10-Q 1 d10q.htm FORM 10-Q Form 10-Q
Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C., 20549

FORM 10-Q

(Mark One)

  [X]  

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 
  For the quarterly period ended September 30, 2010  
  OR  
  [  ]  

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 
  For the transition period from                      to                       

 

Commission        

File

Number

 

  

Exact Name of        

Registrant

as specified

in its charter

 

      

State or other

Jurisdiction of        

Incorporation

 

  

IRS Employer

Identification    

Number

 

    
1-12609    PG&E Corporation      California    94-3234914   
1-2348    Pacific Gas and Electric Company      California    94-0742640   

Pacific Gas and Electric Company                                     

77 Beale Street

P.O. Box 770000

San Francisco, California 94177

 

      

PG&E Corporation

One Market, Spear Tower

Suite 2400

San Francisco, California 94105

 

    
Address of principal executive offices, including zip code   

Pacific Gas and Electric Company                                    

(415) 973-7000

 

    

PG&E Corporation

(415) 267-7000

 

  

Registrant’s telephone number, including area code

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  [X]  Yes    [  ]  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

PG&E Corporation    [X] Yes [  ] No
Pacific Gas and Electric Company:    [  ] Yes  [  ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

PG&E Corporation:    [X] Large accelerated filer    [  ] Accelerated Filer   
   [  ] Non-accelerated filer    [  ] Smaller reporting company   
Pacific Gas and Electric Company:        [  ] Large accelerated filer    [  ] Accelerated Filer   
   [X] Non-accelerated filer    [  ] Smaller reporting company   

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

PG&E Corporation:    [  ] Yes [X] No
Pacific Gas and Electric Company:    [  ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

Common Stock Outstanding as of October 25, 2010:

  

PG&E Corporation

     392,065,793   

Pacific Gas and Electric Company

     264,374,809   

 

 

 


Table of Contents

 

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010

TABLE OF CONTENTS

 

PART I.   FINANCIAL INFORMATION    PAGE  
ITEM 1.   CONDENSED CONSOLIDATED FINANCIAL STATEMENTS   
 

PG&E Corporation

  
 

Condensed Consolidated Statements of Income

     2   
 

Condensed Consolidated Balance Sheets

     3   
 

Condensed Consolidated Statements of Cash Flows

     5   
 

Pacific Gas and Electric Company

  
 

Condensed Consolidated Statements of Income

     6   
 

Condensed Consolidated Balance Sheets

     7   
 

Condensed Consolidated Statements of Cash Flows

     9   
 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
  NOTE 1:   Organization and Basis of Presentation      10   
  NOTE 2:   Significant Accounting Policies      10   
  NOTE 3:   Regulatory Assets, Liabilities, and Balancing Accounts      13   
  NOTE 4:   Debt      16   
  NOTE 5:   Equity      18   
  NOTE 6:   Earnings Per Share      19   
  NOTE 7:   Derivatives and Hedging Activities      20   
  NOTE 8:   Fair Value Measurements      24   
  NOTE 9:   Resolution of Remaining Chapter 11 Disputed Claims      30   
  NOTE 10:   Commitments and Contingencies      31   
ITEM 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   
  Overview      38   
  Cautionary Language Regarding Forward-Looking Statements      41   
  Results of Operations      43   
  Liquidity and Financial Resources      48   
  Contractual Commitments      53   
  Capital Expenditures      53   
  Off-Balance Sheet Arrangements      54   
  Contingencies      55   
  Regulatory Matters      55   
  Environmental Matters      59   
  Other Matters      61   
  Risk Management Activities      63   
  Critical Accounting Policies      64   

ITEM 3.

  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      66   
ITEM 4.   CONTROLS AND PROCEDURES      66   
PART II.   OTHER INFORMATION   
ITEM 1.   LEGAL PROCEEDINGS      67   
ITEM 1A.   RISK FACTORS      67   
ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS      69   
ITEM 5.   OTHER INFORMATION      69   
ITEM 6.   EXHIBITS      70   


Table of Contents

 

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     (Unaudited)  
     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
(in millions, except per share amounts)            2010                     2009                     2010                     2009          

Operating Revenues

        

Electric

     $ 2,857        $ 2,630        $ 7,882        $ 7,610   

Natural gas

     656        605        2,338        2,250   
                                

Total operating revenues

     3,513        3,235        10,220        9,860   
                                

Operating Expenses

        

Cost of electricity

     1,102        997        2,885        2,763   

Cost of natural gas

     182        134        924        879   

Operating and maintenance

     1,225        1,047        3,175        3,144   

Depreciation, amortization, and decommissioning

     501        450        1,420        1,298   
                                

Total operating expenses

     3,010        2,628        8,404        8,084   
                                

Operating Income

     503        607        1,816        1,776   

Interest income

     3        1        7        27   

Interest expense

     (167     (174     (510     (533

Other income, net

     29        23        25        63   
                                

Income Before Income Taxes

     368        457        1,338        1,333   

Income tax provision

     107        136        479        376   
                                

Net Income

     261        321        859        957   

Preferred stock dividend requirement of subsidiary

     3        3        10        10   
                                

Income Available for Common Shareholders

     $ 258        $ 318        $ 849        $ 947   
                                

Weighted Average Common Shares Outstanding, Basic

     390        370        378        367   
                                

Weighted Average Common Shares Outstanding, Diluted

     392        388        391        386   
                                

Net Earnings Per Common Share, Basic

     $ 0.66        $ 0.84        $ 2.22        $ 2.53   
                                

Net Earnings Per Common Share, Diluted

     $ 0.66        $ 0.83        $ 2.19        $ 2.49   
                                

Dividends Declared Per Common Share

     $ 0.46        $ 0.42        $ 1.37        $ 1.26   
                                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

 

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     (Unaudited)  
     Balance At  
(in millions)        September 30,    
2010
        December 31,    
2009
 

ASSETS

    

Current Assets

    

Cash and cash equivalents

     $ 347        $ 527   

Restricted cash ($38 and $39 related to Energy recovery bonds at September 30, 2010 and December 31, 2009, respectively)

     573        633   

Accounts receivable:

    

Customers (net of allowance for doubtful accounts of $76 at September 30, 2010 and $68 at December 31, 2009)

     989        859   

Accrued unbilled revenue

     752        671   

Regulatory balancing accounts

     1,118        1,109   

Other

     786        750   

Inventories:

    

Gas stored underground and fuel oil

     192        114   

Materials and supplies

     187        200   

Income taxes receivable

     -        127   

Prepaid expenses and other

     807        667   
                

Total current assets

     5,751        5,657   
                

Property, Plant, and Equipment

    

Electric

     32,074        30,481   

Gas

     11,079        10,697   

Construction work in progress

     2,180        1,888   

Other

     14        14   
                

Total property, plant, and equipment

     45,347        43,080   

Accumulated depreciation

     (14,672     (14,188
                

Net property, plant, and equipment

     30,675        28,892   
                

Other Noncurrent Assets

    

Regulatory assets ($833 and $1,124 related to Energy recovery bonds at September 30, 2010 and December 31, 2009, respectively)

     5,702        5,522   

Nuclear decommissioning trusts

     1,977        1,899   

Income taxes receivable

     624        596   

Other

     524        379   
                

Total other noncurrent assets

     8,827        8,396   
                

TOTAL ASSETS

     $ 45,253        $ 42,945   
                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

     (Unaudited)  
     Balance At  
(in millions, except share amounts)        September 30,    
2010
        December 31,    
2009
 

LIABILITIES AND EQUITY

    

Current Liabilities

    

Short-term borrowings

     $ 1,076        $ 833   

Long-term debt, classified as current

     500        342   

Energy recovery bonds, classified as current

     399        386   

Accounts payable:

    

Trade creditors

     943        984   

Disputed claims and customer refunds

     746        773   

Regulatory balancing accounts

     371        281   

Other

     364        349   

Interest payable

     787        818   

Income taxes payable

     260        214   

Deferred income taxes

     150        332   

Other

     1,588        1,501   
                

Total current liabilities

     7,184        6,813   
                

Noncurrent Liabilities

    

Long-term debt

     10,727        10,381   

Energy recovery bonds

     528        827   

Regulatory liabilities

     4,446        4,125   

Pension and other postretirement benefits

     2,064        1,773   

Asset retirement obligations

     1,610        1,593   

Deferred income taxes

     5,267        4,732   

Other

     2,152        2,116   
                

Total noncurrent liabilities

     26,794        25,547   
                

Commitments and Contingencies

    

Equity

    

Shareholders’ Equity

    

Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued

     -        -   

Common stock, no par value, authorized 800,000,000 shares, 391,530,616 shares outstanding (including 475,914 restricted shares) at September 30, 2010 and 371,272,457 shares outstanding (including 670,552 restricted shares) at December 31, 2009

     6,712        6,280   

Reinvested earnings

     4,535        4,213   

Accumulated other comprehensive loss

     (224     (160
                

Total shareholders’ equity

     11,023        10,333   

Noncontrolling Interest – Preferred Stock of Subsidiary

     252        252   
                

Total equity

     11,275        10,585   
                

TOTAL LIABILITIES AND EQUITY

     $ 45,253        $ 42,945   
                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

 

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     (Unaudited)  
         Nine Months Ended    
September  30,
 

(in millions)

 

           2010                     2009          

Cash Flows from Operating Activities

    

Net income

     $ 859        $ 957   

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

    

Depreciation, amortization, and decommissioning

     1,609        1,455   

Allowance for equity funds used during construction

     (89     (71

Deferred income taxes and tax credits, net

     328        301   

Other changes in noncurrent assets and liabilities

     (339     61   

Effect of changes in operating assets and liabilities:

    

Accounts receivable

     (246     20   

Inventories

     (65     78   

Accounts payable

     17        (159

Disputed claims and customer refunds

     -        (700

Income taxes receivable/payable

     252        658   

Regulatory balancing accounts, net

     (14     226   

Other current assets

     28        27   

Other current liabilities

     (34     (50

Other

     14        4   
                

Net cash provided by operating activities

     2,320        2,807   
                

Cash Flows from Investing Activities

    

