UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C., 20549

FORM 10-Q

(Mark One)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM 10-Q
(Mark One)
  [X] 
[X]

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009
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

  
Commission
File
Number
_______________

Exact Name of

Registrant

as specified

in its charter

_______________

State or other
Jurisdiction of
Incorporation
______________
IRS Employer
Identification
Number
___________
    

State or other

Jurisdiction of        

Incorporation

IRS Employer

Identification    

Number

 
1-12609PG&E CorporationCalifornia94-3234914
1-2348Pacific Gas and Electric CompanyCalifornia94-0742640
  

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).

Registrant's telephone number, including area codePG&E Corporation
  
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] [X] Yes [  ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). [X] 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
Yes  [  ] Accelerated Filer
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.

[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:
[X] Large accelerated filer[  ] Yes [X] NoAccelerated 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] [X] No

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

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

Common Stock Outstanding as of October 27, 2009:25, 2010:

PG&E Corporation

392,065,793  
PG&E Corporation370,960,212

Pacific Gas and Electric Company

264,374,809
   264,374,809


PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009

2010

TABLE OF CONTENTS


PART I.FINANCIAL INFORMATIONPAGE
ITEM 1.
1.
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E Corporation
  

PG&E Corporation

Condensed Consolidated Statements of Income

3
   
2

Condensed Consolidated Balance Sheets

4
   
3

Condensed Consolidated Statements of Cash Flows

65

Pacific Gas and Electric Company

  

Condensed Consolidated Statements of Income

8
   
6

Condensed Consolidated Balance Sheets

9
   
7

Condensed Consolidated Statements of Cash Flows

119

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
 NOTE 1:
Organization and Basis of Presentation1310
 NOTE 2:
New and Significant Accounting Policies1310
 NOTE 3:
Regulatory Assets, Liabilities, and Balancing Accounts1813
 NOTE 4:
Debt2216
 NOTE 5:
Equity2318
 NOTE 6:
Earnings Per Share2319
 NOTE 7:
Derivatives and Hedging Activities2520
 NOTE 8:
Fair Value Measurements2924
 NOTE 9:33
NOTE 10:3330
 NOTE 11:10:
Commitments and Contingencies3431
ITEM 2.
MANAGEMENT'S
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Overview38  
41
 4341
Results of Operations4443
Liquidity and Financial Resources5148
Contractual Commitments5553
Capital Expenditures5553
Off-Balance Sheet Arrangements5654
Contingencies5655
Regulatory Matters5655
Environmental Matters59
Other Matters61
Risk Management Activities6063
Critical Accounting Policies61
  6164
63
  

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK6566
ITEM 4.
CONTROLS AND PROCEDURES65
  
PART II.OTHER INFORMATION66  
PART II.OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS6667
ITEM 1A.
RISK FACTORS6667
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS6669
ITEM 5.
OTHER INFORMATION6769
ITEM 6.
EXHIBITS6870


2




PART I. FINANCIAL INFORMATION

ITEM 1:1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME 
  
(Unaudited)
 
  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions, except per share amounts) 
2009
  
2008
  
2009
  
2008
 
Operating Revenues            
Electric $2,630  $2,880  $7,610  $8,039 
Natural gas  605   794   2,250   2,946 
Total operating revenues  3,235   3,674   9,860   10,985 
Operating Expenses                
Cost of electricity  997   1,282   2,763   3,406 
Cost of natural gas  134   351   879   1,613 
Operating and maintenance  1,047   983   3,144   3,010 
Depreciation, amortization, and decommissioning  450   419   1,298   1,240 
Total operating expenses  2,628   3,035   8,084   9,269 
Operating Income  607   639   1,776   1,716 
Interest income  1   23   27   82 
Interest expense  (174)  (178)  (533)  (550)
Other income (expense), net  23   (14)  63   (4)
Income Before Income Taxes  457   470   1,333   1,244 
Income tax provision  136   163   376   413 
Net Income  321   307   957   831 
Preferred stock dividend requirement of subsidiary  3   3   10   10 
Income Available for Common Shareholders $318  $304  $947  $821 
Weighted Average Common Shares Outstanding, Basic  370   357   367   356 
Weighted Average Common Shares Outstanding, Diluted  388   358   386   357 
Net Earnings Per Common Share, Basic $0.84  $0.83  $2.53  $2.25 
Net Earnings Per Common Share, Diluted $0.83  $0.83  $2.49  $2.24 
Dividends Declared Per Common Share $0.42  $0.39  $1.26  $1.17 
  
See accompanying Notes to the Condensed Consolidated Financial Statements. 
3

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF INCOME


  
(Unaudited)
 
  
Balance At
 
(in millions) 
September 30,
2009
  
December 31, 2008
 
ASSETS      
Current Assets      
Cash and cash equivalents $700  $219 
Restricted cash  569   1,290 
Accounts receivable:        
Customers (net of allowance for doubtful accounts of $68 million in 2009 and $76 million in 2008)  1,609   1,751 
Accrued unbilled revenue  807   685 
Regulatory balancing accounts  882   1,197 
Inventories:        
Gas stored underground and fuel oil  141   232 
Materials and supplies  204   191 
Income taxes receivable  58   120 
Prepaid expenses and other  640   718 
Total current assets  5,610   6,403 
Property, Plant, and Equipment        
Electric  29,875   27,638 
Gas  10,524   10,155 
Construction work in progress  1,767   2,023 
Other  15   17 
Total property, plant, and equipment  42,181   39,833 
Accumulated depreciation  (13,997)  (13,572)
Net property, plant, and equipment  28,184   26,261 
Other Noncurrent Assets        
Regulatory assets  5,931   5,996 
Nuclear decommissioning funds  1,870   1,718 
Income taxes receivable  506   - 
Other  450   482 
Total other noncurrent assets  8,757   8,196 
TOTAL ASSETS $42,551  $40,860 

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

Operating Revenues

     

Electric

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

Natural gas

   656    605    2,338    2,250  
                 

Total operating revenues

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

Operating Expenses

     

Cost of electricity

   1,102    997    2,885    2,763  

Cost of natural gas

   182    134    924    879  

Operating and maintenance

   1,225    1,047    3,175    3,144  

Depreciation, amortization, and decommissioning

   501    450    1,420    1,298  
                 

Total operating expenses

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

Operating Income

   503    607    1,816    1,776  

Interest income

   3    1    7    27  

Interest expense

   (167  (174  (510  (533

Other income, net

   29    23    25    63  
                 

Income Before Income Taxes

   368    457    1,338    1,333  

Income tax provision

   107    136    479    376  
                 

Net Income

   261    321    859    957  

Preferred stock dividend requirement of subsidiary

   3    3    10    10  
                 

Income Available for Common Shareholders

   $ 258    $ 318    $ 849    $ 947  
                 

Weighted Average Common Shares Outstanding, Basic

   390    370    378    367  
                 

Weighted Average Common Shares Outstanding, Diluted

   392    388    391    386  
                 

Net Earnings Per Common Share, Basic

   $ 0.66    $ 0.84    $ 2.22    $ 2.53  
                 

Net Earnings Per Common Share, Diluted

   $ 0.66    $ 0.83    $ 2.19    $ 2.49  
                 

Dividends Declared Per Common Share

   $ 0.46    $ 0.42    $ 1.37    $ 1.26  
                 

See accompanying Notes to the Condensed Consolidated Financial Statements.

4

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


  
(Unaudited)
 
  
Balance At
 
 
(in millions, except share amounts)
 
September 30,
2009
  
December 31, 2008
 
LIABILITIES AND EQUITY      
Current Liabilities      
Short-term borrowings $500  $287 
Long-term debt, classified as current  342   600 
Energy recovery bonds, classified as current  382   370 
Accounts payable:        
Trade creditors  864   1,096 
Disputed claims and customer refunds  816   1,580 
Regulatory balancing accounts  629   730 
Other  370   343 
Interest payable  794   802 
Income taxes payable  589   - 
Deferred income taxes  172   251 
Other  1,491   1,567 
Total current liabilities  6,949   7,626 
Noncurrent Liabilities        
Long-term debt  9,839   9,321 
Energy recovery bonds  928   1,213 
Regulatory liabilities  4,152   3,657 
Pension and other postretirement benefits  2,221   2,088 
Asset retirement obligations  1,545   1,684 
Income taxes payable  -   35 
Deferred income taxes  4,321   3,397 
Deferred tax credits  90   94 
Other  2,092   2,116 
Total noncurrent liabilities  25,188   23,605 
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, issued 370,877,751 common and 670,552 restricted shares in 2009 and issued 361,059,116 common and 1,287,569 restricted shares in 2008  6,265   5,984 
Reinvested earnings  4,097   3,614 
Accumulated other comprehensive loss  (200)  (221)
Total shareholders’ equity  10,162   9,377 
Noncontrolling Interest – Preferred Stock of Subsidiary  252   252 
Total equity  10,414   9,629 
TOTAL LIABILITIES AND EQUITY $42,551  $40,860 

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

ASSETS

   

Current Assets

   

Cash and cash equivalents

   $ 347    $ 527  

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

   573    633  

Accounts receivable:

   

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

   989    859  

Accrued unbilled revenue

   752    671  

Regulatory balancing accounts

   1,118    1,109  

Other

   786    750  

Inventories:

   

Gas stored underground and fuel oil

   192    114  

Materials and supplies

   187    200  

Income taxes receivable

   -    127  

Prepaid expenses and other

   807    667  
         

Total current assets

   5,751    5,657  
         

Property, Plant, and Equipment

   

Electric

   32,074    30,481  

Gas

   11,079    10,697  

Construction work in progress

   2,180    1,888  

Other

   14    14  
         

Total property, plant, and equipment

   45,347    43,080  

Accumulated depreciation

   (14,672  (14,188
         

Net property, plant, and equipment

   30,675    28,892  
         

Other Noncurrent Assets

   

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

   5,702    5,522  

Nuclear decommissioning trusts

   1,977    1,899  

Income taxes receivable

   624    596  

Other

   524    379  
         

Total other noncurrent assets

   8,827    8,396  
         

TOTAL ASSETS

   $ 45,253    $ 42,945  
         

See accompanying Notes to the Condensed Consolidated Financial Statements.

5

PG&E CORPORATION 
 
  
(Unaudited)
 
  Nine Months Ended 
  
September 30,
 
(in millions) 
2009
  
2008
 
Cash Flows from Operating Activities      
Net income $957  $831 
Adjustments to reconcile net income to net cash provided by operating activities:        
Depreciation, amortization, and decommissioning  1,455   1,388 
Allowance for equity funds used during construction  (71)  (51)
Deferred income taxes and tax credits, net  301   482 
Other changes in noncurrent assets and liabilities  61   87 
Effect of changes in operating assets and liabilities:        
Accounts receivable  20   (181)
Inventories  78   (153)
Accounts payable  (159)  (100)
Disputed claims and customer refunds  (700)  - 
Income taxes receivable/payable  658   177 
Regulatory balancing accounts, net  226   (94)
Other current assets  27   (123)
Other current liabilities  (50)  (68)
Other  4   (3)
Net cash provided by operating activities  2,807   2,192 
Cash Flows from Investing Activities        
Capital expenditures  (3,022)  (2,691)
Decrease (increase) in restricted cash  732   (3)
Proceeds from nuclear decommissioning trust sales  1,177   1,121 
Purchases of nuclear decommissioning trust investments  (1,219)  (1,161)
Other  14   (41)
Net cash used in investing activities  (2,318)  (2,775)
Cash Flows from Financing Activities        
Net borrowings under revolving credit facility  -   283 
Net (repayment) issuance of commercial paper, net of discount of $3 million in 2009 and $9 million in 2008  (290)  524 
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009  499   - 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $16 million in 2009 and $2 million in 2008  1,193   693 
Long-term debt matured or repurchased  (909)  (454)
Energy recovery bonds matured  (273)  (260)
Common stock issued  211   150 
Common stock dividends paid  (435)  (406)
Other  (4)  (41)
Net cash (used in) provided by financing activities  (8)  489 
Net change in cash and cash equivalents  481   (94)
Cash and cash equivalents at January 1  219   345 
Cash and cash equivalents at September 30 $700  $251 
6

Supplemental disclosures of cash flow information      
Cash received (paid) for:      
Interest, net of amounts capitalized $(493) $(449)
Income taxes, net  437   146 
Supplemental disclosures of noncash investing and financing activities        
Common stock dividends declared but not yet paid $156  $140 
Capital expenditures financed through accounts payable  229   224 
Noncash common stock issuances  50   6 
         
See accompanying Notes to the Condensed Consolidated Financial Statements. 
7

PACIFIC GAS AND ELECTRIC COMPANY 
 
  
(Unaudited)
 
  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Operating Revenues            
Electric $2,630  $2,880  $7,610  $8,039 
Natural gas  605   794   2,250   2,946 
Total operating revenues  3,235   3,674   9,860   10,985 
Operating Expenses                
Cost of electricity  997   1,282   2,763   3,406 
Cost of natural gas  134   351   879   1,613 
Operating and maintenance  1,047   982   3,143   3,009 
Depreciation, amortization, and decommissioning  450   419   1,298   1,239 
Total operating expenses  2,628   3,034   8,083   9,267 
Operating Income  607   640   1,777   1,718 
Interest income  3   20   29   77 
Interest expense  (162)  (170)  (501)  (528)
Other income (expense), net  16   (2)  52   24 
Income Before Income Taxes  464   488   1,357   1,291 
Income tax provision  111   167   374   421 
Net Income  353   321   983   870 
Preferred stock dividend requirement  3   3   10   10 
Income Available for Common Stock $350  $318  $973  $860 
  
See accompanying Notes to the Condensed Consolidated Financial Statements. 
8


PACIFIC GAS AND ELECTRIC COMPANY

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


  
(Unaudited)
 
  
Balance At
 
 
(in millions)
 
September 30,
2009
  
December 31,
2008
 
ASSETS      
Current Assets      
Cash and cash equivalents $511  $52 
Restricted cash  569   1,290 
Accounts receivable:        
Customers (net of allowance for doubtful accounts of $68 million in 2009 and $76 million in 2008)  1,609   1,751 
Accrued unbilled revenue  807   685 
Related parties  2   2 
Regulatory balancing accounts  882   1,197 
Inventories:        
Gas stored underground and fuel oil  141   232 
Materials and supplies  204   191 
Income taxes receivable  63   25 
Prepaid expenses and other  635   705 
Total current assets  5,423   6,130 
Property, Plant, and Equipment        
Electric  29,875   27,638 
Gas  10,524   10,155 
Construction work in progress  1,767   2,023 
Total property, plant, and equipment  42,166   39,816 
Accumulated depreciation  (13,983)  (13,557)
Net property, plant, and equipment  28,183   26,259 
Other Noncurrent Assets        
Regulatory assets  5,931   5,996 
Nuclear decommissioning funds  1,870   1,718 
Related parties receivable  26   27 
Income taxes receivable  518   - 
Other  365   407 
Total other noncurrent assets  8,710   8,148 
TOTAL ASSETS $42,316  $40,537 

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

LIABILITIES AND EQUITY

   

Current Liabilities

   

Short-term borrowings

   $ 1,076    $ 833  

Long-term debt, classified as current

   500    342  

Energy recovery bonds, classified as current

   399    386  

Accounts payable:

   

Trade creditors

   943    984  

Disputed claims and customer refunds

   746    773  

Regulatory balancing accounts

   371    281  

Other

   364    349  

Interest payable

   787    818  

Income taxes payable

   260    214  

Deferred income taxes

   150    332  

Other

   1,588    1,501  
         

Total current liabilities

   7,184    6,813  
         

Noncurrent Liabilities

   

Long-term debt

   10,727    10,381  

Energy recovery bonds

   528    827  

Regulatory liabilities

   4,446    4,125  

Pension and other postretirement benefits

   2,064    1,773  

Asset retirement obligations

   1,610    1,593  

Deferred income taxes

   5,267    4,732  

Other

   2,152    2,116  
         

Total noncurrent liabilities

   26,794    25,547  
         

Commitments and Contingencies

   

Equity

   

Shareholders’ Equity

   

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

   -    -  

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

   6,712    6,280  

Reinvested earnings

   4,535    4,213  

Accumulated other comprehensive loss

   (224  (160
         

Total shareholders’ equity

   11,023    10,333  

Noncontrolling Interest – Preferred Stock of Subsidiary

   252    252  
         

Total equity

   11,275    10,585  
         

TOTAL LIABILITIES AND EQUITY

   $ 45,253    $ 42,945  
         

See accompanying Notes to the Condensed Consolidated Financial Statements.

