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GRAPHIC
  PG&E Corporation and Pacific Gas and Electric Company

2012 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

 
53

Notes to the Consolidated Financial Statements

 
65

Quarterly Consolidated Financial Data

 
120

Management's Report on Internal Control Over Financial Reporting

 
121

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

 
124

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

 
124

Shareholder Information

 
126

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FINANCIAL HIGHLIGHTS(1)

PG&E Corporation

(unaudited, in millions, except share and per share amounts)
  2012   2011  

Operating Revenues

  $ 15,040   $ 14,956  
           

Income Available for Common Shareholders

             

Earnings from operations(2)

    1,367     1,438  

Items impacting comparability(3)

    (551 )   (594 )
           

Reported consolidated income available for common shareholders

    816     844  
           

Income Per Common Share, diluted

             

Earnings from operations(2)

    3.22     3.58  

Items impacting comparability(3)

    (1.30 )   (1.48 )
           

Reported consolidated net earnings per common share, diluted

    1.92     2.10  
           

Dividends Declared Per Common Share

    1.82     1.82  
           

Total Assets at December 31,

  $ 52,449   $ 49,750  
           

Number of common shares outstanding at December 31,

    431,436,673     412,257,082  
           

(1)
This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company ("Utility"). 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 the accounting principles generally accepted in the United States of America ("GAAP") and excludes items impacting comparability as described in Note (3) below.
(3)
"Items impacting comparability" represent items that management does not consider part of normal, ongoing operations.

PG&E Corporation's earnings from operations for 2012 and 2011 exclude net costs of $812 million and $739 million, pre-tax, that the Utility incurred in connection with natural gas matters. These amounts included pipeline-related expenses that will not be recoverable through rates to validate safe operating pressures, conduct strength testing, and perform other activities associated with safety improvements to the Utility's natural gas pipeline system, as well as legal and regulatory costs. In addition, a charge was recorded in 2012 for disallowed capital expenditures related to the Utility's pipeline safety enhancement plan that are forecasted to exceed the California Public Utilities Commission's ("CPUC") authorized levels or that were specifically disallowed. Also included are estimated penalties associated with pending CPUC investigations related to various aspects of the Utility's natural gas operations and other potential enforcement matters, accruals for third-party claims arising from the natural gas pipeline accident that occurred in San Bruno, California on September 9, 2010, and a contribution to the City of San Bruno to support the community's recovery efforts after the accident. These costs were partially offset by insurance recoveries. See the table below.

(pre-tax)
  2012   2011  

Pipeline-related expenses

  $ 477   $ 483  

Disallowed capital expenditures

    353      

Accrued penalties

    17     200  

Third-party claims

    80     155  

Insurance recoveries

    (185 )   (99 )

Contribution to City of San Bruno

    70      
           

Natural gas matters

  $ 812   $ 739  
           

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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, 2007 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)
  2012   2011   2010   2009   2008(1)  

PG&E Corporation

                               

For the Year

                               

Operating revenues

  $ 15,040   $ 14,956   $ 13,841   $ 13,399   $ 14,628  

Operating income

    1,693     1,942     2,308     2,299     2,261  

Income from continuing operations

    830     858     1,113     1,234     1,198  

Earnings per common share from continuing operations, basic

    1.92     2.10     2.86     3.25     3.23  

Earnings per common share from continuing operations, diluted

    1.92     2.10     2.82     3.20     3.22  

Dividends declared per common share(2)

    1.82     1.82     1.82     1.68     1.56  

At Year-End

                               

Common stock price per share

  $ 40.18   $ 41.22   $ 47.84   $ 44.65   $ 38.71  

Total assets

    52,449     49,750     46,025     42,945     40,860  

Long-term debt (excluding current portion)

    12,517     11,766     10,906     10,381     9,321  

Capital lease obligations (excluding current portion)(3)

    113     212     248     282     316  

Energy recovery bonds (excluding current portion)(4)

            423     827     1,213  

Pacific Gas and Electric Company

                               

For the Year

                               

Operating revenues

  $ 15,035   $ 14,951   $ 13,840   $ 13,399   $ 14,628  

Operating income

    1,695     1,944     2,314     2,302     2,266  

Income available for common stock

    797     831     1,107     1,236     1,185  

At Year-End

                               

Total assets

    51,923     49,242     45,679     42,709     40,537  

Long-term debt (excluding current portion)

    12,167     11,417     10,557     10,033     9,041  

Capital lease obligations (excluding current portion)(3)

    113     212     248     282     316  

Energy recovery bonds (excluding current portion)(4)

            423     827     1,213  

(1)
In 2008, PG&E Corporation recorded $154 million in income from discontinued operations related to losses incurred and synthetic fuel tax credits claimed by PG&E Corporation's former subsidiary, National Energy & Gas Transmission, Inc.
(2)
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 6 of the Notes to the Consolidated Financial Statements.
(3)
The capital lease obligations amounts are included in noncurrent liabilities—other in PG&E Corporation's and the Utility's Consolidated Balance Sheets.
(4)
See Note 5 of the Notes to the Consolidated Financial Statements.

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

OVERVIEW

        PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company ("Utility"), 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 served approximately 5.2 million electricity distribution customers and approximately 4.4 million natural gas distribution customers at December 31, 2012.

        The Utility is regulated primarily by the California Public Utilities Commission ("CPUC") and the Federal Energy Regulatory Commission ("FERC"). In addition, the Nuclear Regulatory Commission ("NRC") oversees the licensing, construction, operation, and decommissioning of the Utility's nuclear generation facilities. 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 over the rates and terms and conditions of service governing the Utility on its interstate natural gas transportation contracts. 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 ("revenue requirements") 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 general rate case ("GRC") and the gas transmission and storage ("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 a rate of return on equity ("ROE"). 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 transmission owner ("TO") rate case which generally occurs on an annual basis. The FERC does not conduct a separate proceeding to authorize a specific rate of return on the Utility's FERC-jurisdictional assets. Instead, the rate of return is embedded in electric transmission revenues authorized by the FERC in TO rate cases. If the outcome of a TO rate case is reached through a FERC-approved settlement, the rate of return may not be specifically identified but rates would have been set to provide the Utility an opportunity to earn a reasonable rate of return. In other TO rate cases, the FERC may determine a specific rate of return after the FERC has held hearings and the parties have submitted briefs.

        The Utility's ability to recover the revenue requirements that have been authorized by the CPUC in a GRC 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. However, fluctuations in operating and maintenance costs and the amount and timing of capital expenditures may impact the Utility's ability to earn its authorized rate of return. The Utility's ability to recover a portion of its revenue requirements that have been authorized by the CPUC in GT&S rate cases depends on the volume of natural gas transported. The Utility's ability to recover its revenue requirements that have been authorized by the FERC in a TO rate case depends on the volume of electricity sales.

        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, demand response, and customer energy efficiency programs. Therefore, although the timing and amount of these costs can impact the Utility's revenue, these costs generally do not impact net income. The Utility's revenues and net income, however, also may be affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets or fails to meet certain performance criteria, such as customer energy efficiency goals.

        The Utility's revenue requirements are set based on forecasted costs. Differences in actual costs could negatively affect the Utility's ability to earn its authorized return. Differences can occur for numerous reasons, including unanticipated costs related to storms, outages, catastrophic events, or to comply with new legislation, regulations, or orders; or if the Utility is required to pay third-party claims that are not recoverable through insurance. The CPUC

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could also disallow recovery of costs that it finds were not prudently or reasonably incurred. Finally, 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 costs associated with the Utility's natural gas system, penalties associated with investigations or violations, and environmental-related liabilities associated with the Utility's natural gas compressor station located in Hinkley, California, 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 ("MD&A") 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.

Key Factors Affecting Results of Operations and Financial Condition

        PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows have continued to be materially affected by costs the Utility has incurred to improve the safety and reliability of its natural gas operations, as well as by costs related to the ongoing regulatory proceedings, investigations, and civil lawsuits that commenced following the rupture of one of the Utility's natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the "San Bruno accident"). Through December 31, 2012, PG&E Corporation and the Utility have incurred cumulative charges of approximately $1.83 billion related to the San Bruno accident and natural gas matters. For 2012, this amount includes pipeline-related expenses of $477 million and capital expenditures of $353 million that will not be recoverable through rates. (See "CPUC Gas Safety Rulemaking Proceeding" below.) These matters and a number of other factors will continue to have a material negative impact on PG&E Corporation's and the Utility's future results of operations, financial condition, and cash flows.

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Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for 2012

        The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation's income available for common shareholders and earnings per common share for the year ended December 31, 2012:

(in millions, except per share amounts)
  Earnings   Earnings Per
Common Share
(Diluted)
 

Income Available for Common Shareholders—2011

  $ 844   $ 2.10  

Increase in rate base earnings

    80     0.19  

Natural gas matters(1)

    32     0.15  

Storm and outage expenses

    28     0.06  

Litigation and regulatory matters

    27     0.06  

Gas transmission revenues

    15     0.04  

Environmental-related costs

    11     0.03  

Planned incremental work

    (151 )   (0.36 )

Employee operational performance incentive

    (33 )   (0.08 )

Energy efficiency incentive

    (3 )   (0.01 )

Increase in shares outstanding(2)

        (0.19 )

Other

    (34 )   (0.07 )
           

Income Available for Common Shareholders—2012

  $ 816   $ 1.92  
           

(1)
The Utility incurred charges related to natural gas matters of $812 million and $739 million, pre-tax, for 2012 and 2011, respectively. The amount shown above represents the favorable tax impact attributable to the lower amount of non-deductible penalties recorded in 2012 of $17 million, as compared to $200 million recorded in 2011.
(2)
Represents the impact of a higher number of shares outstanding at December 31, 2012, compared to the number of shares outstanding at December 31, 2011. 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.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

        This 2012 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 associated with various investigations; estimated losses and insurance recoveries associated with the civil litigation arising from the San Bruno accident; forecasts of costs the Utility will incur to make safety and reliability improvements, including costs to perform work under the pipeline safety enhancement plan, that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to environmental remediation, tax, 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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RESULTS OF OPERATIONS

        The table below details certain items from the accompanying Consolidated Statements of Income for 2012, 2011, and 2010:

 
  Year ended December 31,  
(in millions)
  2012   2011   2010  

Utility

                   

Electric operating revenues

  $ 12,014   $ 11,601   $ 10,644  

Natural gas operating revenues

    3,021     3,350     3,196  
               

Total operating revenues

    15,035     14,951     13,840  
               

Cost of electricity

    4,162     4,016     3,898  

Cost of natural gas

    861     1,317     1,291  

Operating and maintenance

    6,045     5,459     4,432  

Depreciation, amortization, and decommissioning

    2,272     2,215     1,905  
               

Total operating expenses

    13,340     13,007     11,526  
               

Operating income

    1,695     1,944     2,314  

Interest income

    6     5     9  

Interest expense

    (680 )   (677 )   (650 )

Other income, net

    88     53     22  
               

Income before income taxes

    1,109     1,325     1,695  

Income tax provision

    298     480     574  
               

Net income

    811     845     1,121  

Preferred stock dividend requirement

    14     14     14  
               

Income Available for Common Stock

  $ 797   $ 831   $ 1,107  
               

PG&E Corporation, Eliminations, and Other(1)

                   

Operating revenues

  $ 5   $ 5   $ 1  

Operating expenses

    7     7     7  
               

Operating loss

    (2 )   (2 )   (6 )

Interest income

    1     2      

Interest expense

    (23 )   (23 )   (34 )

Other (expense) income, net

    (18 )   (4 )   5  
               

Loss before income taxes

    (42 )   (27 )   (35 )

Income tax benefit

    (61 )   (40 )   (27 )
               

Net income (loss)

  $ 19   $ 13   $ (8 )
               

Consolidated Total

                   

Operating revenues

  $ 15,040   $ 14,956   $ 13,841  

Operating expenses

    13,347     13,014     11,533  
               

Operating income

    1,693     1,942     2,308  

Interest income

    7     7     9  

Interest expense

    (703 )   (700 )   (684 )

Other income, net

    70     49     27  
               

Income before income taxes

    1,067     1,298     1,660  

Income tax provision

    237     440     547  
               

Net income

    830     858     1,113  

Preferred stock dividend requirement of subsidiary

    14     14     14  
               

Income Available for Common Shareholders

  $ 816   $ 844   $ 1,099  
               

(1)
PG&E Corporation eliminates all intercompany transactions in consolidation.

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        The following presents the Utility's operating results for 2012, 2011, and 2010.

Electric Operating Revenues

        The Utility's electric operating revenues consist of amounts charged to customers for electricity generation, transmission and distribution services, as well as amounts charged to customers to recover the cost of electricity procurement and the cost of public purpose, energy efficiency, and demand response programs.

        The following table provides a summary of the Utility's total electric operating revenues:

(in millions)
  2012   2011   2010  

Revenues excluding passed-through costs

  $ 6,280   $ 6,150   $ 5,473  

Revenues for recovery of passed-through costs

    5,734     5,451     5,171  
               

Total electric operating revenues

  $ 12,014   $ 11,601   $ 10,644  
               

        The Utility's total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $413 million, or 4%, in 2012 compared to 2011. Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $283 million, primarily due to an increase in the cost of electricity (See "Cost of Electricity" below), the cost of public purpose programs, and pension contributions. Electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $130 million, primarily due to an increase in base revenues as authorized in the 2011 GRC and in the TO rate case.

