

Total operating expenses

    13,836     13,347     13,014  
               

Operating Income

    1,762     1,693     1,942  

Interest income

    9     7     7  

Interest expense

    (715 )   (703 )   (700 )

Other income, net

    40     70     49  
               

Income Before Income Taxes

    1,096     1,067     1,298  

Income tax provision

    268     237     440  
               

Net Income

    828     830     858  

Preferred stock dividend requirement of subsidiary

    14     14     14  
               

Income Available for Common Shareholders

  $ 814   $ 816   $ 844  
               
               

Weighted Average Common Shares Outstanding, Basic

    444     424     401  
               
               

Weighted Average Common Shares Outstanding, Diluted

    445     425     402  
               
               

Net Earnings Per Common Share, Basic

  $ 1.83   $ 1.92   $ 2.10  
               
               

Net Earnings Per Common Share, Diluted

  $ 1.83   $ 1.92   $ 2.10  
               
               

   

See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
  Year ended December 31,  
(in millions)
  2013   2012   2011  

Net Income

  $ 828   $ 830   $ 858  
               

Other Comprehensive Income

                   

Pension and other postretirement benefit plans obligations (net of taxes of $80, $72, and $9, at respective dates)

    113     108     (11 )

Gain on investments (net of taxes of $26, $3, and $0, at respective dates)

    38     4      
               

Total other comprehensive income (loss)

    151     112     (11 )
               

Comprehensive Income

    979     942     847  

Preferred stock dividend requirement of subsidiary

    14     14     14  
               

Comprehensive Income Attributable to Common Shareholders

  $ 965   $ 928   $ 833  
               
               

   

See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

 
  Balance at
December 31,
 
 
  2013   2012  

ASSETS

             

Current Assets

             

Cash and cash equivalents

  $ 296   $ 401  

Restricted cash

    301     330  

Accounts receivable

             

Customers (net of allowance for doubtful accounts of $80 and $87 at December 31, 2013 and 2012, respectively)

    1,091     937  

Accrued unbilled revenue

    766     761  

Regulatory balancing accounts

    1,124     936  

Other

    312     365  

Regulatory assets

    448     564  

Inventories

             

Gas stored underground and fuel oil

    137     135  

Materials and supplies

    317     309  

Income taxes receivable

    574     211  

Other

    611     172  
           

Total current assets

    5,977     5,121  
           

Property, Plant, and Equipment

             

Electric

    42,881     39,701  

Gas

    14,379     12,571  

Construction work in progress

    1,834     1,894  

Other

    2     1  
           

Total property, plant, and equipment

    59,096     54,167  

Accumulated depreciation

    (17,844 )   (16,644 )
           

Net property, plant, and equipment

    41,252     37,523  
           

Other Noncurrent Assets

             

Regulatory assets

    4,913     6,809  

Nuclear decommissioning trusts

    2,342     2,161  

Income taxes receivable

    85     176  

Other

    1,036     659  
           

Total other noncurrent assets

    8,376     9,805  
           

TOTAL ASSETS

  $ 55,605   $ 52,449  
           
           

   

See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

 
  Balance at
December 31,
 
 
  2013   2012  

LIABILITIES AND EQUITY

             

Current Liabilities

             

Short-term borrowings

  $ 1,174   $ 492  

Long-term debt, classified as current

    889     400  

Accounts payable

             

Trade creditors

    1,293     1,241  

Disputed claims and customer refunds

    154     157  

Regulatory balancing accounts

    1,008     634  

Other

    471     444  

Interest payable

    892     870  

Other

    1,612     2,018  
           

Total current liabilities

    7,493     6,256  
           

Noncurrent Liabilities

             

Long-term debt

    12,717     12,517  

Regulatory liabilities

    5,660     5,088  

Pension and other postretirement benefits

    1,601     3,575  

Asset retirement obligations

    3,539     2,919  

Deferred income taxes

    7,823     6,748  

Other

    2,178     2,020  
           

Total noncurrent liabilities

    33,518     32,867  
           

Commitments and Contingencies (Note 14)

             

Equity

             

Shareholders' Equity

             

Preferred stock

         

Common stock, no par value, authorized 800,000,000 shares, 456,670,424 shares outstanding at December 31, 2013 and 430,718,293 shares outstanding at December 31, 2012

    9,550     8,428  

Reinvested earnings

    4,742     4,747  

Accumulated other comprehensive income (loss)

    50     (101 )
           

Total shareholders' equity

    14,342     13,074  

Noncontrolling Interest—Preferred Stock of Subsidiary

    252     252  
           

Total equity

    14,594     13,326  
           

TOTAL LIABILITIES AND EQUITY

  $ 55,605   $ 52,449  
           
           

   

See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 
  Year ended December 31,  
 
  2013   2012   2011  

Cash Flows from Operating Activities

                   

Net income

  $ 828   $ 830   $ 858  

Adjustments to reconcile net income to net cash provided by operating activities:

                   

Depreciation, amortization, and decommissioning

    2,077     2,272     2,215  

Allowance for equity funds used during construction

    (101 )   (107 )   (87 )

Deferred income taxes and tax credits, net

    1,075     648     544  

PSEP disallowed capital expenditures

    196     353      

Other

    355     290     326  

Effect of changes in operating assets and liabilities:

                   

Accounts receivable

    (152 )   (40 )   (288 )

Inventories

    (10 )   (24 )   (63 )

Accounts payable

    113     (4 )   65  

Income taxes receivable/payable

    (363 )   (132 )   (103 )