9

PACIFIC GAS AND ELECTRIC COMPANY

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


  
(Unaudited)
 
  
Balance At
 
(in millions, except share amounts) 
September 30,
2009
  
December 31,
2008
 
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current Liabilities      
Short-term borrowings $500  $287 
Long-term debt, classified as current  95   600 
Energy recovery bonds, classified as current  382   370 
Accounts payable:        
Trade creditors  864   1,096 
Disputed claims and customer refunds  816   1,580 
Related parties  14   25 
Regulatory balancing accounts  629   730 
Other  371   325 
Interest payable  777   802 
Income tax payable  612   53 
Deferred income taxes  177   257 
Other  1,289   1,371 
Total current liabilities  6,526   7,496 
Noncurrent Liabilities        
Long-term debt  9,491   9,041 
Energy recovery bonds  928   1,213 
Regulatory liabilities  4,152   3,657 
Pension and other postretirement benefits  2,170   2,040 
Asset retirement obligations  1,545   1,684 
Income taxes payable  -   12 
Deferred income taxes  4,353   3,449 
Deferred tax credits  90   94 
Other  2,057   2,064 
Total noncurrent liabilities  24,786   23,254 
Commitments and Contingencies        
Shareholders’ Equity        
Preferred stock without mandatory redemption provisions:        
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares  145   145 
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares  113   113 
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2009 and 2008  1,322   1,322 
Additional paid-in capital  3,022   2,331 
Reinvested earnings  6,597   6,092 
Accumulated other comprehensive loss  (195)  (216)
Total shareholders’ equity  11,004   9,787 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $42,316  $40,537 

STATEMENTS OF CASH FLOWS

   (Unaudited) 
       Nine Months Ended    
September  30,
 

(in millions)

 

          2010                  2009         

Cash Flows from Operating Activities

   

Net income

   $ 859    $ 957  

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

   

Depreciation, amortization, and decommissioning

   1,609    1,455  

Allowance for equity funds used during construction

   (89  (71

Deferred income taxes and tax credits, net

   328    301  

Other changes in noncurrent assets and liabilities

   (339  61  

Effect of changes in operating assets and liabilities:

   

Accounts receivable

   (246  20  

Inventories

   (65  78  

Accounts payable

   17    (159

Disputed claims and customer refunds

   -    (700

Income taxes receivable/payable

   252    658  

Regulatory balancing accounts, net

   (14  226  

Other current assets

   28    27  

Other current liabilities

   (34  (50

Other

   14    4  
         

Net cash provided by operating activities

   2,320    2,807  
         

Cash Flows from Investing Activities

   

Capital expenditures

   (2,794  (3,022

Decrease in restricted cash

   61    732  

Proceeds from sales and maturities of nuclear decommissioning trust investments

   962    1,177  

Purchases of nuclear decommissioning trust investments

   (1,001  (1,219

Other

   (25  14  
         

Net cash used in investing activities

   (2,797  (2,318
         

Cash Flows from Financing Activities

   

Borrowings under revolving credit facilities

   490    300  

Repayments under revolving credit facilities

   -    (300

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

   251    (290

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

   -    499  

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

   838    1,193  

Short-term debt matured

   (500  -  

Long-term debt matured or repurchased

   (95  (909

Energy recovery bonds matured

   (285  (273

Common stock issued

   141    211  

Common stock dividends paid

   (492  (435

Other

   (51  (4
         

Net cash provided by financing activities

   297    (8
         

Net change in cash and cash equivalents

   (180  481  

Cash and cash equivalents at January 1

   527    219  
         

Cash and cash equivalents at September 30

   $ 347    $ 700  
         

Supplemental disclosures of cash flow information

   

Cash received (paid) for:

   

Interest, net of amounts capitalized

   $ (526  $ (493

Income taxes, net

   (52  437  

Supplemental disclosures of noncash investing and financing activities

   

Common stock dividends declared but not yet paid

   $ 180    $ 156  

Capital expenditures financed through accounts payable

   229    229  

Noncash common stock issuances

   259    50  

See accompanying Notes to the Condensed Consolidated Financial Statements.

10



PACIFIC GAS AND ELECTRIC COMPANY 
 
  
(Unaudited)
 
  Nine Months Ended 
  
September 30,
 
(in millions) 
2009
  
2008
 
Cash Flows from Operating Activities      
Net income $983  $870 
Adjustments to reconcile net income to net cash provided by operating activities:        
Depreciation, amortization, and decommissioning  1,439   1,388 
Allowance for equity funds used during construction  (71)  (51)
Deferred income taxes and tax credits, net  274   470 
Other changes in noncurrent assets and liabilities  95   55 
Effect of changes in operating assets and liabilities:        
Accounts receivable  20   (179)
Inventories  78   (153)
Accounts payable  (151)  (85)
Disputed claims and customer refunds  (700)  - 
Income taxes receivable/payable  534   208 
Regulatory balancing accounts, net  226   (94)
Other current assets  26   (125)
Other current liabilities  (62)  (80)
Other  3   (4)
Net cash provided by operating activities  2,694   2,220 
Cash Flows from Investing Activities        
Capital expenditures  (3,022)  (2,691)
Decrease (increase) in restricted cash  732   (3)
Proceeds from nuclear decommissioning trust sales  1,177   1,121 
Purchases of nuclear decommissioning trust investments  (1,219)  (1,161)
Other  7   21 
Net cash used in investing activities  (2,325)  (2,713)
Cash Flows from Financing Activities        
Net borrowings under revolving credit facility  -   283 
Net (repayment) issuance of commercial paper, net of discount of $3 million in 2009 and $9 million in 2008  (290)  524 
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009  499   - 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008  847   693 
Long-term debt matured or repurchased  (909)  (454)
Energy recovery bonds matured  (273)  (260)
Preferred stock dividends paid  (10)  (10)
Common stock dividends paid  (468)  (426)
Equity contribution  688   90 
Other  6   (31)
Net cash provided by financing activities  90   409 
Net change in cash and cash equivalents  459   (84)
Cash and cash equivalents at January 1  52   141 
Cash and cash equivalents at September 30 $511  $57 
11


Supplemental disclosures of cash flow information      
Cash received (paid) for:      
Interest, net of amounts capitalized $(481) $(436)
Income taxes, net  297   138 
Supplemental disclosures of noncash investing and financing activities        
Capital expenditures financed through accounts payable $229  $224 
         
See accompanying Notes to the Condensed Consolidated Financial Statements. 
12


PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

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

(in millions)

 

  2010  2009  2010  2009 

Operating Revenues

     

Electric

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

Natural gas

   656    605    2,338    2,250  
                 

Total operating revenues

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

Operating Expenses

     

Cost of electricity

   1,102    997    2,885    2,763  

Cost of natural gas

   182    134    924    879  

Operating and maintenance

   1,224    1,047    3,172    3,143  

Depreciation, amortization, and decommissioning

   500    450    1,419    1,298  
                 

Total operating expenses

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

Operating Income

   505    607    1,820    1,777  

Interest income

   3    3    7    29  

Interest expense

   (161  (162  (481  (501

Other income, net

   25    16    20    52  
                 

Income Before Income Taxes

   372    464    1,366    1,357  

Income tax provision

   107    111    498    374  
                 

Net Income

   265    353    868    983  

Preferred stock dividend requirement

   3    3    10    10  
                 

Income Available for Common Stock

   $ 262    $ 350    $ 858    $ 973  
                 

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

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

ASSETS

   

Current Assets

   

Cash and cash equivalents

   $ 119    $ 334  

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

   573    633  

Accounts receivable:

   

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

   989    859  

Accrued unbilled revenue

   752    671  

Regulatory balancing accounts

   1,118    1,109  

Other

   781    751  

Inventories:

   

Gas stored underground and fuel oil

   192    114  

Materials and supplies

   187    200  

Income taxes receivable

   -    138  

Prepaid expenses and other

   806    662  
         

Total current assets

   5,517    5,471  
         

Property, Plant, and Equipment

   

Electric

   32,074    30,481  

Gas

   11,079    10,697  

Construction work in progress

   2,180    1,888  
         

Total property, plant, and equipment

   45,333    43,066  

Accumulated depreciation

   (14,659  (14,175
         

Net property, plant, and equipment

   30,674    28,891  
         

Other Noncurrent Assets

   

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

   5,702    5,522  

Nuclear decommissioning trusts

   1,977    1,899  

Income taxes receivable

   673    610  

Other

   357    316  
         

Total other noncurrent assets

   8,709    8,347  
         

TOTAL ASSETS

   $ 44,900    $ 42,709  
         

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

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

    September 30,    
2010

  

    December 31,    
2009

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

   

Current Liabilities

   

Short-term borrowings

   $ 986    $ 833  

Long-term debt, classified as current

   500    95  

Energy recovery bonds, classified as current

   399    386  

Accounts payable:

   

Trade creditors

   943    984  

Disputed claims and customer refunds

   746    773  

Regulatory balancing accounts

   371    281  

Other

   376    363  

Interest payable

   777    813  

Income taxes payable

   260    223  

Deferred income taxes

   154    334  

Other

   1,377    1,307  
         

Total current liabilities

   6,889    6,392  
         

Noncurrent Liabilities

   

Long-term debt

   10,378    10,033  

Energy recovery bonds

   528    827  

Regulatory liabilities

   4,446    4,125  

Pension and other postretirement benefits

   2,006    1,717  

Asset retirement obligations

   1,610    1,593  

Deferred income taxes

   5,322    4,764  

Other

   2,105    2,073  
         

Total noncurrent liabilities

   26,395    25,132  
         

Commitments and Contingencies

   

Shareholders’ Equity

   

Preferred stock without mandatory redemption provisions:

   

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

   145    145  

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

   113    113  

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

   1,322    1,322  

Additional paid-in capital

   3,228    3,055  

Reinvested earnings

   7,025    6,704  

Accumulated other comprehensive loss

   (217  (154
         

Total shareholders’ equity

   11,616    11,185  
         

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 44,900    $ 42,709  
         

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

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

Cash Flows from Operating Activities

   

Net income

   $ 868    $ 983  

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

   

Depreciation, amortization, and decommissioning

   1,580    1,439  

Allowance for equity funds used during construction

   (89  (71

Deferred income taxes and tax credits, net

   332    274  

Other changes in noncurrent assets and liabilities

   (286  95  

Effect of changes in operating assets and liabilities:

   

Accounts receivable

   (240  20  

Inventories

   (65  78  

Accounts payable

   15    (151

Disputed claims and customer refunds

   -    (700

Income taxes receivable/payable

   241    534  

Regulatory balancing accounts, net

   (14  226  

Other current assets

   28    26  

Other current liabilities

   (33  (62

Other

   14    3  
         

Net cash provided by operating activities

   2,351    2,694  
         

Cash Flows from Investing Activities

   

Capital expenditures

   (2,794  (3,022

Decrease in restricted cash

   61    732  

Proceeds from sales and maturities of nuclear decommissioning trust investments

   962    1,177  

Purchases of nuclear decommissioning trust investments

   (1,001  (1,219

Other

   15    7  
         

Net cash used in investing activities

   (2,757  (2,325
         

Cash Flows from Financing Activities

   

Borrowings under revolving credit facilities

   400    300  

Repayments under revolving credit facilities

   -    (300

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

   251    (290

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

   -    499  

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

   838    847  

Short-term debt matured

   (500  -  

Long-term debt matured or repurchased

   (95  (909

Energy recovery bonds matured

   (285  (273

Preferred stock dividends paid

   (11  (10

Common stock dividends paid

   (537  (468

Equity contribution

   170    688  

Other

   (40  6  
         

Net cash provided by financing activities

   191    90  
         

Net change in cash and cash equivalents

   (215  459  

Cash and cash equivalents at January 1

   334    52  
         

Cash and cash equivalents at September 30

   $ 119    $ 511  
         

Supplemental disclosures of cash flow information

   

Cash received (paid) for:

   

Interest, net of amounts capitalized

   $ (504  $ (481

Income taxes, net

   (87  297  

Supplemental disclosures of noncash investing and financing activities

   

Capital expenditures financed through accounts payable

   $ 229    $ 229  

See accompanying Notes to the Condensed Consolidated Financial Statements.

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 engages ingenerates revenues mainly through the businessessale and delivery of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage.to customers. The Utility is regulated primarily 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.  Therefore, theUtility 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, as well as the accounts of variable interest entities (“VIEs”) for which the Utility absorbs a majority of the risk of loss or gain.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 in the United States of America (“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, and results of operations, and cash flows for the periods presented. The 2009 presentation of borrowings and payments under the revolving credit facilities has been adjusted in the accompanying Condensed Consolidated Statements of Cash Flows to present borrowings and repayments on a gross basis rather than a net basis to conform with GAAP. The information at December 31, 20082009 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 forfiled with the year ended December 31, 2008.SEC on February 19, 2010. PG&E Corporation’s and the Utility’s combined 2009 Annual Report on Form 10-K, for the year ended December 31, 2008, together with the information incorporated by reference into such report, is referred to in this quarterly report on Form 10-Q as the “2008“2009 Annual Report.”


The accounting policies used by PG&E Corporation and This quarterly report should be read in conjunction with the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 20082009 Annual Report.  Any significant changes to those policies or new significant policies are described in Note 2 below.

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 discussed further below in these notes, relate to the Utility’s regulatory assets and liabilities, environmental remediation liability,liabilities, asset retirement obligations (“ARO”), income tax-related assets and liabilities, and pension plan and other postretirement plan obligations,obligations. In addition, management has made significant estimates and assumptions about accruals related to the rupture of a natural gas transmission pipeline owned and operated by the Utility in the City of San Bruno, California on September 9, 2010, as well as accruals for various legal matters. (See Note 10 below.) Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.


This quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s audited Consolidated Financial Statements and Notes to the Consolidated Financial Statements in the 2008 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES


Significant Accounting Policies

Consolidation of Variable Interest Entities

The significant accounting policies used by PG&E Corporation and the Utility are required to consolidate any entity over which it has control.  In most cases, control can be determined based on majority ownership.  However, for certain entities, control is difficult to discern based on voting equity interests only.  These entities are referred to as VIEs.  Characteristics of a VIE include equity investment at risk that is not sufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or equity investors that lack any of the characteristics of a controlling financial interest.  The primary beneficiary, defined as the entity that absorbs a majority of the expected losses of the VIE, receives a majority of the expected residual returns of the VIE, or both, is required to consolidate the VIE.

13

    The Utility’s exposure to VIEs relates primarily to entities with which it has a power purchase agreement.  For those entities, the Utility assesses operational risk, commodity price risk, credit risk,discussed in Notes 1 and tax benefit risk on a qualitative basis to determine whether the Utility is a primary beneficiary of the entity and is required to consolidate the entity.  This qualitative assessment also typically involves comparing the contract life to the economic life of the plant to consider the significance of the commodity price risk that the Utility might absorb.  As of September 30, 2009, the Utility is not the primary beneficiary of any entities with which it has power purchase agreements.

Although the Utility is not required to consolidate any of these VIEs as of September 30, 2009, it held a significant variable interest in three VIEs as a result of being a party to the following power purchase agreements:

·  A 25-year power purchase agreement approved by the CPUC in 2009 to purchase energy from a 250-megawatt (“MW”) solar photovoltaic energy facility beginning on the date of commercial operations (expected in 2012);

·  A 20-year power purchase agreement approved by the CPUC in 2009 to purchase energy from a 550-MW solar photovoltaic energy facility beginning on the date of commercial operations (expected in 2013); and

·  A 25-year power purchase agreement approved by the CPUC in 2008 to purchase energy from a 554-MW solar trough facility beginning on the date of commercial operations (expected in 2011).

Each of these VIEs is a subsidiary of another company whose activities are financed primarily through equity from investors and proceeds from non-recourse project-specific debt financing.  Activities of the VIEs consist of renewable energy production from electric generating facilities for sale to the Utility.  Under each of the power purchase agreements, the Utility is obligated to purchase as-delivered electric generation output from the VIEs.  The Utility does not provide any other financial or other support to these VIEs.  The Utility’s financial exposure is limited to the amounts paid for delivered electricity.

Asset Retirement Obligations

See Note 2 of the Notes to the Consolidated Financial Statements in the 20082009 Annual Report for a discussion of PG&E Corporation’s and the Utility’s accounting policy for ARO.  A reconciliation of theReport. Any significant changes in the ARO liability is as follows:

(in millions)   
ARO liability at December 31, 2008 $1,684 
Revision in estimated cash flows  (172
Accretion  73 
Liabilities settled  (40
ARO liability at September 30, 2009 $1,545 

Detailed studies of the cost to decommission the Utility’s nuclear power plantsthose policies or new significant policies are conducted every three years in conjunction with the filing of the Nuclear Decommissioning Cost Triennial Proceedings.  Estimated cash flows were revised as a result of the studies completed in the first quarter of 2009.

described below.

Pension and Other Postretirement Benefits


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


The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three and nine monthsnine-months ended September 30, 20092010 and 20082009 were as follows:

14

  
Pension Benefits
  
Other Benefits
 
  
Three Months Ended
September 30,
  
Three Months Ended
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Service cost for benefits earned $62  $59  $7  $7 
Interest cost  158   148   23   21 
Expected return on plan assets  (144)  (173)  (17)  (22)
Amortization of transition obligation  -   -   6   6 
Amortization of prior service cost  16   12   4   4 
Amortization of unrecognized (gain) loss  27   1   1   (3)
     Net periodic benefit cost  119   47   24   13 
     Less: transfer to regulatory account (1)
  (78)  (5)  -   - 
     Total $41  $42  $24  $13 
                 
(1) For the three months ended September 30, 2009 and 2008, the Utility recorded $78 million as an addition to the existing pension regulatory asset and $5 million as a reduction to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.
 

  
Pension Benefits
  
Other Benefits
 
  
Nine Months Ended
September 30,
  
Nine Months Ended
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Service cost for benefits earned $194  $177  $22  $22 
Interest cost  468   436   66   61 
Expected return on plan assets  (434)  (522)  (51)  (70)
Amortization of transition obligation  -   -   19   19 
Amortization of prior service cost  39   35   12   12 
Amortization of unrecognized (gain) loss  76   1   2   (11)
     Net periodic benefit cost  343   127   70   33 
     Less: transfer to regulatory account (1)
  (221)  (3)  -   - 
     Total $122  $124  $70  $33 
                 
(1) For the nine months ended September 30, 2009 and 2008, the Utility recorded $221 million as an addition to the existing pension regulatory asset and $3 million as a reduction to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.
 

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

Service cost for benefits earned

   $ 70    $ 62    $ 8    $ 7  

Interest cost

   162    158    21    23  

Expected return on plan assets

   (155  (144  (18  (17

Amortization of transition obligation

   -    -    6    6  

Amortization of prior service cost

   13    16    7    4  

Amortization of unrecognized loss

   11    27    1    1  
                 

Net periodic benefit cost

   101    119    25    24  
                 

Less: transfer to regulatory account (1)

   (60  (78  -    -  
                 

Total

   $ 41    $ 41    $ 25    $ 24  
                 

 

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

   

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

Service cost for benefits earned

   $ 209      $ 194    $ 27    $ 22  

Interest cost

   484    468    66    66  

Expected return on plan assets

   (467  (434  (55  (51

Amortization of transition obligation

   -    -    19    19  

Amortization of prior service cost

   39    39    19    12  

Amortization of unrecognized loss

   32    76    2    2  
                 

Net periodic benefit cost

   297    343    78    70  
                 

Less: transfer to regulatory account (1)

   (175  (221  -    -  
                 

Total

   $ 122    $ 122    $ 78    $ 70  
                 

 

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

   

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

On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional employer contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and 2008.


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


Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133

Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

On January 1, 2009,2010, PG&E Corporation and the Utility adopted Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instrumentsan accounting standards update that changes when and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”).  SFAS No. 161 requireshow to determine, or re-determine, whether an entity to provide qualitative disclosures about its objectives and strategiesis a variable interest entity (“VIE”), which could require consolidation. In addition, the new guidance replaces the quantitative approach for using derivative instruments and quantitative disclosures that detail the fair value amounts of, and gains and losses on, derivative instruments.  SFAS No. 161 also requires disclosures about credit risk-related contingent features of derivative instruments.  (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

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Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51

On January 1, 2009, PG&E Corporation and the Utility adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS No. 160”).  SFAS No. 160 establishes accounting and reporting standards fordetermining who has a noncontrollingcontrolling financial interest in a subsidiaryVIE with a qualitative approach, and forrequires ongoing assessments of whether an entity is the deconsolidationprimary beneficiary of a subsidiary.  SFAS No. 160 defines a “noncontrolling interest,” previously called a “minority interest,” as the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent.  Among other items, SFAS No. 160 requires that an entity (1) include a noncontrolling interest in its consolidated statement of financial position within equity separate from the parent’s equity, (2) report amounts inclusive of both the parent’s and noncontrolling interest’s shares in consolidated net income, and (3) separately report the amounts of consolidated net income attributable to the parent and noncontrolling interest on the consolidated statement of operations.  If a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be measured at fair value, and a gain or loss must be recognized in net income based on such fair value.