Capital expenditures

     (2,794     (3,022

Decrease in restricted cash

     61        732   

Proceeds from sales and maturities of nuclear decommissioning trust investments

     962        1,177   

Purchases of nuclear decommissioning trust investments

     (1,001     (1,219

Other

     (25     14   
                

Net cash used in investing activities

     (2,797     (2,318
                

Cash Flows from Financing Activities

    

Borrowings under revolving credit facilities

     490        300   

Repayments under revolving credit facilities

     -        (300

Net issuance (repayments) of commercial paper, net of discount of $2 in 2010 and $3 in 2009

     251        (290

Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2009

     -        499   

Proceeds from issuance of long-term debt, net of discount and issuance costs of $12 in 2010 and $16 in 2009

     838        1,193   

Short-term debt matured

     (500     -   

Long-term debt matured or repurchased

     (95     (909

Energy recovery bonds matured

     (285     (273

Common stock issued

     141        211   

Common stock dividends paid

     (492     (435

Other

     (51     (4
                

Net cash provided by financing activities

     297        (8
                

Net change in cash and cash equivalents

     (180     481   

Cash and cash equivalents at January 1

     527        219   
                

Cash and cash equivalents at September 30

     $ 347        $ 700   
                

Supplemental disclosures of cash flow information

    

Cash received (paid) for:

    

Interest, net of amounts capitalized

     $ (526     $ (493

Income taxes, net

     (52     437   

Supplemental disclosures of noncash investing and financing activities

    

Common stock dividends declared but not yet paid

     $ 180        $ 156   

Capital expenditures financed through accounts payable

     229        229   

Noncash common stock issuances

     259        50   

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

 

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     (Unaudited)  
         Three Months Ended    
September  30,
     Nine Months Ended 
September 30,
 

(in millions)

 

   2010     2009     2010     2009  

Operating Revenues

        

Electric

     $ 2,857        $ 2,630        $ 7,882        $ 7,610   

Natural gas

     656        605        2,338        2,250   
                                

Total operating revenues

     3,513        3,235        10,220        9,860   
                                

Operating Expenses

        

Cost of electricity

     1,102        997        2,885        2,763   

Cost of natural gas

     182        134        924        879   

Operating and maintenance

     1,224        1,047        3,172        3,143   

Depreciation, amortization, and decommissioning

     500        450        1,419        1,298   
                                

Total operating expenses

     3,008        2,628        8,400        8,083   
                                

Operating Income

     505        607        1,820        1,777   

Interest income

     3        3        7        29   

Interest expense

     (161     (162     (481     (501

Other income, net

     25        16        20        52   
                                

Income Before Income Taxes

     372        464        1,366        1,357   

Income tax provision

     107        111        498        374   
                                

Net Income

     265        353        868        983   

Preferred stock dividend requirement

     3        3        10        10   
                                

Income Available for Common Stock

     $ 262        $ 350        $ 858        $ 973   
                                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

 

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     (Unaudited)  
     Balance At  
(in millions)            September 30,         
2010
            December 31,         
2009
 

ASSETS

    

Current Assets

    

Cash and cash equivalents

     $ 119        $ 334   

Restricted cash ($38 and $39 related to Energy recovery bonds at September 30, 2010 and December 31, 2009, respectively)

     573        633   

Accounts receivable:

    

Customers (net of allowance for doubtful accounts of $76 at September 30, 2010 and $68 at December 31, 2009)

     989        859   

Accrued unbilled revenue

     752        671   

Regulatory balancing accounts

     1,118        1,109   

Other

     781        751   

Inventories:

    

Gas stored underground and fuel oil

     192        114   

Materials and supplies

     187        200   

Income taxes receivable

     -        138   

Prepaid expenses and other

     806        662   
                

Total current assets

     5,517        5,471   
                

Property, Plant, and Equipment

    

Electric

     32,074        30,481   

Gas

     11,079        10,697   

Construction work in progress

     2,180        1,888   
                

Total property, plant, and equipment

     45,333        43,066   

Accumulated depreciation

     (14,659     (14,175
                

Net property, plant, and equipment

     30,674        28,891   
                

Other Noncurrent Assets

    

Regulatory assets ($833 and $1,124 related to Energy recovery bonds at September 30, 2010 and December 31, 2009, respectively)

     5,702        5,522   

Nuclear decommissioning trusts

     1,977        1,899   

Income taxes receivable

     673        610   

Other

     357        316   
                

Total other noncurrent assets

     8,709        8,347   
                

TOTAL ASSETS

     $ 44,900        $ 42,709   
                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

     (Unaudited)  
     Balance At  
(in millions, except share amounts)   

    September 30,    
2010

   

    December 31,    
2009

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current Liabilities

    

Short-term borrowings

     $ 986        $ 833   

Long-term debt, classified as current

     500        95   

Energy recovery bonds, classified as current

     399        386   

Accounts payable:

    

Trade creditors

     943        984   

Disputed claims and customer refunds

     746        773   

Regulatory balancing accounts

     371        281   

Other

     376        363   

Interest payable

     777        813   

Income taxes payable

     260        223   

Deferred income taxes

     154        334   

Other

     1,377        1,307   
                

Total current liabilities

     6,889        6,392   
                

Noncurrent Liabilities

    

Long-term debt

     10,378        10,033   

Energy recovery bonds

     528        827   

Regulatory liabilities

     4,446        4,125   

Pension and other postretirement benefits

     2,006        1,717   

Asset retirement obligations

     1,610        1,593   

Deferred income taxes

     5,322        4,764   

Other

     2,105        2,073   
                

Total noncurrent liabilities

     26,395        25,132   
                

Commitments and Contingencies

    

Shareholders’ Equity

    

Preferred stock without mandatory redemption provisions:

    

Nonredeemable, 5.00% to 6.00%, 5,784,825 shares outstanding at September 30, 2010 and December 31, 2009

     145        145   

Redeemable, 4.36% to 5.00%, 4,534,958 shares outstanding at September 30, 2010 and December 31, 2009

     113        113   

Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at September 30, 2010 and December 31, 2009

     1,322        1,322   

Additional paid-in capital

     3,228        3,055   

Reinvested earnings

     7,025        6,704   

Accumulated other comprehensive loss

     (217     (154
                

Total shareholders’ equity

     11,616        11,185   
                

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

     $ 44,900        $ 42,709   
                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

 

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     (Unaudited)  
         Nine Months Ended    
September  30,
 
(in millions)    2010     2009  

Cash Flows from Operating Activities

    

Net income

     $ 868        $ 983   

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

    

Depreciation, amortization, and decommissioning

     1,580        1,439   

Allowance for equity funds used during construction

     (89     (71

Deferred income taxes and tax credits, net

     332        274   

Other changes in noncurrent assets and liabilities

     (286     95   

Effect of changes in operating assets and liabilities:

    

Accounts receivable

     (240     20   

Inventories

     (65     78   

Accounts payable

     15        (151

Disputed claims and customer refunds

     -        (700

Income taxes receivable/payable

     241        534   

Regulatory balancing accounts, net

     (14     226   

Other current assets

     28        26   

Other current liabilities

     (33     (62

Other

     14        3   
                

Net cash provided by operating activities

     2,351        2,694   
                

Cash Flows from Investing Activities

    

Capital expenditures

     (2,794     (3,022

Decrease in restricted cash

     61        732   

Proceeds from sales and maturities of nuclear decommissioning trust investments

     962        1,177   

Purchases of nuclear decommissioning trust investments

     (1,001     (1,219

Other

     15        7   
                

Net cash used in investing activities

     (2,757     (2,325
                

Cash Flows from Financing Activities

    

Borrowings under revolving credit facilities

     400        300   

Repayments under revolving credit facilities

     -        (300

Net issuance (repayments) of commercial paper, net of discount of $2 in 2010 and $3 in 2009

     251        (290

Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2009

     -        499   

Proceeds from issuance of long-term debt, net of discount and issuance costs of $12 in 2010 and 2009

     838        847   

Short-term debt matured

     (500     -   

Long-term debt matured or repurchased

     (95     (909

Energy recovery bonds matured

     (285     (273

Preferred stock dividends paid

     (11     (10

Common stock dividends paid

     (537     (468

Equity contribution

     170        688   

Other

     (40     6   
                

Net cash provided by financing activities

     191        90   
                

Net change in cash and cash equivalents

     (215     459   

Cash and cash equivalents at January 1

     334        52   
                

Cash and cash equivalents at September 30

     $ 119        $ 511   
                

Supplemental disclosures of cash flow information

    

Cash received (paid) for:

    

Interest, net of amounts capitalized

     $ (504     $ (481

Income taxes, net

     (87     297   

Supplemental disclosures of noncash investing and financing activities

    

Capital expenditures financed through accounts payable

     $ 229        $ 229   

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally 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 is regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility that includes separate Condensed Consolidated Financial Statements for each company. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The 2009 presentation of borrowings and payments under the revolving credit facilities has been adjusted in the accompanying Condensed Consolidated Statements of Cash Flows to present borrowings and repayments on a gross basis rather than a net basis to conform with GAAP. The information at December 31, 2009 in both PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined 2009 Annual Report on Form 10-K filed with the SEC on February 19, 2010. PG&E Corporation’s and the Utility’s combined 2009 Annual Report on Form 10-K, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2009 Annual Report.” This quarterly report should be read in conjunction with the 2009 Annual Report.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions relate to the Utility’s regulatory assets and liabilities, environmental remediation liabilities, asset retirement obligations (“ARO”), income tax-related assets and liabilities, and pension plan and other postretirement plan obligations. In addition, management has made significant estimates and assumptions about accruals related to the rupture of a natural gas transmission pipeline owned and operated by the Utility in the City of San Bruno, California on September 9, 2010, as well as accruals for various legal matters. (See Note 10 below.) Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report. Any significant changes to those policies or new significant policies are described below.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all plans.