Other current assets and liabilities

    (469 )   262     23  

Regulatory assets, liabilities, and balancing accounts, net           

    (202 )   291     (100 )

Other noncurrent assets and liabilities

    80     243     349  
               

Net cash provided by operating activities

    3,427     4,882     3,739  
               

Cash Flows from Investing Activities

                   

Capital expenditures

    (5,207 )   (4,624 )   (4,038 )

Decrease in restricted cash

    29     50     200  

Proceeds from sales and maturities of nuclear decommissioning trust investments

    1,619     1,133     1,928  

Purchases of nuclear decommissioning trust investments           

    (1,604 )   (1,189 )   (1,963 )

Other

    56     104     (113 )
               

Net cash used in investing activities

    (5,107 )   (4,526 )   (3,986 )
               

Cash Flows from Financing Activities

                   

Borrowings under revolving credit facilities

    140     120     358  

Repayments under revolving credit facilities

            (358 )

Net issuances (repayments) of commercial paper, net of discount of $2, $3, and $4 at respective dates

    542     (1,021 )   782  

Proceeds from issuance of short-term debt

            250  

Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $18, $13, and $8 at respective dates

    1,532     1,137     792  

Short-term debt matured

        (250 )   (250 )

Long-term debt matured or repurchased

    (861 )   (50 )   (700 )

Energy recovery bonds matured

        (423 )   (404 )

Common stock issued

    1,045     751     662  

Common stock dividends paid

    (782 )   (746 )   (704 )

Other

    (41 )   14     41  
               

Net cash provided by (used in) financing activities

    1,575     (468 )   469  
               

Net change in cash and cash equivalents

    (105 )   (112 )   222  

Cash and cash equivalents at January 1

    401     513     291  
               

Cash and cash equivalents at December 31

  $ 296   $ 401   $ 513  
               
               

Supplemental disclosures of cash flow information

                   

Cash received (paid) for:

                   

Interest, net of amounts capitalized

  $ (623 ) $ (594 ) $ (647 )

Income taxes, net

    (41 )   114     (42 )

Supplemental disclosures of noncash investing and financing activities

                   

Common stock dividends declared but not yet paid

  $ 208   $ 196   $ 188  

Capital expenditures financed through accounts payable

    322     362     308  

Noncash common stock issuances

    22     22     24  

Terminated capital leases

        136      

   

See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

 
  Common
Stock
Shares
  Common
Stock
Amount
  Reinvested
Earnings
  Accumulated
Other
Comprehensive
Income
(Loss)
  Total
Shareholders'
Equity
  Non
controlling
Interest—
Preferred
Stock of
Subsidiary
  Total
Equity
 

Balance at December 31, 2010

    395,227,205   $ 6,878   $ 4,606   $ (202 ) $ 11,282   $ 252   $ 11,534  

Net income

            858         858         858  

Other comprehensive loss

                (11 )   (11 )       (11 )

Common stock issued, net

    17,029,877     686             686         686  

Stock-based compensation amortization

        37             37         37  

Common stock dividends declared

            (738 )       (738 )       (738 )

Tax benefit from employee stock plans

        1             1         1  

Preferred stock dividend requirement of subsidiary

            (14 )       (14 )       (14 )
                               

Balance at December 31, 2011

    412,257,082     7,602     4,712     (213 )   12,101     252     12,353  

Net income

            830         830         830  

Other comprehensive income

                112     112         112  

Common stock issued, net

    18,461,211     773             773         773  

Stock-based compensation amortization

        52             52         52  

Common stock dividends declared

            (781 )       (781 )       (781 )

Tax benefit from employee stock plans

        1             1         1  

Preferred stock dividend requirement of subsidiary

            (14 )       (14 )       (14 )
                               

Balance at December 31, 2012

    430,718,293   $ 8,428   $ 4,747   $ (101 ) $ 13,074   $ 252   $ 13,326  

Net income

            828         828         828  

Other comprehensive income

                151     151         151  

Common stock issued, net

    25,952,131     1,067             1,067         1,067  

Stock-based compensation amortization

        56             56         56  

Common stock dividends declared

            (819 )       (819 )       (819 )

Tax expense from employee stock plans

        (1 )           (1 )       (1 )

Preferred stock dividend requirement of subsidiary

            (14 )       (14 )       (14 )
                               

Balance at December 31, 2013

    456,670,424   $ 9,550   $ 4,742   $ 50   $ 14,342   $ 252   $ 14,594  
                               
                               

   

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

 
  Year ended December 31,  
 
  2013   2012   2011  

Operating Revenues

                   

Electric

  $ 12,489   $ 12,014   $ 11,601  

Natural gas

    3,104     3,021     3,350  
               

Total operating revenues

    15,593     15,035     14,951  
               

Operating Expenses

                   

Cost of electricity

    5,016     4,162     4,016  

Cost of natural gas

    968     861     1,317  

Operating and maintenance

    5,742     6,045     5,459  

Depreciation, amortization, and decommissioning          

    2,077     2,272     2,215  
               

Total operating expenses

    13,803     13,340     13,007  
               

Operating Income

    1,790     1,695     1,944  

Interest income

    8     6     5  

Interest expense

    (690 )   (680 )   (677 )

Other income, net

    84     88     53  
               

Income Before Income Taxes

    1,192     1,109     1,325  

Income tax provision

    326     298     480  
               

Net Income

    866     811     845  

Preferred stock dividend requirement