PG&E Corporation has reclassified its noncontrolling interest in the Utility from Preferred Stock of Subsidiaries to equity in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 160 for all periods presented.VIE. The Utility had no material noncontrolling interests in consolidated subsidiaries as of September 30, 2009 and December 31, 2008.

PG&E Corporation and the Utility applied the presentation and disclosure requirements of SFAS No. 160 retrospectively.  Other than the change in presentation of noncontrolling interests, adoption of SFAS No. 160the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Issuer’s Accounting

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

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

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

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

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

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

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

Improving Disclosures about Fair Value with a Third-Party Credit Enhancement


Measurements

On January 1, 2009,2010, PG&E Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”).  EITF 08-5 clarifies the unitan accounting standards update that requires disclosures regarding significant transfers in and out of account in determining the fair value of a liability.  Specifically, it requires an entity to exclude any third-party credit enhancements that are issued with,hierarchy levels, and are inseparable from, a debt instrument from the fair value measurement inputs and valuation techniques. Furthermore, the update requires presentation of that debt instrument.  Adoptiondisaggregated activity within the reconciliation for fair value measurements using significant unobservable (Level 3) inputs, beginning for the first quarter of EITF 08-52011. 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.


Equity Method Investment Accounting

On January 1, 2009, PG&E Corporation and the Utility adopted EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”).  EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost.  Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than the Business Combinations Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”).  However, the investor in an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the investor’s share of the investee’s net assets exceeds the investor’s initial costs.  An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment.  Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings.  Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Subsequent Events

On June 30, 2009, PG&E Corporation and the Utility adopted SFAS No. 165, “Subsequent Events” (“SFAS No. 165”).  SFAS No. 165 does not significantly change the prior accounting practice for subsequent events, except for the requirement to disclose the date through which an entity has evaluated subsequent events and the basis for that date.  PG&E Corporation and the Utility have evaluated material subsequent events through October 29, 2009, the issue date of PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.  Other than this disclosure, adoption of SFAS No. 165 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Interim Disclosures about Fair Value of Financial Instruments

On June 30, 2009, PG&E Corporation and the Utility adopted FASB Staff Position (“FSP”) SFAS 107-1 and Accounting Principles Board (“APB”) 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This FSP requires disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods.  In particular, an entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and to disclose where the carrying amount is classified in the Condensed Consolidated Balance Sheets.  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)
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Recognition and Presentation of Other-Than-Temporary Impairments

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.”  Under this FSP, to assess whether an other-than-temporary impairment exists for a debt security, an entity must (1) evaluate the likelihood of liquidating the debt security prior to recovering its cost basis and (2) determine if any impairment of the debt security is related to credit losses.  In addition, this FSP requires enhanced disclosures of other-than-temporary impairments on debt and equity securities in the financial statements.  However, this FSP does not amend recognition and measurement guidance for other-than-temporary impairments of equity securities.  Adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.”  This FSP provides guidance on estimating fair value when the volume or the level of activity for an asset or a liability has significantly decreased or when transactions are not orderly, when compared with normal market conditions.  In particular, this FSP calls for adjustments to quoted prices or historical transaction data when estimating fair value in such circumstances.  This FSP also provides guidance to identify such circumstances.  Furthermore, this FSP requires fair value measurement disclosures made pursuant to the Fair Value Measurements and Disclosures Topic of the FASB ASC to be categorized by major security type (i.e., based on the nature and risks of the security).  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)  Other than this change, adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles

On July 1, 2009, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-01, “Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles” (“ASU No. 2009-01”).  ASU No. 2009-01 re-defines authoritative GAAP for nongovernmental entities to be only comprised of the FASB Accounting Standards CodificationTM (“Codification”) and, for SEC registrants, guidance issued by the SEC.  The Codification is a reorganization and compilation of all then-existing authoritative GAAP for nongovernmental entities, except for guidance issued by the SEC.  The Codification is amended to effect non-SEC changes to authoritative GAAP.  Adoption of ASU No. 2009-01 only changed the referencing convention of GAAP in PG&E Corporation’s and the Utility’s Notes to the Condensed Consolidated Financial Statements.

Accounting Pronouncements Issued But Not Yet Adopted

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.”  This FSP amends and expands the disclosure requirements of the Compensation - Retirement Benefits Topic of the FASB ASC.  In particular, this FSP requires an entity to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets.  In addition, this FSP requires quantitative disclosures showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets that are measured using significant unobservable inputs.  This FSP is effective prospectively for PG&E Corporation and the Utility for the annual period ending December 31, 2009 and for subsequent annual periods.  PG&E Corporation and the Utility will include the expanded disclosures described above in PG&E Corporation’s and the Utility’s Notes to the Consolidated Financial Statements for the annual period ending December 31, 2009.

Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS No. 166”).  SFAS No. 166 eliminates the concept of a qualifying special-purpose entity and clarifies the requirements for derecognizing a financial asset and for applying sale accounting to a transfer of a financial asset.  In addition, SFAS No. 166 requires an entity to disclose more information about transfers of financial assets, the entity’s continuing involvement, if any, with transferred financial assets, and the entity’s continuing risks, if any, from transferred financial assets.  SFAS No. 166 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010.  PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 166.
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Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”).  SFAS No. 167 amends the Consolidation Topic of the FASB ASC regarding when and how to determine, or re-determine, whether an entity is a VIE.  In addition, SFAS No. 167 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach.  Furthermore, SFAS No. 167 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE.  SFAS No. 167 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010.  PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 167.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS


The Utility accounts for

As a regulated entity, the financial effects of regulation based on the Regulated Operations Topic of the FASB ASC, which applies to regulated entities whoseUtility’s rates are designed to recover the costcosts of providing service (“cost-of-service rate regulation”).  All of the Utility’s operations are subject to cost-of-service rate regulation.


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 regulatoryRegulatory assets are amortized over the future periods whenthat 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.

To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Regulatory Assets

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

  
Balance At
 
 
(in millions)
 
September 30,
2009
  
December 31,
2008
 
Pension benefits $1,732  $1,624 
Energy recovery bonds  1,219   1,487 
Deferred income tax  982   847 
Utility retained generation  754   799 
Price risk management  340   362 
Environmental compliance costs  398   385 
Unamortized loss, net of gain, on reacquired debt  209   225 
Regulatory assets associated with plan of reorganization  87   99 
Contract termination costs  71   82 
Other  139   86 
Total long-term regulatory assets $5,931  $5,996 

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 14 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.)

In connection with the December 19, 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”), the CPUC authorized the Utility to recover $2.21 billion (“settlement regulatory asset”) over a nine year period.  In order to lower the costs borne by customers, PG&E Energy Recovery Funding LLC (“PERF”), a wholly owned consolidated subsidiary of the Utility, issued energy recovery bonds (“ERB”) to refinance the settlement regulatory asset.  The regulatory asset for ERBs represents the refinancing of the settlement regulatory asset.  The regulatory asset is amortized over the life of the bonds consistent with the period over which the related billed revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.

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    The regulatory assets for deferred income tax represent deferred income tax benefits previously passed through to customers offset by deferred income tax liabilities.  The CPUC requires the Utility to pass through certain tax benefits to customers, ignoring the effect of deferred taxes on rates.  Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 years.

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 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 16 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 of the Notes to the Condensed Consolidated Financial Statements.)

The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation expense 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 30 years.  (See Note 11 of the Notes to the Condensed Consolidated Financial Statements.)

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 remaining original amortization period of the reacquired debt over the next 17 years, and these costs will be fully recovered by 2026.

Regulatory assets associated with the Utility’s plan of reorganization represent costs incurred in relation to the Utility’s plan of reorganization under Chapter 11, including financing costs and costs to oversee the environmental enhancement projects of the Pacific Forest and Watershed Land Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization.  The Utility expects to recover these costs over the remaining periods ranging from 4 to 25 years, and these costs should be fully recovered by 2034.

The regulatory assets for contract termination costs represent costs that the Utility incurred in terminating a 30-year power purchase agreement.  These costs are being amortized and collected in rates on a straight-line basis through the end of September 2014, the power purchase agreement’s original termination date.

At September 30, 2009, “Other” primarily consisted of regulatory assets relating to ARO costs recorded in accordance with GAAP, which are probable of future recovery through the ratemaking process, as well as 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”), as approved by the CPUC for future recovery.  At December 31, 2008, “Other” primarily consisted of regulatory assets relating to ARO costs, as well as scheduling coordinator costs that the Utility incurred beginning in 1998 in its capacity as scheduling coordinator for its then-existing wholesale electric transmission customers.

In general, the Utility does not earn a return on regulatory assets in which the related costs do not accrue interest.  Accordingly, the Utility earns a return only on the Utility’s retained generation regulatory assets; unamortized loss, net of gain, on reacquired debt; and regulatory assets associated with the plan of reorganization.

Current Regulatory Assets

At September 30, 2009 and December 31, 2008, the Utility had current regulatory assets of $421 million and $355 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 less than one year.  (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)  Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.
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Regulatory Liabilities

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

  
Balance At
 
 
(in millions)
 
September 30,
2009
  
December 31,
2008
 
Cost of removal obligation $2,886  $2,735 
Public purpose programs  521   442 
Recoveries in excess of asset retirement obligation  498   226 
Price risk management  82   81 
Gateway Generating Station  65   67 
Environmental remediation insurance recoveries  39   52 
Other  61   54 
Total long-term regulatory liabilities $4,152  $3,657 

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

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future.  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 decommissioning 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.

The regulatory liability for price risk management represents the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year.  (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

The regulatory liability related to the Gateway Generating Station (“Gateway”) represents the gain associated with the Utility’s acquisition of Gateway, as part of a settlement that the Utility entered with Mirant Corporation, to be credited to customers in future rates.  The regulatory liability is being amortized over 30 years beginning in January 2009, when Gateway was placed in service.

The regulatory liabilities associated with environmental remediation insurance recoveries represent amounts that are refunded to customers as a reduction to rates, as costs are incurred for hazardous substance remediation.

“Other” is an aggregate of various other regulatory liabilities representing amounts collected for future costs.

Current Regulatory Liabilities

At September 30, 2009 and December 31, 2008, the Utility had current regulatory liabilities of $232 million and $313 million, respectively, primarily consisting of regulatory liabilities for the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates.  Current regulatory liabilities are included in Current Liabilities – Other in the Condensed Consolidated Balance Sheets.

Regulatory Balancing Accounts

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 creditedrefunded to customers are recorded as regulatory balancing account liabilities.


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Regulatory Assets

Current Regulatory Assets

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

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

   Balance at 
(in millions)  

    September 30, 2010    

  

    December 31, 2009    

 

Pension benefits

   $ 1,490    $ 1,386  

Deferred income taxes

   1,158    1,027  

Energy recovery bonds

   833    1,124  

Utility retained generation

   684    737  

Price risk management

   599    346  

Environmental compliance costs

   393    408  

Unamortized loss, net of gain, on reacquired debt

   186    203  

Other

   359    291  
         

Total long-term regulatory assets

   $ 5,702    $ 5,522  
         

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

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

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

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

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

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

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

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

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

Regulatory Liabilities

Current Regulatory Liabilities

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

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

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

Cost of removal obligation

   $  3,182     $  2,933  

Public purpose programs

   599     508  

Recoveries in excess of ARO

   542     488  

Other

   123     196  
          

Total long-term regulatory liabilities

   $  4,446     $  4,125  
          

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

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

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

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

Regulatory Balancing Accounts

The Utility’s current regulatory balancing accounts represent the amountamounts expected to be received from or refunded to or received from 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 Assetsother noncurrent assetsRegulatoryregulatory assets and Noncurrent Liabilitiesnoncurrent liabilitiesRegulatoryregulatory liabilities in the Condensed Consolidated Balance Sheets.


Current Regulatory Balancing Accounts, net


  
Receivable (Payable)
 
  
Balance At
 
(in millions) 
September 30, 2009
  
December 31, 2008
 
Utility generation $199  $164 
Gas fixed cost  167   60 
Transmission revenue  147   173 
Public purpose programs  (70)  (263)
Energy procurement costs  (117)  598 
Energy recovery bonds  (167)  (231)
Other  94   (34)
Total regulatory balancing accounts, net
 $253  $467 

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

Utility generation

   $  223    $  355  

Public purpose programs

   158    83  

Gas fixed cost

   134    93  

Distribution revenue adjustment mechanism

   107    152  

Electric transmission

   (19  114  

Energy recovery bonds

   (93  (185

Other

   237    216  
         

Total regulatory balancing accounts, net

   $  747    $  828  
         

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, the under-collectionthere is generally decreasesan over-collection due to higher rates and electric usage that cause an increase in generation revenues.


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

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


volumes.

The electric transmission revenue balancing account representsaccounts represent the difference between electric transmission wheeling revenues received by the Utility from the California Independent System Operator (“CAISO”) (on behalf of electric transmission wholesale customers) and refunds of those revenues to customers, plus interest.


The public purpose programsthe 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 primarily trackinclude the recovery of the authorized public purpose program revenue requirement and the actual cost of such 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.  Aend-user customer refund of $230 million from the California Energy Commission for unspent renewable program funding previously collectedbalancing account, which is being returnedused to refund to customers through lower rates throughout 2009.

over-collected electric transmission revenues.

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, and rates are set to recover such expected costs.


The energy recovery bondsERB balancing account records certainthe benefits and costs associated with ERBs that are provided to, or received from, customers. In addition, thisThis 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 werewas issued.

At September 30, 20092010 and December 31, 2008, “Other” includes2009, “other” primarily consisted of the California Alternate Rates for EnergyDepartment of Water Resources (“DWR”) power charge collection balancing account, which recordsensures amounts collected from customers for DWR-delivered power are remitted to the DWR; balancing accounts that track recovery of the authorized revenue shortfall associated withrequirements and costs related to the low-income customer assistance program.  Participation in the program is generally impacted by economic conditions.  Program spending increases as more customers participate in the programs, resulting in an under-collection.  At December 31, 2008, “Other” also included incentive awards earnedSmartMeterTM advanced metering project; and balancing accounts that track recoverable hazardous substance clean-up costs incurred by the Utility for implementing customer energy efficiency programs.


21

Utility.

NOTE 4: DEBT


PG&E Corporation


Senior

Convertible Subordinated Notes


On March 12, 2009,

PG&E Corporation issued $35016,370,779 shares of common stock upon conversion of the $247 million principal amount of 5.75% SeniorPG&E Corporation’s 9.50% Convertible Subordinated Notes due April 1, 2014.


at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding as of September 30, 2010.

Credit Facility


Facilities

At September 30, 2009,2010, PG&E Corporation had no$90 million of cash borrowings outstanding under its $187 million revolving credit facility.  PG&E Corporation amended its revolving credit facility on April 27, 2009 to remove Lehman Brothers Bank, FSB (“Lehman Bank”) as a lender.  Prior to the amendment, the total borrowing capacity under the revolving credit facility was $200 million, including a commitment from Lehman Bank that represented $13 million, or 7%,which had an average interest rate of the total.0.59%.

Utility


Utility

Senior Notes


On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 6, 2009,1, 2037.

On September 15, 2010, the Utility issued $550 million principal amount of 6.25%3.5% Senior Notes due MarchOctober 1, 2039.


2020.

On June 11, 2009,October 12, 2010, the Utility issued $500$250 million principal amount of Floating Rate Senior Notes due June 10, 2010.October 11, 2011. The interest rate for the Floating Rate Senior Notes is equal to the three-month London Interbank Offered Rate (“LIBOR”) plus 0.95%0.58% and will reset quarterly beginning on September 10, 2009.  At September 30, 2009, the interest rate on the Floating Rate Senior Notes was 1.25%.


January 11, 2011.

Pollution Control Bonds


The California Pollution Control Financing Authority and

On April 8, 2010, the California Infrastructure and Economic Development Bank (“CIEDB”), serving as conduit issuer, have issued various series of tax-exempt pollution control bonds for the benefit of the Utility.


On September 1, 2009, the CIEDB issued $149$50 million of tax-exempt pollution control bonds series 2009 A and BSeries 2010E due on November 1, 2026 and $160 million of tax-exempt pollution control bonds series 2009 C and D due on December 1, 2016.loaned the proceeds to the Utility. The proceeds were used to repurchaserefund the corresponding related series of 2008 pollution control bonds.  The series 2009 bonds issued in 2005 which were repurchased by the Utility in 2008. The Series 2010E bonds bear interest at par with an initial rate of 0.20%, are variable rate demand notes with interest resetting daily2.25% per year through April 1, 2012 and backed by direct-pay letters of credit.  Unlike the series 2008 bonds, interest earned on the series 2009 bonds is not subject to the alternative minimum tax (“AMT”).  A provision in the American Recovery and Reinvestment Act of 2009 allows certain tax-exempt bonds that are subject to AMTmandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode. Interest is payable semi-annually in arrears on April 1 and October 1.

On September 20, 2010, the Utility repurchased $50 million principal amount of pollution control bonds Series 2008F and $45 million principal amount of pollution control bonds Series 2008G that were subject to mandatory tender on the same date. The bonds will be reissuedremarketed in a fixed or refunded in 2009variable rate mode every 30 days until the bonds are reissued. The Utility, as bondholder, will be both the payer and the recipient of principal and interest payments on each remarketing day.

Credit Facilities and Short-Term Borrowings

On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. Of the total credit capacity, $500 million was used to replace the $500 million Floating Rate Senior Notes that matured on June 10, 2010. The aggregate facility of $750 million includes a $75 million commitment for swingline loans, or 2010 as tax-exempt bondsloans that are not subject to AMT.  Asmade available on a result, the series 2009 bonds were issuedsame-day basis and are repayable in full within 30 days. The Utility can, at a lower interest rate, reducingany time, repay amounts outstanding in whole or in part. The credit agreement expires on February 26, 2012, unless extended for additional periods at the Utility’s request and at the sole discretion of each lender.