        The Utility's total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $957 million, or 9%, in 2011 compared to 2010. Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $280 million, primarily due to increases in the cost of electricity (see "Cost of Electricity" below), the cost of public purpose programs, and pension contributions. Electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $677 million. The increase is primarily due to additional base revenues that were authorized by the CPUC in the 2011 GRC and for various separately funded projects, and authorized by the FERC in the TO rate case that became effective March 1, 2011.

        The Utility's future electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, are expected to increase in 2013 as authorized by the CPUC in the 2011 GRC. This increase to future revenues will be offset by the lower revenues authorized by the CPUC in the 2013 Cost of Capital proceeding. (See "Regulatory Matters" below.) Additionally, the Utility's future electric operating revenues are expected to be impacted by revenues authorized by the FERC in the TO rate case (these increased revenues are expected to become effective on May 1, 2013) and by the CPUC in the 2014 GRC, which was filed on November 14, 2012. Future electric operating revenues will also be impacted by the cost of electricity and other revenues intended to recover costs that are passed through to customers.

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 10 of the Notes to the Consolidated Financial Statements.) The Utility's cost of electricity is passed through to customers. The Utility's cost of electricity excludes non-fuel costs associated with operating the Utility's own generation facilities and electric transmission and distribution system, which are included in operating and maintenance expense in the Consolidated Statements of Income.

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        The following table provides a summary of the Utility's cost of electricity and the total amount and average cost of purchased power:

(in millions)
  2012   2011   2010  

Cost of purchased power

  $ 3,873   $ 3,719   $ 3,647  

Fuel used in own generation facilities

    289     297     251  
               

Total cost of electricity

  $ 4,162   $ 4,016   $ 3,898  
               

Average cost of purchased power per kWh(1)

  $ 0.079   $ 0.089   $ 0.081  
               

Total purchased power (in millions of kWh)

    48,933     41,958     44,837  
               

(1)
Kilowatt-hour

        The Utility's total cost of electricity increased by $146 million, or 4%, in 2012 compared to 2011, primarily due to an increase in the volume of power purchased as customer demand increased and higher costs to purchase renewable energy. The higher cost of electricity was partially offset by the decrease in the average cost of purchased power which reflected lower spot prices. The volume of power the Utility purchases is driven by customer demand, the availability of the Utility's own generation facilities, and the cost effectiveness of each source of electricity.

        The Utility's total cost of electricity increased by $118 million, or 3%, in 2011 compared to 2010. The increase was due to an increase in the average cost of purchased power resulting from increased renewable energy deliveries and higher transmission costs.

        Various factors will affect the Utility's future cost of electricity, including the market prices for electricity and natural gas, the availability of Utility-owned generation, and changes in customer demand. Additionally, the cost of electricity is expected to be impacted by the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with current and future California law and regulatory requirements. The Utility's future cost of electricity also will be affected by legislation and rules applicable to GHG emissions. (See "Environmental Matters" below.)

Natural Gas Operating Revenues

        The Utility's natural gas operating revenues consist of amounts charged for transportation, distribution, and storage services, as well as amounts charged to customers to recover the cost of natural gas procurement and public purpose programs.

        The following table provides a summary of the Utility's natural gas operating revenues:

(in millions)
  2012   2011   2010  

Revenues excluding passed-through costs

  $ 1,772   $ 1,696   $ 1,627  

Revenues for recovery of passed-through costs

    1,249     1,654     1,569  
               

Total natural gas operating revenues

  $ 3,021   $ 3,350   $ 3,196  
               

        The Utility's natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $329 million, or 10%, in 2012 compared to 2011. Revenues intended to recover costs that are passed through to customers and do not impact net income decreased by $405 million primarily due to a decrease in the cost of natural gas. Natural gas operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $76 million, primarily due to an increase in base revenues as authorized in the 2011 GT&S rate case and the 2011 GRC and increases in natural gas storage revenues.

        The Utility's natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $154 million, or 5%, in 2011 compared to 2010. Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $85 million, primarily due to an increase in the costs of public purpose programs and pension contributions. Natural gas operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $69 million, primarily due to an increase in authorized base revenue, partially offset by a decrease in natural gas storage revenues. (The Utility's storage facilities were at capacity throughout 2011 and less gas was transported from storage due to the milder weather that prevailed in 2011 compared to 2010. As result, the Utility was unable to accept more gas for storage.)

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        The Utility's operating revenues for natural gas transmission services are expected to increase for 2013 and 2014 as authorized by the CPUC in the 2011 GT&S rate case and will also be impacted by revenues authorized by the CPUC in the 2014 GRC. The Utility's revenues for natural gas distribution services in 2013, excluding revenues intended to recover passed-through costs, will also reflect revenue increases authorized by the CPUC in the 2011 GRC. These increases to future revenues will be offset by the lower revenues authorized by the CPUC in the 2013 Cost of Capital proceeding. (See "Regulatory Matters" below.) Additionally, the Utility's future operating revenues will reflect those revenues authorized by the CPUC under the Utility's pipeline safety enhancement plan. (See "Natural Gas Matters" below.) The Utility's future gas operating revenues also will be impacted by the cost of natural gas, natural gas throughput volume, and other factors.

Cost of Natural 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 10 of the Notes to the Consolidated Financial Statements.) The Utility's cost of natural gas is passed through to customers. The Utility's cost of natural gas excludes the cost of operating the Utility's gas transmission and distribution system, which is included in operating and maintenance expense in the Consolidated Statements of Income.

        The following table provides a summary of the Utility's cost of natural gas:

(in millions)
  2012   2011   2010  

Cost of natural gas sold

  $ 676   $ 1,136   $ 1,119  

Transportation cost of natural gas sold

    185     181     172  
               

Total cost of natural gas

  $ 861   $ 1,317   $ 1,291  
               

Average cost per Mcf of natural gas sold

  $ 2.91   $ 4.49   $ 4.69  
               

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

    232     253     249  
               

(1)
One thousand cubic feet

        The Utility's total cost of natural gas decreased by $456 million, or 35%, in 2012 compared to 2011, primarily due to a lower average market price of natural gas during 2012.

        The Utility's total cost of natural gas increased by $26 million, or 2%, in 2011 compared to 2010, primarily due to the absence of a $49 million refund the Utility received in 2010 to be passed through to customers as part of a litigation settlement.

        The Utility's future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. In addition, the Utility's future cost of natural gas may be affected by federal or state legislation or rules to regulate the GHG emissions from the Utility's natural gas transportation and distribution facilities and from natural gas consumed by the Utility's customers.

Operating and Maintenance

        Operating and maintenance expenses consist mainly of the Utility's costs to operate and maintain its electricity and natural gas facilities, customer billing and service expenses, the cost of public purpose programs, and administrative and general expenses. The Utility's ability to earn its authorized rate of return depends in part on its ability to manage its expenses and to achieve operational and cost efficiencies.

        The Utility's operating and maintenance expenses (including costs passed through to customers) increased by $586 million, or 11%, from $5,459 million in 2011 to $6,045 million in 2012. Excluding costs passed through to customers, operating and maintenance expense increased $488 million, primarily due to costs incurred to improve the safety and reliability of electric and natural gas operations that were $255 million higher than amounts assumed under the 2011 rate cases. The remaining increase was attributable to $73 million of net costs associated with natural gas matters (see table below), $56 million of employee operational performance incentive, and $26 million of planned maintenance costs associated with the Gateway Generating Station. These costs were partially offset by a $25 million decrease in legal and regulatory matters, including penalties associated with the Rancho Cordova accident in 2011. Costs that are passed through to customers and do not impact net income increased by $98 million, primarily due to costs associated with advanced electric and gas meters that use SmartMeterTM technology and pension contributions.

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        The Utility's operating and maintenance expenses (including costs passed through to customers) increased by $1,027 million, or 23%, from $4,432 million in 2010 to $5,459 million in 2011. Excluding costs passed through to customers, operating and maintenance expenses increased by $817 million in 2011 compared to 2010, primarily due to a $456 million increase in costs for natural gas matters. (See table below.) The remaining increase in operating and maintenance costs was attributable to a number of factors, including $122 million for estimated environmental remediation costs and other liabilities associated with Hinkley natural gas compressor site and approximately $82 million for labor and other maintenance-related costs, primarily associated with higher storm costs. Additionally, legal and regulatory matters increased $32 million, including penalties associated with the Rancho Cordova accident. Costs that are passed through to customers and do not impact net income increased by $210 million primarily due to pension expense, public purpose programs, and meter reading.

        The following table provides a summary of the Utility's costs associated with natural gas matters, included in operating and maintenance expenses:

(in millions)
  2012   2011   2010   Total  

Pipeline-related expenses

  $ 477   $ 483   $ 63   $ 1,023  

Disallowed capital expenditures

    353             353  

Accrued penalties

    17     200         217  

Third-party claims

    80     155     220     455  

Insurance recoveries

    (185 )   (99 )       (284 )

Contribution to City of San Bruno

    70             70  
                   

Total natural gas matters

  $ 812   $ 739   $ 283   $ 1,834  
                   

        The Utility incurred net costs of $812 million, $739 million, and $283 million during 2012, 2011 and 2010, respectively, in connection with natural gas matters that are not recoverable through rates. These amounts primarily include pipeline-related expenses which consist of costs to validate safe operating pressures, conduct strength testing, and perform other work (including work within the scope of the Utility's pipeline safety enhancement plan), as well as associated legal and regulatory costs. In addition, a $353 million charge was recorded in 2012 for disallowed capital expenditures related to the Utility's pipeline safety enhancement plan that are forecasted to exceed the CPUC's authorized levels or that were specifically disallowed. Also included above are estimated penalties related to the CPUC's pending investigations and other potential enforcement matters, accruals for third-party claims related to the San Bruno accident, and a contribution to the City of San Bruno. These costs were partially offset by insurance recoveries related to third-party claims. (See "Natural Gas Matters" below.)

        The Utility forecasts that it will incur total pipeline-related costs ranging from $400 million to $500 million in 2013 that will not be recoverable through rates. These amounts include costs to perform work under the Utility's pipeline safety enhancement plan that were disallowed by the CPUC. These amounts also include emerging work related to the Utility's multi-year effort to identify and remove encroachments (such as building structures and vegetation overgrowth) from transmission pipeline rights-of-way, as well as costs associated with the integrity of transmission pipelines and other gas-related work. The Utility also expects it will continue to incur legal and regulatory expenses associated with its natural gas system. The Utility may incur costs to implement any remedial actions the CPUC may order the Utility to perform. (See "Natural Gas Matters—Pending CPUC Investigations and Enforcement Matters" below.)

        Future operating and maintenance expense will also continue to be affected by other costs associated with natural gas matters that are not recoverable through rates, including any additional charges for third-party claims arising from the San Bruno accident that are not recoverable through insurance, additional charges for civil or criminal penalties, or punitive damages, if any, that may be imposed on the Utility. (See "Natural Gas Matters" below.)

        The Utility forecasts that it will incur expenses in 2013 that are approximately $250 million higher than amounts assumed under the 2011 GRC and GT&S rate case as the Utility works to improve the safety and reliability of its electric and natural gas operations.

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Depreciation, Amortization, and Decommissioning

        The Utility's depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil fuel-fired generation facilities and nuclear power facilities. The Utility's depreciation, amortization, and decommissioning expenses increased by $57 million, or 3%, in 2012 compared to 2011, primarily due to capital additions.

        The Utility's depreciation, amortization, and decommissioning expenses increased by $310 million, or 16%, in 2011 compared to 2010, primarily due to capital additions and an increase in depreciation rates as authorized by the 2011 GRC and 2011 GT&S rate cases.

        The Utility's depreciation expense for future periods is expected to be affected as a result of changes in capital expenditures and the implementation of new depreciation rates as authorized by the CPUC in future GRCs and GT&S rate cases. Future TO rate cases authorized by the FERC will also have an impact on depreciation rates.

Interest Income and Interest Expense

        There were no material changes to interest income and interest expense for 2012 compared to 2011 or for 2011 compared to 2010.

Other Income, Net

        The Utility's other income, net increased by $35 million, in 2012 compared to 2011. The increase was primarily due to an increase in allowance for equity funds used during construction ("AFUDC") as the average balance of construction work in progress was higher in 2012 as compared to 2011.

        The Utility's other income, net increased by $31 million, in 2011 compared to 2010 when the Utility incurred costs to support a California ballot initiative that appeared on the June 2010 ballot that were not recoverable in rates. The increase was partially offset by a decrease in AFUDC as the average balance of construction work in progress was lower in 2011 compared to 2010.