 

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The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Statements of Income for the three and nine-months ended September 30, 2010 and 2009 were as follows:

 

     Pension Benefits     Other Benefits  
         Three Months Ended    
September 30,
          Three Months Ended      
    September 30,    
 
(in millions)    2010     2009     2010     2009  

Service cost for benefits earned

     $ 70        $ 62        $ 8        $ 7   

Interest cost

     162        158        21        23   

Expected return on plan assets

     (155     (144     (18     (17

Amortization of transition obligation

     -        -        6        6   

Amortization of prior service cost

     13        16        7        4   

Amortization of unrecognized loss

     11        27        1        1   
                                

Net periodic benefit cost

     101        119        25        24   
                                

Less: transfer to regulatory account (1)

     (60     (78     -        -   
                                

Total

     $ 41        $ 41        $ 25        $ 24   
                                

 

(1) The Utility recorded $60 million and $78 million for the three month periods ended September 30, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

   

 

     Pension Benefits     Other Benefits  
         Nine Months Ended    
September 30,
            Nine Months Ended         
        September 30,        
 
(in millions)    2010     2009     2010     2009  

Service cost for benefits earned

     $ 209          $ 194        $ 27        $ 22   

Interest cost

     484        468        66        66   

Expected return on plan assets

     (467     (434     (55     (51

Amortization of transition obligation

     -        -        19        19   

Amortization of prior service cost

     39        39        19        12   

Amortization of unrecognized loss

     32        76        2        2   
                                

Net periodic benefit cost

     297        343        78        70   
                                

Less: transfer to regulatory account (1)

     (175     (221     -        -   
                                

Total

     $ 122        $ 122        $ 78        $ 70   
                                

 

(1) The Utility recorded $175 million and $221 million for the nine month periods ended September 30, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

   

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three and nine months ended September 30, 2010 and 2009.

On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional employer contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the plans. The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to pension and other postretirement benefits and a decrease to other comprehensive income of $148 million. The impact to net periodic benefit cost was not material.

 

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Adoption of New Accounting Pronouncements

Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

On January 1, 2010, PG&E Corporation and the Utility adopted an accounting standards update that changes when and how to determine, or re-determine, whether an entity is a variable interest entity (“VIE”), which could require consolidation. In addition, the new guidance replaces the quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach, and requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. The adoption of the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

PG&E Corporation and the Utility are required to consolidate any entities which the companies control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on equity or voting interests alone. These entities are referred to as VIEs. A VIE is an entity which does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to the VIE and the power to direct the activities that are most significant to the VIE’s economic performance. The enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is the enterprise that is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in the VIE, the Utility must first assess whether it absorbs any of the VIE’s expected losses or receives portions of the expected residual returns as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders. These VIEs are typically exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others. The Utility analyzes the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin to determine whether the Utility absorbs variability, resulting in a variable interest. Factors that may be considered when assessing the impact of the power purchase agreement on the VIE’s gross margin include the pricing structure of the agreement and the cost of inputs and production, depending on the technology of the power plant.

For each variable interest, the Utility must also determine whether it has the power to direct the activities of the power plant that most directly impact the VIE’s economic performance. The Utility’s assessment of the activities that are economically significant to the VIE’s performance often include decision-making rights associated with designing the VIE, dispatch rights, operating and maintenance activities, and re-marketing activities of the power plant after the end of its power purchase agreement with the Utility.

The Utility held a variable interest in several entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, hydroelectric, and other technologies. Under each power purchase agreement, the Utility is obligated to purchase electricity or capacity, or both, from the VIEs. The Utility does not provide any other financial or other support to these VIEs and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 10 below.) The Utility does not have the power to direct the activities of the VIE that are most significant to the VIE’s economic performance. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at September 30, 2010, the Utility was not the primary beneficiary of any of these VIEs.

The Utility continues to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at September 30, 2010, as the Utility is the primary beneficiary of PERF. The Utility has a controlling financial interest in PERF as the Utility is exposed to PERF’s losses and returns through the Utility’s equity investment in PERF, and the Utility was involved in the design of PERF, an activity that is significant to PERF’s economic performance. The assets of PERF were $1.0 billion at September 30, 2010, and primarily consisted of assets related to energy recovery bonds, which is included in noncurrent regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $927 million at September 30, 2010, and consisted of energy recovery bonds, which is included in current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.) The assets of PERF are only available to settle the liabilities of PERF.

As of September 30, 2010, PG&E Corporation’s affiliates had entered into four tax equity agreements with privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation will provide payments of up to $300 million, and in return, receive the benefits of local rebates, federal investment tax credits, and a share of these entities’ customer payments. As of September 30, 2010, PG&E Corporation had made total payments of $100 million under these tax equity agreements, which was recorded in noncurrent assets – other in the Condensed Consolidated Balance Sheet. PG&E Corporation holds a variable interest in these entities as a result of these tax equity agreements. When determining whether PG&E

 

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Corporation was the primary beneficiary of the VIEs, PG&E Corporation evaluated which party had control over significant economic activities such as designing the entities, vendor selection, construction, customer selection, and remarketing activities at the end of the customer leases, among other activities. As these activities were under the control of these VIEs, PG&E Corporation was not the primary beneficiary at September 30, 2010. PG&E Corporation’s financial exposure for these arrangements is primarily limited to its lease payments and investment contributions to these entities.

Improving Disclosures about Fair Value Measurements

On January 1, 2010, PG&E Corporation and the Utility adopted an accounting standards update that requires disclosures regarding significant transfers in and out of fair value hierarchy levels, and fair value measurement inputs and valuation techniques. Furthermore, the update requires presentation of disaggregated activity within the reconciliation for fair value measurements using significant unobservable (Level 3) inputs, beginning for the first quarter of 2011. The adoption of the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

As a regulated entity, the Utility’s rates are designed to recover the costs of providing service. The Utility capitalizes and records, as a regulatory asset, 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, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory liabilities.

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities.

Regulatory Assets

Current Regulatory Assets

At September 30, 2010 and December 31, 2009, the Utility had current regulatory assets of $641 million and $427 million, respectively, consisting primarily of the current portion of price risk management regulatory assets. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 7 below for further discussion.) Current regulatory assets are included in prepaid expenses and other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

 

     Balance at  
(in millions)   

    September 30, 2010    

   

    December 31, 2009    

 

Pension benefits

     $ 1,490        $ 1,386   

Deferred income taxes

     1,158        1,027   

Energy recovery bonds

     833        1,124   

Utility retained generation

     684        737   

Price risk management

     599        346   

Environmental compliance costs

     393        408   

Unamortized loss, net of gain, on reacquired debt

     186        203   

Other

     359        291   
                

Total long-term regulatory assets

     $ 5,702        $ 5,522   
                

 

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The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 13 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.)

The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to customers. The CPUC requires the Utility to pass through certain tax benefits to customers by reducing rates, thereby ignoring the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover these regulatory assets over average plant depreciation lives of 1 to 45 years.

The regulatory asset for energy recovery bonds (“ERBs”) represents the refinancing of the regulatory asset provided for in the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). (See Note 4 below.) The regulatory asset is amortized over the life of the bonds, consistent with the period over which the related revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.

In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 14 years.

Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.)

The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation costs that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over the next 32 years. (See Note 10 below.)

The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next 16 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At September 30, 2010 and December 31, 2009, “other” primarily consisted of regulatory assets relating to ARO expenses for decommissioning of the Utility’s fossil facilities that are probable of future recovery through the ratemaking process; costs that the Utility incurred in terminating a 30-year power purchase agreement, which are being amortized and collected in rates through September 2014; and costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004. Additionally, at September 30, 2010, “other” included removal costs associated with the replacement of old electromechanical meters with SmartMeter™ devices.

In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return only on its retained generation regulatory assets and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At September 30, 2010 and December 31, 2009, the Utility had current regulatory liabilities of $81 million and $163 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers for over-collected electric transmission rates; amounts that the Utility expects to refund to electric transmission customers for their portion of settlements the Utility entered into with various electricity suppliers to resolve certain remaining Chapter 11 disputed claims; and the current portion of price risk management regulatory liabilities. Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms of one year or less. Current regulatory liabilities are included in current liabilities – other in the Condensed Consolidated Balance Sheets.

 

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Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

 

     Balance at  
(in millions)        September 30, 2010              December 31, 2009      

Cost of removal obligation

     $  3,182         $  2,933   

Public purpose programs

     599         508   

Recoveries in excess of ARO

     542         488   

Other

     123         196   
                 

Total long-term regulatory liabilities

     $  4,446         $  4,125   
                 

The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. The public purpose programs regulatory liabilities primarily consist of revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties, and under the Self-Generation program to promote distributed generation technologies installed on the customer’s side of the Utility meter that provide electricity and gas for all or a portion of that customer’s load.

The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.

“Other” at September 30, 2010 and December 31, 2009 primarily consisted of regulatory liabilities related to the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year, the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered into with Mirant Corporation, and insurance recoveries for hazardous substance remediation.

Regulatory Balancing Accounts

The Utility’s current regulatory balancing accounts represent the amounts expected to be received from or refunded to the Utility’s customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in other noncurrent assets – regulatory assets and noncurrent liabilities – regulatory liabilities in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, net

 

     Receivable (Payable)  
     Balance at  
(in millions)        September 30, 2010             December 31, 2009      

Utility generation

     $  223        $  355   

Public purpose programs

     158        83   

Gas fixed cost

     134        93   

Distribution revenue adjustment mechanism

     107        152   

Electric transmission

     (19     114   

Energy recovery bonds

     (93     (185

Other

     237        216   
                

Total regulatory balancing accounts, net

     $  747        $  828   
                

 

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The utility generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue adjustment mechanism balancing account is used to record and recover the authorized electric distribution revenue requirements and certain other electric distribution-related authorized costs. The Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation revenues.

The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirements and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs.

The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas distribution-related costs. The under-collected or over-collected position of this account is dependent on seasonality and volatility in gas volumes.

The electric transmission balancing accounts represent the difference between electric transmission wheeling revenues received by the Utility from the California Independent System Operator (“CAISO”) (on behalf of electric transmission customers) and refunds of those revenues to customers, the pass-through of transition access charge and credits for high voltage transmission, reliability service charges, and interest accrued on these account balances. In addition, these balancing accounts include the end-user customer refund balancing account, which is used to refund to customers over-collected electric transmission revenues.

