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 June 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

1-2348

  

 

PG&E Corporation

Pacific Gas and Electric Company

  

 

California

California

  

 

94-3234914

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 July 29, 2010:

 

PG&E Corporation   

390,752,206

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 JUNE 30, 2010

TABLE OF CONTENTS

 

          PAGE

PART I.

 

FINANCIAL INFORMATION

  

ITEM 1.

 

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E Corporation

  
 

Condensed Consolidated Statements of Income

   3
 

Condensed Consolidated Balance Sheets

   4
 

Condensed Consolidated Statements of Cash Flows

   6
 

Pacific Gas and Electric Company

  
 

Condensed Consolidated Statements of Income

   7
 

Condensed Consolidated Balance Sheets

   8
 

Condensed Consolidated Statements of Cash Flows

   10
 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
 

NOTE 1:

 

Organization and Basis of Presentation

   11
 

NOTE 2:

 

Significant Accounting Policies

   11
 

NOTE 3:

 

Regulatory Assets, Liabilities, and Balancing Accounts

   14
 

NOTE 4:

 

Debt

   17
 

NOTE 5:

 

Equity

   18
 

NOTE 6:

 

Earnings Per Share

   19
 

NOTE 7:

 

Derivatives and Hedging Activities

   21
 

NOTE 8:

 

Fair Value Measurements

   25
 

NOTE 9:

 

Related Party Agreements and Transactions

   31
 

NOTE 10:

 

Resolution of Remaining Chapter 11 Disputed Claims

   31
 

NOTE 11:

 

Commitments and Contingencies

   32

ITEM 2.

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

Overview

   39
 

Cautionary Language Regarding Forward-Looking Statements

   41
 

Results of Operations

   43
 

Liquidity and Financial Resources

   49
 

Contractual Commitments

   53
 

Capital Expenditures

   53
 

Off-Balance Sheet Arrangements

   55
 

Contingencies

   55
 

Regulatory Matters

   55
 

Environmental Matters

   57
 

Other Matters

   59
 

Risk Management Activities

   60
 

Critical Accounting Policies

   62

ITEM 3.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   63

ITEM 4.

 

CONTROLS AND PROCEDURES

   63

PART II.

 

OTHER INFORMATION

  

ITEM 1.

  LEGAL PROCEEDINGS    64

ITEM 2.

 

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

   64

ITEM 5.

 

OTHER INFORMATION

   65

ITEM 6.

 

EXHIBITS

   66

 

2


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
June 30,
    Six Months Ended
June 30,
 
(in millions, except per share amounts)    2010     2009     2010     2009  

Operating Revenues

        

Electric

   $ 2,515     $ 2,554     $ 5,025     $ 4,980  

Natural gas

     717       640       1,682       1,645  
                                

Total operating revenues

     3,232       3,194       6,707       6,625  
                                

Operating Expenses

        

Cost of electricity

     863       883       1,783       1,766  

Cost of natural gas

     247       188       742       745  

Operating and maintenance

     959       1,038       1,950       2,097  

Depreciation, amortization, and decommissioning

     468       429       919       848  
                                

Total operating expenses

     2,537       2,538       5,394       5,456  
                                

Operating Income

     695       656       1,313       1,169  

Interest income

     2       17       4       26  

Interest expense

     (175     (178     (343     (359

Other income (expense), net

     2       22       (4     40  
                                

Income Before Income Taxes

     524       517       970       876  

Income tax provision

     187       125       372       240  
                                

Net Income

     337       392       598       636  

Preferred stock dividend requirement of subsidiary

     4       4       7       7  
                                

Income Available for Common Shareholders

   $ 333     $ 388     $ 591     $ 629  
                                

Weighted Average Common Shares Outstanding, Basic

     373       368       372       366  
                                

Weighted Average Common Shares Outstanding, Diluted

     390       369       389       367  
                                

Net Earnings Per Common Share, Basic

   $ 0.88     $ 1.03     $ 1.56     $ 1.68  
                                

Net Earnings Per Common Share, Diluted

   $ 0.86     $ 1.02     $ 1.54     $ 1.67  
                                

Dividends Declared Per Common Share

   $ 0.46     $ 0.42     $ 0.91     $ 0.84  
                                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

3


Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

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

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 265     $ 527  

Restricted cash

     583       633  

Accounts receivable:

    

Customers (net of allowance for doubtful accounts of $71 at June 30, 2010 and $68 at December 31, 2009)

     846       859  

Accrued unbilled revenue

     722       671  

Regulatory balancing accounts

     1,369       1,109  

Other

     759       750  

Inventories:

    

Gas stored underground and fuel oil

     142       114  

Materials and supplies

     192       200  

Income taxes receivable

     —          127  

Prepaid expenses and other

     734       667  
                

Total current assets

     5,612       5,657  
                

Property, Plant, and Equipment

    

Electric

     31,408       30,481  

Gas

     10,971       10,697  

Construction work in progress

     2,149       1,888  

Other

     14       14  
                

Total property, plant, and equipment

     44,542       43,080  

Accumulated depreciation

     (14,559     (14,188
                

Net property, plant, and equipment

     29,983       28,892  
                

Other Noncurrent Assets

    

Regulatory assets ($944 and $1,124 related to Energy Recovery Bonds at June 30, 2010 and December 31, 2009, respectively)

     5,610       5,522  

Nuclear decommissioning trusts

     1,854       1,899  

Income taxes receivable

     693       596  

Other

     466       379  
                

Total other noncurrent assets

     8,623       8,396  
                

TOTAL ASSETS

   $ 44,218     $ 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)    June 30,
2010
    December 31,
2009
 

LIABILITIES AND EQUITY

    

Current Liabilities

    

Short-term borrowings

   $ 1,057     $ 833  

Long-term debt, classified as current

     595       342  

Energy recovery bonds, classified as current

     395       386  

Accounts payable:

    

Trade creditors

     920       984  

Disputed claims and customer refunds

     746       773  

Regulatory balancing accounts

     437       281  

Other

     356       349  

Interest payable

     839       818  

Income taxes payable

     634       214  

Deferred income taxes

     403       332  

Other

     1,237       1,501  
                

Total current liabilities

     7,619       6,813  
                

Noncurrent Liabilities

    

Long-term debt

     10,179       10,381  

Energy recovery bonds

     636       827  

Regulatory liabilities

     4,275       4,125  

Pension and other postretirement benefits

     2,018       1,773  

Asset retirement obligations

     1,600       1,593  

Deferred income taxes

     4,637       4,732  

Other

     2,131       2,116  
                

Total noncurrent liabilities

     25,476       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, 390,103,473 shares outstanding (including 476,312 restricted shares) at June 30, 2010 and 371,272,457 shares outstanding (including 670,552 restricted shares) at December 31, 2009