Income Tax Provision

        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 rates for 2012 decreased compared to 2011, primarily due to lower non-tax deductible penalties related to natural gas matters, and higher state benefits received and deductions in 2012, including a benefit associated with a California research and development claim, with no comparable amount in 2011; a higher California tax deduction resulting from an accounting method change for repairs as compared to 2011; and a California tax benefit associated with shorter depreciable lives related to meters that use SmartMeterTM technology recorded in 2012 with no comparable amount in 2011.

        The Utility's income tax provision decreased by $94 million, or 16%, in 2011 compared to 2010. The effective tax rates were 36% and 34% for 2011 and 2010, respectively. The effective tax rate for 2011 increased as compared to 2010, mainly due to non- tax deductible penalties related to natural gas matters recorded in 2011, with no comparable penalties recorded in 2010, partially offset by a benefit associated with a loss carryback recorded in 2011 and the reversal of a deferred tax asset attributable to the Medicare Part D subsidy, which affected the tax provision balance in 2010, with no comparable effect in 2011.

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        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 2012, 2011, and 2010 were as follows:

 
  2012   2011   2010  

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)

    (3.0 )   1.6     1.0  

Effect of regulatory treatment of fixed asset differences

    (3.9 )   (4.2 )   (3.0 )

Tax credits

    (0.6 )   (0.5 )   (0.4 )

Benefit of loss carryback

    (0.4 )   (2.1 )    

Non deductible penalties

    0.5     6.3     0.2  

Other, net

    (0.8 )   0.1     1.1  
               

Effective tax rate

    26.8 %   36.2 %   33.9 %
               

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

        PG&E Corporation's revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation's operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation's interest expense relates to PG&E Corporation's outstanding senior notes, and is not allocated to affiliates.

        There were no material changes to PG&E Corporation's operating results in 2012 compared to 2011 and 2011 compared to 2010.

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 the level of cash distributions received from the Utility and PG&E Corporation's access to the capital and credit markets.

        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 the Utility's commercial paper and the costs associated with their respective credit facilities, and long-term debt.

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        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)
  2012   2011  

PG&E Corporation

  $ 207   $ 209  

Utility

    194     304  
           

Total consolidated cash and cash equivalents

  $ 401   $ 513  
           

        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 ("Chapter 11"). (See Note 13 of the Notes to the Consolidated Financial Statements.)

Revolving Credit Facilities and Commercial Paper Program

        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, 2012:

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

PG&E Corporation

  May 2016   $ 300 (1) $   $ 120   $   $ 180  

Utility

  May 2016     3,000 (2)   266         370 (3)   2,364 (3)
                           

Total revolving credit facilities

      $ 3,300   $ 266   $ 120   $ 370   $ 2,544  
                           

(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 2012, the average outstanding borrowings under PG&E Corporation's revolving credit facility were $21 million and the maximum outstanding balance during the year was $120 million. For 2012, the Utility's average outstanding commercial paper balance was $665 million and the maximum outstanding balance during the year was $1.4 billion. The Utility did not borrow under its credit facility in 2012.

        The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including 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, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

        See Note 4 of the Notes to the Consolidated Financial Statements for additional information about the credit facilities and the Utility's commercial paper program.

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2012 Financings

Utility

        The following table summarizes long-term debt issuances in 2012:

(in millions)
  Issue Date   Amount  

Senior Notes

           

4.45%, due 2042

  April 16   $ 400  

2.45%, due 2022

  August 16     400  

3.75%, due 2042

  August 16     350  
           

Total debt issuances in 2012

      $ 1,150  
           

        The net proceeds from the issuance of Utility senior notes in 2012 were used to repay a portion of outstanding commercial paper, and for general corporate purposes.

        The Utility also received cash contributions of $885 million from PG&E Corporation during 2012 to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC.

PG&E Corporation

        In November 2011, PG&E Corporation entered into an Equity Distribution Agreement providing for the sale of PG&E Corporation common stock having an aggregate gross offering price of up to $400 million. Sales of the shares are made by means of ordinary brokers' transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. For 2012, PG&E Corporation sold 5,446,760 shares of its common stock under the Equity Distribution Agreement for cash proceeds of $234 million, net of fees and commissions paid of $2 million. The proceeds from these sales were used for general corporate purposes, including the infusion of equity into the Utility. As of December 31, 2012, PG&E Corporation had the ability to issue an additional $64 million of its common stock under the November Equity Distribution Agreement.

        In March 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions. In addition, during 2012, PG&E Corporation issued 6,803,101 shares of common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans, generating $263 million of cash.

Future Financing Needs

        The amount and timing of the Utility's future debt financings and equity needs will depend on various factors, including:

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        PG&E Corporation contributes equity to the Utility as needed to maintain the Utility's CPUC-authorized capital structure. In December 2012, the CPUC issued a final decision authorizing the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt and 1% preferred stock, beginning on January 1, 2013. The decision also reduced the authorized ROE from 11.35% to 10.40%. (See the "2013 Cost of Capital Proceeding" discussion in "Regulatory Matters" below.) 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. Further, given the Utility's significant ongoing capital expenditures, it will continue to need equity contributions from PG&E Corporation to maintain its authorized capital structure.

        PG&E Corporation's equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation also may use draws under its revolving credit facility to occasionally fund equity contributions on an interim basis. Additional common stock issued by PG&E Corporation in the future to fund further equity contributions to the Utility could have a material dilutive effect on PG&E Corporation's earnings per common share.

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 2012, for an annual dividend of $1.82 per share.

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

(in millions)
  2012   2011   2010  

PG&E Corporation:

                   

Common stock dividends paid

  $ 746   $ 704   $ 662  

Common stock dividends reinvested in Dividend Reinvestment and Stock Purchase Plan

    22     24     18  

Utility:

                   

Common stock dividends paid

  $ 716   $ 716   $ 716  

Preferred stock dividends paid

    14     14     14  

        In December 2012, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $196 million, of which $191 million was paid on January 15, 2013 to shareholders of record on December 31, 2012. The remaining $5 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

        In December 2012, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on February 15, 2013, to shareholders of record on January 31, 2013.

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        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.

        The Utility's cash flows from operating activities for 2012, 2011, and 2010 were as follows:

(in millions)
  2012   2011   2010  

Net income

  $ 811   $ 845   $ 1,121  

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

                   

Depreciation, amortization, and decommissioning

    2,272     2,215     1,905  

Allowance for equity funds used during construction

    (107 )   (87 )   (110 )

Deferred income taxes and tax credits, net

    684     582     762  

Disallowed capital expenditures

    353         36  

Other

    236     289     221  

Effect of changes in operating assets and liabilities:

                   

Accounts receivable

    (40 )   (227 )   (105 )

Inventories

    (24 )   (63 )   (43 )

Accounts payable

    (26 )   51     109  

Income taxes receivable/payable

    (50 )   (192 )   (58 )

Other current assets and liabilities

    272     36     123  

Regulatory assets, liabilities, and balancing accounts, net

    291     (100 )   (394 )

Other noncurrent assets and liabilities

    256     414     (331 )
               

Net cash provided by operating activities

  $ 4,928   $ 3,763   $ 3,236  
               

        During 2012, net cash provided by operating activities increased by $1,165 million compared to 2011. This increase was primarily due to a decrease of $352 million in net collateral paid by the Utility related to price risk management activities, a $353 million disallowance for capital expenditures incurred in connection with its pipeline safety enhancement plan, a receipt of $250 million, net of legal fees, from the U.S. Treasury related to spent nuclear fuel costs, and a decrease in tax payments of $224 million. 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 2011, net cash provided by operating activities increased $527 million compared to 2010 primarily due to a decrease of $214 million in net collateral paid by the Utility related to price risk management activities. This increase also reflects a decrease in tax payments of $121 million in 2011 compared to 2010. The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as collateral and the timing and amount of customer billings and collections.

        Future cash flow from operating activities will be affected by the timing and amount of payments to be made to third parties in connection with the San Bruno accident, including related insurance recoveries; the timing and amount of penalties that may be assessed, as well as any remedial actions the CPUC may order the Utility to perform; and the anticipated higher operating and maintenance costs associated with the Utility's natural gas and electric operations, among other factors. (See "Operating and Maintenance" above and "Natural Gas Matters" below.)

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

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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 2012, 2011, and 2010 were as follows:

(in millions)
  2012   2011   2010  

Capital expenditures

  $ (4,624 ) $ (4,038 ) $ (3,802 )

Decrease in restricted cash

    50     200     66  

Proceeds from sales and maturities of nuclear decommissioning trust investments

    1,133     1,928     1,405  

Purchases of nuclear decommissioning trust investments

    (1,189 )   (1,963 )   (1,456 )

Other

    16     14     19  
               

Net cash used in investing activities

  $ (4,614 ) $ (3,859 ) $ (3,768 )
               

        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.

        Net cash used in investing activities increased by $91 million in 2011 compared to 2010, primarily due to an increase in capital expenditures of $236 million as compared to 2010. This increase was partially offset by a decrease of $134 million in restricted cash that was primarily due to releases from escrow for resolved Chapter 11 disputed claims in 2011, with few similar releases in 2010.

        Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. (See "Capital Expenditures" below for further discussion of expected spending and significant capital projects.)

Financing Activities

        The Utility's cash flows from financing activities for 2012, 2011, and 2010 were as follows:

(in millions)
  2012   2011   2010  

Borrowings under revolving credit facilities

  $   $ 208   $ 400  

Repayments under revolving credit facilities

        (208 )   (400 )

Net issuances (repayments) of commercial paper, net of discount of $3 in 2012, $4 in 2011, and $3 in 2010

    (1,021 )   782     267  

Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2011 and 2010

        250     249  

Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $13 in 2012, $8 in 2011, and $23 in 2010

    1,137     792     1,327  

Short-term debt matured

    (250 )   (250 )   (500 )

Long-term debt matured or repurchased

    (50 )   (700 )   (95 )

Energy recovery bonds matured

    (423 )   (404 )   (386 )

Preferred stock dividends paid

    (14 )   (14 )   (14 )

Common stock dividends paid

    (716 )   (716 )   (716 )

Equity contribution

    885     555     190  

Other

    28     54     (73 )
               

Net cash provided by (used in) financing activities

  $ (424 ) $ 349   $ 249  
               

        In 2012, net cash provided by financing activities decreased by $773 million compared to the same period in 2011. In 2011, net cash provided by financing activities increased by $100 million compared to 2010. 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 and the level of cash provided by or used in investing activities. 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.

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PG&E Corporation

        As of December 31, 2012, PG&E Corporation's affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. PG&E Corporation's financial exposure from these arrangements is generally limited to its lease payments and investment contributions to these companies. As of December 31, 2012, PG&E Corporation had made total payments of $361 million under these tax equity agreements and received $228 million in benefits and customer payments. 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, 2012, 2011, and 2010: dividend payments, common stock issuances, borrowings and repayments under the revolving credit facility in 2012 and 2011, 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, 2012:

 
  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

  $ 1,035   $ 2,148   $ 1,824   $ 17,305   $ 22,312  

Variable rate obligations

    2     8     941     153     1,104  

Purchase obligations(2):

                               

Power purchase agreements:

                               

Qualifying facilities ("QF")

    892     1,641     1,108     2,238     5,879  

Renewable Energy (other than QF)

    1,356     3,881     4,107     30,958     40,302  

Other power purchase agreements

    846     1,326     1,223     3,322     6,717  

Natural gas supply, transportation, and storage

    707     400     260     865     2,232  

Nuclear fuel agreements

    113     322     295     878     1,608  

Pension and other benefits(3)

    455     796     796     398 (6)   2,445  

Capital lease obligations(4)

    35     51     40     20     146  

Operating leases(4)

    42     69     55     206     372  

Preferred dividends(5)

    14     28     28         70  

PG&E Corporation

                               

Long-term debt(1):

                               

Fixed rate obligations

    20     355             375  

(1)
Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2012 and outstanding principal for each instrument with the terms ending at each instrument's maturity. Variable rate obligations consist of pollution control bonds, due in 2016 and 2026 and related loans and are backed by letters of credit that expire on May 31, 2016. (See Note 4 of the Notes to the Consolidated Financial Statements.)
(2)
This table includes power purchase agreements that have been approved by the CPUC and have completed major milestones for construction. (See Note 15 of the Notes to the Consolidated Financial Statements.
(3)
PG&E Corporation's and the Utility's funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. (See Note 12 of the Notes to the Consolidated Financial Statements.)
(4)
See Note 15 of the Notes to the Consolidated Financial Statements.
(5)
Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed period of five years.
(6)
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 reflected represents only 1 year of contributions for the Utility's pension and other benefit plans.

        The contractual commitments table above excludes potential commitments associated with the conversion of existing overhead electric facilities to underground electric facilities. At December 31, 2012, the Utility was

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committed to spending approximately $277 million for these conversions. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and communication utilities involved. The Utility expects to spend $86 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed, resulting in the capital expenditures being recoverable from customers.

        The contractual commitments table above also 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 9 of the Notes to the Consolidated Financial Statements.

CAPITAL EXPENDITURES

        The Utility makes various capital investments in its electric generation and electric and natural gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet growth. Most of the Utility's revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO, and GT&S rate cases. (See "2014 General Rate Case" below.) The Utility also collects additional revenue requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric distribution projects, and the SmartMeterTM advanced metering infrastructure.