The ERB balancing account records the benefits and costs associated with ERBs that are provided to, or received from, customers. This account ensures that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility after the second series of ERBs was issued.

At September 30, 2010 and December 31, 2009, “other” primarily consisted of the California Department of Water Resources (“DWR”) power charge collection balancing account, which ensures amounts collected from customers for DWR-delivered power are remitted to the DWR; balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeterTM advanced metering project; and balancing accounts that track recoverable hazardous substance clean-up costs incurred by the Utility.

NOTE 4: DEBT

PG&E Corporation

Convertible Subordinated Notes

PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s 9.50% Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding as of September 30, 2010.

Credit Facilities

At September 30, 2010, PG&E Corporation had $90 million of cash borrowings outstanding under its $187 million revolving credit facility which had an average interest rate of 0.59%.

Utility

Senior Notes

On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.

On September 15, 2010, the Utility issued $550 million principal amount of 3.5% Senior Notes due October 1, 2020.

 

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On October 12, 2010, the Utility issued $250 million principal amount of Floating Rate Senior Notes due October 11, 2011. The interest rate for the Floating Rate Senior Notes is equal to the three-month London Interbank Offered Rate (“LIBOR”) plus 0.58% and will reset quarterly beginning on January 11, 2011.

Pollution Control Bonds

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds Series 2010E due November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The Series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode. Interest is payable semi-annually in arrears on April 1 and October 1.

On September 20, 2010, the Utility repurchased $50 million principal amount of pollution control bonds Series 2008F and $45 million principal amount of pollution control bonds Series 2008G that were subject to mandatory tender on the same date. The bonds will be remarketed in a fixed or variable rate mode every 30 days until the bonds are reissued. The Utility, as bondholder, will be both the payer and the recipient of principal and interest payments on each remarketing day.

Credit Facilities and Short-Term Borrowings

On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. Of the total credit capacity, $500 million was used to replace the $500 million Floating Rate Senior Notes that matured on June 10, 2010. The aggregate facility of $750 million includes a $75 million commitment for swingline loans, or loans that are made available on a same-day basis and are repayable in full within 30 days. The Utility can, at any time, repay amounts outstanding in whole or in part. The credit agreement expires on February 26, 2012, unless extended for additional periods at the Utility’s request and at the sole discretion of each lender.

Borrowings under the credit agreement (other than swingline loans) will bear interest based, at the Utility’s election, on (1) LIBOR plus an applicable margin or (2) the base rate, which will equal the higher of the (i) administrative agent’s announced base rate, (ii) 0.5% above the federal funds rate, or (iii) the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. The Utility also will pay a facility fee on the total commitments of the lenders under the credit agreement. The applicable margin for LIBOR loans and the facility fee will be based on the Utility’s senior unsecured, non-credit enhanced debt ratings issued by Standard & Poor’s Ratings Services and Moody’s Investors Service. Facility fees are payable quarterly in arrears.

The credit agreement contains covenants that are substantially similar to the covenants contained in the Utility’s existing $1.9 billion credit facility, and are usual and customary for credit facilities of this type. Both credit facilities require that 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.

At September 30, 2010, the Utility had $400 million of cash borrowings outstanding under its $1.9 billion revolving credit facility which had an average interest rate of 0.45%, and no cash borrowings outstanding under its $750 million revolving credit facility. The $400 million borrowing was repaid on October 29, 2010.

At September 30, 2010, the Utility had $289 million of letters of credit outstanding under its $1.9 billion revolving credit facility.

The Utility’s revolving credit facilities also provide liquidity support for commercial paper offerings. At September 30, 2010, the Utility had $586 million of commercial paper outstanding at an average yield of 0.54%.

Energy Recovery Bonds

In 2005, PERF, a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component to be collected from the Utility’s electricity customers. The total amount of ERB principal outstanding was $927 million at September 30, 2010.

 

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While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the Utility. The assets of PERF, including the recovery property, are not available to creditors of the Utility or PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2010 were as follows:

 

         PG&E Corporation         Utility  
(in millions)    Total
Equity
    Total
  Shareholders’ Equity  
 

Balance at December 31, 2009

     $  10,585        $  11,185   

Net income

     859        868   

Common stock issued

     400        -   

Share-based compensation expense

     28        -   

Common stock dividends declared

     (527     (537

Preferred stock dividend requirement

     -        (10

Preferred stock dividend requirement of subsidiary

     (10     -   

Tax benefit from employee stock plans

     4        3   

Other comprehensive loss

     (64     (63

Equity contribution

     -        170   
                

Balance at September 30, 2010

     $  11,275        $  11,616   
                

Between June 23 and June 29, 2010, PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s Convertible Subordinated Notes. In addition, for the nine months ended September 30, 2010, PG&E Corporation issued 3,766,678 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan.

For the nine months ended September 30, 2010, PG&E Corporation contributed equity of $170 million to the Utility in order to maintain the 52% common equity ratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

Comprehensive Income

Comprehensive income consists of net income and other comprehensive income, which includes certain changes in equity that are excluded from net income. Specifically, adjustments for employee benefit plans, net of tax, are recorded in other comprehensive income.

 

     PG&E Corporation  
           Three Months Ended      
September 30,
           Nine Months Ended      
September 30,
 
(in millions)    2010      2009      2010     2009  

Net income

     $  261         $  321         $  859        $  957   

Employee benefit plan adjustment, net of tax (1)

     8         7         (64     21   
                                  

Comprehensive income

     $  269         $  328         $  795        $  978   
                                  

 

(1) These balances are net of income tax expense of $7 million and $5 million for the three months ended September 30, 2010 and 2009, respectively. For the nine months ended September 30, 2010, the income tax benefit was $42 million and for the nine months ended September 30, 2009, the income tax expense was $14 million.

    

 

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     Utility  
           Three Months Ended      
September 30,
           Nine Months Ended      
September 30,
 
(in millions)    2010      2009      2010     2009  

Net income

   $   265       $   353       $   868      $   983   

Employee benefit plan adjustment, net of tax (1)

     9         7         (63     21   
                                  

Comprehensive income

   $   274       $   360       $   805      $   1,004   
                                  

 

(1) These balances are net of income tax expense of $7 million and $5 million for the three months ended September 30, 2010 and 2009, respectively. For the nine months ended September 30, 2010, the income tax benefit was $42 million and for the nine months ended September 30, 2009, the income tax expense was $14 million.

    

Dividends

PG&E Corporation

During the nine months ended September 30, 2010, PG&E Corporation paid common stock dividends totaling $492 million, net of $12 million that was reinvested in additional shares of common stock by participants in the Dividend Reinvestment and Stock Purchase Plan. On September 15, 2010, the Board of Directors of PG&E Corporation declared dividends of $0.455 per share, totaling $180 million, which were paid on October 15, 2010 to shareholders on record as of September 30, 2010.

Utility

During the nine months ended September 30, 2010, the Utility paid common stock dividends totaling $537 million to PG&E Corporation.

During the nine months ended September 30, 2010, the Utility paid dividends totaling $11 million to holders of its outstanding series of preferred stock. On September 15, 2010, the Board of Directors of the Utility declared dividends totaling $3 million on its outstanding series of preferred stock, payable on November 15, 2010, to shareholders on record as of October 29, 2010.

NOTE 6: EARNINGS PER SHARE

Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities. PG&E Corporation’s Convertible Subordinated Notes met the criteria of participating securities as the holders were entitled to receive pass-through dividends on a 1:1 basis with shares of common stock.

As of September 30, 2010, all of PG&E Corporation’s Convertible Subordinated Notes have been converted into common stock. (See Note 4 above for further discussion.)

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic EPS:

 

    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
(in millions, except per share amounts)   2010     2009     2010     2009  

Basic

       

Income available for common shareholders

  $   258      $   318      $   849      $   947   

Less: distributed earnings to common shareholders

    179        156        527        465   
                               

Undistributed earnings

  $   79      $   162      $   322      $   482   
                               

Allocation of undistributed earnings to common shareholders

       

Distributed earnings to common shareholders

  $   179      $   156      $   527      $   465   

Undistributed earnings allocated to common shareholders

    79        155        313        461   
                               

Total common shareholders earnings

  $   258      $   311      $   840      $   926   
                               

Weighted average common shares outstanding, basic

    390        370        378        367   

Convertible subordinated notes

    -        16        11        17   
                               

Weighted average common shares outstanding and participating securities

    390        386        389        384   
                               

Net earnings per common share, basic

       

 

Distributed earnings, basic (1)

  $   0.46      $   0.42      $   1.39      $   1.27   

Undistributed earnings, basic

    0.20        0.42        0.83        1.26   
                               

Total

  $   0.66      $   0.84      $   2.22      $   2.53   
                               

 

(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding.

   

 

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In calculating diluted EPS, PG&E Corporation applies the “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for three and nine months ended September 30, 2010 and 2009:

 

       Three Months Ended  
September 30,
       Nine Months Ended  
September 30,
 
(in millions, except per share amounts)    2010      2009      2010      2009  

Diluted

           

Income available for common shareholders

   $   258       $   318       $   849       $   947   

Add earnings impact of assumed conversion of participating securities:

           

Interest expense on convertible subordinated notes, net of tax

     -         4         8         12   

Unrealized loss on embedded derivative, net of tax

     -         -         -         2   
                                   

Income available for common shareholders and assumed conversion

   $   258       $   322       $   857       $   961   
                                   

Weighted average common shares outstanding, basic

     390         370         378         367   

Add incremental shares from assumed conversions:

           

Convertible subordinated notes

     -         16         11         17   

Employee share-based compensation

     2         2         2         2   
                                   

Weighted average common shares outstanding, diluted

     392         388         391         386   
                                   

Total earnings per common share, diluted

   $   0.66       $   0.83       $   2.19       $   2.49   
                                   

For each of the periods presented above, the calculation of outstanding shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility faces market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers. The CPUC and the FERC allow the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity and natural gas. As these costs are passed through to customers in rates, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of electricity and natural gas.