     6,646       6,280  

Reinvested earnings

     4,457       4,213  

Accumulated other comprehensive loss

     (232     (160
                

Total shareholders’ equity

     10,871       10,333  

Noncontrolling Interest – Preferred Stock of Subsidiary

     252       252  
                

Total equity

     11,123       10,585  
                

TOTAL LIABILITIES AND EQUITY

   $ 44,218     $ 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)  
     Six Months Ended
June 30,
 
(in millions)    2010     2009  

Cash Flows from Operating Activities

    

Net income

   $ 598     $ 636  

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

    

Depreciation, amortization, and decommissioning

     1,038       944  

Allowance for equity funds used during construction

     (57     (47

Deferred income taxes and tax credits, net

     (3     377  

Other changes in noncurrent assets and liabilities

     (97     (46

Effect of changes in operating assets and liabilities:

    

Accounts receivable

     (47     198  

Inventories

     (20     113  

Accounts payable

     7       (143

Income taxes receivable/payable

     458       161  

Regulatory balancing accounts, net

     (206     (228

Other current assets

     28        10  

Other current liabilities

     (326     (224

Other

     —          3  
                

Net cash provided by operating activities

     1,373       1,754  
                

Cash Flows from Investing Activities

    

Capital expenditures

     (1,786     (2,077

Decrease in restricted cash

     50       15  

Proceeds from sales and maturities of nuclear decommissioning trust investments

     685       954  

Purchases of nuclear decommissioning trust investments

     (696     (985

Other

     4       12  
                

Net cash used in investing activities

     (1,743     (2,081
                

Cash Flows from Financing Activities

    

Borrowings under revolving credit facilities

     30       300  

Repayments under revolving credit facilities

     —          (300 )

Net issuance (repayments) of commercial paper, net of discount of $1 in 2010 and $3 in 2009

     693       (47

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 $5 in 2010 and $16 in 2009

     295       884  

Short-term debt matured

     (500     —     

Long-term debt matured

     —          (600

Energy recovery bonds matured

     (182     (174

Common stock issued

     89       182  

Common stock dividends paid

     (320     (286

Other

     3       (12
                

Net cash provided by financing activities

     108       446  
                

Net change in cash and cash equivalents

     (262     119  

Cash and cash equivalents at January 1

     527       219  
                

Cash and cash equivalents at June 30

   $ 265     $ 338   
                

Supplemental disclosures of cash flow information

    

Cash received (paid) for:

    

Interest, net of amounts capitalized

   $ (309 )   $ (298

Income taxes, net

     36       201  

Supplemental disclosures of noncash investing and financing activities

    

Common stock dividends declared but not yet paid

   $ 178     $ 155  

Capital expenditures financed through accounts payable

     209       245  

Noncash common stock issuances

     253       39  

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
June 30,
    Six Months Ended
June 30,
 
(in millions)    2010     2009     2010     2009  

Operating Revenues

        

Electric

   $ 2,515     $ 2,554     $ 5,025      $ 4,980  

Natural gas

     717       640       1,682        1,645  
                                

Total operating revenues

     3,232       3,194       6,707        6,625  
                                

Operating Expenses

        

Cost of electricity

     863       883       1,783        1,766  

Cost of natural gas

     247       188       742        745  

Operating and maintenance

     958       1,037       1,948        2,096  

Depreciation, amortization, and decommissioning

     468       429       919        848  
                                

Total operating expenses

     2,536       2,537       5,392        5,455  
                                

Operating Income

     696       657       1,315       1,170  

Interest income

     2       17       4       26  

Interest expense

     (164     (166     (320     (339

Other income (expense), net

     1       15       (5     36  
                                

Income Before Income Taxes

     535       523       994       893  

Income tax provision

     196       132       391       263  
                                

Net Income

     339       391       603       630  

Preferred stock dividend requirement

     4       4       7       7  
                                

Income Available for Common Stock

   $ 335     $ 387     $ 596     $ 623  
                                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

7


Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

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

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 60     $ 334  

Restricted cash

     583       633  

Accounts receivable:

    

Customers (net of allowance for doubtful accounts of $71 at June 30, 2010 and $68 at December 31, 2009)

     846       859  

Accrued unbilled revenue

     722       671  

Regulatory balancing accounts

     1,369       1,109  

Other

     794       751  

Inventories:

    

Gas stored underground and fuel oil

     142       114  

Materials and supplies

     192       200  

Income taxes receivable

     —          138  

Prepaid expenses and other

     733       662  
                

Total current assets

     5,441        5,471  
                

Property, Plant, and Equipment

    

Electric

     31,408       30,481  

Gas

     10,971       10,697  

Construction work in progress

     2,149       1,888  
                

Total property, plant, and equipment

     44,528       43,066  

Accumulated depreciation

     (14,546     (14,175
                

Net property, plant, and equipment

     29,982       28,891  
                

Other Noncurrent Assets

    

Regulatory assets ($944 and $1,124 related to Energy Recovery Bonds at June 30, 2010 and December 31, 2009, respectively)

     5,610       5,522  

Nuclear decommissioning trusts

     1,854       1,899  

Income taxes receivable

     740       610  

Other

     368        316  
                

Total other noncurrent assets

     8,572        8,347  
                

TOTAL ASSETS

   $ 43,995     $ 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)    June 30,
2010
    December 31,
2009
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current Liabilities

    

Short-term borrowings

   $ 1,027     $ 833  

Long-term debt, classified as current

     595       95  

Energy recovery bonds, classified as current

     395       386  

Accounts payable:

    

Trade creditors

     920       984  

Disputed claims and customer refunds

     746       773  

Regulatory balancing accounts

     437       281  

Other

     367       363  

Interest payable

     834       813  

Income tax payable

     662       223  

Deferred income taxes

     409       334  

Other

     1,032       1,307  
                

Total current liabilities

     7,424       6,392  
                

Noncurrent Liabilities

    

Long-term debt

     9,831       10,033  

Energy recovery bonds

     636       827  

Regulatory liabilities

     4,275       4,125  

Pension and other postretirement benefits

     1,960       1,717  

Asset retirement obligations

     1,600       1,593  

Deferred income taxes

     4,688       4,764  

Other

     2,099       2,073  
                

Total noncurrent liabilities

     25,089       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 June 30, 2010 and December 31, 2009

     145       145  

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

     113       113  

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

     1,322       1,322  

Additional paid-in capital

     3,186       3,055  

Reinvested earnings

     6,942       6,704  

Accumulated other comprehensive loss

     (226     (154
                

Total shareholders’ equity

     11,482       11,185  
                

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 43,995     $ 42,709  
                

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     (Unaudited)  
     Six Months Ended
June 30,
 
(in millions)    2010     2009  

Cash Flows from Operating Activities

    

Net income

   $ 603     $ 630  

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

    

Depreciation, amortization, and decommissioning

     1,016       932  

Allowance for equity funds used during construction

     (57     (47

Deferred income taxes and tax credits, net

     (1     368  

Other changes in noncurrent assets and liabilities

     (63     (34

Effect of changes in operating assets and liabilities:

    

Accounts receivable

     (81     199  

Inventories

     (20     113  

Accounts payable

     4       (140

Income taxes receivable/payable

     475       64  

Regulatory balancing accounts, net

     (206     (228

Other current assets

     28        10  

Other current liabilities

     (316     (220

Other

     —          3  
                

Net cash provided by operating activities

     1,382       1,650  
                

Cash Flows from Investing Activities

    

Capital expenditures

     (1,786     (2,077

Decrease in restricted cash

     50       15  

Proceeds from sales and maturities of nuclear decommissioning trust investments

     685       954  

Purchases of nuclear decommissioning trust investments

     (696     (985

Other

     11       5  
                

Net cash used in investing activities

     (1,736     (2,088
                

Cash Flows from Financing Activities

    

Borrowings under revolving credit facilities

     —          300  

Repayments under revolving credit facilities

     —          (300 )

Net issuance (repayments) of commercial paper, net of discount of $1 in 2010 and $3 in 2009

     693       (47

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 $5 in 2010 and $12 in 2009

     295       538  

Short-term debt matured

     (500     —     

Long-term debt matured

     —          (600

Energy recovery bonds matured

     (182     (174

Preferred stock dividends paid

     (7     (7

Common stock dividends paid

     (358     (312

Equity contribution

     130       653  

Other

     9       (6
                

Net cash provided by financing activities

     80       544  
                

Net change in cash and cash equivalents

     (274     106  

Cash and cash equivalents at January 1

     334       52  
                

Cash and cash equivalents at June 30

   $ 60     $ 158  
                

Supplemental disclosures of cash flow information

    

Cash received (paid) for:

    

Interest, net of amounts capitalized

   $ (287   $ (286

Income taxes, net

     34       70  

Supplemental disclosures of noncash investing and financing activities

    

Capital expenditures financed through accounts payable

   $ 209      $ 245  

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 primarily 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 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 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.”

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, pension plan and other postretirement plan obligations, and accruals for legal matters. 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. This quarterly report should be read in conjunction with the 2009 Annual Report.

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 six-months ended June 30, 2010 and 2009 were as follows:

 

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

Service cost for benefits earned

   $ 69     $ 67     $ 9     $ 7  
 

Interest cost

     161       155       23       21  
 

Expected return on plan assets

     (156     (145     (18     (17
 

Amortization of transition obligation

     —          —          6       7  
 

Amortization of prior service cost

     13       12       6       4  
 

Amortization of unrecognized loss

     11       24       1        1  
                                  
 

Net periodic benefit cost

     98       113       27       23  
                                  
 

Less: transfer to regulatory account (1)

     (58     (72     —          —     
                                  
 

Total

   $ 40     $ 41     $ 27     $ 23  
                                  

 

        

(1)  

  The Utility recorded $58 million and $72 million for the three month periods ended June 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  
       Six Months Ended
June 30,
    Six Months Ended
June  30,
 
  (in millions)    2010     2009     2010     2009  
 

Service cost for benefits earned

   $ 139     $ 133     $ 19     $ 15  
 

Interest cost

     322       310       46       42  
 

Expected return on plan assets

     (312     (290     (36     (34
 

Amortization of transition obligation

     —          —          12       13  
 

Amortization of prior service cost

     27       23       12       8  
 

Amortization of unrecognized loss

     21       49       2        2  
                                  
 

Net periodic benefit cost

     197       225       55       46  
                                  
 

Less: transfer to regulatory account (1)

     (115     (143     —          —     
                                  
 

Total

   $ 82     $ 82     $ 55     $ 46  
                                  

 

        

(1)

  The Utility recorded $115 million and $143 million for the six month periods ended June 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 six months ended June 30, 2010 and 2009.

On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional 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.

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.

 

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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 (1) the obligation to absorb expected losses or receive expected gains that could potentially be significant to the VIE and (2) 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 11 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 June 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 June 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 $1.1 billion at June 30, 2010, and primarily consisted of regulatory assets related to energy recovery bonds, which is included in long-term regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $1.0 billion at June 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 June 30, 2010, PG&E Corporation’s affiliates had entered into tax equity agreements with two privately held companies, SolarCity Corp. (“SolarCity”) and SunRun, Inc. (“SunRun”), to fund residential and commercial retail solar energy installations. SolarCity and SunRun are VIEs. Under master lease agreements with SolarCity, PG&E Corporation will provide payments of up to $80 million, and in return, receive a share of SolarCity customer lease revenues, along with the benefits of local rebates and federal investment tax credits. Under an agreement with SunRun, PG&E Corporation will fund investments up to $100 million and will receive a share of customer payments, as well as federal investment tax credits and other tax benefits. As of June 30, 2010, PG&E Corporation had made total payments of $33 million under these two arrangements, which was recorded in noncurrent assets – other in the Condensed Consolidated Balance Sheets. PG&E Corporation held a variable interest in these entities as a result of these tax equity agreements. When determining whether PG&E Corporation was the primary beneficiary of the VIEs, PG&E Corporation evaluated which party had control over significant economic activities such as designing the entity, 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 SolarCity and SunRun, PG&E Corporation was not the primary beneficiary of these VIEs at June 30, 2010. PG&E Corporation’s financial exposure for these arrangements is primarily limited to its tax equity investments in SolarCity and SunRun.

 

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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. The regulatory assets are amortized over future periods when 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 June 30, 2010 and December 31, 2009, the Utility had current regulatory assets of $570 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)    June 30, 2010    December 31, 2009

Pension benefits

   $ 1,455    $ 1,386

Deferred income taxes

     1,116      1,027

Energy recovery bonds

     944      1,124

Utility retained generation

     701      737

Price risk management

     459      346

Environmental compliance costs

     398      408

Unamortized loss, net of gain, on reacquired debt

     192      203

Other

     345      291
             

Total long-term regulatory assets

   $ 5,610    $ 5,522
             

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.

 

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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 11 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 June 30, 2010 and December 31, 2009, “other” consisted of regulatory assets relating to ARO expenses that are probable of future recovery through the ratemaking process, removal costs associated with the replacement of the steam generators in the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), and removal costs associated with the replacement of old electromechanical meters with SmartMeter devices. “Other” also consisted of costs that the Utility incurred in terminating a 30-year power purchase agreement, which are being amortized and collected in rates through September 2014, as well as costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004.

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 June 30, 2010 and December 31, 2009, the Utility had current regulatory liabilities of $81 million and $163 million, respectively, primarily consisting of the amounts that the Utility expects to refund to customers for over-collected electric transmission rates 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.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

 

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

Cost of removal obligation

   $ 3,112    $ 2,933

Public purpose programs

     604      508

Recoveries in excess of ARO

     433      488

Other

     126      196
             

Total long-term regulatory liabilities

   $ 4,275    $ 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.