Borrowings under the credit agreement (other than swingline loans) will bear interest expense.


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

The credit agreement contains covenants that are substantially similar to the covenants contained in the Utility’s existing $1.9 billion credit facility, and Short-Term Borrowings


are usual and customary for credit facilities of this type. Both credit facilities require that the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of, at most, 65% as of the end of each fiscal quarter.

At September 30, 2009,2010, the Utility had $273$400 million of cash borrowings outstanding under its $1.9 billion revolving credit facility which had an average interest rate of 0.45%, and no cash borrowings outstanding under its $750 million revolving credit facility. The $400 million borrowing was repaid on October 29, 2010.

At September 30, 2010, the Utility had $289 million of letters of credit outstanding under the Utility’s $1.94its $1.9 billion revolving credit facility.

The Utility amended itsUtility’s revolving credit facility on April 27, 2009 to remove Lehman Bank as a lender.  Prior to the amendment, the total borrowing capacity under the revolving credit facility was $2.0 billion, including a commitment from Lehman Bank that represented $60 million, or 3%, of the total.


The revolving credit facilityfacilities also providesprovide liquidity support for commercial paper offerings. At September 30, 2009,2010, the Utility had no$586 million of commercial paper outstanding.

outstanding at an average yield of 0.54%.

Energy Recovery Bonds


PG&E Energy Recovery Funding LLC,

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 in 2005.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.component to be collected from the Utility’s electricity customers. The total amount of ERB principal outstanding was $1.3 billion$927 million at September 30, 2009.


2010.

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


22

NOTE 5: EQUITY


PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 20092010 were as follows:


  
PG&E Corporation
  
Utility
 
(in millions) 
Total
Equity
  
Total
Shareholders’ Equity
 
Balance at December 31, 2008 $9,629  $9,787 
Net income  957   983 
Common stock issued  261   - 
Share-based compensation amortization  17   - 
Common stock dividends declared and paid  (309)  (468)
Common stock dividends declared but not yet paid  (156)  - 
Preferred stock dividend requirement  -   (10)
Preferred stock dividend requirement of subsidiary  (10)  - 
Tax benefit from employee stock plans  4   3 
Other comprehensive income  21   21 
Equity contribution  -   688 
Balance at September 30, 2009 $10,414  $11,004 

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

Balance at December 31, 2009

   $  10,585    $  11,185  

Net income

   859    868  

Common stock issued

   400    -  

Share-based compensation expense

   28    -  

Common stock dividends declared

   (527  (537

Preferred stock dividend requirement

   -    (10

Preferred stock dividend requirement of subsidiary

   (10  -  

Tax benefit from employee stock plans

   4    3  

Other comprehensive loss

   (64  (63

Equity contribution

   -    170  
         

Balance at September 30, 2010

   $  11,275    $  11,616  
         

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

For the nine months ended September 30, 2009,2010, PG&E Corporation contributed equity of $688$170 million to the Utility in order to maintain the 52% common equity targetratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.


Comprehensive Income

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

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

Net income

   $  261     $  321     $  859    $  957  

Employee benefit plan adjustment, net of tax(1)

   8     7     (64  21  
                   

Comprehensive income

   $  269     $  328     $  795    $  978  
                   

 

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

    

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

Net income

  $  265    $  353    $  868   $  983  

Employee benefit plan adjustment, net of tax(1)

   9     7     (63  21  
                   

Comprehensive income

  $  274    $  360    $  805   $  1,004  
                   

 

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

    

Dividends


PG&E Corporation

During the nine months ended September 30, 2009, the Utility paid common stock dividends totaling $468 million to PG&E Corporation.


During the nine months ended September 30, 2009,2010, PG&E Corporation paid common stock dividends totaling $435$492 million, net of $18$12 million that was reinvested in additional shares of common stock by participants in the PG&E Corporation Dividend Reinvestment and Stock Purchase Plan. On September 16, 2009,15, 2010, the Board of Directors of PG&E Corporation declared a dividenddividends of $0.42$0.455 per share, totaling $156$180 million, which waswere paid on October 15, 20092010 to shareholders ofon record onas of September 30, 2009.

2010.

Utility

During the nine months ended September 30, 2009,2010, the Utility paid cashcommon stock dividends totaling $10$537 million to PG&E Corporation.

During the nine months ended September 30, 2010, the Utility paid dividends totaling $11 million to holders of its outstanding series of preferred stock. On September 16, 2009,15, 2010, the Board of Directors of the Utility declared a cash dividenddividends totaling $3 million on its outstanding series of preferred stock, payable on November 15, 20092010, to shareholders on record as of record on October 30, 2009.


29, 2010.

NOTE 6: EARNINGS PER SHARE


Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, by 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 9.5% Convertible Subordinated Notes (“Convertible Subordinated Notes”) aremet the criteria of participating securities as the holders were entitled to receive pass-through dividends and meet the criteria of participating securities.  All of the participating securities participate in dividends on a 1:1 basis with shares of common stock.


23

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

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


  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions, except per share amounts) 
2009
  
2008
  
2009
  
2008
 
Basic            
Income Available for Common Shareholders $318  $304  $947  $821 
Less: distributed earnings to common shareholders  156   140   465   419 
Undistributed earnings $162  $164  $482  $402 
Allocation of undistributed earnings to common shareholders                
Distributed earnings to common shareholders $156  $140  $465  $419 
Undistributed earnings allocated to common shareholders  155   156   461   382 
Total common shareholders earnings $311  $296  $926  $801 
Weighted average common shares outstanding, basic  370   357   367   356 
Convertible Subordinated Notes  16   19   17   19 
Weighted average common shares outstanding and participating securities  386   376   384   375 
Net earnings per common share, basic                
Distributed earnings, basic (1)
 $0.42  $0.39  $1.27  $1.18 
Undistributed earnings, basic  0.42   0.44   1.26   1.07 
Total $0.84  $0.83  $2.53  $2.25 
    
(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.
 

EPS:

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

Basic

    

Income available for common shareholders

 $  258   $  318   $  849   $  947  

Less: distributed earnings to common shareholders

  179    156    527    465  
                

Undistributed earnings

 $  79   $  162   $  322   $  482  
                

Allocation of undistributed earnings to common shareholders

    

Distributed earnings to common shareholders

 $  179   $  156   $  527   $  465  

Undistributed earnings allocated to common shareholders

  79    155    313    461  
                

Total common shareholders earnings

 $  258   $  311   $  840   $  926  
                

Weighted average common shares outstanding, basic

  390    370    378    367  

Convertible subordinated notes

  -    16    11    17  
                

Weighted average common shares outstanding and participating securities

  390    386    389    384  
                

Net earnings per common share, basic

    

 

Distributed earnings, basic(1)

 $  0.46   $  0.42   $  1.39   $  1.27  

Undistributed earnings, basic

  0.20    0.42    0.83    1.26  
                

Total

 $  0.66   $  0.84   $  2.22   $  2.53  
                

 

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

   

In calculating diluted EPS, PG&E Corporation applies the if-converted“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 earnings per shareEPS for three and nine months ended September 30, 2010 and 2009:


  
September 30, 2009
 
(in millions, except per share amounts) 
Three Months Ended
  
Nine Months Ended
 
Diluted      
Income Available for Common Shareholders $318  $947 
Add earnings impact of assumed conversion of participating securities:        
Interest expense on Convertible Subordinated Notes, net of tax
  4   12 
Unrealized loss on embedded derivative, net of tax
  -   2 
Income Available for Common Shareholders and Assumed Conversion $322  $961 
         
Weighted average common shares outstanding, basic  370   367 
Add incremental shares from assumed conversions:        
Convertible Subordinated Notes
  16   17 
Employee share-based compensation
  2   2 
Weighted average common shares outstanding, diluted  388   386 
Total earnings per common share, diluted $0.83  $2.49 

Stock

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

Diluted

        

Income available for common shareholders

  $  258    $  318    $  849    $  947  

Add earnings impact of assumed conversion of participating securities:

        

Interest expense on convertible subordinated notes, net of tax

   -     4     8     12  

Unrealized loss on embedded derivative, net of tax

   -     -     -     2  
                    

Income available for common shareholders and assumed conversion

  $  258    $  322    $  857    $  961  
                    

Weighted average common shares outstanding, basic

   390     370     378     367  

Add incremental shares from assumed conversions:

        

Convertible subordinated notes

   -     16     11     17  

Employee share-based compensation

   2     2     2     2  
                    

Weighted average common shares outstanding, diluted

   392     388     391     386  
                    

Total earnings per common share, diluted

  $  0.66    $  0.83    $  2.19    $  2.49  
                    

For each of the periods presented above, the calculation of outstanding shares on a diluted basis excluded an insignificant amount of options to purchase 7,285 and 11,935 shares of PG&E Corporation common stocksecurities that were excluded from the computation of diluted EPS for the three and nine months ended September 30, 2009, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these periods.


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 earnings per share for three and nine months ended September 30, 2008:
24

  
September 30, 2008
 
(in millions, except per share amounts) 
Three Months Ended
  
Nine Months Ended
 
Diluted      
Income Available for Common Shareholders $304  $821 
Less: distributed earnings to common shareholders  140   419 
Undistributed earnings $164  $402 
         
Allocation of undistributed earnings to common shareholders        
Distributed earnings to common shareholders $140  $419 
Undistributed earnings allocated to common shareholders  156   382 
Total common shareholders earnings $296  $801 
         
Weighted average common shares outstanding, basic  357   356 
Convertible Subordinated Notes  19   19 
Weighted average common shares outstanding and participating securities, basic  376   375 
Weighted average common shares outstanding, basic  357   356 
Employee share-based compensation  1   1 
Weighted average common shares outstanding, diluted  358   357 
Convertible Subordinated Notes  19   19 
Weighted average common shares outstanding and participating securities, diluted  377   376 
Net earnings per common share, diluted        
Distributed earnings, diluted $0.39  $1.17 
Undistributed earnings, diluted  0.44   1.07 
Total earnings per common share, diluted $0.83  $2.24 

Stock options to purchase 7,285 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three and nine months ended September 30, 2008, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these periods.

antidilutive.

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES


Use of Derivative Instruments


The Utility faces market risk primarily related to electricity and natural gas commodity prices. Substantially allAll 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;

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

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.

·  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 that commit the Utility to purchase a commodity or make a cash settlement at a specified price and future date.

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

25

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.  Certain commodity-related price risk management activities reduce the cash flow variability associated with fluctuating commodity prices.  Prior to September 2009, the Utility designated qualifying derivative transactions as cash flow hedges for accounting purposes. 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 including those designated as cash flow hedges, are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.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.  As of September 30, 2009, the Utility de-designated all cash flow hedge relationships.  Due to the regulatory accounting treatment described above, the de-designation of cash flow hedge relationships had no impact on Income Available for Common Shareholders or the Condensed Consolidated Balance Sheet.


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


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


Electricity Procurement


The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under California Department of Water Resources (“DWR”)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 and, therefore, are recorded at fair value within the Condensed Consolidated Balance Sheets.instruments. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.  Derivative instruments that are eligible for the normal purchase and normal sales exception are not required to be recorded at fair value.


A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the cash flow variability associated with fluctuating electricity prices,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 and are recorded at fair value within the Condensed Consolidated Balance Sheets.


instruments.

Electric Transmission Congestion Revenue Rights


The CAISO-controlledCAISO 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 Update on April 1, 2009.  The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load servingload-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 servingload-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). InThe CRRs held by the third quarter of 2009, the Utility acquired CRRs through both allocation and auction.


CRRs are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.

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 future cash flow variability associated with fluctuating natural gas prices,volatility in customer rates, the Utility purchases financial instruments such as futures, swaps, and options.options to reduce future cash flow variability associated with fluctuating natural gas prices. These financial instruments are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.

26

instruments.

Natural Gas Procurement (Small Commercial and Residential Customers)


The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “core,” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot marketmarkets to balance such seasonal supply and demand.


The Utility manages its winter exposure to variable natural gas prices in accordance with its CPUC-approved annual core portfolio hedging implementation plan.  Accordingly, the Utility has entered into variouspurchases financial instruments such as swaps and options intendedas part of its core winter hedging program in order to reduce the uncertainty associated with fluctuating naturalmanage customer exposure to high gas purchase prices.prices during peak winter months. These financial instruments are considered derivative instruments that are recorded at fair value within the Condensed Consolidated Balance Sheets.

Other Risk

At September 30, 2009, PG&E Corporation had $247 million of Convertible Subordinated Notes outstanding scheduled to mature on June 30, 2010.   The holders of the Convertible Subordinated Notes are 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.  The dividend participation rights associated with the Convertible Subordinated Notes are embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements.  Changes in fair value of the dividend participation rights are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as non-operating expense or income (in Other income (expense), net).

instruments.

Volume of Derivative Activity


At September 30, 2009,2010, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts waswere as follows:


   
Contract Volumes (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  331,103,829   192,707,140   21,277,500   - 
 Options  136,232,644   86,837,080   -   - 
                  
Electricity (Megawatt-hours)Forwards, Futures, and Swaps  3,508,656   7,644,024   5,093,912   4,768,447 
 Options  9,400   11,450   110,980   557,512 
 Congestion Revenue Rights  55,374,468   64,267,318   59,648,715   107,581,890 
                  
PG&E Corporation Equity
(Shares)
Dividend Participation Rights  16,370,789   -   -   - 
                  
(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 2014 and 2022.
 
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.
 
(4) Million British Thermal Units.
 
27

      Contract Volume(1) 

    Underlying    

Product

  

    Instruments    

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

Natural Gas (3)

(MMBtus(4))

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

 

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

  

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

Presentation of Derivative Instruments in the Financial Statements


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


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

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

 

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

  

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

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


(in millions)
 
Gross Derivative Balance (1)
  
Netting (2)
  
Cash Collateral (2)
  
Total Derivative Balances
 
Commodity Risk (PG&E Corporation and Utility)
 
Current Assets – Prepaid expenses and other $48  $(9) $63  $102 
Other Noncurrent Assets – Other  120   (40)  21   101 
Current Liabilities – Other  (253)  9   84   (160)
Noncurrent Liabilities – Other  (379)  40   29   (310)
Total commodity risk $(464) $-  $197  $(267)
                 
Other Risk Instruments (3) (PG&E Corporation Only)
 
Current Liabilities – Other $(20) $-  $-  $(20)
Total derivatives $(484) $-  $197  $(287)
                 
(1) See Note 8 of the Notes to the Condensed Consolidated Financial Statements 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.
 
(3) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.
 

Expenses related to the dividend participation rights are not recoverable in customers’ rates.  Therefore, changes in the fair value of these instruments are recorded in PG&E Corporation’s Condensed Consolidated Statements of Income.

For the nine month period ended September 30, 2009, the gains

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

 

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

  

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

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


(in millions)
   
Commodity Risk
 (PG&E Corporation and Utility)
 
Unrealized gain/(loss) - Regulatory assets andliabilities (1)
 $32 
Realized gain/(loss) - Cost of electricity(2)
  (558)
Realized gain/(loss)- Cost of natural gas (2)
  (30)
Total commodity risk instruments $(556)
Other Risk Instruments(3)
 (PG&E Corporation Only)
 
Other income, net $1 
Total other risk instruments $1 
     
(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.
 
(3) This category relates to dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.
 
28

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

 

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

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

   

   

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


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


At September 30, 2009,2010, the additional cash collateral the Utility would be required to post if its credit-risk-relatedcredit risk-related contingent features were triggered was as follows:


(in millions)   
Derivatives in a liability position with credit-risk-relatedcontingencies that are not fully collateralized
 $(541)
Related derivatives in an asset position  57 
Collateral posting in the normal course of business relatedto these derivatives
  70 
Net position of derivative contracts/additional collateral posting requirements (1)
 $(414)
     
(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.
 

(in millions)

Derivatives in a liability position with credit-risk-related contingencies that are not fully collateralized$  (652
Related derivatives in an asset position1
Collateral posting in the normal course of business related to these derivatives74
Net position of derivative contracts/additional collateral posting requirements(1)        $  (577

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

NOTE 8: FAIR VALUE MEASUREMENTS


PG&E Corporation and the Utility determinemeasure 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 of certain assets and liabilitiesis 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.liabilities in active markets.

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

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

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

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

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

Assets:

        

Money market investments

   $  227     $ -     $ -     $  227  
                    

Nuclear decommissioning trusts

        

U.S. equity securities(1)

   796     6     -     802  

Non-U.S. equity securities

   328     -     -     328  

U.S. government and agency securities

   757     48     -     805  

Municipal securities

   -     107     -     107  

Other fixed income securities

   -     80     -     80  
                    

Total nuclear decommissioning trusts(2)

   1,881     241     -     2,122  
                    

Price risk management instruments

        

Electric(3)

   83     -     -     83  
                    

Total price risk management instruments

   83     -     -     83  
                    

Rabbi trusts

        

Equity securities

   23     -     -     23  

Life insurance contracts

   -     65     -     65  
                    

Total rabbi trusts

   23     65     -     88  
                    

Long-term disability trust

        

U.S. equity securities(1)

   7     23     -     30  

Corporate debt securities(1)

   -     132     -     132  
                    

Total long-term disability trust

   7     155     -     162  
                    

Total assets

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

Liabilities:

        

Price risk management instruments

        

Electric(4)

   $ -     $  30     $  436     $  466  

Gas(5)

   -     2     57     59  
                    

Total price risk management instruments

   -     32     493     525  
                    

Total liabilities

   $ -     $  32           $  493     $  525  
                    

(1)

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

(2)

Excludes deferred taxes on appreciation of investment value.