The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:

 

   

forward contracts that commit the Utility to purchase a commodity in the future;

 

   

swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity;

 

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option contracts that provide the Utility with the right to buy a commodity at a predetermined price; and

 

   

futures contracts that are exchange-traded contracts committing the Utility to make a cash settlement at a specified price and future date.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.

Commodity-Related Price Risk

Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates, all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated with the change in fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities. The amount of electricity the Utility needs to meet the demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s customers is subject to change for a number of reasons, including:

 

   

periodic expirations or terminations of existing electricity purchase contracts, including the DWR’s contracts;

 

   

the execution of new electricity purchase contracts;

 

   

fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;

 

   

changes in the Utility’s customers’ electricity demands due to customer and economic growth or decline, weather, implementation of new energy efficiency and demand response programs, direct access, and community choice aggregation;

 

   

the acquisition, retirement, or closure of generation facilities; and

 

   

changes in market prices that make it more economical to purchase power in the market rather than use the Utility’s existing resources.

The Utility enters into third-party power purchase agreements to ensure sufficient electricity to meet customer needs. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the volatility in customer rates, the Utility has entered into financial swap contracts to effectively fix the price of future purchases and reduce the cash flow variability associated with fluctuating electricity prices under some of those power purchase agreements. These financial swaps are considered derivative instruments.

 

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Electric Transmission Congestion Revenue Rights

The CAISO controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of transmission congestion. The congestion revenue rights (“CRRs”) allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The CRRs held by the Utility are considered derivative instruments.

Natural Gas Procurement (Electric Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the volatility in customer rates, the Utility purchases financial instruments such as futures, swaps, and options to reduce future cash flow variability associated with fluctuating natural gas prices. These financial instruments are considered derivative instruments.

Natural Gas Procurement (Small Commercial and Residential Customers)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “core,” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot markets to balance such seasonal supply and demand. The Utility purchases financial instruments such as swaps and options as part of its core winter hedging program in order to manage customer exposure to high gas prices during peak winter months. These financial instruments are considered derivative instruments.

Volume of Derivative Activity

At September 30, 2010, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts were as follows:

 

          Contract Volume (1)  

    Underlying    

Product

  

    Instruments    

       Less Than 1    
Year
     Greater Than
1 Year But
Less Than 3
Years
     Greater Than
3 Years But
Less Than 5
Years
     Greater Than 5
Years (2)
 

Natural Gas (3)

(MMBtus (4))

   Forwards, Futures, and Swaps      393,102,663         266,868,040         8,970,000         -   
   Options      218,112,080         172,925,000         10,800,000         -   
Electricity (Megawatt-hours)    Forwards, Futures, and Swaps      5,242,021         7,664,859         4,060,087         4,974,816   
   Options      1,211,030         -         239,028         421,464   
   Congestion Revenue Rights      53,171,874         69,986,929         67,512,934         93,842,817   

 

(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.

  

(2) Derivatives in this category expire between 2015 and 2022.   
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.   
(4) Million British Thermal Units.   

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral associated with derivative positions.

 

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At September 30, 2010, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

 

(in millions)   Gross
Derivative
    Balance 
(1)     
        Netting (2)         Cash
    Collateral
 
(2)    
    Total
    Derivative    
Balances
 
Commodity Risk (PG&E Corporation and Utility)   
Current assets – prepaid expenses
and other
    $  19                $  (11     $  52        $  60   
Other noncurrent assets – other     59        (42     64        81   
Current liabilities – other     (411     11        177        (223
Noncurrent liabilities – other     (641     42        239        (360
                               
Total commodity risk             $  (974     $ -                $  532                $  (442
                               

 

(1) See Note 8 below for a discussion of the valuation techniques used to calculate the fair value of these instruments.

  

(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.   

At December 31, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

 

(in millions)   Gross
    Derivative    
Balance
        Netting (1)         Cash
    Collateral
 
(1)    
    Total
    Derivative    
Balances
 
Commodity Risk (PG&E Corporation and Utility)   
Current assets – prepaid expenses
and other
    $  76                $  (12     $  77        $  141   
Other noncurrent assets – other     64        (44     13        33   
Current liabilities – other     (231     12        54        (165
Noncurrent liabilities – other     (390     44        44        (302
                               
Total commodity risk     $  (481     $ -        $  188        $  (293
                               
Other Risk Instruments (2) (PG&E Corporation Only)   
Current liabilities – other     $  (13     $ -        $ -        $  (13
                               
Total derivatives             $  (494     $ -                $  188                $  (306
                               

 

(1) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.

  

(2) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes, which were fully converted as of September 30, 2010.    

Gains and losses recorded on PG&E Corporation’s and the Utility’s derivative instruments were as follows:

 

     Commodity Risk
(PG&E Corporation and Utility)
 
     Three months  ended
September 30,
    Nine months  ended
September 30,
 
(in millions)    2010     2009     2010     2009  
Unrealized gain/(loss) - regulatory assets and liabilities (1)      $  (222             $  192        $  (493     $  32   
Realized gain/(loss) - cost of electricity (2)      (154     (133     (435     (558
Realized gain/(loss) - cost of natural gas (2)      (6     (1     (50     (30
                                
Total commodity risk instruments              $  (382     $  58                $  (978             $  (556
                                

 

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.

(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

   

   

Cash inflows and outflows associated with the settlement of all derivative instruments are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

 

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The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

At September 30, 2010, the additional cash collateral the Utility would be required to post if its credit risk-related contingent features were triggered was as follows:

 

(in millions)

  
Derivatives in a liability position with credit-risk-related contingencies that are not fully collateralized      $  (652
Related derivatives in an asset position      1   
Collateral posting in the normal course of business related to these derivatives      74   
        
Net position of derivative contracts/additional collateral posting requirements (1)              $  (577
        

 

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.

   

NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:

Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2—Include other inputs that are directly or indirectly observable in the marketplace.

Level 3—Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (money market investments and assets held in rabbi trusts are held by PG&E Corporation and not the Utility):

 

Fair Value Measurements at September 30, 2010   
(in millions)    Level 1      Level 2      Level 3      Total  

Assets:

           

Money market investments

     $  227         $ -         $ -         $  227   
                                   

Nuclear decommissioning trusts

           

U.S. equity securities (1)

     796         6         -         802   

Non-U.S. equity securities

     328         -         -         328   

U.S. government and agency securities

     757         48         -         805   

Municipal securities

     -         107         -         107   

Other fixed income securities

     -         80         -         80   
                                   

Total nuclear decommissioning trusts (2)

     1,881         241         -         2,122   
                                   

Price risk management instruments

           

Electric (3)

     83         -         -         83   
                                   

Total price risk management instruments

     83         -         -         83   
                                   

Rabbi trusts

           

Equity securities

     23         -         -         23   

Life insurance contracts

     -         65         -         65   
                                   

Total rabbi trusts

     23         65         -         88   
                                   

Long-term disability trust

           

U.S. equity securities (1)

     7         23         -         30   

Corporate debt securities (1)

     -         132         -         132   
                                   

Total long-term disability trust

     7         155         -         162   
                                   

Total assets

         $  2,221               $  461         $ -             $  2,682   
                                   

Liabilities:

           

Price risk management instruments

           

Electric (4)

     $ -         $  30         $  436         $  466   

Gas (5)

     -         2         57         59   
                                   

Total price risk management instruments

     -         32         493         525   
                                   

Total liabilities

     $ -         $  32               $  493         $  525   
                                   

 

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  (1)  

Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.

  (2)  

Excludes deferred taxes on appreciation of investment value.

  (3)  

Balances include the impact of netting adjustments of $365 million to Level 1. Includes natural gas for electric portfolio.

  (4)  

Balances include the impact of netting adjustments of $62 million to Level 2 and $52 million to Level 3. Includes natural gas for electric portfolio.

  (5)  

Balances include the impact of netting adjustments of $53 million to Level 3. Includes natural gas for core customers.

 

Fair Value Measurements at December 31, 2009   
(in millions)    Level 1      Level 2      Level 3      Total  

Assets:

           

Money market investments

     $  189         $ -         $  4         $  193   
                                   

Nuclear decommissioning trusts

           

U.S. equity securities (1)

     762         6         -         768   

Non-U.S. equity securities

     344         -         -         344   

U.S. government and agency securities

     653         51         -         704   

Municipal securities

     1         89         -         90   

Other fixed income securities

     -         108         -         108   
                                   

Total nuclear decommissioning trusts (2)

     1,760         254         -         2,014   
                                   

Rabbi trusts

           

Equity securities

     21         -         -         21   

Life insurance contracts

     60         -         -         60   
                                   

Total rabbi trusts

     81         -         -         81   
                                   

Long-term disability trust

           

U.S. equity securities (1)

     52         23         -         75   

Corporate debt securities (1)

     -         113         -         113   
                                   

Total long-term disability trust

     52         136         -         188   
                                   

Total assets

         $  2,082               $  390         $  4             $  2,476   
                                   

Liabilities:

           

Dividend participation rights (3)

     $ -         $ -         $  12         $  12   
                                   

Price risk management instruments

           

Electric (4)

     2         73         157         232   

Gas (5)

     1         -         60         61   
                                   

Total price risk management instruments

     3         73         217         293   
                                   

Other liabilities

     -         -         3         3   
                                   

Total liabilities

     $  3         $  73               $  232         $  308   
                                   

 

(1) Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.

(2) Excludes deferred taxes on appreciation of investment value.

 

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(3) The dividend participation rights were associated with PG&E Corporation’s Convertible Subordinated Notes which were no longer outstanding as of September 30, 2010.

(4) Balances include the impact of netting adjustments of $108 million to Level 1, $48 million to Level 2, and $19 million to Level 3. Includes natural gas for electric portfolio.

(5) Balances include the impact of netting adjustments of $13 million to Level 3. Includes natural gas for core customers.