        The Utility's capital expenditures for property, plant, and equipment totaled $4.8 billion in 2012, $4.2 billion in 2011, and $3.9 billion in 2010. The Utility forecasts that capital expenditures will total approximately $5.1 billion in 2013, including expenditures related to its pipeline safety enhancement plan.

Natural Gas Pipeline Safety Enhancement Plan

        On December 28, 2012, the CPUC issued a decision that approved the Utility's proposed pipeline safety enhancement plan (filed in August 2011) but disallowed the Utility's request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014). The CPUC decision limited the Utility's recovery of capital expenditures to $1.0 billion of the total $1.4 billion requested. As a result, the Utility recorded a charge of $353 million in 2012 for disallowed capital expenditures. (See "Natural Gas Matters—CPUC Gas Safety Rulemaking Proceeding" below.)

Oakley Generation Facility

        On December 20, 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. During January 2013, several parties filed applications for rehearing of the CPUC decision. PG&E Corporation and Utility are uncertain whether the CPUC will modify its decision based on these applications.

NATURAL GAS MATTERS

        PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows, have continued to be negatively affected by costs the Utility has incurred to improve the safety and reliability of the Utility's natural gas operations, as well as by costs related to the on-going regulatory proceedings, investigations, and civil lawsuits related to the San Bruno accident and the Utility's natural gas operations. Since the San Bruno accident, PG&E

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Corporation and the Utility have incurred total cumulative charges to net income of $1.83 billion related to natural gas matters.

(in millions)
  2012   2011   2010   Total  

Pipeline-related expenses(1)

  $ 477   $ 483   $ 63   $ 1,023  

Disallowed capital expenditures(1)

    353             353  

Accrued penalties(2)

    17     200         217  

Third-party claims(3)

    80     155     220     455  

Insurance recoveries(3)

    (185 )   (99 )       (284 )

Contribution to the City of San Bruno(4)

    70             70  
                   

Total natural gas matters

  $ 812   $ 739   $ 283   $ 1,834  
                   

(1)
See "CPUC Gas Safety Rulemaking Proceeding" below.
(2)
See "Pending CPUC Investigations and Enforcement Matters" below.
(3)
See "Third-Party Claims" below.
(4)
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 and Enforcement Matters

        The CPUC is conducting three investigations of the Utility's natural gas operations 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. (See Note 15 of the Notes to the Consolidated Financial Statements.) Although the Utility, the CPUC's Safety and Enforcement Division ("SED"), and other parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not reached an agreement. PG&E Corporation and the Utility are uncertain whether or when any stipulated outcome might be reached. Any agreement regarding a stipulated outcome would be subject to CPUC approval.

        The CPUC has concluded evidentiary hearings in each of these investigations. The CPUC administrative law judges ("ALJs") who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties' briefs must be submitted. The ALJs have also permitted the other parties (the City of San Bruno, The Utility Reform Network, and the City and County of San Francisco) to separately address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the SED. The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013. After briefing has been completed, the ALJs will issue one or more presiding officer's decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions. Based on the revised procedural schedule, one or more presiding officer's decisions will be issued by July 23, 2013. The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time. (See "Penalties Conclusion" below.)

Other Potential Enforcement Matters

        California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations' natural gas operating practices. The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations. In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility's self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule. (The Utility has paid the penalty and completed all of the missed leak surveys.) As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports. The SED has not yet taken formal action with respect to the Utility's other self-reports. The SED may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. (See "Penalties Conclusion" below.)

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        In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility's gas transmission pipeline rights-of-way. The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period. (See "Operating and Maintenance" above.) PG&E Corporation and the Utility are uncertain how this matter will affect the above investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

Penalties Conclusion

        The CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.) The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised this wide discretion in determining penalties. The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that the SED finds.

        The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders. In determining the amount of penalties the ALJs may consider the testimony of financial consultants engaged by the SED and the Utility. The SED's financial consultant prepared a report concluding that PG&E Corporation could raise approximately $2.25 billion through equity issuances, in addition to equity PG&E Corporation had already forecasted it would issue in 2012, to fund CPUC-imposed penalties on the Utility. The Utility's financial consultant disagreed with this financial analysis and asserted that a fine in excess of financial analysts' expectations, which the consultant's report cited as a mean of $477 million, would make financing more difficult and expensive. The ALJs have scheduled a hearing to be held on March 4 and March 5, 2013 to consider the SED's and Utility's testimony. The SED and other parties are scheduled to file briefs to address potential monetary penalties and remedies in all three investigations by April 26, 2013.

        PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their consolidated financial statements. PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount accrued due to the many variables that could affect the final outcome of these matters and the ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued. These variables include how the CPUC and the SED will exercise their discretion in calculating the amount of penalties, including how the total number of violations will be counted; how the duration of the violations will be determined; whether the amount of penalties in each investigation will be determined separately or in the aggregate; how the financial resources testimony submitted by the SED and the Utility will be considered; whether the Utility's costs to perform any required remedial actions will be considered; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered. (See "CPUC Gas Safety Rulemaking Proceeding" below.)

        These estimates, and the assumptions on which they are based, are subject to change based on many factors, including rulings, orders, or decisions that may be issued by the ALJs; whether the outcome of the investigations is resolved through a fully litigated process or a stipulated outcome that is approved by the CPUC; whether the SED will take additional action with respect to the Utility's self-reports; and whether the CPUC or the SED takes any action with respect to the encroachment matter described above. 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.

CPUC Gas Safety Rulemaking Proceeding

        The CPUC is conducting a rulemaking proceeding to develop and adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms. On December 28, 2012, the CPUC issued a decision that approved most of the Utility's proposed pipeline safety

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enhancement plan to modernize and upgrade its natural gas transmission system, but disallowed the Utility's request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014).

        In its application filed in August 2011, the Utility forecasted that it would incur total plan-related costs of approximately $2.2 billion, composed of $1.4 billion in capital expenditures and $750 million in expenses. The CPUC decision prohibited the Utility from recovering any expenses incurred before December 20, 2012, the effective date of the decision, and from recovering certain categories of expenses that the Utility forecasts it will incur in 2013 and 2014. The CPUC decision also limits the Utility's recovery of capital expenditures to $1 billion. The Utility will be unable to recover any costs in excess of the adopted capital and expense amounts and the adopted amounts will be reduced by the cost of any plan project not completed and not replaced with a higher priority project. The CPUC also determined that the Utility should not recover in rates the costs of pressure testing pipeline placed into service after January 1, 1956 for which the Utility is unable to produce pressure test records. The CPUC may disallow additional costs based on the final results of the Utility's pipeline records search and pipeline pressure validation work, which the Utility expects to complete by May 2013. The Utility is required to update its plan and file an application within 30 days after this work is completed.

        The following table compares the Utility's requested expense and capital amounts (based on forecasts included in the August 2011 application) with the amounts authorized by the CPUC:

(in millions)
  2011   2012   2013   2014   Total  

Expense

                               

Requested

  $ 221 (1) $ 231   $ 155   $ 144   $ 751  

Authorized

        3     73     89     165  
                       

Difference

  $ 221 (1) $ 228   $ 82   $ 55   $ 586  
                       

Capital

                               

Requested

  $ 69   $ 384   $ 480   $ 500   $ 1,433  

Authorized

    47     260     348     348     1,003  
                       

Difference

  $ 22   $ 124   $ 132   $ 152   $ 430  
                       

(1)
The Utility's August 2011 application did not request recovery of forecast 2011 plan-related expenses of $221 million.

        For the year ended December 31, 2012, the Utility incurred total pipeline-related expenses of $477 million, including plan-related expenses of $271 million. As a result of the decision, the Utility also recorded a charge of $353 million for capital expenditures that are forecast to exceed the CPUC's authorized levels or that were specifically disallowed. All plan-related costs for 2013 and 2014 will be charged to net income in the period incurred. Unrecoverable plan-related costs are expected to range from approximately $150 million to $200 million in 2013 and a comparable amount in 2014. The CPUC stated that the Utility's recovery of the amounts authorized in the decision will be subject to refund, noting the possibility that further ratemaking adjustments may be made in the pending CPUC investigations in which the CPUC will address potential penalties to be imposed on the Utility. (See "Pending CPUC Investigations and Enforcement Matters" above.)

        The CPUC delegated authority to the SED to oversee all of the Utility's work performed pursuant to the pipeline safety enhancement plan, including the authority to participate in all plan-related activities and review and modify all changes proposed by the Utility. The Utility must submit quarterly compliance reports to the CPUC that will include information about actual cost compared to authorized cost for each work project; the construction status of projects; and changes in scope and prioritization of projects. As a result of the compliance reporting process, the Utility could incur additional non-recoverable costs. The CPUC also ordered the SED to engage consultants to conduct management and financial audits to address safety-related corporate culture and historical spending. (As discussed below, the financial audit of the Utility's natural gas distribution spending will be considered in the 2014 GRC, but the scope and timing of the management audit is still uncertain.) (See "2014 GRC" below.)

        On January 28, 2013, several parties filed applications for rehearing of the CPUC's decision. The applications for rehearing state, among other arguments, that the CPUC should have disallowed more of the Utility's costs and that the CPUC should have approved a reduced ROE for capital expenditures made under the plan. Several parties also have filed petitions for modification of the decision. It is uncertain whether or when the CPUC will grant these requests.

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        The second phase of the Utility's pipeline safety enhancement plan in 2015 will focus on pipeline segments in less populated areas, as well as certain pressure testing and pipeline replacement work that the CPUC deferred from the first phase. The Utility expects to address the scope, timing, and cost recovery of the second phase in late 2013 and request that changes to rates be made effective January 1, 2015.

Criminal Investigation

        The U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office are conducting an investigation of the San Bruno accident and have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees.

        PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility as a consequence of this investigation.

Third-Party Claims

        In addition to the investigations and proceedings discussed above, at December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 450 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. These cases were coordinated and assigned to one judge in the San Mateo County Superior Court. Many of the plaintiffs' claims have been resolved through settlements. The trial of the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings. On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court. The court has urged the parties to settle the remaining cases. As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs. It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement.

        At December 31, 2012, the Utility had recorded cumulative charges of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during 2012, primarily to reflect settlements and information exchanged by the parties during the settlement and discovery process. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident. (See Note 15 to the Consolidated Financial Statements.)

        The Utility has recognized cumulative insurance recoveries of $284 million for third-party claims, which included $185 million for 2012 and $99 million for 2011. Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries. (See Note 15 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. To state their claims, the plaintiffs cited the SED's January 2012 investigative report of the San Bruno accident that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively. The SED recommended that the Utility should use such amounts to fund future gas transmission expenditures and operations. Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code ("Section 17200")

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and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 ("Section 2106"), which provides a private right of action for violations of the California constitution or state laws by public utilities. Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106.

        PG&E Corporation and the Utility contest the plaintiffs' allegations. In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs' allegations. In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded. The court has set a hearing on the motion for April 26, 2013. Due to the early stage of this proceeding, PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses that may be incurred in connection with this matter.

Other Pending Lawsuits and Claim

        In October 2010, a purported shareholder derivative lawsuit was filed in San Mateo Superior Court following the San Bruno accident to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims, relating to the Utility's natural gas business. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court. On February 7, 2013, another purported shareholder derivative lawsuit was filed in U.S. District Court for the Northern District of California to seek recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims.

        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.

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 results of operations and financial condition.

2013 Cost of Capital Proceeding

        On December 20, 2012, the CPUC issued a final decision authorizing the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt, and 1% preferred stock, beginning on January 1, 2013. This capital structure applies to the Utility's electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. In addition, the CPUC authorized the Utility to earn a rate of return on each component of the capital structure, including a ROE of 10.40%, compared to the 11% ROE requested by the Utility. The following table compares the 2012 and 2013 authorized capital structure and rates of return:

 
  2012 Authorized   2013 Authorized  
 
  Cost   Capital
Structure
  Weighted
Cost
  Cost   Capital
Structure
  Weighted
Cost
 

Long-term debt

    6.05 %   46 %   2.78 %   5.52 %   47 %   2.59 %

Preferred stock

    5.68 %   2 %   0.11 %   5.60 %   1 %   0.06 %

Return on common equity

    11.35 %   52 %   5.90 %   10.40 %   52 %   5.41 %
                                   

Overall Rate of Return

                8.79 %               8.06 %

        The Utility estimates that the 2013 revenue requirement associated with the authorized cost of capital will be approximately $235 million less than the currently authorized revenue requirement. Approximately $165 million of this estimated decrease is attributable to the lower authorized ROE. Changes to the Utility's revenue requirement became effective on January 1, 2013.