(3)

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

(4)

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

(5)

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

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

Assets:

        

Money market investments

   $  189     $ -     $  4     $  193  
                    

Nuclear decommissioning trusts

        

U.S. equity securities(1)

   762     6     -     768  

Non-U.S. equity securities

   344     -     -     344  

U.S. government and agency securities

   653     51     -     704  

Municipal securities

   1     89     -     90  

Other fixed income securities

   -     108     -     108  
                    

Total nuclear decommissioning trusts(2)

   1,760     254     -     2,014  
                    

Rabbi trusts

        

Equity securities

   21     -     -     21  

Life insurance contracts

   60     -     -     60  
                    

Total rabbi trusts

   81     -     -     81  
                    

Long-term disability trust

        

U.S. equity securities(1)

   52     23     -     75  

Corporate debt securities(1)

   -     113     -     113  
                    

Total long-term disability trust

   52     136     -     188  
                    

Total assets

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

Liabilities:

        

Dividend participation rights(3)

   $ -     $ -     $  12     $  12  
                    

Price risk management instruments

        

Electric(4)

   2     73     157     232  

Gas(5)

   1     -     60     61  
                    

Total price risk management instruments

   3     73     217     293  
                    

Other liabilities

   -     -     3     3  
                    

Total liabilities

   $  3     $  73           $  232     $  308  
                    

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

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

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

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

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

Trust Assets

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

Price Risk Management Instruments

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

Certain exchange-traded contracts are classified as Level 2 measurements because the contract term extends to observable inputs in determining fair value.  An instrument’s level withina period at which the hierarchymarket is no longer considered active; however, the prices are still observable. This determination is based on an analysis of the lowest levelrelevant characteristics of any significant inputthe market such as trading hours and volumes, frequency of available quotes, and open interest. In addition, a number of over -the -counter contracts are valued using unadjusted exchange prices of similar instruments in active markets. Such instruments are classified as Level 2 measurements as they are not exchange-traded instruments.

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

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

The Utility enters into power purchase agreements for the purchase of electricity to meet the demand of its customers. (See Note 7 above.) The Utility uses internal models to determine the fair value measurement.  See Note 12 of these power purchase agreements. These power purchase agreements include contract terms that extend beyond a period for which an active market exists. The Utility utilizes market data for the Notesunderlying commodity to the Consolidated Financial Statementsextent that it is available in determining the 2008 Annual Report for further discussionfair 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 measurements.


The following table sets forthincludes the fair value hierarchy by leveluse of PG&E Corporation’s and the Utility’s recurring fair value financial instruments at September 30, 2009.  PG&E Corporation’s and the Utility’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PG&E Corporation
 
Fair Value Measurements at September 30, 2009
 
(in millions) 
Level 1
  
Level 2
  
Level 3
  
Total
 
Assets:            
Money market investments (held by PG&E Corporation) $185  $-  $5  $190 
Nuclear decommissioning trusts                
     Equity securities  1,081   -   6   1,087 
     U.S. government and agency issues  661   52   -   713 
     Municipal bonds and other  -   183   -   183 
Total nuclear decommissioning trusts (1)
  1,742   235   6   1,983 
Rabbi trusts-equity securities  76   -   -   76 
Long-term disability trust                
     Equity securities  8   -   20   28 
     Corporate debt securities  -   -   101   101 
Total long-term disability trust  8   -   121   129 
Total assets $2,011  $235  $132  $2,378 
Liabilities:                
Dividend participation rights $-  $-  $20  $20 
Price risk management instruments(2)
  25   85   157   267 
Other  -   -   4   4 
Total liabilities $25  $85  $181  $291 
                 
(1) Excludes deferred taxes on appreciation of investment value.
 
(2) Balances include the impact of netting adjustments of $76 million to Level 1, $33 million to Level 2, and $88 million to Level 3.
 
29

Utility
 
Fair Value Measurements at September 30, 2009
 
(in millions) 
Level 1
  
Level 2
  
Level 3
  
Total
 
Assets:            
Nuclear decommissioning trusts            
     Equity securities $1,081  $-  $6  $1,087 
     U.S. government and agency issues  661   52   -   713 
     Municipal bonds and other  -   183   -   183 
Total nuclear decommissioning trusts(1)
  1,742   235   6   1,983 
Long-term disability trust                
     Equity securities  8   -   20   28 
     Corporate debt securities  -   -   101   101 
Total long-term disability trust  8   -   121   129 
Total assets $1,750  $235  $127  $2,112 
Liabilities:                
Price risk management instruments (2)
 $25  $85  $157  $267 
Other  -   -   4   4 
 Total liabilities $25  $85  $161  $271 
                 
(1) Excludes deferred taxes on appreciation of investment value.
 
(2) Balances include the impact of netting adjustments of $76 million to Level 1, $33 million to Level 2, and $88 million to Level 3.
 

PG&E Corporation’s and the Utility’s fair value measurements incorporate various factors, such as nonperformance and credit risk adjustments.  At September 30, 2009, the nonperformance and credit risk adjustment represented 1% of the net price risk management value.  unobservable forward prices.

Transfers between Levels

PG&E Corporation and the Utility utilize a mid-market pricing convention (the midpointrecognize any transfers between bid and ask prices)levels in the fair value hierarchy as a practical expedient in valuingof the majorityend of its derivativethe reporting period. There were no significant transfers between levels for the nine month period ended September 30, 2010. The following tables present reconciliations for assets and liabilities measured and recorded at fair value.


value on a recurring basis, using significant unobservable inputs (Level 3), for the three and nine month periods ended September 30, 2010 and 2009:

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

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

Included in earnings

  -    -    -    -    -    -    -    -  

Included in regulatory assets and liabilities or balancing accounts

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

 

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

 

  

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

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

Included in earnings

  -    -    -    -    8    2    -    10  

Included in regulatory assets and liabilities or balancing accounts

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

 

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

  

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

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

Included in earnings

  -    -    -    -    -    -    -    -  

Included in regulatory assets and liabilities or balancing accounts

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

 

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

 

  

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

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

Included in earnings

  -    1    -    -    11    3    -    15  

Included in regulatory assets and liabilities or balancing accounts

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

 

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

  

Financial Instruments


 PG&E Corporation and the

The Utility use the following methods and assumptions in estimating the fair value of financial instruments:


·The fair values of cash and cash equivalents, restricted cash and deposits, net accounts receivable, price risk management assets and liabilities, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2009 and December 31, 2008.
·The fair values of the Utility’s fixed rate senior notes, fixed rate pollution control bond loan agreements, PG&E Corporation’s Convertible Subordinated Notes, PG&E Corporation’s fixed rate senior notes, and the ERBs issued by PERF were based on quoted market prices at September 30, 2009 and December 31, 2008.

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

  
At September 30,
  
At December 31,
 
  
2009
  
2008
 
(in millions) 
Carrying Amount
  
Fair Value
  
Carrying Amount
  
Fair Value
 
Debt (Note 4):             
PG&E Corporation $597  $1,061  $280  $739 
Utility  8,690   9,528   8,740   9,134 
Energy recovery bonds (Note 4)  1,310   1,357   1,583   1,564 
30

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

Debt (Note 4):

    

PG&E Corporation (1)

  $  349    $  394    $  597    $  1,096  

Utility

  9,956    11,226    9,240    9,824  

Energy recovery bonds (Note 4)

  927    973    1,213    1,269  

 

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

  

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

Nuclear Decommissioning Trust Investments

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


The following table provides a summary of the fair value of thesummarizes unrealized gains and losses related to available-for-sale investments held in the Utility’s nuclear decommissioning trusts:


  
Maturity Date
  
Amortized Cost
  
Total Unrealized Gains
  
Total Unrealized Losses
  
Estimated (1) Fair Value
 
(in millions)               
Nine months ended September 30, 2009               
U.S. government and agency issues  2009-2038  $648  $66  $(1) $713 
Municipal bonds and other  2009-2049   179   6   (2)  183 
Equity securities      546   543   (2)  1,087 
Total     $1,373  $615  $(5) $1,983 
    
(1) Excludes deferred taxes on appreciation of investment value.
 

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

(in millions)

As of September 30, 2010

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

Total

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

As of December 31, 2009

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

Total

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

 

(1)Excludes taxes on appreciation of investment value.

  

The costfollowing table summarizes the estimated fair value of debt and equity securities sold is determinedclassified by specific identification.  the contractual maturity date of the security:

    At September 30,    
2010
(in millions)

Less than 1 year

$  64

1–5 years

447

5–10 years

238

More than 10 years

242

Total maturities of debt securities

        $  991

The following table provides a summary of the activity for the debt and equityavailable-for-sale securities:


  
Nine Months Ended September 30,
  
Year Ended December 31,
 
  
2009
  
2008
 
(in millions)      
Gross realized gains on sales of securities held as available-for-sale $24  $30 
Gross realized losses on sales of securities held as available-for-sale  (52)  (142)

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

Proceeds received from sales of securities

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

In general, investments held in the nuclear decommissioning trusttrusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Due to the level of risk associated with certain investment securities, itIt 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.


Level 3 Rollforward

The following table is a reconciliation of changes in fair value of PG&E Corporation’s instruments that have been classified as Level 3 in the fair value hierarchy for the nine month period ended September 30, 2009:
31

  
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
  
Total
 
Asset (Liability) Balance as of January 1, 2009 $12  $(42) $(156) $5  $54  $24  $(2) $(105)
Realized and unrealized gains (losses):                                
Included in earnings  -   1   -   -   11   3   -   15 
Included in regulatory assets and liabilities or balancing accounts  -   -   (1)  1   -   -   (2)  (2)
Purchases, issuances, and settlements  (7)  21   -   -   (45)  74   -   43 
Transfers in to Level 3  -   -   -   -   -   -   -   - 
Asset (Liability) Balance as of September 30, 2009 $5  $(20) $(157) $6  $20  $101  $(4) $(49)
                                 
(1) Excludes deferred taxes on appreciation of investment value.
                     

Earnings for the period were impacted by a $15 million unrealized gain relating to assets or liabilities still held at September 30, 2009.

The following table is a reconciliation of changes in fair value of PG&E Corporation’s instruments that have been classified as Level 3 in the fair value hierarchy for the three month period ended September 30, 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
  
Total
 
Asset (Liability) Balance as of July 1, 2009 $5  $(27) $(189) $5  $57  $24  $(3) $(128)
Realized and unrealized gains (losses):                                
Included in earnings  -   -   -   -   8   2   -   10 
Included in regulatory assets and liabilities or balancing accounts  -   -   32   1   -   -   (1)  32 
Purchases, issuances, and settlements  -   7   -   -   (45)  75   -   37 
Transfers in to Level 3  -   -   -   -   -   -   -   - 
Asset (Liability) Balance as of September 30, 2009 $5  $(20) $(157) $6  $20  $101  $(4) $(49)
                          
(1) Excludes deferred taxes on appreciation of investment value.
             

Earnings for the period were impacted by a $10 million unrealized gain relating to assets or liabilities still held at September 30, 2009.
PG&E Corporation and the Utility did not have any nonrecurring financial measurements requiring disclosure at September 30, 2009.
32

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 generally priced at the higher of fully loaded cost (i.e., direct cost of goods or services 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
  
Nine Months Ended
 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Utility revenues from:            
Administrative services provided to
PG&E Corporation
 $2  $-  $4  $2 
Utility expenses from:                
Administrative services received from PG&E Corporation $14  $34  $47  $86 
Utility employee benefit due to PG&E Corporation  4   5   13   16 

At September 30, 2009 and December 31, 2008, the Utility had a receivable of $28 million and $29 million, respectively, from PG&E Corporation included in Accounts receivable – Related parties and Other Noncurrent Assets – Related parties receivable on the Utility’s Condensed Consolidated Balance Sheets, and a payable of $14 million and $25 million, respectively, to PG&E Corporation included in Accounts payable – Related parties on the Utility’s Condensed Consolidated Balance Sheets.

NOTE 10:9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS


Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001.


In connection with the Utility’s proceeding under Chapter 11, the Utility established an escrow account to fund future settlements and for the payment of disputed claims, which is included within Restricted cash on the Condensed Consolidated Balance Sheets. At September 30, 20092010 and December 31, 2008,2009, the Utility held $512 million and $515 million and $1,212 million, respectively, 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 creditedrefunded to customers.


On August 26, 2009, following the approval by the FERC, the bankruptcy court presiding over the PX’s bankruptcy case, and the bankruptcy court that retains jurisdiction over the Utility’s Chapter 11 proceeding, the Utility paid $700 million to the PX from the Utility’s escrow account to reduce the Utility’s liability for the remaining net disputed claims.

The following table presents the changes in the remaining disputed claims liability and interest accrued from December 31, 20082009 to September 30, 2009:

33

(in millions)   
Balance at December 31, 2008 $1,750 
Interest accrued  45 
Less: Supplier Settlements  (90)  
Less: August 26, 2009 payment  (700)  
Balance at September 30, 2009 $1,005 

2010:

(in millions)

Balance at December 31, 2009

$  946

Interest accrued

23

Less: supplier settlements

(41

Balance at September 30, 2010

        $  928

At September 30, 2009,2010, the Utility’s net disputed claims liability was $1,005$928 million, consisting of $816$746 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within Accountsaccounts payable – Disputeddisputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $683$676 million (classified on the Condensed Consolidated Balance Sheets within Interestinterest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within Accountsaccounts receivable – Customers)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.


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 11:10: COMMITMENTS AND CONTINGENCIES


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


Commitments


Utility


Third-Party Power Purchase Agreements


As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase.  Forward prices at September 30, 2009 are used to determine the undiscounted future expected payments for contracts with variable pricing terms.  

At September 30, 2009,2010, the undiscounted future expected power purchase agreement payments were as follows:


(in millions)   
2009 $535 
2010  2,165 
2011  2,111 
2012  2,211 
2013  2,209 
Thereafter  36,141 
Total $45,372 

(in millions)    

2010

   $  600  

2011

   2,424  

2012

   2,483  

2013

   2,958  

2014

   3,188  

Thereafter

   54,375  
     

Total

           $  66,028  
     

Payments made by the Utility under power purchase agreements amounted to $1,809$1,791 million and $3,631$1,809 million for the nine months ended September 30, 20092010 and September 30, 2008,2009, 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.

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Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying co-generation facilities and qualifying small power production facilities (“QFs”)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 third-party power purchase agreements table above.) The fixed capacity payments are discounted to their present value in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the Amountamount representing interest.


(in millions)   
2009 $11 
2010  50 
2011  50 
2012  50 
2013  50 
Thereafter  206 
Total fixed capacity payments  417 
Less: Amount representing interest  95 
Present value of fixed capacity payments $322 

(in millions)    

2010

   $  11  

2011

   50  

2012

   50  

2013

   50  

2014

   42  

Thereafter

   162  
     

Total fixed capacity payments

   365  

Amount representing interest

   77  
     

Present value of fixed capacity payments

           $  288  
     

Minimum lease payments associated with the lease obligation are included in Costcost 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.


Capacity

At September 30, 2010 and December 31, 2009, PG&E Corporation and the Utility had, respectively, $33 million and $32 million included in current liabilities – other, and $255 million and $282 million included in noncurrent liabilities – other, respectively representing the present value of the fixed capacity payments due under these contracts recorded on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The corresponding assets at September 30, 2010 and December 31, 2009 of $288 million and $314 million, including amortization of $120 million and $94 million, respectively, are basedincluded in property, plant, and equipment on PG&E Corporation’s and the QF’s total available capacity and contractual capacity commitment.  Capacity payments may be adjusted if the QF exceeds or fails to meet performance requirements specified in the applicable power purchase agreement.


Utility’s Condensed Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and TransportationStorage 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)States supply basins) to the points at which the Utility’s natural gas transportation system begins.


In addition, the Utility has contracted for gas storage services in its market area in order to better meet winter peak customer loads.

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

At September 30, 2009,2010, the Utility’s undiscounted obligations for natural gas purchases, and gas transportation services, and gas storage were as follows:


(in millions)   
2009 $341 
2010  610 
2011  124 
2012  49 
2013  42 
Thereafter  157 
Total $1,323 

(in millions)    

2010

   $  301  

2011

   550  

2012

   84  

2013

   68  

2014

   49  

Thereafter

   115  
     

Total(1)

     $  1,167  
     

 

  

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

  

Payments for natural gas purchases, and gas transportation services, and gas storage amounted to $959$1,183 million and $2,227$959 million for the nine months ended September 30, 20092010 and September 30, 2008,2009, respectively.


Ruby Pipeline

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

Nuclear Fuel Agreements


The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 1614 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 2013,2014, 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.  New agreements are primarily based on forward market pricing and will begin to impact nuclear fuel costs starting in 2010.

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At September 30, 2009,2010, the undiscounted obligations under nuclear fuel agreements were as follows:


(in millions)   
2009 $153 
2010  108 
2011  100 
2012  90 
2013  118 
Thereafter  1,226 
Total $1,795 

(in millions)    

2010

   $  15  

2011

   82  

2012

   69  

2013

   107  

2014

   135  

Thereafter

   1,215  
     

Total

     $  1,623  
     

Payments for nuclear fuel amounted to $67$140 million and $96$67 million for the nine months ended September 30, 20092010 and September 30, 2008,2009, respectively.


Contingencies


PG&E Corporation


PG&E Corporation retains a guarantee related to certain indemnity obligations of its former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”), that were issued to the purchaser of an NEGT subsidiary company.company in 2000. PG&E Corporation’s soleprimary 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


Application

Energy Efficiency Programs and Incentive Ratemaking

The CPUC has established a ratemaking mechanism to Recover Hydroelectric Facility Divestiture Costs


On April 16, 2009,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 approved a decision to authorizehas 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 recover $47 millionthe CPUC’s completion of costs, including $12 million of interest,the final true-up process.

On September 28, 2010, a proposed decision was issued by the assigned CPUC administrative law judge recommending that no additional incentive revenues be awarded to the Utility. Also, on September 28, 2010, an alternate proposed decision was issued by a CPUC commissioner recommending that the Utility incurred in connection with its effortsbe awarded additional incentive revenues of $40 million, an amount equal to determine the market value of its hydroelectric generation facilities in 2000 and 2001.  These efforts were undertaken as requiredamounts that had been held back from the interim awards.

The CPUC is scheduled to issue a final decision to complete the true-up process by the CPUC in connection withend of 2010. PG&E Corporation and the proposed divestitureUtility are unable to predict the amount, if any, of the facilities to further the development of a competitive generation market in California.  The CPUC subsequently withdrew this requirement.  The Utility continues to own its hydroelectric generation assets.  The Utility expectsadditional incentive revenues that the rate adjustments necessary to recover these authorized costsUtility will be combined with other rate adjustments inreceive for the Utility’s annual electric rate true-up proceeding.  These rate changes are expected to become effective in January 2010.


2006-2008 program cycle.

Spent Nuclear Fuel Storage Proceedings


As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”) and its retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”).  The DOE failed to develop a permanent storage site by January 31, 1998.


The Utility believes that the existing spent fuel pools at Diablo Canyon, which include newly constructed temporary storage racks, have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2.  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 andcomplete. During 2009, the movement ofUtility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage began in June 2009.