Trust Assets

The assets held by the nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust are comprised primarily of equity securities and debt securities. Equity securities primarily include investments in common stock and commingled funds comprised of equity across multiple industry sectors in the U.S. and other regions of the world. Equity securities are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. A market based valuation approach is generally used to estimate the fair value of debt securities classified as Level 2 instruments in the tables above. Under a market approach, fair values are determined based on evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. No trust assets were measured at fair value using significant unobservable inputs (Level 3) at September 30, 2010.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as futures, forwards, swaps, options, and CRRs that are either exchange-traded or over-the-counter traded. Some futures, forwards, and swaps are valued using observable market prices for the underlying commodity or an identical instrument and are classified as Level 1 or Level 2 instruments. Other instruments are valued using unobservable inputs and are considered Level 3 instruments.

Certain exchange-traded contracts are classified as Level 2 measurements because the contract term extends to a period at which the market is no longer considered active; however, the prices are still observable. This determination is based on an analysis of the relevant characteristics of the market such as trading hours and volumes, frequency of available quotes, and open interest. In addition, a number of over -the -counter contracts are valued using unadjusted exchange prices of similar instruments in active markets. Such instruments are classified as Level 2 measurements as they are not exchange-traded instruments.

All energy-related options are classified as Level 3 and are valued using a standard option pricing model with various assumptions, including forward prices for the underlying commodity, time value at a risk free rate, and volatility. Some of these assumptions are derived from internal models as they are unobservable. The Utility’s demand response contracts with third-party aggregators of retail electricity customers contain a call option entitling the Utility to require that the aggregator reduce electric usage by the aggregator’s customers at times of peak energy demand or in response to a CAISO alert or other emergency.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead markets. CRRs are valued based on the forecasted settlement price at the delivery points underlying the CRR using internal models. The Utility also uses the most current annual auction prices published by the CAISO to calibrate internal models. Limited market data is available between auction dates; therefore, CRRs are classified as Level 3 measurements.

The Utility enters into power purchase agreements for the purchase of electricity to meet the demand of its customers. (See Note 7 above.) The Utility uses internal models to determine the fair value of these power purchase agreements. These power purchase agreements include contract terms that extend beyond a period for which an active market exists. The Utility utilizes market data for the underlying commodity to the extent that it is available in determining the fair value. For periods where market data is not available, the Utility extrapolates forward prices based on historical data. These power purchase agreements are considered Level 3 instruments as the determination of their fair value includes the use of unobservable forward prices.

 

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Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no significant transfers between levels for the nine month period ended September 30, 2010. The following tables present reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis, using significant unobservable inputs (Level 3), for the three and nine month periods ended September 30, 2010 and 2009:

 

    PG&E Corporation
Only
    PG&E Corporation and the Utility        
(in millions)   Money
Market
    Dividend
Participation
Rights
    Price Risk
Management
Instruments
    Nuclear
Decommissioning
Trusts

Equity
Securities 
(1)
    Long-
Term
Disability
Equity
Securities
    Long-Term
Disability
Corp. Debt
Securities
    Other
Liabilities
    Total  
Asset (liability) balance as of June 30, 2010     $ -        $ -        $  (400     $ -        $ -        $ -            $  (2         $  (402
                                                               
Realized and unrealized gains (losses):                

Included in earnings

    -        -        -        -        -        -        -        -   

Included in regulatory assets and liabilities or balancing accounts

    -        -        (93     -        -        -        2        (91
Purchases, issuances, and settlements     -        -        -        -        -        -        -        -   
Transfers into Level 3     -        -        -        -        -        -        -        -   
Transfers out of Level 3     -        -        -        -        -        -        -        -   
                                                               
Asset (liability) balance as of September 30, 2010             $ -                $ -            $  (493             $ -                $ -                $ -        $ -        $  (493
                                                               

 

  (1) Excludes deferred taxes on appreciation of investment value.

 

  

    PG&E Corporation
Only
    PG&E Corporation and the Utility        
(in millions)   Money
Market
    Dividend
Participation
Rights
    Price Risk
Management
Instruments
    Nuclear
Decommissioning
Trusts

Equity
Securities (1)
    Long-
Term
Disability
Equity
Securities
    Long-Term
Disability
Corp. Debt
Securities
    Other
Liabilities
    Total  
Asset (liability) balance as of June 30, 2009     $  5        $  (27     $  (189     $  5        $  57        $  24        $  (3     $  (128
                                                               
Realized and unrealized gains (losses):                

Included in earnings

    -        -        -        -        8        2        -        10   

Included in regulatory assets and liabilities or balancing accounts

    -        -        32        1        -        -        (1     32   
Purchases, issuances, and settlements     -        7        -        -        (45     75        -        37   
Transfers into Level 3     -        -        -        -        -        -        -        -   
Transfers out of Level 3     -        -        -        -        -        -        -        -   
                                                               
Asset (liability) balance as of September 30, 2009     $  5        $  (20     $  (157     $  6        $  20        $  101        $  (4     $  (49
                                                               

 

  (1) Excludes deferred taxes on appreciation of investment value.

  

 

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    PG&E  Corporation
Only
    PG&E Corporation and the Utility        
(in millions)   Money
Market
    Dividend
Participation
Rights
    Price Risk
Management
Instruments
    Nuclear
Decommissioning
Trusts

Equity
Securities (1)
    Long-
Term
Disability
Equity
Securities
    Long-Term
Disability
Corp. Debt
Securities
    Other
Liabilities
    Total  
Asset (liability) balance as of December 31, 2009             $  4                $  (12           $  (217             $ -                $ -                $ -                $  (3         $  (228
                                                               
Realized and unrealized gains (losses):                

Included in earnings

    -        -        -        -        -        -        -        -   

Included in regulatory assets and liabilities or balancing accounts

    -        -        (276     -        -        -        3        (273
Purchases, issuances, and settlements     (4     12        -        -        -        -        -        8   
Transfers into Level 3     -        -        -        -        -        -        -        -   
Transfers out of Level 3     -        -        -        -        -        -        -        -   
                                                               
Asset (liability) balance as of September 30, 2010     $ -        $ -        $  (493     $ -        $ -        $ -        $ -        $  (493
                                                               

 

  (1) Excludes deferred taxes on appreciation of investment value.

 

  

    PG&E Corporation
Only
    PG&E Corporation and the Utility        
(in millions)   Money
Market
    Dividend
Participation
Rights
    Price Risk
Management
Instruments
    Nuclear
Decommissioning
Trusts

Equity
Securities (1)
    Long-
Term
Disability
Equity
Securities
    Long-Term
Disability
Corp. Debt
Securities
    Other
Liabilities
    Total  
Asset (liability) balance as of December 31, 2008     $  12        $  (42     $  (156     $  5        $  54        $  24        $  (2     $  (105
                                                               
Realized and unrealized gains (losses):                

Included in earnings

    -        1        -        -        11        3        -        15   

Included in regulatory assets and liabilities or balancing accounts

    -        -        (1     1        -        -        (2     (2
Purchases, issuances, and settlements     (7     21        -        -        (45     74        -        43   
Transfers into Level 3     -        -        -        -        -        -        -        -   
Transfers out of Level 3     -        -        -        -        -        -        -        -   
                                                               
Asset (liability) balance as of September 30, 2009     $  5        $  (20     $  (157     $  6        $  20        $  101        $  (4     $  (49
                                                               

 

(1) Excludes deferred taxes on appreciation of investment value.

  

 

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Financial Instruments

The Utility values its long-term debt using quoted market prices that are readily available. The carrying amount and fair value of PG&E Corporation’s and the Utility’s financial instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

 

    At September 30,     At December 31,  
    2010     2009  
(in millions)     Carrying  
Amount
    Fair
  Value (2)  
      Carrying  
Amount
    Fair
  Value
(2)  
 

Debt (Note 4):

       

PG&E Corporation (1)

    $  349        $  394        $  597        $  1,096   

Utility

    9,956        11,226        9,240        9,824   

Energy recovery bonds (Note 4)

    927        973        1,213        1,269   

 

(1) PG&E Corporation Convertible Subordinated Notes were no longer outstanding as of September 30, 2010.

  

(2) Fair values are determined using readily available quoted market prices.   

Nuclear Decommissioning Trust Investments

The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the day-to-day investing activities of the trusts are managed by external investment managers, the Utility is unable to assert that it has the intent and ability to hold investments to maturity. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. (See Note 3 above for further discussion.)

The following table summarizes unrealized gains and losses related to available-for-sale investments held in the Utility’s nuclear decommissioning trusts:

 

      Amortized  
Cost
    Total
  Unrealized  
Gains
    Total
  Unrealized  
Losses
      Estimated (1)  
Fair Value
 

(in millions)

As of September 30, 2010

       
U.S. equity securities     $  359        $  446        $  (3     $  802   
Non-U.S. equity securities     178        151        (1     328   
U.S. government and agency securities     710        95        -        805   
Municipal securities     104        4        (1     107   
Other fixed income securities     77        3        -        80   
                               

Total

            $  1,428                $  699                $  (5             $  2,122   
                               

As of December 31, 2009

       
U.S. equity securities     $  344        $  425        $  (1     $  768   
Non-U.S. equity securities     182        163        (1     344   
U.S. government and agency securities     656        52        (4     704   
Municipal securities     89        1        -        90   
Other fixed income securities     108        2        (2     108   
                               

Total

    $  1,379        $  643        $  (8     $  2,014   
                               

 

(1) Excludes taxes on appreciation of investment value.

  

The following table summarizes the estimated fair value of debt securities classified by the contractual maturity date of the security:

 

         At September 30,      
     2010  
(in millions)       

Less than 1 year

     $  64   

1–5 years

     447   

5–10 years

     238   

More than 10 years

     242   
        

Total maturities of debt securities

             $  991   
        

 

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The following table provides a summary of activity for available-for-sale securities:

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  
(in millions)                         

Proceeds received from sales of securities

     $  277        $  223        $  962        $  1,177   
Gross realized gains on sales of securities held as available-for-sale      4        12        26        24   
Gross realized losses on sales of securities held as available-for-sale      (2     (2     (8     (52

In general, investments held in the nuclear decommissioning trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. It is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ fair value.