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        The Utility and other parties have submitted a joint stipulation to the CPUC in which the parties agreed to continue the annual cost of capital adjustment mechanism that had been in effect since 2008, and to file the next full cost of capital applications in April 2015 for the 2016 test year. Under the mechanism as proposed to be continued, the Utility's ROE would be adjusted if the 12-month October-through-September average of the Moody's Investors Service long-term Baa utility bond index increases or decreases by more than 1.00% as compared to the applicable benchmark. If the adjustment mechanism is triggered, the Utility's authorized ROE, beginning January 1st of the following year, would be adjusted by one-half of the difference between the index and the benchmark. Additionally, the Utility's authorized costs of long-term debt and preferred stock would be updated to reflect actual August month-end embedded costs and forecasted interest rates for variable long-term debt, as well as new long-term debt and preferred stock scheduled to be issued. In any year where the 12-month average yield triggers an automatic ROE adjustment, that average would become the new benchmark.

        The CPUC is scheduled to issue a proposed decision by March 15, 2013 with a final decision by April 18, 2013.

2014 General Rate Case

        On November 15, 2012, the Utility filed its 2014 GRC application with the CPUC. In the Utility's 2014 GRC, the CPUC will determine the annual amount of revenue requirements that the Utility will be authorized to collect from customers from 2014 through 2016 to recover its anticipated costs for electric and natural gas distribution and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return.

        The Utility has requested that the CPUC increase the Utility's authorized base revenues for 2014 by a total of $1.28 billion over the comparable base revenues for 2013 that were previously authorized by the CPUC. Over the 2014-2016 GRC period, the Utility plans to make annual additional capital investments of nearly $4 billion in electric and natural gas distribution and electric generation infrastructure. The Utility forecasts that its 2014 weighted average rate base for the portion of the Utility's business reviewed in the GRC will be $21.4 billion.

        The following table compares the requested 2014 revenue requirement amounts by line of business with the comparable revenue requirements currently authorized for 2013:

(in millions)
Line of Business:
  Amounts
requested in the
GRC application
  Amounts currently
authorized for 2013
  Increase compared
to currently
authorized amounts
 

Electric distribution

  $ 4,355   $ 3,768   $ 587  

Gas distribution

    1,810     1,324     486  

Electric generation

    1,946     1,737     209  
               

Total revenue requirements

  $ 8,111   $ 6,829   $ 1,282  
               

        The Utility's 2014 forecast for gas distribution operations includes increased costs to replace 180 miles of distribution line per year (compared to 30 miles currently), use new leak detection technologies and survey the entire system more frequently, remotely monitor and control a significant number of valves, implement an asset management system to provide detailed, readily accessible information about the gas distribution system, and reduce response times for customer gas odor reports. The Utility's forecast for electric distribution operations includes increased costs to upgrade and replace assets to improve safety and reduce outages, use infrared technology to identify and correct equipment issues, install more automation to limit the impact and duration of outages, mitigate wildfire risk, increase system capacity to meet new customer demand, and enhance asset records management and integrate it with key systems. The Utility's forecast for electric generation includes increased costs to operate the Utility's hydroelectric system (including costs related to the Helms pumped storage facility and costs associated with operating licenses issued by the FERC), comply with new requirements adopted by the NRC applicable to the Utility's Diablo Canyon nuclear power plant, and operate and maintain the Utility's fossil fuel-fired and other generating facilities. In addition, the Utility's forecast includes increased costs to improve service at the Utility's local offices and customer contact centers and to improve the service provided by field account representatives to small and mid-sized business customers.

        In its application, the Utility has requested that the CPUC establish new balancing accounts to allow the Utility to recover costs associated with gas leak survey and repair work, major emergencies, and new regulatory requirements related to nuclear operations and hydroelectric relicensing, because these costs are subject to a high degree of uncertainty. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility's authorized revenues in 2015 and 2016, primarily to reflect increases in rate base due to capital

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investments in infrastructure and, to a lesser extent, anticipated increases in wages and other expenses. The Utility also has requested that revenue requirements be adjusted to reflect certain externally driven changes in the Utility's costs, such as changes in franchise fees. The Utility estimates that this mechanism would result in increases in revenue of $492 million in 2015 and an additional $504 million in 2016.

        Independent consultants engaged by the SED are reviewing and evaluating certain operational plans underlying the Utility's 2014 cost forecast to ensure that safety and security concerns have been addressed and that the plans properly incorporate risk assessments and mitigation measures. The SED has also engaged independent consultants to conduct a financial audit of the Utility's gas distribution system, which will examine the Utility's authorized and budgeted capital investments and operation and maintenance expenditures for its last two authorized GRC cycles. The SED reports on the results of the consultants' evaluations and financial audit are due May 31, 2013. The Utility and other parties will be able to respond to the reports.

        According to the CPUC's current procedural schedule for the proceeding, which may be subject to change in the future, the CPUC's Division of Ratepayer Advocates ("DRA") is scheduled to serve its report on the Utility's application by May 3, 2013. Additional testimony from other parties must be submitted by May 17, 2013. The schedule contemplates evidentiary hearings to be held this summer, followed by a proposed decision to be released in November 2013 and a final CPUC decision to be issued in December 2013. If the decision is delayed, the Utility will, consistent with CPUC practice in prior GRCs, request that the CPUC issue an order directing that the authorized revenue requirement changes be effective January 1, 2014, even if the decision is issued after that date.

FERC Transmission Owner Rate Case

        On September 28, 2012, the Utility filed an application with the FERC to increase the Utility's retail and wholesale electric transmission customer rates that have been in effect since March 1, 2011. The proposed rate changes will become effective on May 1, 2013, subject to refund following the FERC's issuance of a final decision. The most significant factors driving the requested increase are the Utility's continuing needs to replace and modernize aging electric transmission infrastructure; to interconnect new electric generation, including renewable resources; and to accommodate the magnitude and location of forecasted electric load growth in California. The Utility forecasts that it will make investments of $783 million in 2012 and an additional $837 million in 2013 in various capital projects, including projects to add transmission capacity, expand automation technology, improve overall system reliability, and maintain and replace equipment at substations. The proposed rate base in 2013 is forecast to be $4.5 billion compared to $3.6 billion in 2011. The operations and maintenance costs associated with this request are forecast to be approximately $191 million in 2013, compared to $152 million in 2011.

        Compared to present rates, the Utility estimated that revenues would increase by $254 million based on the Utility's requested ROE of 11.5%, for total 2013 electric transmission revenues of $1.2 billion. On November 29, 2012, the FERC issued an order that accepted the Utility's application but directed the Utility to reduce its proposed revenue requirement and rates to reflect the median ROE of a comparative group of other utilities. In response to the FERC's order, on December 21, 2012, the Utility revised its requested revenue requirements and rates to reflect a 9.1% ROE. Based on the reduced ROE, the Utility estimates that revenues would increase by approximately $158 million, for total annual electric transmission revenues of $1.1 billion beginning on May 1, 2013. On December 21, 2012, the Utility also filed a request for rehearing of the FERC's order. It is uncertain when the FERC will act on the request for rehearing. The ultimate resolution of revenue requirements and rates will be addressed through hearings and settlement procedures.

Energy Efficiency Programs and Incentive Ratemaking

        On December 20, 2012, the CPUC approved a new energy efficiency incentive mechanism to reward the Utility and other California energy utilities for the successful implementation of their 2010-2012 energy efficiency programs. The CPUC awarded the Utility $21 million for the successful implementation of the Utility's 2010 energy efficiency programs. The CPUC decision also established the process that is expected to apply to incentive claims for program years 2011 and 2012. After the CPUC completes its audit of the utilities' 2011 program expenditures, the utilities must file their incentive claims in the third quarter of 2013 for approval by the CPUC in the fourth quarter of 2013. Similarly, the utilities will file their incentive claims based on the CPUC-audited 2012 program expenditures in the third quarter of 2014 for approval by the CPUC in the fourth quarter of 2014.

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Diablo Canyon Nuclear Power Plant

        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. Among other directives, the NRC requested nuclear power plant owners to provide additional information about seismic and flooding hazards and emergency preparedness. In response to the orders, the utilities are required to re-evaluate the models used to determine compliance with the license conditions relating to seismic and flooding design. Each nuclear power plant owner will be required to be in full compliance with the NRC orders within two refueling outages or by December 31, 2016, whichever comes first. The Utility has already provided the initially requested information to the NRC and will continue to respond to the NRC orders as required. After reviewing the information submitted by the Utility and other nuclear power plant owners, the NRC may issue further orders which may include facility-specific orders. The Utility will incur costs to comply with Fukushima related NRC orders. The Utility has requested that the CPUC allow the Utility to recover costs incurred in 2014 through 2016 to comply with NRC orders through rates to be authorized by the CPUC in the Utility's 2014 GRC.

        The Utility also has filed an application at the NRC to renew the operating licenses for the two operating units at Diablo Canyon which expire in 2024 and 2025. In May 2011, after the Fukushima-Dai-ichi event, the NRC granted the Utility's request to delay processing the Utility's application until certain advanced seismic studies were completed by the Utility. When the Utility began the studies in 2010, it was anticipated that the studies would be completed in 2013 or 2014, depending upon whether required permits were timely obtained from environmental and local government agencies. In November 2012, the California Coastal Commission denied the Utility's request for permits to conduct off-shore three-dimensional high-energy seismic studies, in part, based on the finding that, because the studies were not necessary for NRC compliance, the potential environmental effects did not outweigh the risks. The Utility has completed the data collection phases for the on-shore advanced seismic studies as well as other off-shore low-energy seismic studies. The Utility is assessing whether it has sufficient seismic data without conducting high energy off-shore studies or if other studies are needed. Depending on the outcome of the Utility's assessment, it is uncertain when the Utility would request the NRC to resume the relicensing proceeding. In order to receive renewed operating licenses, the Utility also must undergo a consistency review by the California Coastal Commission. 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 which is not expected to be issued before September 2014. 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.)

        Finally, the CPUC is also considering the Utility's application to recover estimated costs to decommission the Utility's nuclear facilities at Diablo Canyon and the retired nuclear facility located at the Utility's Humboldt Bay Generation Station. The Utility files an application with the CPUC every three years requesting approval of the Utility's estimated decommissioning costs and authorization to recover the estimated costs through rates. (See the discussion of the 2012 Nuclear Decommissioning Cost Triennal Proceeding in Note 2 of the Notes to the Consolidated Financial Statements.)

Other Matters

Electric Distribution Facilities

        The Utility conducted a system-wide review of its patrol and inspection records for underground and overhead electric distribution facilities after the Utility reported to the CPUC in July 2012 that some of the Utility's facilities were not patrolled and/or inspected at the periodic intervals required by the CPUC's rules. The Utility concluded a system-wide review and found that approximately 0.4% of its total electric distribution facilities had not been patrolled and/or inspected at the intervals required by CPUC rules. The Utility has submitted the results of its review to the SED and has completed the patrols and inspections of all such facilities.

        In October 2012, the Utility also reported to the CPUC that it planned to re-inspect electric distribution underground and overhead facilities that had been identified as inspected by a contractor after a review determined that the inspection practices used by some of the contractor's employees did not meet the Utility's standards. The re-inspections have been completed.

        PG&E Corporation and the Utility are uncertain how the above matters will affect the other regulatory proceedings and current investigations involving the Utility, or whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

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Residential Rate Design

        In June 2012, the CPUC opened a rulemaking proceeding to examine electric rate design for residential customers among California's electric utilities and consider regulatory and legislative changes that may be needed to the current rate structure. PG&E Corporation and the Utility are uncertain how the outcome of this rulemaking proceeding will affect the Utility's future electric rate structure.

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. (See "Risk Factors" below.) 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.

Remediation

        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 include former manufactured gas plant ("MGP") 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. (See Note 15 of the Notes to the Consolidated Financial Statements.)

        The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility's natural gas compressor sites. The Utility is also required to take measures to abate the effects of the contamination on the environment. At the Hinkley natural gas compressor site, the Utility's remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region ("Regional Board"). The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

        The Utility submitted its proposed final remediation plan to the Regional Board in September 2011 recommending a combination of remedial methods to clean up groundwater contamination, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. In August 2012, the Regional Board issued a draft environmental impact report ("EIR") that evaluated the Utility's proposed methods and the potential environmental impacts. The Utility expects that the Regional Board will consider certification of the final EIR in the second quarter of 2013. Following certification of the EIR, the Regional Board is expected to issue the final cleanup standards.

        The Regional Board ordered the Utility in October 2011 to provide an interim and permanent replacement water system for resident households located near the chromium plume that have domestic wells containing hexavalent chromium in concentrations greater than 0.02 parts per billion. The Utility filed a petition with the California State Water Resources Control Board ("California Water Board") to contest certain provisions of the order. In June 2012, the Regional Board issued an amended order to allow the Utility to implement a whole house water replacement program for resident households located near the chromium plume boundary. Eligible residents may decide whether to accept a replacement water supply or have the Utility purchase their properties, or alternatively not participate in the program. As of January 31, 2013, approximately 350 residential households are covered by the program and the majority have opted to accept the Utility's offer to purchase their properties. The Utility is required to complete implementation of the whole house water replacement systems by August 31, 2013. The Utility will maintain and operate the whole house replacement systems for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.