After various parties appealedstorage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006 requiringCircuit. The appellants claim that the NRC failed to issue a supplementaladequately consider environmental assessment report on the potential environmental consequences in the eventimpacts of a potential terrorist attack at Diablo Canyon,Canyon. The Ninth Circuit has set November 4, 2010 as well as to review other contentions raised by the appealing parties related to potential terrorism threats.  In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.
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In October 2008, the NRC rejected the final contention that had been made during the appeal.  The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit.  On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding.  The Utility’s brief on appeal was filed on April 8, 2009.  No date has been set for oral argument.

As a result of the DOE’s failure to build a national 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 seekssought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the DOE now concedes thatU.S. Court of Federal Claims awarded the Utility is entitled to recover approximately $82 million$89 million. The DOE filed an appeal of these costs, but the DOE continues to dispute the remaining amount.  The trial to determine the appropriate method to calculate the amounts owed to the Utility beganthis decision on October 15, 2009.  May 28, 2010.

The Utility also will seek to recover costs incurred after 2004at least $188 million between 2005 and 2009 to build on-site storage facilities.


PG&E Corporation and On August 3, 2010, the Utility are unablefiled two complaints against the DOE in the U.S. Court of Federal Claims seeking to predict the amountrecover all costs incurred to build on-site storage facilities between 2005 and timing of any recoveries that the Utility will receive from the DOE.2009. Amounts recovered from the DOE will be credited to customers.

Energy Efficiency Programs and Incentive Ratemaking

The CPUC previously established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles.  On December 18, 2008, based on their first interim claims, the CPUC awarded interim incentive earnings to the utilities for their 2006-2007 program performance.  In the fourth quarter of 2008, the Utility recognized a CPUC award of $41.5 million for the Utility’s energy efficiency program performance in 2006-2007.  Under the existing incentive ratemaking mechanism, the maximum amount of revenue that the Utility could earn and the maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.

On January 29, 2009, the CPUC established a new rulemaking proceeding to modify the existing incentive ratemaking mechanism for programs beginning in 2009 and future years, to adopt a new framework to review the utilities’ 2006-2008 program performance for the second interim claim, and to conduct a final review of the utilities’ performance over the 2006-2008 program period.  On May 21, 2009, the Utility, San Diego Gas & Electric Company, Southern California Gas Company, and the Natural Resources Defense Council jointly requested that the CPUC approve a proposed settlement to resolve the utilities’ second interim claims and their final 2006-2008 true-up incentive claims.  On July 10, 2009, the Utility submitted calculations, based on the methodology included in the proposed settlement, indicating that the Utility would be entitled to earn the remaining amount of the maximum incentives that could be earned for the 2006-2008 period.  Based on the holdback amount proposed in the settlement, the Utility would be entitled to receive $76.6 million in incentive earnings and an additional $61.9 million would be held back and subject to verification in the final 2006-2008 true-up process to be completed in 2010.  The assigned administrative law judge has ruled that there will be no hearings on the settlement proposal.


In accordance with the process established by the current incentive ratemaking mechanism, on October 15, 2009, the CPUC approved a second verification report issued by the CPUC’s Energy Division relating to the second interim claims for the utilities’ 2006-2008 program performance.  The report calculates potential incentive amounts for the Utility, based on different energy savings assumptions and measurement methods, that range up to $20.6 million with up to an additional $33.4 million to be held back pending completion of the 2006-2008 true-up process in 2010.  In addition, on September 3 and October 1, 2009, the CPUC’s Energy Division released additional incentive award scenarios, including scenarios based on the proposed settlement, that result in a wide range of potential financial outcomes.  It is uncertain what effect, if any, the issuance of the verification report or the scenarios will have on the likelihood of the proposed settlement becoming effective.  Whether the proposed settlement will be approved and the amounts of any interim and final claims that may be awarded to the Utility are uncertain at this time.
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 $3.24$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 $39.7$40 million per one-year policy term.

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NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Under the Terrorism Risk Insurance Program Reauthorization Act of 2007 (“TRIPRA”), acts of terrorism may be “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 damagedamages 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 $3.24NEIL’s policy limit of $3.2 billion within a 12-month period plus theany additional amounts recovered by NEIL for these losses from reinsurance. (TRIPRA extendsCertain acts of terrorism may be “certified” by the Terrorism Risk Insurance ActSecretary of 2002 through December 31, 2014.)


the Treasury. For damages caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss caused by these certified acts of terrorism. The $3.2 billion amount would not be shared as is described above for damages caused by acts of terrorism that have not been certified.

Under the Price-Anderson Act, public liability claims that arise from a nuclear incidentincidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $12.5$12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300$375 million for Diablo Canyon. The balance of the $12.5$12.6 billion of liability protection is covered byprovided under a loss-sharing program among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher.  If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $117.5 million per reactor, with payments in each year limited to a maximum of $17.5 million per incident until the Utility has fully paid its share of the liability.  Since Diablo Canyon has two nuclear reactors, each with a rated capacity of over 100 MW, theThe 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 per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.


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

In addition, the Utility has $53.3$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 $53.3$53 million of liability insurance.


Severance Costs

As of September 30, 2009, the Utility has recorded a liability of $76 million related to severance costs.  The following table presents the changes in the liability from December 31, 2008:

(in millions)   
Balance at December 31, 2008 $27 
Additional severance costs accrued  72 
 Less: Payments  (23)
Balance at September 30, 2009 $76 

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 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.

The cost of environmental remediation is difficult to estimate.  The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of possible clean-up costs.  The Utility reviews its remediation liability on a quarterly basis.  The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure using current technology, and considering enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties.  Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range.  The Utility estimates the upper end of this cost range using possible outcomes that are least favorable to the Utility.  It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility’s responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives.
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The Utility had an undiscounted and gross environmental remediation liability of $597 million at September 30, 2009 and $568 million at December 31, 2008.  The $597 million accrued at September 30, 2009 consists of:

·$49 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;
·$156 million for remediation at the Utility’s natural gas compressor site located in Topock, Arizona, near the California border;
·$86 million related to remediation at divested generation facilities;
·$246 million related to remediation costs for the Utility’s generation and other facilities, third-party disposal sites, and manufactured gas plant 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 manufactured gas plant sites); and
· $60 million related to remediation costs for fossil decommissioning sites.

Of the $597 million environmental remediation liability, $146 million has been included in prior rate setting proceedings and the Utility expects that an additional amount of $366 million will be recoverable in future rates.  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.  Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable from customers.

The Utility’s undiscounted future costs could increase to as much as $1 billion if the other potentially responsible parties are not financially able to contribute to these costs or if the extent of contamination or necessary remediation is greater than anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements.  

Diablo Canyon and other generating facilities the Utility purchases electricity from uses a process known as “once-through cooling” that takes in water from the ocean to cool the generating facility and discharges the heated water back into the ocean.  There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts.  In July 2004, the U.S. Environmental Protection Agency (“EPA”) issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures.  These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis.  The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases.

Various parties separately challenged the EPA’s regulations, and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test could not be used.  The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations.  The U.S. Supreme Court granted review of the cost-benefit question and in April 2009 issued a decision reversing the Second Circuit and finding permissible the EPA’s use of cost-benefit analysis to set national compliance standards for cooling water intake systems and variances to those standards.  The EPA is currently revising its regulations regarding cooling water intake systems.  In response to the EPA regulations, the California State Water Resources Control Board (“Water Board”) issued an initial proposed policy to address once-through cooling in June 2006.  Since that time, the Water Board reviewed and revised its proposal in response to comments from various California agencies and concerned stakeholders.  The Water Board’s current draft proposal, issued in June 2009, requires fossil and nuclear plants to either retrofit to closed cycle cooling or install operational and structural controls to achieve a similar reduction and provides a compliance timeframe for each once-through-cooled facility.  The proposal also requires the development of a once-through cooling alternatives study for nuclear plants and requires that Diablo Canyon be in compliance with the policy by December 31, 2021, unless compliance would conflict with a nuclear safety requirement or the cost of compliance is wholly disproportionate to the benefits.

Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates.  If either of the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.
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Tax Matters

In March 2009, PG&E Corporation received a cash refund of $294 million, in accordance with the settlement reached with the Internal Revenue Service (“IRS”) to resolve the IRS’ audits of tax years 2001 through 2004.  (PG&E Corporation applied $80 million of the refund it otherwise would have received in cash to make an estimated income tax payment for tax year 2008.)   Currently, PG&E Corporation has approximately $65 million of federal capital loss carry forwards based on tax returns as filed and the resolution of the IRS audit of tax years 2001 through 2004.  Of the $65 million federal capital loss carry forwards, approximately $25 million will expire if not used by the end of 2009.

On June 8, 2009, the IRS agreed to settle refund claims related to the 1998 and 1999 tax years.  As a result of this settlement, PG&E Corporation and the Utility recognized after tax income of $56 million in the second quarter of 2009.  In the third quarter of 2009, PG&E Corporation and the Utility received cash refunds of tax and interest totaling $311 million in accordance with this settlement.

During the three months ended September 30, 2009, PG&E Corporation recognized $12 million in California tax and related interest benefits attributable to the two IRS settlements discussed above.

The IRS is currently auditing PG&E Corporation’s consolidated income tax returns for tax years 2005 through 2007.  The IRS has not proposed any material adjustments for the 2005 through 2007 audit.  On September 16, 2009, the IRS released standards for the resolution of an issue involved in the 2005-2007 audit, enabling PG&E Corporation to recognize net tax benefit of $17 million.

PG&E Corporation is participating in the IRS’s Compliance Assurance Process (“CAP”), a real-time audit process intended to expedite the resolution of issues raised during audits, for tax years 2008 and 2009.   The IRS has not proposed any material adjustments for tax years 2008 or 2009, except for adjustments to reflect the rollover impact of audit settlements involving prior tax years.  In September 2009, the IRS gave its consent for PG&E Corporation to change a tax method for 2008.  This allowed PG&E Corporation to record a net benefit of $2 million, including interest, due to this change.

As a result of the events described above, PG&E Corporation’s forecasted effective tax rate for 2009 has decreased by 1.6%.  In addition, the primary impact to PG&E Corporation and the Utility’s balance sheets is an increase of regulatory asset by $37 million, an increase of noncurrent income tax receivable by $522 million, and an increase of noncurrent deferred tax liabilities by $543 million in the third quarter 2009.

The California Franchise Tax Board is currently auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns.  To date, no material adjustments have been proposed.  In addition to the federal capital loss carry forwards, PG&E Corporation has approximately $200 million of California capital loss carry forwards based on tax returns as filed, the majority of which will expire if not used by the end of 2009.

For a discussion of unrecognized tax benefits, see Note 10 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.  During the three months ended September 30, 2009, PG&E Corporation increased the gross amount of unrecognized tax benefits by $531 million due to the events described above.   If the full amount were recognized, approximately $50 million would reduce PG&E Corporation’s effective tax rate with the remaining balance representing the probable deferral of taxes to later years. Further, 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.

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 makerecord a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

Explosion and Fires in San Bruno, California

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

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

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

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

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

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

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

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

Other Legal Matters

The accrued liability for legal matters (other than those related to the San Bruno Accident as discussed above) is included in PG&E Corporation’s and the Utility’s Current Liabilitiescurrent liabilitiesOtherother in the Condensed Consolidated Balance Sheets and totaled $51$46 million at September 30, 20092010 and $72$57 million at December 31, 2008.  After2009. PG&E Corporation and the Utility are not able to predict the ultimate outcome of these various legal matters, but after consideration of these accruals, PG&E Corporation and the Utility do not expectbelieve that losses associated with legalthese matters would have a material adverse impact on their financial condition andor results of operations.

Environmental Matters

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

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts.

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

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

  (in millions)

  Balance at December 31, 2009

$ 586

  Additional remediation costs accrued:

  Transfer to regulatory account for recovery

86

  Amounts not recoverable from customers

21

  Less: Payments

(85

  Balance at September 30, 2010

  $ 608

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

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

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

$87 million related to remediation at divested generation facilities;

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

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

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

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

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

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility’s undiscounted future costs could increase to as much as $1.1 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements.

Tax Matters

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

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

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

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

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

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

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

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

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 engages ingenerates revenues mainly through the businessessale and delivery of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage.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 5.15.2 million electricity distribution customers and 4.3 million natural gas distribution customers at September 30, 2009.2010. The Utility had $42.3$44.9 billion in assets at September 30, 20092010 and generated revenues of $9.9$10.2 billion in the nine months ended September 30, 2009.


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 Utility generates revenues mainly throughCPUC has jurisdiction over the salerates and deliveryterms and conditions of electricityservice for the Utility’s electric and natural gas atdistribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates set byand 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.  Rates are setFERC authorize the annual amount of revenue (“revenue requirements”) that the Utility is authorized to permit the Utilitycollect from its customers to recover its reasonable operating and capital costs of providing utility services. The authorized “revenue requirements” from customers.  Revenuerevenue requirements are designed to allowalso provide the Utility an opportunity to recover its reasonable costs ofearn a return on “rate base” (i.e., the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility services, includingservice to its customers.) The CPUC requires the Utility to maintain a returncertain 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 fairspecific rate of return on its investmenteach capital component.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in Utility facilities (“rate base”).  Pending regulatory proceedings that could resultconjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in rate changes and affect the Utility’s revenues are discussedthis 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, 2008,2009 which together withincorporates by reference each company’s audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information incorporated by reference into(“2009 Annual Report”).

Explosion and Fires in San Bruno, California

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

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

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

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

The CPUC also has initiated an investigation of the San Bruno Accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory. The CPUC has appointed an independent review panel to gather facts, review these facts, make a technical assessment of the San Bruno Accident and its root cause, and make recommendations for action by the CPUC to ensure such report,an accident is referrednot repeated. These recommendations may include changes to design, construction, operation and maintenance of natural gas facilities, management practices at the Utility in the areas of pipeline integrity and public safety, regulatory and statutory changes, and other recommendations deemed appropriate, including whether there are systemic management problems at the Utility and whether greater resources are needed to achieve fundamental infrastructure improvement. The Utility is committed to working with the NTSB, the CPUC, and the independent panel to determine the cause of the rupture.

Various lawsuits, including two class action lawsuits, have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. (See Part II, Item 1. Legal Proceedings, below.) Several other residents also have submitted damage claims to the Utility. In addition, on October 4, 2010, PG&E Corporation received a letter on behalf of a purported shareholder demanding that the PG&E Corporation Board of Directors (1) institute an independent investigation of the San Bruno Accident and related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including board members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The letter requests a response within 60 days, i.e., by December 3, 2010. PG&E Corporation intends to respond before December 3, 2010. A purported shareholder derivative action also has been filed to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

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

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the costs the Utility incurs for third-party claims relating to the San Bruno Accident will ultimately be covered by this quarterly reportinsurance, no amounts for insurance recoveries have been recorded as of September 30, 2010. PG&E Corporation and the “2008 Annual Report.”  SignificantUtility are unable to predict the amount and timing of insurance recoveries.

Other significant developments that have occurred since the 20082009 Annual Report was filed with the Securities and Exchange Commission (“SEC”)on February 19, 2010 are discussed in this Quarterly Report on Form 10-Q.


This is a combined quarterly report of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities.  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, as well as the accounts of variable interest entities for which the Utility absorbs a majority of the risk of loss or gain.  This combined Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) of PG&E Corporation and the Utility should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report, as well as the MD&A, the audited Consolidated Financial Statements, and the Notes to the Consolidated Financial Statements incorporated by reference in the 2008 Annual Report.

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three and Nine Months Ended September 30, 2009


2010

PG&E Corporation’s diluted earnings per common share (“EPS”) was $0.83 for each of the three months ended September 30, 2009 and 2008.2010 was $0.66 compared to $0.83 for the same period in 2009. For the nine months ended September 30, 2009,2010, PG&E Corporation’s diluted EPS was $2.49$2.19 compared to $2.24$2.49 for the same period in 2008.2009. PG&E Corporation’s income available for common shareholders for the three months ended September 30, 2009 increased2010 decreased by $14$60 million, or 5%19%, to $318$258 million, compared to $304$318 million for the same period in 2008.2009. For the nine months ended September 30, 2009,2010, income available for common shareholders increaseddecreased by $126$98 million, or 15%10%, to $947$849 million, compared to $821$947 million for the same period in 2008.


2009. The increase in incomeprimary factors associated with these decreases are discussed below.

Income available for common shareholders decreased for both the three and nine months ended September 30, 2010, as compared to the same periods in 2009, primarily due to costs of $141 million, after tax, related to the San Bruno Accident.

For the three months ended September 30, 2009,2010, the costs related to the San Bruno Accident were partially offset by $26 million that the Utility earned on higher authorized capital investments as compared to the same period in 2008, is attributable to (1) an increase of $24 million, after tax, due to the Utility’s return on equity (“ROE”) earned on2009. In addition, net income was higher authorized capital investments, (2) a tax benefit of $10 million associated with the settlement of tax refund claims involving the 1998 and 1999 tax years, (3) a benefit of $11 million, after-tax, as compared to the same period in the prior year2009 when the Utility incurred costs to oppose certain legislation and municipalization efforts, and (4) an increase of $12 million, after tax, reflecting the sum of incentives earned for managing natural gas procurement costs and lower accrual levels for uncollectibles and environmental costs.  These increases were partially offset by (1) a $30 million after tax, decrease attributable toof employee severance costs and (2) a $16 million after tax, decrease attributable toof costs to perform accelerated natural gas leak surveys and associated remedial work.

41

The increase in diluted EPS and income available for common shareholders forsurveys. These comparative increases also helped to offset the costs related to the San Bruno Accident.

For the nine months ended September 30, 2009, as2010, the decrease in income available for common shareholders also was driven by (1) $45 million, after tax, of costs the Utility incurred to support a June 2010 ballot initiative and (2) a $19 million, after tax, charge triggered by the elimination of the tax deductibility of the Medicare Part D federal subsidy. These negative factors were partially offset by (1) an increase of $65 million, after tax, that the Utility earned on higher authorized capital investments compared to the same period in 2008, is attributable to (1) an increase2009 and (2) higher net income of $73$32 million, after tax, representing the Utility’s ROE earned on higher authorized capital investments, (2) an increase of $28 million, after tax, due to the recovery of previously incurred costs related to the Utility’s hydroelectric generation facilities, (3) a benefit of $11 million, after-tax, as compared to the same period in the prior year2009 when the Utility incurred costs to oppose certain legislation and municipalization efforts, (4)in connection with a tax benefit of $66 million associated with the settlement of tax refund claims involving the 1998 and 1999 tax years, and (5) a benefit of $24 million, after tax, as compared to the same period in the prior year when the Utility incurred higher storm andscheduled refueling outage expenses.  These increases were partially offset by (1) a $39 million, after tax, decrease attributable to employee severance costs, and (2) a $32 million, after tax, decrease attributable to costs to perform accelerated natural gas leak surveys and associated remedial work.


at Diablo Canyon.