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. At September 30, 2010 and December 31, 2009, the Utility held $512 million and $515 million in escrow, respectively, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

While the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The proceeds from these settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, will continue to be refunded to customers in rates. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

The following table presents the changes in the remaining disputed claims liability and interest accrued from December 31, 2009 to September 30, 2010:

 

(in millions)       

Balance at December 31, 2009

     $  946   

Interest accrued

     23   

Less: supplier settlements

     (41
        

Balance at September 30, 2010

             $  928   
        

At September 30, 2010, the Utility’s net disputed claims liability was $928 million, consisting of $746 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $676 million (classified on the Condensed Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within accounts receivable – other).

Interest accrues on the liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any excess net interest collected from customers. The amount of any interest that the Utility may be required to pay will depend on the final amounts to be paid by the Utility with respect to the disputed claims and when such interest is paid.

 

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PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be resolved, and the amount of any potential refunds that the Utility may receive or the amount of disputed claims, including interest that the Utility will be required to pay.

NOTE 10: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility’s operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, environmental compliance and remediation, tax matters, and legal matters.

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase.

At September 30, 2010, the undiscounted future expected power purchase agreement payments were as follows:

 

(in millions)       

2010

     $  600   

2011

     2,424   

2012

     2,483   

2013

     2,958   

2014

     3,188   

Thereafter

     54,375   
        

Total

             $  66,028   
        

Payments made by the Utility under power purchase agreements amounted to $1,791 million and $1,809 million for the nine months ended September 30, 2010 and September 30, 2009, respectively. The amounts above do not include payments related to the DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities (“QF”s) are treated as capital leases. The following table shows the future fixed capacity payments due under the QF contracts that are treated as capital leases. (These amounts are also included in the table above.) The fixed capacity payments are discounted to their present value using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown as the amount representing interest.

 

(in millions)       

2010

     $  11   

2011

     50   

2012

     50   

2013

     50   

2014

     42   

Thereafter

     162   
        

Total fixed capacity payments

     365   

Amount representing interest

     77   
        

Present value of fixed capacity payments

             $  288   
        

Minimum lease payments associated with the lease obligation are included in cost of electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. The timing of the Utility’s recognition of the lease expense conforms to the ratemaking treatment for the Utility’s recovery of the cost of electricity. The QF contracts that are treated as capital leases expire between April 2014 and September 2021.

 

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At September 30, 2010 and December 31, 2009, PG&E Corporation and the Utility had, respectively, $33 million and $32 million included in current liabilities – other, and $255 million and $282 million included in noncurrent liabilities – other, respectively representing the present value of the fixed capacity payments due under these contracts recorded on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The corresponding assets at September 30, 2010 and December 31, 2009 of $288 million and $314 million, including amortization of $120 million and $94 million, respectively, are included in property, plant, and equipment on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation to transport natural gas from the points at which the Utility takes delivery (typically in Canada and the southwestern United States supply basins) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for gas storage services in its market area in order to better meet winter peak customer loads.

The Utility also purchases natural gas to fuel its owned-generation facilities. Contract terms typically range in length from one to three years.

At September 30, 2010, the Utility’s undiscounted obligations for natural gas purchases, gas transportation services, and gas storage were as follows:

 

(in millions)       

2010

     $  301   

2011

     550   

2012

     84   

2013

     68   

2014

     49   

Thereafter

     115   
        

Total (1)

       $  1,167   
        

 

  

(1) Total does not include Ruby Pipeline reservation cost commitment described below.

  

Payments for natural gas purchases, gas transportation services, and gas storage amounted to $1,183 million and $959 million for the nine months ended September 30, 2010 and September 30, 2009, respectively.

Ruby Pipeline

On April 5, 2010, the FERC issued an order authorizing El Paso Corporation to construct, operate, and maintain its proposed 675-mile gas transmission pipeline (“Ruby Pipeline”), which would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border and have an initial capacity of 1.5 billion cubic feet per day. Construction began in July 2010, and the facilities are scheduled to be in service in the spring of 2011. The Utility has contracted for firm service rights on the Ruby Pipeline of approximately 0.4 billion cubic feet per day beginning in 2011. Under these agreements the Utility will have a cumulative commitment of $1.4 billion over 15 years.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 14 years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2014, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2011. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

 

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At September 30, 2010, the undiscounted obligations under nuclear fuel agreements were as follows:

 

(in millions)       

2010

     $  15   

2011

     82   

2012

     69   

2013

     107   

2014

     135   

Thereafter

     1,215   
        

Total

       $  1,623   
        

Payments for nuclear fuel amounted to $140 million and $67 million for the nine months ended September 30, 2010 and September 30, 2009, respectively.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”), that were issued to the purchaser of an NEGT subsidiary company in 2000. PG&E Corporation’s primary remaining exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the guarantee. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.

Utility

Energy Efficiency Programs and Incentive Ratemaking

The CPUC has established a ratemaking mechanism to provide incentives to the California investor-owned utilities to meet the CPUC’s energy savings goals through implementation of the utilities’ 2006-2008 energy efficiency programs. In accordance with this mechanism, the CPUC has awarded the Utility interim incentive revenues totaling $75 million through December 31, 2009 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. The amount of additional incentive revenues the Utility may earn, if any, is subject to the CPUC’s completion of the final true-up process.

On September 28, 2010, a proposed decision was issued by the assigned CPUC administrative law judge recommending that no additional incentive revenues be awarded to the Utility. Also, on September 28, 2010, an alternate proposed decision was issued by a CPUC commissioner recommending that the Utility be awarded additional incentive revenues of $40 million, an amount equal to the amounts that had been held back from the interim awards.

The CPUC is scheduled to issue a final decision to complete the true-up process by the end of 2010. PG&E Corporation and the Utility are unable to predict the amount, if any, of additional incentive revenues that the Utility will receive for the 2006-2008 program cycle.

Spent Nuclear Fuel Storage Proceedings

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”) and its retired nuclear facility at Humboldt Bay.

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the Nuclear Regulatory Commission (“NRC”) to build an on-site dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. The construction of the dry cask storage facility is complete. During 2009, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit has set November 4, 2010 as the date for oral argument.

 

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As a result of the DOE’s failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010.

The Utility incurred at least $188 million between 2005 and 2009 to build on-site storage facilities. On August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred to build on-site storage facilities between 2005 and 2009. Amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired nuclear generation facility at Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $40 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of terrorism cause damages covered under any of the nuclear insurance policies issued by NEIL to any NEIL member, the maximum recovery under all those nuclear insurance policies may not exceed NEIL’s policy limit of $3.2 billion within a 12-month period plus any additional amounts recovered by NEIL for these losses from reinsurance. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. For damages caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss caused by these certified acts of terrorism. The $3.2 billion amount would not be shared as is described above for damages caused by acts of terrorism that have not been certified.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $235 million per nuclear incident under this program, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. Such claims are covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by separate supplier’s and transporter’s (“S&T”) insurance policies. The Utility has an S&T policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident. The Utility could incur losses that are either not covered by insurance or exceed the amount of insurance available.

In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability insurance.

Legal 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 named as parties in a number of claims and lawsuits.

PG&E Corporation and the Utility record a provision for a liability when it is both probable that a liability 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 costs and record a liability based on the lower end of the range, 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, 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 such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

 

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Explosion and Fires in San Bruno, California

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility ruptured in a residential area located in the City of San Bruno, California (the “San Bruno Accident”). The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The cause of the rupture remains unknown. The California Governor’s office declared a state of emergency in San Mateo County, where San Bruno is located, to mobilize state emergency services and resources.

On September 10, 2010, the National Transportation Safety Board (“NTSB”) began an investigation of the San Bruno Accident. In addition to reviewing the physical evidence collected from the site and conducting further metallurgical tests, the NTSB is expected to examine, among other aspects, the performance, qualifications and experience of the relevant employees; and the emergency preparedness and response of the Utility and of public emergency personnel and other first responders. While the NTSB investigation is pending the Utility generally is prohibited from disclosing information related to the investigation without approval from the NTSB.

On September 12, 2010, the Utility announced that it would provide up to $100 million to assist affected residents and the City of San Bruno, California, to pay for (1) affected residents’ immediate expenses not otherwise covered by insurance, including temporary living expenses, insurance deductibles and immediate medical expenses; (2) property replacement, repair or purchase (in the case of homes destroyed or substantially damaged) and (3) work needed to rebuild or replace public property damaged or destroyed in the San Bruno Accident, as well as costs incurred by emergency responders and government services to respond to the fire. These payments are not intended to satisfy any potential claims for personal injury or wrongful death, which will be addressed separately.

On October 13, 2010, the NTSB released a preliminary report. The report included a timeline of events before and after the gas line rupture, but did not identify the cause of the rupture. The NTSB also identified which tests had been performed on the section of ruptured pipeline and which tests were yet to be completed. The NTSB stated that additional factual updates will be provided and distributed via media advisory as investigative information is developed.

The CPUC also has initiated an investigation of the San Bruno Accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory. The CPUC has appointed an independent review panel to gather facts, review these facts, make a technical assessment of the San Bruno Accident and its root cause, and make recommendations for action by the CPUC to ensure such an accident is not repeated. These recommendations may include changes to design, construction, operation and maintenance of natural gas facilities, management practices at the Utility in the areas of pipeline integrity and public safety, regulatory and statutory changes, and other recommendations deemed appropriate, including whether there are systemic management problems at the Utility and whether greater resources are needed to achieve fundamental infrastructure improvement. The Utility is committed to working with the NTSB, the CPUC, and the independent panel to determine the cause of the rupture.

Various lawsuits, including two class action lawsuits, have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. The class action lawsuits allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief, including a demand that the $100 million the Utility announced would be available for assistance (discussed above) be placed under court supervision. In addition, some of these lawsuits seek recovery for wrongful death, property damage, and personal injury. Several other residents also have submitted damage claims to the Utility.