 

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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. For example, these regulatory liabilities include revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

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 June 30, 2010 and December 31, 2009 included 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)    June 30, 2010     December 31, 2009  

Utility generation

   $ 542     $ 355  

Distribution revenue adjustment mechanism

     319       152  

Public purpose programs

     71       83  

Gas fixed cost

     13       93  

Energy procurement costs

     (12     128  

Electric transmission

     (39     114   

Energy recovery bonds

     (163     (185

Other

     201       88  
                

Total regulatory balancing accounts, net

   $ 932     $ 828  
                

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, the actual costs of such programs, 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 Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs. The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur during the following year. The Utility’s electric rates are set to recover such expected costs.

 

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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 June 30, 2010 and December 31, 2009, “other” included 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 at June 30, 2010.

In addition to conversion rights, the holders of the Convertible Subordinated Notes were entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion price. In the six months ended June 30, 2010, PG&E Corporation paid $14 million of pass-through dividends. The payment of pass-through dividends is recognized as an operating cash flow in PG&E Corporation’s Condensed Consolidated Statement of Cash Flows. Changes in the fair value of the dividend participation rights, which are treated as a derivative, are recognized in PG&E Corporation’s Condensed Consolidated Statement of Income as a non-operating expense or income. (See Note 7 below for further discussion of these instruments.)

Credit Facilities

At June 30, 2010, PG&E Corporation had $30 million of cash borrowings outstanding under its $187 million revolving credit facility which had an average interest rate of 0.70%.

Utility

Senior Notes

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

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 on 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.

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. The Utility has the right to increase, in one or more requests given no more than once a year, the aggregate facility by up to $250 million, provided certain conditions are met.

 

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Borrowings under the credit agreement (other than swingline loans) will bear interest based, at the Utility’s election, on (1) a London Interbank Offered Rate (“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 June 30, 2010, the Utility had no cash borrowings outstanding under its $1.9 billion and $750 million revolving credit facilities.

At June 30, 2010, the Utility had $256 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 June 30, 2010, the Utility had $1.0 billion of commercial paper outstanding at an average yield of 0.45%.

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 $1.0 billion at June 30, 2010.

While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the Utility. The assets, including the recovery property, of PERF 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 six months ended June 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

     598       603  

Common stock issued

     342       —     

Share-based compensation expense

     22       —     

Common stock dividends declared

     (347 )     (358

Preferred stock dividend requirement

     —          (7

Preferred stock dividend requirement of subsidiary

     (7     —     

Tax benefit from employee stock plans

     2       1  

Other comprehensive income

     (72     (72

Equity contribution

     —          130  
                

Balance at June 30, 2010

   $ 11,123     $ 11,482  
                

During the six months ended June 30, 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, PG&E Corporation issued 2,340,451 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 six months ended June 30, 2010, PG&E Corporation contributed equity of $130 million to the Utility in order to maintain the 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

 

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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, cumulative adjustments for employee benefit plans, net of tax, are included in accumulated other comprehensive income.

 

     PG&E Corporation
     Three Months Ended
June 30,
   Six Months Ended
June 30,
(in millions)    2010    2009    2010     2009

Net income

   $ 337    $ 392    $ 598     $ 636

Employee benefit plan adjustment, net of tax(1)

     8      7      (72     14
                            

Comprehensive income

   $ 345    $ 399    $ 526     $ 650
                            

 

(1)

These balances are net of income tax expense of $6 million and $5 million for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010, the income tax benefit was $49 million and for the six months ended June 30, 2009, the income tax expense was $9 million.

 

     Utility
     Three Months Ended
June 30,
   Six Months Ended
June 30,
(in millions)    2010    2009    2010     2009

Net income

   $ 339    $ 391    $ 603     $ 630

Employee benefit plan adjustment, net of tax(1)

     8      7      (72     14
                            

Comprehensive income

   $ 347    $ 398    $ 531     $ 644
                            

 

(1)

These balances are net of income tax expense of $6 million and $5 million for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010, the income tax benefit was $49 million and for the six months ended June 30, 2009, the income tax expense was $9 million.

Dividends

During the six months ended June 30, 2010, PG&E Corporation paid common stock dividends totaling $320 million, net of $6 million that was reinvested in additional shares of common stock by participants in the Dividend Reinvestment and Stock Purchase Plan. On June 16, 2010, the Board of Directors of PG&E Corporation declared dividends of $0.455 per share, totaling $178 million, which were paid on July 15, 2010 to shareholders on record as of June 30, 2010.

During the six months ended June 30, 2010, the Utility paid common stock dividends totaling $358 million to PG&E Corporation.

During the six months ended June 30, 2010, the Utility paid dividends totaling $7 million to holders of its outstanding series of preferred stock. On June 16, 2010, the Board of Directors of the Utility declared dividends totaling $4 million on its outstanding series of preferred stock, payable on August 15, 2010, to shareholders on record as of July 30, 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 June 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
June 30,
   Six Months Ended
June 30,
(in millions, except per share amounts)    2010    2009    2010    2009

Basic

           

Income available for common shareholders

   $ 333    $ 388    $ 591    $ 629

Less: distributed earnings to common shareholders

     178      155      347      309
                           

Undistributed earnings

   $ 155    $ 233    $ 244    $ 320
                           

Allocation of undistributed earnings to common shareholders

           

Distributed earnings to common shareholders

   $ 178    $ 155    $ 347    $ 309

Undistributed earnings allocated to common shareholders

     149      223      234      306
                           

Total common shareholders earnings

   $ 327    $ 378    $ 581    $ 615
                           

Weighted average common shares outstanding, basic

     373      368      372      366

Convertible subordinated notes

     15      17      16      17
                           

Weighted average common shares outstanding and participating securities

     388      385      388      383
                           

Net earnings per common share, basic

           

Distributed earnings, basic (1)

   $ 0.48    $ 0.42    $ 0.93    $ 0.84

Undistributed earnings, basic

     0.40      0.61      0.63      0.84
                           

Total

   $ 0.88    $ 1.03    $ 1.56    $ 1.68
                           

 

(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 six months ended June 30, 2010:

 

(in millions, except per share amounts)    Three
Months Ended
June  30, 2010
   Six
Months Ended
June 30, 2010

Diluted

     

Income available for common shareholders

   $ 333    $ 591

Add earnings impact of assumed conversion of participating securities:

     

Interest expense on convertible subordinated notes, net of tax

     4      8
             

Income available for common shareholders and assumed conversion

   $ 337    $ 599
             

Weighted average common shares outstanding, basic

     373      372

Add incremental shares from assumed conversions:

     

Convertible subordinated notes

     15      16

Employee share-based compensation

     2      1
             

Weighted average common shares outstanding, diluted

     390      389
             

Total earnings per common share, diluted

   $ 0.86    $ 1.54
             

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 the three and six months ended June 30, 2009:

 

(in millions, except per share amounts)    Three
Months Ended
June 30, 2009
   Six
Months Ended
June 30, 2009

Diluted

     

Income available for common shareholders

   $ 388    $ 629

Less: distributed earnings to common shareholders

     155      309
             

Undistributed earnings

   $ 233    $ 320
             

Allocation of undistributed earnings to common shareholders

     

Distributed earnings to common shareholders

   $ 155    $ 309

Undistributed earnings allocated to common shareholders

     223      306
             

Total common shareholders earnings

   $ 378    $ 615
             

Weighted average common shares outstanding, basic

     368      366

Convertible subordinated notes

     17      17
             

Weighted average common shares outstanding and participating securities, basic

     385      383
             

Weighted average common shares outstanding, basic

     368      366

Employee share-based compensation

     1      1
             

Weighted average common shares outstanding, diluted

     369      367

Convertible subordinated notes

     17      17
             

Weighted average common shares outstanding and participating securities, diluted

     386      384
             

Net earnings per common share, diluted

     

Distributed earnings, diluted

   $ 0.42    $ 0.84

Undistributed earnings, diluted

     0.60      0.83
             

Total earnings per common share, diluted

   $ 1.02    $ 1.67
             

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.

 

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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;

 

 

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.

 

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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.

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 CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Upgrade on April 1, 2009. The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new 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.

 

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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

Other Risk

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 at a conversion price of $15.09 per share. Prior to conversion, the holders of the Convertible Subordinated Notes were entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion prices. These “pass-through dividends” were classified as embedded derivative instruments and bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements. Upon conversion of the notes, the dividend participation rights ceased to exist. For the six months ended June 30, 2010, PG&E Corporation paid $14 million of pass-through dividends associated with the Convertible Subordinated Notes. (See Note 4 above for further information.)

Volume of Derivative Activity

At June 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    366,497,007    254,825,476    15,180,000    —  
  

Options

   222,787,080    142,750,000    15,600,000    —  

Electricity (Megawatt-hours)

   Forwards, Futures, and Swaps    5,059,221    8,305,259    4,446,487    5,388,528
  

Options

   628,718    —      196,632    463,860
  

Congestion Revenue Rights

   59,215,388    67,233,474    67,167,528    103,387,526

 

(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.

At June 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

   $ 30     $ (18   $ 49    $ 61  

Other noncurrent assets – other

     81       (62     65      84  

Current liabilities – other

     (342     18       147      (177

Noncurrent liabilities – other

     (521     62       129      (330
                               

Total commodity risk

   $ (752   $ —        $ 390    $ (362
                               

 

(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.

 

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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 June 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 June 30,     Six months ended June 30,  
(in millions)    2010     2009     2010     2009  

Unrealized gain/(loss) - regulatory assets and liabilities (1)

   $ 18     $ 147     $ (271   $ (160

Realized gain/(loss) - cost of electricity (2)

     (175     (223     (281     (425

Realized gain/(loss) - cost of natural gas (2)

     (5     (6     (44     (29
                                

Total commodity risk instruments

   $ (162   $ (82   $ (596   $ (614
                                

 

(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.

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 June 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

   $ (708

Related derivatives in an asset position

     78  

Collateral posting in the normal course of business related to these derivatives

     204  
        

Net position of derivative contracts/additional collateral posting requirements (1)

   $ (426
        

 

(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.

 

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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 also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. (See Note 11 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for further discussion of fair value measurements.)

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 June 30, 2010

 

(in millions)

   Level 1    Level 2    Level 3    Total

Assets:

           

Money market investments

   $ 204    $ —      $ —      $ 204
                           

Nuclear decommissioning trusts

           

U.S. equity securities (1)

     706      20      —        726

Non-U.S. equity securities

     282      —        —        282

U.S. government and agency securities

     720      58      —        778

Municipal securities

     5      87      —        92

Other fixed income securities

     —        79      —        79
                           

Total nuclear decommissioning trusts (2)

     1,713      244      —        1,957
                           

Price risk management instruments

           

Electric (3)

     74      —        —        74
                           

Total price risk management instruments

     74      —        —        74
                           

Rabbi trusts

           

Equity securities

     23      —        —        23

Life insurance contracts

     —        64      —        64
                           

Total rabbi trusts

     23      64      —        87
                           

Long-term disability trust

           

U.S. equity securities (1)

     3      23      —        26

Corporate debt securities (1)

     —        142      —        142
                           

Total long-term disability trust

     3      165      —        168
                           

Total assets

   $ 2,017    $ 473    $ —      $ 2,490
                           

Liabilities:

           

Price risk management instruments

           

Electric (4)

     —        35      358      393

Gas (5)

     —        1      42      43
                           

Total price risk management instruments

     —        36      400      436
                           

Other liabilities

     —        —        2      2
                           

Total liabilities

   $ —      $ 36    $ 402    $ 438
                           

 

(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 $280 million to Level 1. Includes natural gas for electric portfolio.

(4)

Balances include the impact of netting adjustments of $43 million to Level 2, and $33 million to Level 3. Includes natural gas for electric portfolio.

(5)

Balances include the impact of netting adjustments of $34 million to Level 3. Includes natural gas for core customers.

 

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Table of Contents

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

   $ —      $ —      $ 12    $ 12
                           

Price risk management instruments

           

Electric (3)

     2      73      157      232

Gas (4)

     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 taxes on appreciation of investment value.

(3)

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.

(4)

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. Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. Equity securities and debt securities are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. 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

 

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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 June 30, 2010.

Price Risk Management Instruments

Price risk management instruments are composed of physical and financial derivative contracts, including futures, forwards, swaps, options, and CRRs that are exchange-traded or over-the-counter traded contracts. Futures, forwards, and swaps are valued using observable market prices for the underlying commodity or an identical instrument. As observable market prices are available, these instruments are classified as Level 1 or Level 2 instruments.

Certain exchange-traded contracts are classified as Level 2 measurements because the contract term extends to a point at which the market is no longer considered active but where 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 have been 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. Certain power purchase agreements meet the definition of a derivative instrument. Some of these power purchase agreements do not qualify as normal purchases and sales, therefore, the fair value of these power purchase agreements are recorded on the Condensed Consolidated Balance Sheets. 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 the point 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.

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 six month period ended June 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 six month periods ended June 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
Decommission-
ing Trusts
Equity
Securities (1)
   Long-
Term
Disability
Equity
Securities
   Long-Term
Disability
Corp. Debt
Securities
   Other
Liabilities
    Total  

Asset (liability) balance as of March 31, 2010

   $ —      $ (7   $ (336   $ —      $ —      $ —      $ (1   $ (344

Realized and unrealized gains (losses):

                    

Included in earnings

     —        —          —          —        —        —        —          —     

Included in regulatory assets and liabilities or balancing accounts

     —        —          (64     —        —        —        (1     (65

Purchases, issuances, and settlements

     —        7        —          —        —        —        —          7   

Transfers into Level 3

     —        —          —          —        —        —        —          —     

Transfers out of Level 3

     —        —          —          —        —        —        —          —     

Asset (liability) balance as of June 30, 2010

   $ —      $ —        $ (400   $ —      $ —      $ —      $ (2   $ (402

 

(1)

Excludes deferred taxes on appreciation of investment value.