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 ImpactFERC, the outcome of Ratemaking Mechanisms.  Mostwhich 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 are set basedfor 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 costs of service in proceedings such as the General Rate Case (“GRC”) filed with the CPUC and transmission owner13th Electric Transmission Owner (“TO”) rate cases filed withcase requesting the FERC.FERC to determine the amount of electric transmission revenues the Utility can recover beginning in March 2011. (See “Regulatory Matters” below.) TheFrom time to time the Utility intends to file its 2011-2013 GRC application withalso requests that the CPUC before the end of 2009 to request an increase in authorized electric distribution, gas distribution, and electric generation revenue requirements.  On September 18, 2009, the Utility requested the CPUC to determine the rates, and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011.  The Utility also files separate applications requesting the CPUC or the FERC to authorize additional base revenue requirements for specific capital expenditure projects such as new power plants, gas or electric transmission facilities, installation of an advanced metering infrastructure, and reliability or system infrastructure improvements.plants. (See “Capital Expenditures” below.) The Utility’s revenues will also be affected by incentive ratemaking, such as the CPUC’s customer energy efficiency shareholder incentive mechanism.  In addition, the CPUC has authorized the Utility to recover 100%outcome of its reasonable electric fuel and energy procurement costs and has established a timely rate adjustment mechanism to recover such costs.  As a result, the Utility’s revenues and coststhese regulatory proceedings can be affected by volatility inmany factors, including general economic conditions, the priceslevel of natural gascustomer rates, and electricity.  (See “Risk Management Activities” below.)political and regulatory policies.

 
·
Capital Structure and Return on Common Equity.  The Utility’s current CPUC-authorized capital structure includes a 52% common equity component, which will remain in effect through 2012.  The CPUC has authorized the Utility to set rates targeted to earn an ROE of 11.35% on the equity component of its electric and natural gas distribution and electric generation rate base through 2010.  The Utility’s cost of capital for 2011 and 2012 will change only if the annual adjustment mechanism established by the CPUC is triggered.  If the adjustment is triggered, the Utility’s authorized cost of capital would be adjusted effective January 1 of the following year.  The Utility can also apply for an adjustment to either its capital structure or its cost of capital at any time in the event of extraordinary circumstances. (See “Regulatory Matters” below.)
 
·

The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability.Costs. The Utility’s revenue requirements are generally set by the CPUC and the FERC at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses, as well as to earn an ROEa return on equity (“ROE”) and recover depreciation, tax, and interest expenseexpenses associated with authorizedforecasted capital expenditures. Actual costs may differ from forecasts, or the Utility may incur significant unanticipated costs related to storms, outages, catastrophic events, or to comply with regulatory orders or legislation. Although the Utility continuously reprioritizes its capital and expense spending to meet customer needs and maintain and improve operational safety and reliability, the Utility may be unable to offset unanticipated costs. Differences in the amount or timing of forecasted or authorized and actual operating expenses and capital expenditurescosts can affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. (See “Capital Expenditures” below.)

Authorized Capital Structure, Rate of Return, and Financing.The Utility also seeks to make the amount and timing of itsCPUC has authorized a capital expenditures consistent with budgeted amounts and timing.  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.  Items that could cause higher expenses than providedstructure for in the last GRC primarily relate to the Utility’s efforts to maintain its aging electric and natural gas systems infrastructure,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 improve the reliability and safetyearn a rate of return on each component of its electric and natural gas system, andcapital structure, including a ROE of 11.35%. These rates will remain in effect through 2011. The rates for 2012 are subject to improve its information technology infrastructure, support, and security.  The Utility continually seeks to achieve operational efficiencies and improve reliability while creating future sustainable cost savings to offset these higher anticipated expenses.  In connection with these efforts,an annual adjustment mechanism that will be triggered if the Utility has accrued severance costs, including severance costs related12-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 reduction of approximately 2%applicable benchmark. The amount of the Utility’s workforce, inauthorized equity earnings is determined by the three months ended September 30, 2009.  (See “Results52% equity component, the 11.35% ROE, and the aggregate amount of Operations” below.)

·
Timingrate base authorized by the CPUC. The rate of return that the Utility earns on its FERC-jurisdictional rate base is not specifically 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 Amount of Debtshort-term debt that the Utility may issue and Equity Financing.authorizes the Utility to recover its related debt financing costs. The timing and amount of the Utility’s future financing needs will depend on various factors, including the conditionsas discussed in the capital markets, the amount“Liquidity and timing of scheduled principal and interest payments on long-term debt, the amount and timing of planned capital expenditures, and the amount and timing of interest payments related to the remaining disputed claims that were made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”).  (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)  The amount of the Utility’s short-term financing will vary depending on the level of operating cash flows, seasonal demand for electricity and natural gas, volatility in electricity and natural gas prices, and collateral requirements related to price risk management activities, among other factors.  In order to maintain the Utility’s CPUC-authorized capital structure,Resources” below. PG&E Corporation contributed $688 million ofcontributes equity to the Utility during 2009.  The timing and amount of future equity contributions toas needed by the Utility will affectto maintain its CPUC-authorized capital structure. PG&E Corporation may issue debt or equity in the timing and amount of any future to fund these equity or debt issuances by PG&E Corporation.  (See “Liquidity and Financial Resources” below.)contributions.


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CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS


This combined quarterly report on Form 10-Q 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,expenditures; estimated environmental remediation, liabilities, estimated tax, liabilities,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,proceedings; estimated losses and insurance recoveries associated with the San Bruno Accident; estimated future cash flows,flows; and the level of future equity or debt issuances, andissuances. 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 and timely recover its costs through rates;


the outcome of pending and future regulatory or legislative proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno Accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory, and whether the utility is required to incur costs to comply with regulatory or legislative mandates that it is unable to recover through rates or insurance;

·the Utility’s ability to manage capital expenditures and its operating and maintenance expenses within authorized levels;
·the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;
·the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets, including the ability of the Utility and its counterparties to post or return collateral;
·explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and computer 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, that affect customer demand, or that damage or disrupt the facilities, operations, or information technology and computer systems owned by the Utility, its customers, or third parties on which the Utility relies;
·the potential impacts of climate change on the Utility’s electricity and natural gas businesses;
·changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology including the development of alternative energy sources, or other reasons;
·operating performance of the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;
·whether the Utility can maintain the cost savings that it has recognized from operating efficiencies that it has achieved and identify and successfully implement additional sustainable cost-saving measures;
·whether the Utility incurs substantial expense to improve the safety and reliability of its electric and natural gas systems;
·whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives that the Utility may earn in a timely manner;
·the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
·the impact of changing wholesale electric or gas market rules, including the impact of future FERC-ordered changes that will be incorporated into the new day-ahead, hour-ahead, and real-time wholesale electricity markets established by the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;
·how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;
·the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, or from other third parties;
·the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;
·the impact of environmental laws and regulations and the costs of compliance and remediation;
·the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; and
·the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations.

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 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;

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;

43

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 extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, including those arising from the San Bruno Accident, that are not recoverable through insurance, rates, 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 20082009 Annual Report and the discussion below under Part II. Other Information, Item 1A. Risk Factors.in Part II below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

RESULTS OF OPERATIONS


The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three and nine months ended September 30, 20092010 and 2008:2009:

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

  Utility

    

  Electric operating revenues

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

  Natural gas operating revenues

  656    605    2,338    2,250  
                

  Total operating revenues

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

  Cost of electricity

  1,102    997    2,885    2,763  

  Cost of natural gas

  182    134    924    879  

  Operating and maintenance

  1,224    1,047    3,172    3,143  

  Depreciation, amortization, and decommissioning

  500    450    1,419    1,298  
                

  Total operating expenses

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

  Operating Income

  505    607    1,820    1,777  

  Interest income

  3    3    7    29  

  Interest expense

  (161  (162  (481  (501

  Other income, net

  25    16    20    52  
                

  Income Before Income Taxes

  372    464    1,366    1,357  

  Income tax provision

  107    111    498    374  
                

  Net Income

  265    353    868    983  

  Preferred stock dividend requirement

  3    3    10    10  
                

  Income Available for Common Stock

  $  262    $  350    $  858    $  973  
                

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

    

  Operating revenues

  $  -    $  -    $  -    $  -  

  Operating expenses

  2    -    4    1  
                

  Operating Loss

  (2  -    (4  (1

  Interest income

  -    (2  -    (2

  Interest expense

  (6  (12  (29  (32

  Other income, net

  4    7    5    11  
                

  Loss Before Income Taxes

  (4  (7  (28  (24

  Income tax provision (benefit)

  -    25    (19  2  
                

  Net Loss

  $  (4  $  (32  $  (9  $  (26
                

  Consolidated Total

    

  Operating revenues

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

  Operating expenses

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

  Operating Income

  503    607    1,816    1,776  

  Interest income

  3    1    7    27  

  Interest expense

  (167  (174  (510  (533

  Other income, net

  29    23    25    63  
                

  Income Before Income Taxes

  368    457    1,338    1,333  

  Income tax provision

  107    136    479    376  
                

  Net Income

  261    321    859    957  

  Preferred stock dividend requirement of subsidiary

  3    3    10    10  
                

  Income Available for Common Shareholders

  $  258    $  318    $  849    $  947  
                

 

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

  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Utility            
Electric operating revenues $2,630  $2,880  $7,610  $8,039 
Natural gas operating revenues  605   794   2,250   2,946 
   Total operating revenues  3,235   3,674   9,860   10,985 
Cost of electricity  997   1,282   2,763   3,406 
Cost of natural gas  134   351   879   1,613 
Operating and maintenance  1,047   982   3,143   3,009 
Depreciation, amortization, and decommissioning  450   419   1,298   1,239 
   Total operating expenses  2,628   3,034   8,083   9,267 
Operating Income  607   640   1,777   1,718 
Interest income  3   20   29   77 
Interest expense  (162)  (170)  (501)  (528)
Other income (expense), net  16   (2)  52   24 
Income Before Income Taxes  464   488   1,357   1,291 
Income tax provision  111   167   374   421 
Net Income  353   321   983   870 
Preferred stock dividend requirement  3   3   10   10 
Income Available for Common Stock $350  $318  $973  $860 
PG&E Corporation, Eliminations, and Other(1)
                
Operating revenues $-  $-  $-  $- 
Operating expenses  -   1   1   2 
Operating Loss  -   (1)  (1)  (2)
Interest income  (2)  3   (2)  5 
Interest expense  (12)  (8)  (32)  (22)
Other income (expense), net  7   (12)  11   (28)
Loss Before Income Taxes  (7)  (18)  (24)  (47)
Income tax provision (benefit)  25   (4)  2   (8)
Net Income (Loss) $(32) $(14) $(26) $(39)
Consolidated Total                
Operating revenues $3,235  $3,674  $9,860  $10,985 
Operating expenses  2,628   3,035   8,084   9,269 
Operating Income  607   639   1,776   1,716 
Interest income  1   23   27   82 
Interest expense  (174)  (178)  (533)  (550)
Other income (expense), net  23   (14)  63   (4)
Income Before Income Taxes  457   470   1,333   1,244 
Income tax provision  136   163   376   413 
Net Income  321   307   957   831 
Preferred stock dividend requirement of subsidiary  3   3   10   10 
Income Available for Common Shareholders $318  $304  $947  $821 
                 
(1) PG&E Corporation eliminates all intercompany transactions in consolidation.
 
44

Utility


The following presents the Utility’s operating results for the three and nine months ended September 30, 20092010 and 2008.


2009.

Electric Operating Revenues


The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of electric procurement, and public purpose, energy efficiency, and demand response programs. The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, the Utility relies on electricity provided under long-term contracts entered into by the California Department of Water Resources (“DWR”) to meet a material portion of the Utility’s customers’ demand for electricity (“load”).  The Utility’s electric operating revenues consist is satisfied by electricity provided under long-term contracts between the California Department of amounts charged to customers for electricity generationWater Resources (“DWR”) and procurement and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of public purpose, energy efficiency, and demand response programs.


various power suppliers.

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


  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Electric revenues $3,233  $3,255  $9,066  $9,044 
DWR pass-through revenues(1)
  (603)  (375)  (1,456)  (1,005)
Total electric operating revenues $2,630  $2,880  $7,610  $8,039 
    
(1)These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility’s Condensed Consolidated Statements of Income.
 

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

  Electric revenues

   $  3,245    $  3,233    $  8,930    $  9,066  

  DWR pass-through revenues(1)

   (388  (603  (1,048  (1,456
                 

  Total electric operating revenues

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

 

     

 (1) These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility’s Condensed Consolidated Statements of Income.

   

The Utility’s total electric operating revenues, decreasedincluding revenues intended to recover costs that are passed through to customers, increased by $250$227 million, or 9%, in the three months ended September 30, 20092010, as compared to the same period in 2009. Costs that are passed through to customers and $429do not impact net income increased by $145 million, primarily due to an increase in the cost of public purpose programs, higher costs of electric procurement, and the return of collateral from counterparties in 2009. (See “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $82 million. This was primarily due to an increase in authorized base revenues of $60 million.

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $272 million, or 5%,4% in the nine months ended September 30, 2009,2010, as compared to the same period in 2008,2009. Costs that are passed through to customers and do not impact net income increased by $124 million, primarily due to an increase in the following factors:


·Electricity costs passed through to customers decreased by $285 million in the three months ended September 30, 2009 and $643 million in the nine months ended September 30, 2009.  (See “Cost of Electricity” below.)
·Public purpose program costs passed through to customers decreased by $2 million in the three months ended September 30, 2009 and $46 million in the nine months ended September 30, 2009 due to the timing of program spending.  (See “Operating and Maintenance” below.)
·CAISO collateral costs, passed through to customers, related to the new day-ahead market decreased by $20 million in the three months ended September 30, 2009.  (See “Operating and Maintenance” below.)
·Other miscellaneous electric operating revenues decreased by $13 million in the three months ended September 30, 2009.

These decreases werecost of public purpose programs and higher costs of electric procurement. (See “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $148 million. This was primarily due to an increase in authorized base revenues of $163 million, which was partially offset by a decrease in revenues of $35 million, representing the following:

·Base revenues increased by $26 million in the three months ended September 30, 2009 and $77 million in the nine months ended September 30, 2009, as previously authorized in the 2007 GRC.
·Revenues associated with separately funded projects placed in service, including the Gateway Generating Station and the new steam generators at Diablo Canyon, increased by $44 million in the three months ended September 30, 2009 and $137 million in the nine months ended September 30, 2009.
·Electric operating revenues increased by $35 million in the nine months ended September 30, 2009 for the recovery of previously incurred costs related to hydroelectric generation facilities.  (See “Regulatory Matters” below.)
·Other miscellaneous electric operating revenues increased by $11 million in the nine months ended September 30, 2009.
45

amount the Utility received in April 2009 to recover costs it had previously incurred in connection with its hydroelectric generation facilities.

The Utility’s future electric operating revenues forwill depend on the remainderamount of 2009 and 2010 are expected to increase, as authorized by the CPUC in the 2007 GRC.  The Utility’s electric operating revenues for future years are also expected to increase, asrevenue requirements authorized by the FERC in the TO rate cases and by the CPUC in the 2011 GRC.  (See “Regulatory Matters” below.)


In addition, thevarious regulatory proceedings. The Utility also expects to continue to collect revenue requirements to recover capital expenditures related to CPUC-approved capital expenditures outsidespecific projects approved by the GRC, including capital expenditures for the new Utility-owned generation projects and the SmartMeterTM advanced metering project.  Revenues would also increase to the extent that the CPUC approves the Utility’s proposal for other capital projects.CPUC. (See “Capital Expenditures” below.)

Revenue requirements associated with new or expanded public purpose, Finally, the CPUC has not yet determined how the existing energy efficiency and demand response programsincentive mechanism will also result in increased electric operating revenues.  In addition, future electric operatingbe modified, so the amount of incentive revenues are affected by changes in the Utility’s electricity procurement costs, as discussed under “Cost of Electricity” below.  Finally, the Utility may recognize additional incentive revenues toearn for the extent that it achieves the CPUC’s energy efficiency goals.implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

Cost of Electricity


The Utility’s cost of electricity includes purchasedcosts to purchase power costs,from third parties, certain transmission costs, the cost of fuel used in its generation facilities, and the cost of fuel supplied to other facilities under tolling agreements. These costs are passed through to customers.  The Utility’s cost of electricity also includes realized gains and losses on price risk management activities. (See NotesNote 7 and 8 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of electricity is passed through to customers. The Utility’s cost of electricity excludes non-fuel costs associated with the Utility’s own generation facilities, which are included in Operatingoperating and maintenance expense in the Condensed Consolidated Statements of Income. The cost of electricity provided to the Utility customers under power purchase agreements between the DWR and various power suppliers is also excluded from the Utility’s cost of electricity.


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


  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Cost of purchased power $947  $1,244  $2,620  $3,286 
Fuel used in own generation  50   38   143   120 
Total cost of electricity $997  $1,282  $2,763  $3,406 
Average cost of purchased power per kWh (1)
 $0.076  $0.092  $0.081  $0.090 
Total purchased power (in millions of kWh)  12,524   13,561   32,238   36,553 
                 
(1) Kilowatt-hour.
                

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

  Cost of purchased power

  $  1,041    $  947    $  2,694    $  2,620  

  Fuel used in own generation

  61    50    191    143  
                

  Total cost of electricity

  $  1,102    $  997    $  2,885    $  2,763  
                

  Average cost of purchased power per kWh(1)

  $  0.082    $  0.076    $  0.083    $  0.081  
                

  Total purchased power (in kWh)

  12,742    12,524    32,568    32,238  
                

 

   

 (1) Kilowatt-hour

   

   

The Utility’s total cost of electricity decreasedincreased by $285$105 million, or 22%11%, and $122 million, or 4%, in the three months ended September 30, 2009 and by $643 million, or 19%, in the nine months ended September 30, 2009, compared to the same periods in 2008.  This was primarily due to a decrease in the average cost of purchased power of 17% for the three months ended September 30, 2009 and 10% for the nine months ended September 30, 2009, as well as a decrease in the total volume of purchased power of 8% for the three months ended September 30, 2009 and 12% for the nine months ended September 30, 2009.  The decrease in the average cost of purchased power was primarily driven by lower market prices for electricity and gas.  The decrease in the volume of purchased power was primarily the result of milder weather and a decrease in residential, commercial, and industrial demand due to the continued economic downturn2010, respectively, as compared to the same periods in 2008.