        At December 31, 2012 and 2011, $226 million and $149 million, respectively, were accrued in PG&E Corporation's and the Utility's Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. The increase primarily reflects the Utility's best estimate of costs associated with the

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developments described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers through rates. Future costs will depend on many factors, including the Regional Board's certification of the final EIR, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the Utility's required time frame for remediation, and adoption of a final drinking water standard currently under development by the State of California, as mentioned above. As more information becomes known regarding these factors, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions may have a material impact on PG&E Corporation's and the Utility's future financial condition, results of operations, and cash flows.

Climate Change

        A report issued in 2012 by the U.S. Environmental Protection Agency ("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.

GHG Cap-and-Trade

        The California Global Warming Solutions Act of 2006 (also known as California Assembly Bill 32 or AB 32) requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. The California Air Resources Board ("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, including regulations that established a state-wide, comprehensive "cap-and-trade" program that sets a gradually declining limit (or "cap") on the amount of GHGs that may be emitted by the major sources of GHG emissions each 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 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. Emitters may meet up to 8% of their compliance obligation through the purchase of "offset credits" which represent GHG emissions abatement achieved in sectors that are not subject to the cap.

        Each year the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters (also known as covered entities) are required to obtain and surrender allowances equal to the amount of their GHG emissions within a particular compliance period. Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties or exchanges on the secondary market for trading GHG allowances. The CARB's first quarterly auction was held on November 14, 2012.

        Also, during each year of the program, the CARB will allocate 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 allowances for auction by the CARB. The CPUC has ordered the utilities to allocate their auction revenues, including accrued interest, among certain classes of their electricity distribution customers in accordance with existing state law. Although the CPUC had previously authorized the utilities to recover their GHG compliance costs through rates, the CPUC decided that the recovery of GHG compliance costs should be deferred until the CPUC adopted a final auction revenue allocation methodology. Until a final methodology is adopted, the utilities have been ordered to track GHG costs and auction revenues for future rate recovery. (See Note 3 of the Notes to the Consolidated Financial Statements.) The CARB has not yet decided whether and to what extent allowances will be freely allocated to regulated gas utilities for the benefit of their natural gas customers starting in the second compliance period beginning in 2015.

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

Renewable Energy Resources

        California's Renewables Portfolio Standard ("RPS") program increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. The RPS program, which became effective in December 2011, established compliance periods: 2011 through 2013, 2014 through 2016, 2017 through 2020, and 2021 and thereafter. The RPS compliance requirement that must be met for each of these compliance periods will

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gradually increase through 2020 and will be determined on an annual basis thereafter. In June 2012, the CPUC adopted rules for transitioning between the prior 20% RPS program and the 33% RPS program, applying excess procurement quantities across compliance periods, using procurement from short-term contracts to meet compliance requirements, and reporting annual RPS compliance to the CPUC.

        The Utility has made substantial financial commitments under third-party renewable energy contracts to meet RPS procurement quantity requirements. (See Note 15 of the Notes to the Consolidated Financial Statements.) The Utility currently forecasts that it will comply with its procurement requirements. The costs incurred by the Utility under third-party contracts to meet RPS requirements are expected to be recovered with other procurement costs through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximum amounts authorized by the CPUC for the respective project.

Water Quality

        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, 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. The EPA is required to issue final regulations by July 2013.

        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. The committee's assessment is due by October 2013. If the California Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility 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. 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. The Utility's Diablo Canyon operations must be in compliance with the California Water Board's policy by December 31, 2024.

LEGAL MATTERS

        In addition to the provisions made for contingencies related to the San Bruno accident, PG&E Corporation's and the Utility's Consolidated Financial Statements also include provisions for claims and lawsuits that have arisen in the ordinary course of business, regulatory proceedings, and other legal matters. (See "Legal and Regulatory Contingencies" in Note 15 of the Notes to the Consolidated Financial Statements.)

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 15 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.

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        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.

        On July 21, 2010, President Obama signed into law federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank"). PG&E Corporation and the Utility are implementing programs to comply with the final regulations that have been issued pursuant to Dodd-Frank.

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. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility's price exposure. When market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.

        The Utility's value-at-risk calculated under the methodology described above was approximately $13 million and $11 million at December 31, 2012 and 2011, respectively. During the 12 months ended December 31, 2012, the Utility's approximate high, low, and average values-at-risk were $13 million, $10 million and $12 million, respectively. And during 2011, the value-at-risk amounts were $11 million, $7 million and $9 million, respectively. (See Note 10 of the Notes to the Consolidated Financial Statements for further discussion of price risk management activities.)

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, 2012 and December 31, 2011, if interest rates changed by 1% for all current PG&E Corporation and Utility variable rate and short-term debt and investments, the change would affect net income for the next 12 months by $7 million and $13 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 other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, 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

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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 net credit risk exposure to its counterparties, as well as the Utility's credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of December 31, 2012 and December 31, 2011:

(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, 2012

  $ 94   $ (9 ) $ 85     2     62  

December 31, 2011

    151     (13 )   138     2     106  

(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). 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 accounting principles generally accepted in the United States of America ("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 Assets and Liabilities

        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 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 during 2012, 2011, and 2010, the recovery of any material costs previously recognized by the Utility as regulatory assets.

        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, 2012, PG&E Corporation and the

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Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $8.3 billion and regulatory liabilities (including current balancing accounts payable) of $6.1 billion.

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.

        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, 2012 and 2011, the Utility's accruals for undiscounted gross environmental liabilities were $910 million and $785 million, respectively. The Utility's undiscounted future costs could increase to as much as $1.6 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 "Legal and Regulatory Contingencies" in Note 15 of the Notes to the Consolidated Financial Statements.)

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Asset Retirement Obligations

        PG&E Corporation and the Utility account for an asset retirement obligation ("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 and certain fossil fuel-fired generation facilities. 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 increase in the estimated obligation of $1.3 billion was primarily 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 1.57%. Similarly, an increase in the discount rate by 25 basis points would decrease the amount of the ARO by 4.03%. At December 31, 2012, the Utility's recorded ARO for the estimated cost of retiring these long-lived assets was $2.9 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. (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 2012 is 7.5%, gradually decreasing to the ultimate trend rate of 5% in 2018 and beyond.

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        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 5.4% compares to a ten-year actual return of 10.2%.

        The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 648 Aa-grade non-callable bonds at December 31, 2012. 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 2012
Pension
Costs
  Increase in Projected
Benefit Obligation at
December 31, 2012
 

Discount rate

    (0.50 )% $ 110   $ 1,262  

Rate of return on plan assets

    (0.50 )%   54      

Rate of increase in compensation

    0.50 %   50     308  

        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 2012
Other Postretirement
Benefit Costs
  Increase in Accumulated
Benefit Obligation at
December 31, 2012
 

Health care cost trend rate

    0.50 % $ 4   $ 53  

Discount rate

    (0.50 )%   2     132  

Rate of return on plan assets

    (0.50 )%   7      

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RISK FACTORS

PG&E Corporation's and the Utility's reputations have been significantly affected by the negative publicity surrounding the San Bruno accident, the related investigations and civil litigation, and the various reports the Utility has submitted to the CPUC to disclose noncompliance with applicable regulations. 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 that may be commenced, and by media or public scrutiny of the Utility's electricity and natural gas operations. Such further 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 San Bruno accident for which the Utility has acknowledged liability; the June 2011 investigative report from the CPUC's independent review panel and the August 2011 National Transportation Safety Board ("NTSB") report, both of which criticized the Utility's safety recordkeeping for its natural gas transmission system and the Utility's pipeline installation, integrity management, and other operational practices; and the media coverage of the accident and the related investigations and lawsuits. After the San Bruno accident, the CPUC initiated three investigations pertaining to the Utility's natural gas transmission pipeline operations, including an investigation of the San Bruno accident. (See "Natural Gas Matters" above.) A criminal investigation of the San Bruno accident also has been commenced. The media also has widely reported on the civil lawsuits arising from the San Bruno accident which seek compensation and punitive damages for personal injuries, deaths, and property damage.

        In addition, the Utility has notified the SED of various self-identified violations of regulations applicable to natural gas safety and operating practices since December 2011 when the CPUC imposed the self-reporting requirement and authorized the SED to impose penalties based on the self-identified violations. In January 2012, the SED imposed penalties of $17 million on the Utility for self-reported failure to perform certain leak surveys and the SED may impose additional penalties based on other self-reported violations. These self-reports also have received negative media attention.

        The Utility's operations are also subject to heightened and well-publicized concerns about many aspects of its operations, such as the Utility's nuclear generation operations at Diablo Canyon and the risks of terrorist acts, earthquakes, or a nuclear accident; the Utility's environmental remediation activities; and the accuracy, privacy, and safety of the Utility's information and operating systems, including those used to measure customer energy usage and generate bills. These 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.

        Further, these concerns may cause investors to 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. Given PG&E Corporation's and the Utility's greater equity needs, a declining stock price would cause further dilution in net income per share. The extent to which their 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 pipeline safety enhancement plan, whether they can respond to the findings and recommendations made by the CPUC's independent review panel and the NTSB, and whether they are able to adequately convince regulators, legislators, law enforcement officials, the media and the public that they have done so. Their ability to repair their reputations also may be affected by developments that may occur in the pending investigations, including the amount of civil or criminal penalties that may be imposed on the Utility; whether there are new investigations or citations; and developments that may occur in the San Bruno accident-related civil litigation. If PG&E Corporation and the Utility are unable to repair their reputations, their financial conditions, results of operations and cash flows may be further negatively affected.

PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially affected by the ultimate amount of penalties imposed on the Utility; the costs of taking required remedial actions; the ultimate amount of criminal penalties, if any, imposed by governmental authorities; and the ultimate amount of third-party liability arising from the San Bruno accident and the availability, timing and amount of related insurance recoveries.

        The CPUC has stated that it is prepared to impose substantial penalties on the Utility in connection with the investigations. Although the parties have engaged in settlement discussions in an effort to reach a stipulated outcome to resolve the investigations, the parties have not reached an agreement. If a stipulated outcome is not reached and the CPUC issues a decision that finds that the Utility violated applicable laws, rules or orders, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.) The CPUC has

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wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised this discretion in determining penalties. The SED also has this discretion under the authority delegated to it by the CPUC, but the SED is required to impose the maximum statutory penalty per violation, per day.

        PG&E Corporation and the Utility have concluded that it is probable that the Utility will be required to pay penalties in connection with the investigations and potential SED enforcement related to the self-reports and have accrued an amount in their financial statements that reflects the reasonably estimable minimum amount of penalties they believe it is probable that the Utility will incur. After considering the many variables that could affect the ultimate amount of penalties the Utility may be required to pay, PG&E Corporation and the Utility are unable to make a better estimate of the probable loss or estimate the reasonably possible amount of penalties that the Utility could incur in excess of the amount accrued and such amount could be material. In addition to penalties, the Utility could incur significant costs to implement any remedial actions the CPUC may order the Utility to perform.

        PG&E Corporation and the Utility also are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any criminal penalties that may be imposed in connection with the pending criminal investigation. Any civil or criminal penalties imposed on the Utility will not be recoverable from customers. (See Note 15 of the Notes to the Consolidated Financial Statements.) PG&E Corporation and the Utility also have concluded that it is probable that the Utility will incur a loss in connection with the lawsuits arising from the San Bruno accident and have accrued an amount in their financial statements for the reasonably estimable minimum amount of loss. PG&E Corporation and the Utility believe that a significant portion of the third-party liabilities the Utility incurs will be recoverable through insurance, but there is a risk that the insurers could deny coverage for claims under the terms of the policies, deem settlement amounts excessive and not payable, or be financially unable to pay the Utility's claims. Further, although many of the San Bruno lawsuits have been settled, a substantial number of cases are unresolved and plaintiffs continue to pursue compensatory and punitive damages. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any punitive damages that could be awarded to plaintiffs in the civil litigation. (See Note 15 of the Notes to the Consolidated Financial Statements.)

        The estimates and assumptions underlying the accrued amounts and the ultimate amount of penalties and third-party losses are subject to change based on the amount of penalties actually imposed by the CPUC or agreed to in a stipulated outcome that may be reached to resolve the investigations, by the outcome of trials in the San Bruno litigation, and the terms of additional settlement agreements that may be reached with remaining plaintiffs. Future changes to estimates and assumptions could result in additional accruals in future periods which could have a material impact on PG&E Corporation's and the Utility's financial condition and results of operations in the period in which they are recognized.

PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows have been, and will continue to be, materially affected by costs incurred by the Utility to perform work under its pipeline safety enhancement plan, to undertake other pipeline-related work, and to improve the safety and reliability of its natural gas and electricity operations.

        Although the CPUC approved most of the proposed scope and timing of projects under the Utility's pipeline safety enhancement plan, the CPUC disallowed the Utility's request for rate recovery of a significant portion of capital costs and expenses through 2014, including costs of pressure testing pipelines placed into service after January 1, 1956 for which the Utility is unable to produce pressure test records. The CPUC may disallow additional costs based on the final results of the Utility's pipeline records search and pipeline pressure validation work, which the Utility expects to complete by May 2013. (See "Natural Gas Matters" above.) The Utility will be unable to recover any costs in excess of the adopted capital and expense amounts and the adopted amounts will be reduced by the cost of any plan project not completed during the first phase and not replaced with a higher priority project. Further, actual costs for 2013 and 2014 may be materially higher than the Utility currently forecasts. During 2013, the Utility expects to request that the CPUC approve the proposed timing, scope and cost recovery for the first three years (2015, 2016, and 2017) of the second phase of the plan beginning on January 1, 2015. While the Utility's request will include updated cost forecasts based on the Utility's experience during the first phase, there is some risk that categories of costs that were disallowed by the CPUC in its decision on the first phase also will be disallowed in the second phase.