 

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Table of Contents
     PG&E Corporation
Only
    PG&E Corporation and the Utility        
(in millions)    Money
Market
    Dividend
Participation
Rights
    Price Risk
Management
Instruments
    Nuclear
Decommission-
ing Trusts
Equity
Securities (1)
   Long-
Term
Disability
Equity
Securities
   Long-Term
Disability
Corp. Debt
Securities
   Other
Liabilities
    Total  

Asset (liability) balance as of March 31, 2009

   $ 8      $ (33 )   $ (176   $ 4    $ 47    $ 24    $ (1   $ (127
                                                             

Realized and unrealized gains (losses):

                   

Included in earnings

     —          (1     —          —        10      —        —          9  

Included in regulatory assets and liabilities or balancing accounts

     —          —          (13     1      —        —        (2 )     (14

Purchases, issuances, and settlements

     (3     7       —          —        —        —        —          4  

Transfers into Level 3

     —          —          —          —        —        —        —          —     

Transfers out of Level 3

     —          —          —          —        —        —        —          —     
                                                             

Asset (liability) balance as of June 30, 2009

   $ 5     $ (27   $ (189   $ 5    $ 57    $ 24    $ (3 )   $ (128
                                                             

 

(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
Decommission-

ing 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

     —          —          (183 )     —        —        —        1       (182

Purchases, issuances, and settlements

     (4     12       —          —        —        —        —          8  

Transfers into Level 3

     —          —          —          —        —        —        —          —     

Transfers out of Level 3

     —          —          —          —        —        —        —          —     
                                                             

Asset (liability) balance as of June 30, 2010

   $ —        $ —        $ (400 )   $ —      $ —      $ —      $ (2 )   $ (402
                                                             

 

(1)

Excludes deferred taxes on appreciation of investment value.

 

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Table of Contents
     PG&E Corporation
Only
    PG&E Corporation and the Utility        
(in millions)    Money
Market
    Dividend
Participation
Rights
    Price Risk
Management
Instruments
    Nuclear
Decommission-

ing 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       —          —        3      —        —          4  

Included in regulatory assets and liabilities or balancing accounts

     —          —          (33     —        —        —        (1     (34

Purchases, issuances, and settlements

     (7 )     14       —          —        —        —        —          7  

Transfers into Level 3

     —          —          —          —        —        —        —          —     

Transfers out of Level 3

     —          —          —          —        —        —        —          —     
                                                             

Asset (liability) balance as of June 30, 2009

   $ 5     $ (27   $ (189   $ 5    $ 57    $ 24    $ (3 )   $ (128
                                                             

 

(1)

Excludes deferred taxes on appreciation of investment value.

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 June 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)

   $ —      $ —      $ 597    $ 1,096

Utility

     9,540      10,553      9,240      9,824

Energy recovery bonds

     1,031      1,171      1,213      1,269

 

(1)

PG&E Corporation Convertible Subordinated Notes were no longer outstanding as of June 30, 2010.

(2)

Fair values are determined using readily available quoted market prices.

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.)

 

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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 June 30, 2010

          

U.S. equity securities

   $ 360    $ 371    $ (5   $ 726

Non-U.S. equity securities

     177      109      (4     282

U.S. government and agency securities

     698      80      —          778

Municipal securities

     91      2      (1     92

Other fixed income securities

     77      2      —          79
                            

Total

   $ 1,403    $ 564    $ (10   $ 1,957
                            

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 June 30,
      2010
(in millions)     

Less than 1 year

   $ 40

1–5 years

     424

5–10 years

     248

More than 10 years

     237
      

Total maturities of debt securities

   $ 949
      

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

 

     Three Months Ended
June  30,
    Six Months Ended
June  30,
 
     2010     2009     2010     2009  
(in millions)                         

Proceeds received from sales of securities

   $ 348     $ 567     $ 685     $ 954   

Gross realized gains on sales of securities held as available-for-sale

     7       4       22       12   

Gross realized losses on sales of securities held as available-for-sale

     (1 )     (16     (6     (50

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.

 

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Table of Contents

NOTE 9: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were as follows:

 

     Three Months Ended    Six Months Ended
     June 30,    June 30,
(in millions)    2010    2009    2010    2009

Utility revenues from:

           

Administrative services provided to PG&E Corporation

   $ 2    $ 1    $ 3    $ 2

Utility expenses from:

           

Administrative services received from PG&E Corporation

   $ 9    $ 14    $ 25    $ 33

Utility employee benefit due to PG&E Corporation

     5      3      15      9

At June 30, 2010 and December 31, 2009, the Utility had a receivable of $60 million and $26 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Condensed Consolidated Balance Sheets, and a payable of $12 million and $16 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Condensed Consolidated Balance Sheets.

NOTE 10: 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 June 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 credited to customers.

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

 

(in millions)       

Balance at December 31, 2009

   $ 946  

Interest accrued

     15  

Less: supplier settlements

     (41
        

Balance at June 30, 2010

   $ 920  
        

 

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At June 30, 2010, the Utility’s net disputed claims liability was $920 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 $668 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.

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 11: 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 June 30, 2010, the undiscounted future expected power purchase agreement payments were as follows:

 

(in millions)     

2010

   $ 1,202

2011

     2,329

2012

     2,466

2013

     2,726

2014

     2,739

Thereafter

     44,625
      

Total

   $ 56,087
      

Payments made by the Utility under power purchase agreements amounted to $1,094 million and $1,154 million for the six months ended June 30, 2010 and June 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.

 

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(in millions)     

2010

   $ 29

2011

     50

2012

     50

2013

     50

2014

     42

Thereafter

     162
      

Total fixed capacity payments

     383

Amount representing interest

     81
      

Present value of fixed capacity payments

   $ 302
      

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.

At June 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 $269 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 June 30, 2010 and December 31, 2009 of $302 million and $314 million, including amortization of $106 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 June 30, 2010, the Utility’s undiscounted obligations for natural gas purchases, gas transportation services, and gas storage were as follows:

 

(in millions)     

2010

   $ 443

2011

     455

2012

     78

2013

     59

2014

     44

Thereafter

     115
      

Total (1)

   $ 1,194
      

 

(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 $912 million and $737 million for the six months ended June 30, 2010 and June 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 of the project is scheduled to begin in the third quarter of 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.

 

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Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 16 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.