As of September 30, 2010, the Utility has recorded a provision of $220 million for estimated third-party claims related to the San Bruno Accident, including personal injury and property damage claims, damage to infrastructure, emergency response, and other damage claims. The provision is included in operating and maintenance expense in PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income, and other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for the period ended September 30, 2010. The Utility estimates that it may incur as much as $400 million for third-party claims depending on the final outcome of the NTSB and CPUC investigations and the number, nature, and value of third-party claims. This range of estimates incorporates up to $100 million that the Utility has stated it would provide the affected residents and the City of San Bruno. The process for estimating costs associated with third-party claims relating to the San Bruno Accident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including information resulting from the NTSB and CPUC investigations, management’s estimates and assumptions regarding the financial impact of the San Bruno Accident may change.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for third-party claims relating to the San Bruno Accident will ultimately be covered by this insurance, no amounts for insurance recoveries have been recorded as of September 30, 2010. PG&E Corporation and the Utility are unable to predict the amount and timing of insurance recoveries.

 

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Other Legal Matters

The accrued liability for legal matters (other than those related to the San Bruno Accident as discussed above) is included in PG&E Corporation’s and the Utility’s current liabilities – other in the Condensed Consolidated Balance Sheets and totaled $46 million at September 30, 2010 and $57 million at December 31, 2009. PG&E Corporation and the Utility are not able to predict the ultimate outcome of these various legal matters, but after consideration of these accruals, PG&E Corporation and the Utility do not believe that losses associated with these matters would have a material adverse impact on their financial condition or results of operations.

Environmental Matters

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

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. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts.

The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.

The Utility had an undiscounted gross environmental remediation liability of $608 million at September 30, 2010 and $586 million at December 31, 2009. The following table presents the changes in the environmental remediation liability from December 31, 2009:

 

  (in millions)       

  Balance at December 31, 2009

     $ 586   

  Additional remediation costs accrued:

  

  Transfer to regulatory account for recovery

     86   

  Amounts not recoverable from customers

     21   

  Less: Payments

     (85
        

  Balance at September 30, 2010

       $ 608   
        

The $608 million accrued at September 30, 2010 consists of the following:

 

   

$41 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

 

   

$173 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

 

   

$87 million related to remediation at divested generation facilities;

 

   

$116 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

 

   

$141 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

 

   

$50 million related to remediation decommissioning fossil-fueled sites.

The Utility has a program, in cooperation with the California Environmental Protection Agency, to evaluate and take appropriate action to mitigate any potential environmental concerns posed by certain former MGPs located throughout the Utility’s service territory. Of the forty one MGP sites owned or operated by the Utility, forty have been or are in the process of being investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site.

 

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Of the $608 million environmental remediation liability, the Utility expects to recover $323 million through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs without a reasonableness review (excluding any remediation associated with the Hinkley natural gas compressor site) and $121 million through the ratemaking mechanism that authorizes the Utility to recover 100% of remediation costs for decommissioning fossil-fueled sites and certain of the Utility’s transmission stations. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

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. The Utility’s undiscounted future costs could increase to as much as $1.1 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.

Tax Matters

PG&E Corporation and the Utility receive a federal subsidy for maintaining a retiree medical benefit plan with prescription drug benefits that is actuarially equivalent to Medicare Part D. For federal income tax purposes, the subsidy was deductible when contributed to the benefit plan maintained for these benefits. On March 30, 2010, federal healthcare legislation was signed eliminating the deduction for subsidy contributions after 2012. As a result, PG&E Corporation and the Utility recognized an expense of $20 million in the first quarter of 2010 to reverse previously recognized federal tax benefits (recorded as an increase to income tax provision and a reduction to deferred income tax assets for subsidy amounts included in the calculation of accrued retiree medical benefit obligation).

On September 29, 2010, PG&E Corporation received the Internal Revenue Service (“IRS”) examination report for the 2005 to 2007 audit years and resolved substantially all matters except for several items that will be discussed with the IRS Appeals office. Included in the 2005 to 2007 audit was the resolution of the change in accounting method related to the capitalization of indirect service costs for those years. As a result, PG&E Corporation recorded a $25 million reduction to income tax expense in the third quarter of 2010.

For tax years 2008 through 2010, PG&E Corporation participates in the Compliance Assurance Process (“CAP”), a real-time IRS audit intended to expedite matter resolution. The CAP audit culminates with a letter from the IRS indicating their acceptance of the return. The IRS partially accepted the 2008 return, withholding two issues for further review. The most significant of these relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. While the IRS approved PG&E Corporation’s request for a change in method, the IRS will audit the methodology to determine the proper deduction. This audit has not progressed significantly because the IRS is working with the utility industry to resolve this matter in a consistent manner for all utilities before auditing individual companies.

On August 24, 2010, the IRS accepted PG&E Corporation’s 2009 tax return. The IRS has ninety days to conduct a post-filing review to ensure that the final return properly reflects the positions agreed upon.

The California Franchise Tax Board is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns, as well as the 1997-2007 amended income tax returns reflecting IRS settlements for these years and claim filings that apply only to California. It is uncertain when the Franchise Tax Board will complete the California audits.

PG&E Corporation believes that the final resolution of the federal and California audits will not have a material adverse impact on its financial condition or results of operations. PG&E Corporation is neither under audit nor subject to any material risk in any other jurisdiction.

As of September 30, 2010, PG&E Corporation has $24 million of federal and California capital loss carry forwards based on filed tax returns, of which approximately $9 million will expire if not used by December 31, 2011. For all periods presented, PG&E Corporation has provided a full valuation allowance against its deferred income tax assets for capital loss carry forwards.

For a discussion of unrecognized tax benefits, see Note 9 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report. PG&E Corporation and the Utility believe there are no positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within 12 months of the reporting date.

 

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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 whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally 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. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

The Utility served 5.2 million electricity distribution customers and 4.3 million natural gas distribution customers at September 30, 2010. The Utility had $44.9 billion in assets at September 30, 2010 and generated revenues of $10.2 billion in the nine months ended September 30, 2010.

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, including the Diablo Canyon power plant (“Diablo Canyon”). The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric 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. Before setting rates, the CPUC and the FERC authorize 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 of providing utility services. The authorized revenue requirements also provide the Utility an opportunity to earn a return on “rate base” (i.e., the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers.) The CPUC requires the Utility to maintain a certain capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) when financing its rate base and authorizes the Utility to earn a specific rate of return on each capital component.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. In addition, this quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2009 which incorporates by reference each company’s audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information incorporated by reference (“2009 Annual Report”).

Explosion and Fires in San Bruno, California

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility ruptured in a residential area located in the City of San Bruno, California (the “San Bruno Accident”). The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The cause of the rupture remains unknown. The California Governor’s office declared a state of emergency in San Mateo County, where San Bruno is located, to mobilize state emergency services and resources.

On September 10, 2010, the National Transportation Safety Board (“NTSB”) began an investigation of the San Bruno Accident. In addition to reviewing the physical evidence collected from the site and conducting further metallurgical tests, the NTSB is expected to examine, among other aspects, the performance, qualifications and experience of the relevant employees, and the emergency preparedness and response of the Utility and of public emergency personnel and other first responders. While the NTSB investigation is pending the Utility generally is prohibited from disclosing information related to the investigation without approval from the NTSB.

On September 12, 2010, the Utility announced that it would provide up to $100 million to assist affected residents and the City of San Bruno, California, to pay for (1) affected residents’ immediate expenses not otherwise covered by insurance, including temporary living expenses, insurance deductibles, and immediate medical expenses; (2) property replacement, repair or purchase (in the case of homes destroyed or substantially damaged) and (3) work needed to rebuild or replace public property damaged or destroyed in the San Bruno Accident, as well as costs incurred by emergency responders and government services to respond to the fire. These payments are not intended to satisfy any potential claims for personal injury or wrongful death, which will be addressed separately.

 

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On October 13, 2010, the NTSB released a preliminary report. The report included a timeline of events before and after the gas line rupture, but did not identify the cause of the rupture. The NTSB also identified which tests had been performed on the section of ruptured pipeline and which tests were yet to be completed. The NTSB stated that additional factual updates will be provided and distributed via media advisory as investigative information is developed.

The CPUC also has initiated an investigation of the San Bruno Accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory. The CPUC has appointed an independent review panel to gather facts, review these facts, make a technical assessment of the San Bruno Accident and its root cause, and make recommendations for action by the CPUC to ensure such an accident is not repeated. These recommendations may include changes to design, construction, operation and maintenance of natural gas facilities, management practices at the Utility in the areas of pipeline integrity and public safety, regulatory and statutory changes, and other recommendations deemed appropriate, including whether there are systemic management problems at the Utility and whether greater resources are needed to achieve fundamental infrastructure improvement. The Utility is committed to working with the NTSB, the CPUC, and the independent panel to determine the cause of the rupture.

Various lawsuits, including two class action lawsuits, have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. (See Part II, Item 1. Legal Proceedings, below.) Several other residents also have submitted damage claims to the Utility. In addition, on October 4, 2010, PG&E Corporation received a letter on behalf of a purported shareholder demanding that the PG&E Corporation 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 members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The letter requests a response within 60 days, i.e., by December 3, 2010. PG&E Corporation intends to respond before December 3, 2010. A purported shareholder derivative action also has been filed 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.

As of September 30, 2010, the Utility has recorded a provision of $220 million for estimated third-party claims related to the San Bruno Accident, including personal injury and property damage claims, damage to infrastructure, emergency response, and other damage claims. The provision is included in operating and maintenance expense in PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income, and other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for the period ended September 30, 2010. The Utility estimates that it may incur as much as $400 million for third-party claims depending on the final outcome of the NTSB and CPUC investigations and the number, nature, and value of third-party claims. This range of estimates incorporates up to $100 million that the Utility has stated it would provide the affected residents and the City of San Bruno. The process for estimating costs associated with third-party claims relating to the San Bruno Accident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including information resulting from the NTSB and CPUC investigations, management’s estimates and assumptions regarding the financial impact of the San Bruno Accident may change.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for third-party claims relating to the San Bruno Accident will ultimately be covered by this insurance, no amounts for insurance recoveries have been recorded as of September 30, 2010. PG&E Corporation and the Utility are unable to predict the amount and timing of insurance recoveries.

Other significant developments that have occurred since the 2009 Annual Report was filed with the Securities and Exchange Commission on February 19, 2010 are dis