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        In addition, the Utility forecasts that it will incur additional costs outside of the scope of the pipeline safety enhancement plan in 2013 and 2014 that are not expected to be recoverable through rates. This includes costs to establish the parameters of the Utility's "rights-of-way" surrounding pipelines and to identify and remove encroachments from these pipeline rights-of-way. The Utility also forecasts it will continue to incur additional costs associated with the integrity of transmission pipelines, conduct other gas-related work, and legal and regulatory expenses. The Utility also forecasts that it will incur costs to improve electric and gas distribution operations in 2013 that exceed the amounts assumed when rates were set in the last rate cases. (See "Operating and Maintenance" above.) Actual costs may be materially higher than forecast. Further, as the Utility continues to review its natural gas system and operating practices and as industry practices and standards evolve, the Utility may undertake additional work in the future to improve the safety and reliability of its natural gas utility services, for example, to validate the maximum allowable operating pressure of other facilities in its natural gas transmission system, such as compressor stations. The Utility may be unable to recover the costs of such additional work through rates. The Utility also may incur third-party liability related to service disruptions caused by changes in pressure on its natural gas transmission system as work is performed.

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 pipeline safety enhancement plan, 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 pipeline safety enhancement plan before the CPUC approved the plan. The CPUC did not address the Utility's request and as a result the 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.

        Fluctuating commodity prices, 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. 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. Further, current California law restricts the ability of the CPUC to adjust electricity rates for certain customer classes which could lead to a perception that some customers are unfairly subsidizing other customers and that some commercial customers are competitively disadvantaged as compared to similar customers in other states. The customer concerns caused by these perceived inequities could also make it more difficult for the Utility to recover its operational costs.

        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.

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        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 costs timely may be affected by increasing renewable energy requirements, the continuing functioning of the wholesale electricity market in California, and the new 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 principles of "least cost dispatch."

        The Utility enters into power purchase agreements, including contracts to purchase renewable energy, in compliance with a long-term procurement plan approved by the CPUC. The Utility executes power purchase agreements following competitive requests for offers. The Utility submits the winning contracts to the CPUC for approval and authorization 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 purchases energy through the day-ahead wholesale electricity market operated by the California Independent System Operator ("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. 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, 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, with the beginning of the first compliance period under the new California cap-and-trade regulations on January 1, 2013, electricity costs include associated cap-and-trade compliance costs. Although some of these costs will 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

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these projects also face many of these risks. Changes in tax laws or policies, such as those relating "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. 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.

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 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 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, 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 and weather conditions that 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. The Utility's ability to earn its authorized rate of return depends on its ability to efficiently maintain and operate its facilities and provide electricity and natural gas services safely and reliably. The maintenance and operation of the Utility's facilities, and

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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:

        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. 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, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, 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 could significantly disrupt operations; result in public and employee safety lapse; result in outages; 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 increases 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.

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        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 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, 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 expose 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 Nuclear Electric Insurance Limited ("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, NEIL has notified the Utility and the other NEIL members that it will be significantly reducing its coverage for non-nuclear losses. This change will affect the Utility beginning in April 2013. 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 is not likely to be available at rates and on 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.

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        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 $235 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 15 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.

        The Utility has filed an application at the NRC to renew the operating licenses for the two operating units at Diablo Canyon which expire in 2024 and 2025. In May 2011, after the Fukushima-Dai-ichi event, the NRC granted the Utility's request to delay processing the Utility's application until certain advanced seismic studies that the CPUC ordered the Utility to conduct were completed. In November 2012, the California Coastal Commission denied the Utility's request for permits to conduct some of these advanced studies. The Utility is assessing whether it has sufficient seismic data without conducting the high energy off-shore studies or if other studies are needed. It is uncertain when the Utility would request the NRC to resume the relicensing proceeding. In order to receive renewed operating licenses, the Utility also must undergo a sufficiency review by the California Coastal Commission. 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's original "waste confidence decision" in which the NRC found that spent nuclear fuel can be safely managed until a permanent off-site repository is established, was successfully challenged on the basis that the NRC's environmental review was deficient. In August 2012, the NRC ruled that it will not issue final decisions in licensing or re-licensing proceedings, including the Utility's re-licensing application, until it had reconsidered the waste confidence issues. The NRC stated that it would consider all available options for resolving the waste confidence issue, which could include generic or site-specific NRC actions, or some combination of both. The NRC has instructed its staff to develop and issue a new waste confidence decision and temporary storage rule by September 2014.

        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 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 or orders. Further, 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 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 testing

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of natural gas pipelines have included costs to obtain local agency and environmental permits to conduct the tests as well as costs to treat and dispose of the water used in the tests that becomes contaminated as the water travels through the pipes. 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 penalties 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 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. (See Note 15 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.

        Further, the CPUC has ruled that the Utility's environmental costs for certain sites, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through this ratemaking mechanism. 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. 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 change, PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows could be materially affected.

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The Utility is subject to 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.

        On January 1, 2012, the CPUC's statutory authority to impose penalties increased from up to $20,000 per day, per violation, to 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 penalties. The CPUC has delegated authority to the SED to levy citations and impose penalties 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. (For a discussion of pending investigations and potential enforcement proceedings, see MD&A "Natural Gas Matters" above.) There is a risk that the CPUC could delegate additional enforcement authority to its staff or that legislation could be enacted to require the CPUC to further delegate enforcement authority.

        In addition, the federal Pipeline and Hazardous Materials Safety Administration can impose penalties 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. The FERC can impose penalties (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 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, 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.

        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.

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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, changes in assumptions as to decommissioning dates, technology and costs of labor, materials and equipment change, and assumed rate of return on plan assets. 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 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. 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. At December 31, 2012, PG&E Corporation and the Utility reported regulatory assets of $8.3 billion and regulatory liabilities of $6.1 billion. (See Note 3 of the Notes to the Consolidated Financial Statements.) Management believes that currently available facts support the continued application of regulatory accounting and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment. Since the San Bruno accident in September 2010, the Utility has recorded cumulative charges of approximately $1.83 billion related to its natural gas operations that are not recoverable through rates. To the extent that rates are not set at a level that allows the Utility to recover the cost

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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.

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. Further, the CPUC could adopt the SED's financial recommendations made in its January 12, 2012 report on the San Bruno accident, including that the Utility "should target retained earnings towards safety improvements before providing dividends, especially if the Utility's ROE exceeds the level set in a GRC." 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.

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 is not allowed to recover through rates, 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.

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." 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

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such needs. Following the San Bruno accident, PG&E Corporation has issued a material amount of equity to fund its equity contributions to the Utility as the Utility has incurred costs and expenses it cannot recover through rates.

        PG&E Corporation forecasts that it will continue to issue additional material amounts of equity as the Utility continues to incur costs that it cannot recover through rates, such as costs under its pipeline safety enhancement plan, to improve electricity and natural gas operations, and to pay penalties. PG&E Corporation may also be required to access the capital markets when the Utility is successful in selling long-term debt so that PG&E Corporation can contribute equity to the Utility as needed to maintain the Utility's authorized capital structure.

        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 amount of penalties imposed on the Utility in connection with the matters described above under "Natural Gas Maters;" 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; disruptions, uncertainty or volatility in the capital and credit markets; and general economic and 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 could 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. If PG&E Corporation is required to contribute equity to the Utility in these circumstances, it would be required to seek these funds from the capital or credit markets. 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.

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PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

 
  Year ended December 31,  
 
  2012   2011   2010  

Operating Revenues

                   

Electric

  $ 12,019   $ 11,606   $ 10,645  

Natural gas

    3,021     3,350     3,196  
               

Total operating revenues

    15,040     14,956     13,841  
               

Operating Expenses

                   

Cost of electricity

    4,162     4,016     3,898  

Cost of natural gas

    861     1,317     1,291  

Operating and maintenance

    6,052     5,466     4,439  

Depreciation, amortization, and decommissioning

    2,272     2,215     1,905  
               

Total operating expenses

    13,347     13,014     11,533  
               

Operating Income

    1,693     1,942     2,308  

Interest income

    7     7     9  

Interest expense

    (703 )   (700 )   (684 )

Other income, net

    70     49     27  
               

Income Before Income Taxes

    1,067     1,298     1,660  

Income tax provision

    237     440     547  
               

Net Income

    830     858     1,113  

Preferred stock dividend requirement of subsidiary

    14     14     14  
               

Income Available for Common Shareholders

  $ 816   $ 844   $ 1,099  
               

Weighted Average Common Shares Outstanding, Basic

    424     401     382  
               

Weighted Average Common Shares Outstanding, Diluted

    425     402     392  
               

Net Earnings Per Common Share, Basic

  $ 1.92   $ 2.10   $ 2.86  
               

Net Earnings Per Common Share, Diluted

  $ 1.92   $ 2.10   $ 2.82  
               

Dividends Declared Per Common Share

  $ 1.82   $ 1.82   $ 1.82  
               

   

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)
  2012   2011   2010  

Net Income

  $ 830   $ 858   $ 1,113  
               

Other Comprehensive Income

                   

Pension and other postretirement benefit plans

                   

Unrecognized prior service credit (cost) (net of income tax of $14, $24, and $20 in 2012, 2011, and 2010, respectively)

    17     36     (29 )

Unrecognized net gain (loss) (net of income tax of $20, $452, and $73 in 2012 , 2011, and 2010, respectively)

    31     (655 )   (110 )

Unrecognized net transition obligation (net of income tax of $8 in 2012, and $11 in 2011 and 2010, respectively)

    16     15     15  

Transfer to regulatory account (net of income tax of $30, $408, and $57 in 2012, 2011, and 2010, respectively)

    44     593     82  

Other (net of income tax of $3 in 2012)

    4          
               

Total other comprehensive income (loss)

    112     (11 )   (42 )
               

Comprehensive Income

    942     847     1,071  

Preferred stock dividend requirement of subsidiary

    14     14     14  
               

Comprehensive Income Attributable to Common Shareholders

  $ 928   $ 833   $ 1,057  
               

   

See accompanying Notes to the Consolidated Financial Statements.

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PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

 
  Balance at
December 31,
 
 
  2012   2011  

ASSETS

             

Current Assets

             

Cash and cash equivalents

  $ 401   $ 513  

Restricted cash ($0 and $51 related to energy recovery bonds at December 31, 2012 and 2011, respectively)

    330     380  

Accounts receivable

             

Customers (net of allowance for doubtful accounts of $87 and $81 at December 31, 2012 and 2011, respectively)

    937     992  

Accrued unbilled revenue

    761     763  

Regulatory balancing accounts

    936     1,082  

Other

    365     839  

Regulatory assets ($0 and $336 related to energy recovery bonds at December 31, 2012 and 2011, respectively)

    564     1,090  

Inventories

             

Gas stored underground and fuel oil

    135     159  

Materials and supplies

    309     261  

Income taxes receivable

    211     183  

Other

    172     218  
           

Total current assets

    5,121     6,480  
           

Property, Plant, and Equipment

             

Electric

    39,701     35,851  

Gas

    12,571     11,931  

Construction work in progress

    1,894     1,770  

Other

    1     15  
           

Total property, plant, and equipment

    54,167     49,567  

Accumulated depreciation

    (16,644 )   (15,912 )
           

Net property, plant, and equipment

    37,523     33,655  
           

Other Noncurrent Assets

             

Regulatory assets

    6,809     6,506  

Nuclear decommissioning trusts

    2,161     2,041  

Income taxes receivable

    176     386  

Other

    659     682  
           

Total other noncurrent assets

    9,805     9,615  
           

TOTAL ASSETS

  $ 52,449   $ 49,750  
           

   

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,
 
 
  2012   2011  

LIABILITIES AND EQUITY

             

Current Liabilities

             

Short-term borrowings

  $ 492   $ 1,647  

Long-term debt, classified as current

    400     50  

Energy recovery bonds, classified as current

        423  

Accounts payable

             

Trade creditors

    1,241     1,177  

Disputed claims and customer refunds

    157     673  

Regulatory balancing accounts

    634     374  

Other

    444     420  

Interest payable

    870     843  

Income taxes payable

    6     110  

Deferred income taxes

        196  

Other

    2,012     1,836  
           

Total current liabilities

    6,256     7,749  
           

Noncurrent Liabilities

             

Long-term debt

    12,517     11,766  

Regulatory liabilities

    5,088     4,733  

Pension and other postretirement benefits

    3,575     3,396  

Asset retirement obligations

    2,919     1,609  

Deferred income taxes

    6,748     6,008  

Other

    2,020     2,136  
           

Total noncurrent liabilities

    32,867     29,648  
           

Commitments and Contingencies (Note 15)

             

Equity

             

Shareholders' Equity

             