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

 

(in millions)     

2010

   $ 58

2011

     82

2012

     69

2013

     107

2014

     135

Thereafter

     1,215
      

Total

   $ 1,666
      

Payments for nuclear fuel amounted to $95 million and $61 million for the six months ended June 30, 2010 and June 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. In April 2010, the assigned CPUC commissioner directed the parties to hold settlement discussions in an effort to agree on the 2010 final true-up amounts. The CPUC commissioner also directed the Energy Division to calculate various true-up amounts based on a range of possible scenarios that use different assumptions about energy savings, goals, and costs, noting that the CPUC can consider alternative approaches to calculate the final true-up amounts instead of relying solely on the Energy Division’s evaluation of the final energy savings over the 2006-2008 program cycle.

On May 4, 2010, the Energy Division released various scenarios of additional incentive amounts using data from the Energy Division’s draft evaluation report released on April 15, 2010. The calculation scenarios for the Utility range from a penalty of $75 million, based on a scenario using the Energy Division’s evaluated results, to a reward of $105 million. The Energy Division’s draft report did not include the scenario jointly proposed by the utilities. On July 9, 2010, the Energy Division released its final evaluation report and updated the results of its scenario calculations. The range of possible final true-up amounts contained in the final scenario report are substantially the same as the amounts contained in the scenario report released in May 2010. On July 16, 2010, the utilities submitted data to the CPUC to support the utilities’ joint scenario using the verified results in the Energy Division’s final evaluation report. Based on this scenario, the Utility would be entitled to additional incentive revenues of approximately $63 million.

 

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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 or penalties the Utility may be assessed 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 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.

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 approximately $188 million between 2005 and 2009 to build on-site storage facilities. The Utility will also seek to recover these costs from the DOE. 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 that have been “certified” by the Secretary of the Treasury. For a certified act of terrorism, NEIL can obtain compensation from the federal government and will provide up to the full policy limits to the Utility for an insured loss. If one or more non-certified acts of terrorism cause property damage 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 $3.2 billion within a 12-month period plus the additional amounts recovered by NEIL for these losses from reinsurance.

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.

 

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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.

Environmental Matters

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

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 $615 million at June 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

     68  

Amounts not recoverable from customers

     16  

Less: Payments

     (55
        

Balance at June 30, 2010

   $ 615   
        

The $615 million accrued at June 30, 2010 consists of the following:

 

   

$42 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

 

   

$177 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;

 

   

$121 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

 

   

$139 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

 

   

$49 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 41 MGP sites owned or operated by the Utility, 33 have been or are in the process of being remediated. The Utility has notified the owners of properties located on the remaining eight sites and offered to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action. Two of these sites are located in urban, residential areas of San Francisco and one site is located in a predominantly commercial area of San Francisco. Although the Utility has entered into or is negotiating site access agreements with several of the property owners, others have not responded to the Utility’s offer. Until its investigation is complete, the extent of its obligation to remediate is established, and appropriate remedial actions are determined, the Utility is unable to estimate the ultimate amount it may incur with respect to the remediation of these sites.

The Utility expects to recover $326 million of the $615 million environmental remediation liability, in accordance with a CPUC-approved ratemaking mechanism under which the Utility is authorized to recover 90% of hazardous waste remediation costs without a

 

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reasonableness review. (Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable under this mechanism.) In addition, the CPUC and the FERC have authorized the Utility to recover $123 million in rates relating to 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. In addition, it is reasonably possible that the Utility will incur losses related to certain MGP sites located in San Francisco, but the Utility is unable to reasonably estimate the amount of such loss.

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 make 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. 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.

The accrued liability for legal matters is included in PG&E Corporation’s and the Utility’s current liabilities – other in the Condensed Consolidated Balance Sheets and totaled $56 million at June 30, 2010 and $57 million at December 31, 2009. PG&E Corporation and the Utility are not able to predict the ultimate outcome of the 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.

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 (recorded as an increase to income tax provision and a reduction to deferred income tax asset for subsidy amounts included in the calculation of accrued retiree medical benefit obligation).

The Internal Revenue Service (“IRS”) is currently auditing PG&E Corporation’s consolidated 2005–2007 income tax returns. For 2008 and 2009, 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 accepted the 2008 return but held back several matters for further review. The most significant of these relates to a tax accounting method change used 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 maintained the right to further review the amount of the additional deduction. This review has not progressed significantly because the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities before auditing individual companies. Although the IRS is still reviewing PG&E Corporation’s 2009 tax return, PG&E Corporation anticipates that the IRS will hold back the same matters for further review.

The California Franchise Tax Board is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns, as well as 1997-2007 amended income tax returns reflecting IRS settlements for these years and claim filings that apply only to California. Based on recent communications with the Franchise Tax Board, PG&E Corporation does not expect the California audits to be completed prior to the latter part of 2011.

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.

 

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As of June 30, 2010, PG&E Corporation has $25 million of federal and California capital loss carry forwards based on filed tax returns, of which approximately $10 million will expire if not used by 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. It is reasonably possible that unrecognized tax benefits could decrease in the next 12 months by an amount ranging from $0 to $30 million for PG&E Corporation and the Utility.

 

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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 June 30, 2010. The Utility had $44.0 billion in assets at June 30, 2010 and generated revenues of $6.7 billion in the six months ended June 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”).

Significant developments that have occurred since the 2009 Annual Report was filed with the Securities and Exchange Commission on February 19, 2010 are discussed in this Quarterly Report on Form 10-Q.

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three and Six Months Ended June 30, 2010

PG&E Corporation’s diluted earnings per common share (“EPS”) for the three months ended June 30, 2010 was $0.86 compared to $1.02 for the same period in 2009. For the six months ended June 30, 2010, PG&E Corporation’s diluted EPS was $1.54 compared to $1.67 for the same period in 2009. PG&E Corporation’s income available for common shareholders for the three months ended June 30, 2010 decreased by $55 million, or 14%, to $333 million, compared to $388 million for the same period in 2009. For the six months ended June 30, 2010, income available for common shareholders decreased by $38 million, or 6%, to $591 million, compared to $629 million for the same period in 2009. The primary factors for these decreases are discussed below.

Diluted EPS and income available for common shareholders decreased for both the three and six months ended June 30, 2010, as compared to the same periods in 2009 when the Utility recognized a $28 million, after tax, recovery of costs previously incurred in connection with its hydroelectric generation facilities and a $56 million, after tax, income benefit as a result of a tax settlement.

For the three months ended June 30, 2010, the Utility incurred costs of $20 million, after tax, to support Proposition 16 - Taxpayers Right to Vote Act (“Proposition 16”) that also contributed to a decrease in diluted EPS and income available for common shareholders during the quarter. These negative factors were partially offset by (1) an increase of $19 million, after tax, that the Utility earned on higher authorized capital investments, (2) a decrease of $4 million, after tax, in employee termination costs, and (3) a decrease of $11 million, after tax, representing costs the Utility incurred during the three months ended June 30, 2009 to perform accelerated natural gas leak surveys.

For the six months ended June 30, 2010, the Utility incurred (1) $45 million, after tax, of costs to support Proposition

 

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16, (2) a $20 million, after tax, charge triggered by the elimination of the tax deductibility of the Medicare Part D federal subsidy, and (3) $12 million, after tax, of storm-related costs. These negative factors were partially offset by (1) an increase of $40 million, after tax, that the Utility earned on higher authorized capital investments, (2) a decrease of $22 million, after tax, representing costs the Utility incurred in 2009 in connection with a scheduled refueling outage at Diablo Canyon, (3) a decrease of $10 million, after tax, in employee termination costs, (4) a decrease of $16 million, after tax, representing costs the Utility incurred during the six months ended June 30, 2009 to perform accelerated natural gas leak surveys, and (5) a decrease of $7 million, after tax, in uncollectible expense as a result of customer outreach and increased collection efforts as compared to the same period in 2009.

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, recover its authorized costs timely, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation’s and the Utility’s results of operations and financial condition, including:

 

   

The Outcome of Regulatory Proceedings. There are several rate cases that are currently pending at the CPUC and the FERC, the outcome of which will determine the majority of the Utility’s base revenue requirements for 2011 and several years thereafter. In the 2011 General Rate Case (“2011 GRC”), the CPUC will authorize the Utility’s revenue requirements for its electric and natural gas distribution operations and its electric generation operations from 2011 through 2013. The CPUC will also authorize the Utility’s revenue requirements for its natural gas transportation and storage services from 2011 through 2014 in the pending gas transmission and storage rate case. In addition, on July 28, 2010, the Utility filed its 13th Electric Transmission Owner (“TO”) rate case requesting the FERC to determine the amount of electric transmission revenues the Utility can recover beginning in March 2011. (See “Regulatory Matters” below.) From time to time the Utility also requests that the CPUC authorize additional base revenue requirements for specific capital expenditure projects such as new power plants. (See “Capital Expenditures” below.) The outcome of these regulatory proceedings can be affected by many factors, including general economic conditions, the level of customer rates, and political and regulatory policies.

 

   

The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability. The Utility’s revenue requirements in general rate cases and TO rate cases are generally set at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses, as well as to earn a return on equity (“ROE”) and recover depreciation, tax, and interest expense associated with authorized capital expenditures. Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can affect the Utility’s ability to earn its CPUC-authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. In addition, the Utility may incur higher than anticipated operating expenses than provided for in the last general rate case. The Utility continuously re-prioritizes spending to meet customer needs and seeks to achieve sustainable operational efficiencies to maximize its ability to earn its authorized return while maintaining and improving operational safety and reliability. (See “Results of Operations” below.) The Utility also seeks to make the amount and timing of its capital expenditures consistent with customer demand and forecasted amounts and timing and to manage separately funded projects within approved cost limits. When capital expenditures are higher than authorized levels, the Utility incurs associated depreciation, property tax, and interest expense but does not recover revenues to fully offset these expenses or earn an ROE until the increased capital expenditures are added to rate base in future rate cases. (See “Capital Expenditures” below.)

 

   

Capital Structure and Financing. The CPUC has authorized a capital structure for the Utility’s electric and natural gas distribution and electric generation rate base that consists of 52% common equity and 48% debt and preferred stock. This authorized capital structure will remain in effect through 2012. The CPUC also has authorized the Utility to earn a rate of return on each component of its capital structure, including a ROE of 11.35%. These rates will remain in effect through 2010. The rates for 2011 and 2012 are subject to an annual adjustment mechanism that will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Service utility bond index increases or decreases by more than 1% as compared to the applicable benchmark. The amount of the Utility’s authorized equity earnings is determined by the 52% equity component, the 11.35% ROE, and the aggregate amount of rate base authorized by the CPUC. The rate of return that the Utility earns on its FERC-jurisdictional rate base is not specifically

 

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authorized, but rates are designed to allow the Utility to earn a reasonable rate of return. The CPUC periodically authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The timing and amount of the Utility’s future financing will depend on various factors, as discussed in “Liquidity and Financial Resources” below. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. PG&E Corporation may issue debt or equity in the future to fund these equity contributions.

In addition to the key factors discussed above, PG&E Corporation’s and the Utility’s future results of operations and financial condition are subject to risk factors. (See “Risk Factors” in the 2009 Annual Report.)

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures; estimated environmental remediation, tax, and other liabilities; estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies; the anticipated outcome of various regulatory and legal proceedings; estimated future cash flows; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

 

   

the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels;

 

   

the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;

 

   

the adequacy and price of electricity and natural gas supplies and whether the new day-ahead, hour-ahead, and real-time wholesale electricity markets established by the California Independent System Operator (“CAISO”) will continue to function effectively, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

 

   

explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

 

   

the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

 

   

the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

 

   

changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

 

   

the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon, the availability of nuclear fuel, the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, or other matters associated with the operations at Diablo Canyon;

 

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whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

 

   

the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

 

   

whether the Utility can successfully implement its program to install advanced meters for its electric and natural gas customers and integrate the new meters with its customer billing and other systems, the outcome of the independent investigation ordered by the CPUC and the California Legislature into customer concerns about the new meters, and the ability of the Utility to implement various rate changes including “dynamic pricing” by offering electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices;

 

   

how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;

 

   

the outcome of litigation, including litigation involving the application of various California wage and hour laws, and the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, or from other third parties;

 

   

the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

 

   

the impact of environmental laws and regulations and the costs of compliance and remediation;

 

   

the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

 

   

the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations.

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the 2009 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

 

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RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three and six months ended June 30, 2010 and 2009:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
(in millions)    2010     2009     2010     2009  

Utility

        

Electric operating revenues

   $ 2,515     $ 2,554     $ 5,025     $ 4,980  

Natural gas operating revenues

     717       640       1,682       1,645  
                                

Total operating revenues

     3,232       3,194       6,707       6,625  
                                

Cost of electricity

     863       883       1,783       1,766  

Cost of natural gas

     247       188       742       745  

Operating and maintenance

     958       1,037       1,948       2,096  

Depreciation, amortization, and decommissioning

     468       429       919       848  
                                

Total operating expenses

     2,536       2,537       5,392       5,455  
                                

Operating Income

     696       657       1,315       1,170  

Interest income

     2       17       4       26  

Interest expense

     (164     (166     (320     (339

Other income (expense), net

     1       15       (5     36  
                                

Income Before Income Taxes

     535       523       994       893  

Income tax provision

     196       132       391       263  
                                

Net Income

     339       391       603       630  

Preferred stock dividend requirement

     4       4       7       7  
                                

Income Available for Common Stock

   $ 335     $ 387     $ 596     $ 623  
                                

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