Preferred stock

         

Common stock, no par value, authorized 800,000,000 shares, 430,718,293 shares outstanding at December 31, 2012 and 412,257,082 shares outstanding at December 31, 2011

    8,428     7,602  

Reinvested earnings

    4,747     4,712  

Accumulated other comprehensive loss

    (101 )   (213 )
           

Total shareholders' equity

    13,074     12,101  

Noncontrolling Interest—Preferred Stock of Subsidiary

    252     252  
           

Total equity

    13,326     12,353  
           

TOTAL LIABILITIES AND EQUITY

  $ 52,449   $ 49,750  
           

   

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,  
 
  2012   2011   2010  

Cash Flows from Operating Activities

                   

Net income

  $ 830   $ 858   $ 1,113  

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

                   

Depreciation, amortization, and decommissioning

    2,272     2,215     1,905  

Allowance for equity funds used during construction

    (107 )   (87 )   (110 )

Deferred income taxes and tax credits, net

    648     544     756  

Disallowed capital expenditures

    353         36  

Other

    290     326     257  

Effect of changes in operating assets and liabilities:

                   

Accounts receivable

    (40 )   (288 )   (44 )

Inventories

    (24 )   (63 )   (43 )

Accounts payable

    (4 )   65     48  

Income taxes receivable/payable

    (132 )   (103 )   (78 )

Other current assets and liabilities

    262     23     111  

Regulatory assets, liabilities, and balancing accounts, net

    291     (100 )   (394 )

Other noncurrent assets and liabilities

    243     349     (351 )
               

Net cash provided by operating activities

    4,882     3,739     3,206  
               

Cash Flows from Investing Activities

                   

Capital expenditures

    (4,624 )   (4,038 )   (3,802 )

Decrease in restricted cash

    50     200     66  

Proceeds from sales and maturities of nuclear decommissioning trust investments

    1,133     1,928     1,405  

Purchases of nuclear decommissioning trust investments

    (1,189 )   (1,963 )   (1,456 )

Other

    104     (113 )   (70 )
               

Net cash used in investing activities

    (4,526 )   (3,986 )   (3,857 )
               

Cash Flows from Financing Activities

                   

Borrowings under revolving credit facilities

    120     358     490  

Repayments under revolving credit facilities

        (358 )   (490 )

Net issuances (repayments) of commercial paper, net of discount of $3 in 2012, $4 in 2011, and $3 in 2010

    (1,021 )   782     267  

Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010

        250     249  

Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $13 in 2012, $8 in 2011, and $23 in 2010

    1,137     792     1,327  

Short-term debt matured

    (250 )   (250 )   (500 )

Long-term debt matured or repurchased

    (50 )   (700 )   (95 )

Energy recovery bonds matured

    (423 )   (404 )   (386 )

Common stock issued

    751     662     303  

Common stock dividends paid

    (746 )   (704 )   (662 )

Other

    14     41     (88 )
               

Net cash provided by (used in) financing activities

    (468 )   469     415  
               

Net change in cash and cash equivalents

    (112 )   222     (236 )

Cash and cash equivalents at January 1

    513     291     527  
               

Cash and cash equivalents at December 31

  $ 401   $ 513   $ 291  
               

Supplemental disclosures of cash flow information

                   

Cash received (paid) for:

                   

Interest, net of amounts capitalized

  $ (594 ) $ (647 ) $ (627 )

Income taxes, net

    114     (42 )   (135 )

Supplemental disclosures of noncash investing and financing activities

                   

Common stock dividends declared but not yet paid

  $ 196   $ 188   $ 183  

Capital expenditures financed through accounts payable

    362     308     364  

Noncash common stock issuances

    22     24     265  

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, 2009

    371,272,457   $ 6,280   $ 4,213   $ (160 ) $ 10,333   $ 252   $ 10,585  

Net income

            1,113         1,113         1,113  

Other comprehensive loss

                (42 )   (42 )       (42 )

Common stock issued, net

    23,954,748     568             568         568  

Stock-based compensation amortization

        34             34         34  

Common stock dividends declared

            (706 )       (706 )       (706 )

Tax expense from employee stock plans

        (4 )           (4 )       (4 )

Preferred stock dividend requirement of subsidiary

            (14 )       (14 )       (14 )
                               

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  
                               

   

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,  
 
  2012   2011   2010  

Operating Revenues

                   

Electric

  $ 12,014   $ 11,601   $ 10,644  

Natural gas

    3,021     3,350     3,196  
               

Total operating revenues

    15,035     14,951     13,840  
               

Operating Expenses

                   

Cost of electricity

    4,162     4,016     3,898  

Cost of natural gas

    861     1,317     1,291  

Operating and maintenance

    6,045     5,459     4,432  

Depreciation, amortization, and decommissioning

    2,272     2,215     1,905  
               

Total operating expenses

    13,340     13,007     11,526  
               

Operating Income

    1,695     1,944     2,314  

Interest income

    6     5     9  

Interest expense

    (680 )   (677 )   (650 )

Other income, net

    88     53     22  
               

Income Before Income Taxes

    1,109     1,325     1,695  

Income tax provision

    298     480     574  
               

Net Income

    811     845     1,121  

Preferred stock dividend requirement

    14     14     14  
               

Income Available for Common Stock

  $ 797   $ 831   $ 1,107  
               

   

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
  Year ended December 31,  
(in millions)
  2012   2011   2010  

Net Income

  $ 811   $ 845   $ 1,121  
               

Other Comprehensive Income

                   

Pension and other postretirement benefit plans

                   

Unrecognized prior service credit (cost) (net of income tax of $13, $24, and $21 in 2012, 2011, and 2010, respectively)

    16     36     (30 )

Unrecognized net gain (loss) (net of income tax of $22, $447, and $74 in 2012, 2011, and 2010, respectively)

    33     (651 )   (108 )

Unrecognized net transition obligation (net of income tax of $8 in 2012, and $11 in 2011 and 2010, respectively)

    16     15     15  

Transfer to regulatory account (net of income tax of $30, $408, and $57 in 2012, 2011, and 2010, respectively)

    44     593     82  
               

Total other comprehensive income (loss)

    109     (7 )   (41 )
               

Comprehensive Income

  $ 920   $ 838   $ 1,080  
               

   

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

 
  Balance at December 31,  
 
  2012   2011  

ASSETS

             

Current Assets

             

Cash and cash equivalents

  $ 194   $ 304  

Restricted cash ($0 and $51 related to energy recovery bonds at December 31, 2012 and 2011, respectively)

    330     380  

Accounts receivable

             

Customers (net of allowance for doubtful accounts of $87 and $81 at December 31, 2012 and 2011, respectively)

    937     992  

Accrued unbilled revenue

    761     763  

Regulatory balancing accounts

    936     1,082  

Other

    366     840  

Regulatory assets ($0 and $336 related to energy recovery bonds at December 31, 2012 and 2011, respectively)

    564     1,090  

Inventories

             

Gas stored underground and fuel oil

    135     159  

Materials and supplies

    309     261  

Income taxes receivable

    186     242  

Other

    160     213  
           

Total current assets

    4,878     6,326  
           

Property, Plant, and Equipment

             

Electric

    39,701     35,851  

Gas

    12,571     11,931  

Construction work in progress

    1,894     1,770  
           

Total property, plant, and equipment

    54,166     49,552  

Accumulated depreciation

    (16,643 )   (15,898 )
           

Net property, plant, and equipment

    37,523     33,654  
           

Other Noncurrent Assets

             

Regulatory assets

    6,809     6,506  

Nuclear decommissioning trusts

    2,161     2,041  

Income taxes receivable

    171     384  

Other

    381     331  
           

Total other noncurrent assets

    9,522     9,262  
           

TOTAL ASSETS

  $ 51,923   $ 49,242  
           

   

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

 
  Balance at December 31,  
 
  2012   2011  

LIABILITIES AND SHAREHOLDERS' EQUITY

             

Current Liabilities

             

Short-term borrowings

  $ 372   $ 1,647  

Long-term debt, classified as current

    400     50  

Energy recovery bonds, classified as current

        423  

Accounts payable

             

Trade creditors

    1,241     1,177  

Disputed claims and customer refunds

    157     673  

Regulatory balancing accounts

    634     374  

Other

    419     417  

Interest payable

    865     838  

Income taxes payable

    12     118  

Deferred income taxes

        199  

Other

    1,794     1,628  
           

Total current liabilities

    5,894     7,544  
           

Noncurrent Liabilities

             

Long-term debt

    12,167     11,417  

Regulatory liabilities

    5,088     4,733  

Pension and other postretirement benefits

    3,497     3,325  

Asset retirement obligations

    2,919     1,609  

Deferred income taxes

    6,939     6,160  

Other

    1,959     2,070  
           

Total noncurrent liabilities

    32,569     29,314  
           

Commitments and Contingencies (Note 15)

             

Shareholders' Equity

             

Preferred stock

    258     258  

Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at December 31, 2012 and 2011

    1,322     1,322  

Additional paid-in capital

    4,682     3,796  

Reinvested earnings

    7,291     7,210  

Accumulated other comprehensive loss

    (93 )   (202 )
           

Total shareholders' equity

    13,460     12,384  
           

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

  $ 51,923   $ 49,242  
           

   

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 
  Year ended December 31,  
 
  2012   2011   2010  

Cash Flows from Operating Activities

                   

Net income

  $ 811   $ 845   $ 1,121  

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

                   

Depreciation, amortization, and decommissioning

    2,272     2,215     1,905  

Allowance for equity funds used during construction

    (107 )   (87 )   (110 )

Deferred income taxes and tax credits, net

    684     582     762  

Disallowed capital expenditures

    353         36  

Other

    236     289     221  

Effect of changes in operating assets and liabilities:

                   

Accounts receivable

    (40 )   (227 )   (105 )

Inventories

    (24 )   (63 )   (43 )

Accounts payable

    (26 )   51     109  

Income taxes receivable/payable

    (50 )   (192 )   (58 )

Other current assets and liabilities

    272     36     123  

Regulatory assets, liabilities, and balancing accounts, net

    291     (100 )   (394 )

Other noncurrent assets and liabilities

    256     414     (331 )
               

Net cash provided by operating activities

    4,928     3,763     3,236  
               

Cash Flows from Investing Activities

                   

Capital expenditures

    (4,624 )   (4,038 )   (3,802 )

Decrease in restricted cash

    50     200     66  

Proceeds from sales and maturities of nuclear decommissioning trust investments

    1,133     1,928     1,405  

Purchases of nuclear decommissioning trust investments

    (1,189 )   (1,963 )   (1,456 )

Other

    16     14     19  
               

Net cash used in investing activities

    (4,614 )   (3,859 )   (3,768 )
               

Cash Flows from Financing Activities

                   

Borrowings under revolving credit facilities

        208     400  

Repayments under revolving credit facilities

        (208 )   (400 )

Net issuances (repayments) of commercial paper, net of discount of $3 in 2012, $4 in 2011, and $3 in 2010

    (1,021 )   782     267  

Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010

        250     249  

Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $13 in 2012, $8 in 2011, and $23 in 2010

    1,137     792     1,327  

Short-term debt matured

    (250 )   (250 )   (500 )

Long-term debt matured or repurchased

    (50 )   (700 )   (95 )

Energy recovery bonds matured

    (423 )   (404 )   (386 )

Preferred stock dividends paid

    (14 )   (14 )   (14 )

Common stock dividends paid

    (716 )   (716 )   (716 )

Equity contribution

    885     555     190  

Other

    28     54     (73 )
               

Net cash provided by (used in) financing activities

    (424 )   349     249  
               

Net change in cash and cash equivalents

    (110 )   253     (283 )

Cash and cash equivalents at January 1

    304     51     334  
               

Cash and cash equivalents at December 31

  $ 194   $ 304   $ 51  
               

Supplemental disclosures of cash flow information

                   

Cash received (paid) for:

                   

Interest, net of amounts capitalized

  $ (574 ) $ (627 ) $ (595 )

Income taxes, net

    174     (50 )   (171 )

Supplemental disclosures of noncash investing and financing activities

                   

Capital expenditures financed through accounts payable

  $ 362   $ 308   $ 364  

Terminated capital leases

    136          

   

See accompanying Notes to the Consolidated Financial Statements.

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(in millions)

 
  Preferred
Stock
  Common
Stock
  Additional
Paid-in
Capital
  Reinvested
Earnings
  Accumulated
Other
Comprehensive
Income (Loss)
  Total
Shareholders'
Equity
 

Balance at December 31, 2009

  $ 258   $ 1,322   $ 3,055   $ 6,704   $ (154 ) $ 11,185  

Net income

                1,121         1,121  

Other comprehensive loss

                    (41 )   (41 )

Equity contribution

            190             190  

Tax expense from employee stock plans

            (4 )           (4 )

Common stock dividend

                (716 )       (716 )

Preferred stock dividend

                (14 )       (14 )
                           

Balance at December 31, 2010

    258     1,322     3,241     7,095     (195 )   11,721  

Net income

                845         845  

Other comprehensive loss

                    (7 )   (7 )

Equity contribution

            555             555  

Common stock dividend

                (716 )    <