2009. This was caused by an increase in the price of purchased power and an increase in the cost of fuel used in the Utility’s own generation facilities as the Utility increased its non-nuclear generation to replace power that had previously been provided under a DWR contract that expired at the end of 2009 (costs associated with power provided to the Utility’s customers under DWR contracts are not included in the Utility’s cost of purchased power). The Utility’s mix of resources is determined by the availability of the Utility’s own electricity generation and the cost-effectiveness of each source of electricity.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the level of hydroelectric and nuclear power thatproduced by the Utility, produces, the cost of procuring more renewable energy, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, novated, or renegotiated.  The Utility will incur higher costs to purchase power during the extended scheduled outage that began at Diablo Canyon Unit 2 in October 2009 to refuel and replace the unit’s reactor vessel head.  In addition, the output from the Utility’s hydroelectric generation facilities is dependent on levels of precipitation and could impact the volume of purchased power.


46

The Utility’s future cost of electricity may also may be affected by federal or state legislation or rules that may be adopted to regulate the emissions of greenhouse gases (“GHG”) from the Utility’s electricity generating facilities or theother generating facilities from which the Utility procures electricity. In particular, costs are likely to increase in the future when California’s statewide greenhouse gas emissions reduction lawthe California Global Warming Solutions Act of 2006 (“AB 32”) is implemented.


(See “Environmental Matters” below.)

Natural Gas Operating Revenues


The Utility sells natural gas, natural gas transportation services, and natural gas transportationstorage services. The Utility’s transportation services are provided by a transmission system and a distribution system. The transmission system transports gas throughout its service territory for delivery to the Utility’s distribution system, which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas to large end-use customers who are connected directly to the transmission system. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.


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


  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Bundled natural gas revenues $525  $709  $2,003  $2,699 
Transportation service-only revenues  80   85   247   247 
Total natural gas operating revenues $605  $794  $2,250  $2,946 
Average bundled revenue per Mcf(1) of natural gas sold
 $15.91  $20.85  $10.77  $13.36 
Total bundled natural gas sales (in millions of Mcf)  33   34   186   202 
                 
(1) One thousand cubic feet.
 

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

  Bundled natural gas revenues

  $  568    $  525    $  2,062    $  2,003  

  Transportation service-only revenues

  88    80    276    247  
                

  Total natural gas operating revenues

  $  656    $  605    $  2,338    $  2,250  
                

The Utility’s total natural gas operating revenues, decreasedincluding revenues intended to recover costs that are passed through to customers, increased by $189$51 million, or 24%8%, in the three months ended September 30, 2010 as compared to the same period in 2009. This reflects a $48 million increase in the total cost of natural gas due to higher market prices which is passed through to customers and does not impact net income. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding items passed through to customers, increased by $3 million. This was primarily due to a $16 million increase in authorized base revenues, partially offset by an $8 million decrease as compared to the same period in 2009 andwhen the Utility received a shareholder incentive award based on its core portfolio gas procurement.

The Utility’s total natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $696$88 million, or 24%4%, in the nine months ended September 30, 2009,2010 as compared to the same periodsperiod in 2008, primarily due to decreases2009. This reflects a $45 million increase in the total cost of natural gas of $217due to higher market prices and a $16 million increase in the three months ended September 30, 2009cost of public purpose programs, which are passed through to customers and $734do not impact net income. Natural gas operating revenues, excluding items passed through to customers, increased by $27 million. This was primarily due to a $39 million increase in the nine months ended September 30, 2009.  (See “Cost of Natural Gas” below.)  This decrease wasauthorized base revenues, partially offset by an $8 million decrease as compared to the following:


·Natural gas operating revenues increased by $8 million and $24 million in the three and nine months ended September 30, 2009, respectively, due to previously authorized increases in the Utility’s base revenue requirements for natural gas transportation, storage, and distribution services.
·Public purpose program costs passed through to customers increased by $10 million in the three months ended September 30, 2009 and $5 million in the nine months ended September 30, 2009 primarily due to increased energy efficiency measures and rebates.  (See “Operating and Maintenance” below.)
·Other miscellaneous natural gas operating revenues increased by $10 million in the three months ended September 30, 2009 and $9 million in the nine months ended September 30, 2009.

same period in 2009 when the Utility received a shareholder incentive award based on its core portfolio gas procurement.

The Utility’s future natural gas operating revenues will depend on the amount of revenue requirements authorized by the CPUC in various regulatory proceedings. (See “Regulatory Matters” below.) Additionally, the Utility’s future natural gas operating revenues will be affectedimpacted by changes in the cost of natural gas,gas. The Utility also expects future natural gas throughput volume, previously authorized increases in 2010 revenue requirements, andoperating revenues to increase to the extent that the CPUC approves the Utility’s separately funded capital projects. The CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues that the Utility may receive toearn for the extent that it achieves the CPUC’s energy efficiency goals.  The Utility’simplementation of its programs in 2009 and future natural gas operating revenues will also be affected by the outcome of the Utility’s application in its Gas Transmission and Storage rate case in which the Utility has requested the CPUC to establish revenue requirements for natural gas transmission and storage services for 2011 through 2014.years is uncertain. (See “Regulatory Matters” below.)


Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines, and intrastate pipelines, and gas storage costs, but excludes the transportation costs on intrastate pipelines for large commercialcore and industrial (or “non-core”)non-core customers, which are included in Operatingoperating and maintenance expense in the Condensed Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See NotesNote 7 and 8 of the Notes to the Condensed Consolidated Financial Statements.)

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


  Three Months Ended  Nine Months Ended 
  
September 30,
  
September 30,
 
(in millions) 
2009
  
2008
  
2009
  
2008
 
Cost of natural gas sold $96  $314  $760  $1,517 
Transportation cost of natural gas sold  38   37   119   96 
Total cost of natural gas $134  $351  $879  $1,613 
Average cost per Mcf of natural gas sold $2.91  $9.24  $4.09  $7.51 
Total natural gas sold (in millions of Mcf)  33   34   186   202 

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

  Cost of natural gas sold

  $  142    $  96    $  796    $  760  

  Transportation cost of natural gas sold

  40    38    128    119  
                

  Total cost of natural gas

  $  182    $  134    $  924    $  879  
                

  Average cost per Mcf(1) of natural gas sold

  $  4.18    $  2.91    $  4.54    $  4.09  
                

  Total natural gas sold (in Mcf)

  34    33    186    186  
                

 

    

 (1) One thousand cubic feet.

  

   

The Utility’s total cost of natural gas decreasedincreased by $48 million, or 36%, and $45 million, or 5%, in the three and nine months ended September 30, 2009 by $217 million, or 62%, and by $734 million, or 46%,2010, respectively, as compared to the same periods in 2008,2009, primarily due to decreaseshigher market prices for natural gas, which are passed through to customers and do not impact net income. The increase in the nine months ended September 30, 2010 was partially offset by the $49 million the Utility received in the first quarter of 2010 to be refunded to customers as part of a litigation settlement arising from the manipulation of the natural gas market price of natural gas.


by third parties during 1999-2002.

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


Operating and Maintenance


Operating and maintenance expenses consist mainly of the Utility’s costs to operate and maintain its electricity and natural gas facilities, customer accountsbilling and service expenses, the cost of public purpose program expenses,programs, and administrative and general expenses.  Operating and maintenance expenses are influenced by wage inflation; employee benefits; property taxes; the timing and length of Diablo Canyon refueling outages; storms, wild fires, and other events causing outages and damages in the Utility’s service territory; environmental remediation costs; legal costs; materials costs; the level of uncollectible customer accounts; and various other administrative and general expenses.  The Utility seeks to recover these expenses through authorized revenue requirements collected in rates.  The CPUC authorizes the majority of the Utility’s revenue requirements intended to recover these expenses in GRCs.  Revenue requirements are typically based on a forecast of costs for the first (or “test”) year of a GRC cycle followed by annual attrition increases until the first year of the next GRC.  The Utility’s next GRC will set revenue requirements beginning January 1, 2011.  (See “Regulatory Matters” below.)  In addition to authorized attrition increases in revenue requirements for 2009 and 2010 that help to offset increased expenses, the Utility seeks to achieve operational efficiencies and implement other anticipated cost-saving measures to manage expenses.


The Utility’s operating and maintenance expenses increased by $65$177 million, or 7%17%, in the three months ended September 30, 2010, as compared to the same period in 2009, primarily due to $238 million of costs associated with the San Bruno Accident. This amount includes a netprovision of $220 million for estimated third-party claims. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) This increase was partially offset by a $51 million decrease in employee severance costs of $50 million.  (This amount includes an accrual of $57 million for severance costsas compared to the same period in 2009 when charges were incurred related to the reduction of approximately 2% of the Utility’s workforce.)  In addition, the Utility incurredworkforce, and by a $27 million increasedecrease in labor and other costs as compared to performthe same period in 2009 when the Utility performed accelerated natural gas leak surveys and associated remedial work.

The Utility’s operating and maintenance expenses increased by $29 million, or 1%, in the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to $238 million of costs associated with the San Bruno Accident, partially offset by decreases of $105 million in labor costs and other costs as compared to 2009 when costs were incurred in connection with the scheduled refueling outage at Diablo Canyon and accelerated natural gas leak surveys and associated remedial work, and $69 million in severance costs as compared to the same period in 2008.  (The Utility targets completing the accelerated portion of this survey work by the second quarter of 2010.)  The Utility also2009 when charges were incurred a $20 million increase in employee benefit costs (primarily driven by rising healthcare costs) and a $6 million increase in property taxes.  These increases were partially offset by a $20 million decrease in CAISO collateral costs, which are passed through to customers, related to the new day-ahead market, an $8 million decrease in public purpose programreduction of approximately 2% of the Utility’s workforce. Additionally, operating and maintenance expenses decreased as a $4 million decrease in uncollectible customer accounts, andresult of a $6$35 million decrease in other miscellaneous operating and maintenance expenses.


The Utility’s operating and maintenance expenses, increased by $134 million, or 4%, in the nine months ended September 30, 2009 compared to the same period in 2008, primarily due to a net increase in employee severanceincluding costs of $65 million, a $54 million increase in costs to perform accelerated natural gas leak surveys and associated remedial work, a $46 million increase in employee benefit costs (primarily driven by rising healthcare costs), and an increase of $20 million in the accrual for employee vacation pay, as compared to the same period in 2008.  In addition, there was a $15 million increase in property taxes, an increase of $8 million in the Utility’swith uncollectible customer accounts asand pass through costs associated with the new day-ahead market.

The Utility estimates it may incur a resultmaterial amount of economic conditionsadditional expenses related to the San Bruno Accident through 2011. In addition, the Utility may incur costs in response to recommendations that may be made by the NTSB and rising unemploymentthe CPUC in the Utility’s service territory, and a $23 million increase in other miscellaneous operating and maintenance expenses.  These increases were partially offset by decreases in public purpose program expensescourse of $59 million, and decreases in labor costs of $38 million compared to those incurred in 2008 as a resulttheir investigations of the January 2008 winter storm.

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TheSan Bruno Accident and possible federal and/or state legislative mandates. Depending on the outcome of the NTSB and CPUC investigations and other factors, the Utility anticipates that it willmay also incur higher costs inadditional provisions for third-party claims related to the futureSan Bruno Accident. (See Note 10 of the Notes to improve the safety and reliability of its electric and natural gas system infrastructure and to maintain its aging electric distribution system.Condensed Consolidated Financial Statements.) The Utility also expectsmay incur costs to comply with CPUC orders or recommendations that it willmay be made as the CPUC conducts the “safety phase” of the Utility’s 2011 Gas Transmission and Storage Rate Case. (See “Regulatory Matters” below.) Finally, the Utility may incur higher expenses in future periods to obtain permits or comply with permitting requirements, including costs associated with renewing FERC licenses for the Utility’s hydroelectric generation facilities.  To help offset these increased costs, the Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficienciesrenew permits and to create future sustainable cost savings.

operate and maintain its aging electric and natural gas infrastructure.

Depreciation, Amortization, and Decommissioning


The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $31$50 million, or 7%11%, in the three months ended September 30, 20092010, and $59$121 million, or 5%9%, in the nine months ended September 30, 2009,2010, as compared to the same periods in 2008.  Depreciation expense increased by $25 million and $82 million in the three and nine months ended September 30, 2009, respectively,2009. These changes are primarily due to authorizedan increase in capital additions and depreciation rate changes.  In addition, amortization expense related to the energy recovery bonds (“ERBs”) increased by $6 million in the three and nine months ended September 30, 2009 compared to the same periods in 2008 primarily due to increased recovery rates.  These increases were partially offset by a decrease in decommissioning expense of $22 million in the nine months ended September 30, 2009, as compared to the same period in 2008.  In addition, miscellaneous amortization and decommissioning expenses decreased $7 million in the nine months ended September 30, 2009, as compared to the same period in 2008.


additions.

The Utility’s depreciation expense for the remainder of 2009 and 2010future periods is expected to increase as a result of an overall increase in net capital expenditures and implementation ofadditions. Additionally, depreciation rates authorized by the CPUC.  Depreciation expensesexpense in subsequent years will be determined based onimpacted by the depreciation rates set by the CPUC in the 2011 GRC and the 2011 Gas Transmissiongas transmission and Storagestorage rate case, and by the FERC in future TO rate cases.


Interest Income


In

The Utility’s interest income decreased by less than $1 million, or less than 1%, in the three and nine months ended September 30, 2009, the Utility’s interest income decreased $17 million, or 85%, and $48 million, or 62%, respectively,2010 as compared to the same periodsperiod in 2008 primarily due to the following factors:


·Interest income decreased by $6 million in the three months ended September 30, 2009, and $34 million in the nine months ended September 30, 2009, due to lower interest rates affecting various balancing accounts and regulatory assets.
·Interest income decreased by $6 million in the three months ended September 30, 2009, and $19 million in the nine months ended September 30, 2009, due to lower interest rates earned on restricted cash held in escrow related to Chapter 11 disputed claims.  (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)
·Interest income decreased by $5 million in the three months ended September 30, 2009, and $7 million in the nine months ended September 30, 2009, due to decreases in other interest income.

 The decrease2009. Interest income decreased by $22 million, or 76% in the nine months ended September 30, 20092010, as compared to the same period in 2008 was partially offset by an increase of2009, when the Utility recovered $12 million in the nine months ended September 30, 2009 for the recovery of interest on previously incurred costs related to the proposed divestiture of its hydroelectric generation facilities.  (See “Regulatory Matters” below.)

facilities (with no similar activity in the current year).

The Utility’s interest income in 2009 and future periods primarily will be primarily affected by changes in the balance of restricted cashfunds held in escrow pending resolution of the Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in interest rates.


Interest Expense


In

The Utility’s interest expense decreased by $1 million, or less than 1%, and $20 million, or 4% in the three and nine months ended September 30, 2009, interest expense decreased $8 million, or 5%, and $27 million, or 5%,2010, respectively, as compared to the same periods in 20082009. This decrease was primarily attributable to lower interest rates on outstanding short-term debt and decreases in the outstanding balances of the liability for Chapter 11 disputed claims and various regulatory balancing accounts and regulatory assets. This decrease was partially offset by interest that accrued on higher outstanding balances of long-term debt due to the following factors:

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·Interest expense accrued on the liability for Chapter 11 disputed claims decreased by $12 million in the three months ended September 30, 2009, and $40 million in the nine months ended September 30, 2009, as the FERC-mandated interest rates declined.
·Interest expense decreased by $9 million in the three months ended September 30, 2009, and $26 million in the nine months ended September 30, 2009, due to lower interest rates affecting various balancing accounts.
·Interest expense decreased by $4 million in the three months ended September 30, 2009, and $12 million in the nine months ended September 30, 2009, due to the reduction of the outstanding balance of ERBs.
·Interest expense on pollution control bonds decreased by $2 million in the three months ended September 30, 2009, and $10 million in the nine months ended September 30, 2009, primarily due to the repurchase of auction rate pollution control bonds in March and April 2008, which the Utility partially refunded, though at lower interest rates, in September and October 2008.
·Interest expense decreased by $9 million in the nine months ended September 30, 2009, due to an increase in interest expense in 2008 related to previously incurred scheduling coordinator costs.
·Interest expense decreased by $5 million in the three months ended September 30, 2009, and $6 million in the nine months ended September 30, 2009, due to lower interest rates on the Utility’s short-term debt.
·Interest expense decreased by $2 million in the three months ended September 30, 2009, and $5 million in the nine months ended September 30, 2009, due to decreases in other interest expense.

These decreases were partially offset by additional interest expensetiming of $26 million insenior note issuances. (See Note 4 of the three months ended September 30, 2009, and $81 million inNotes to the nine months ended September 30, 2009, primarily related to $1.8 billion in senior notes that were issued in the fourth quarter of 2008 and March 2009.

Condensed Consolidated Financial Statements for further discussion.)

The Utility’s interest expense in 2009 and future periods will be impacted by changes in interest rates, changes in the balance of the liability for Chapter 11 disputed claims, changes in regulatory balancing accounts and regulatory assets, and changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is issued.  (See “Liquidity and Financial Resources” below.)


Other Income, (Expense), Net


The Utility’s other income (expense), net increased by $18$9 million, or 900%56%, in the three months ended September 30, 2009 and $282010, as compared to the same periods in 2009. The increase in the three months ended September 30, 2010 was primarily due to an increase in allowance for equity funds used during construction due to higher average balances of construction work in progress.

The Utility’s other income net decreased by $32 million, or 117%62%, in the nine months ended September 30, 2009,2010, as compared to the same periodsperiod in 2008 when the Utility incurred costs to oppose certain legislation and municipalization efforts.  In addition, there was an increase2009. The decrease in the Utility’s allowance for funds used during constructionnine months ended September 30, 2010 was primarily due to an increase in spending relatedother expenses as a result of costs the Utility incurred to various projects, includingsupport the Colusa and Humboldt Bay Generating Stations.  This increase was partially offset whenTaxpayers’ Right to Vote Act, a California ballot initiative that appeared on the Gateway Generating Station and Diablo Canyon steam generators replacement projects became operativeJune 2010 ballot. These costs are not recovered in 2009 and 2008, respectively.


rates.

Income Tax Provision

The Utility’s income tax provision decreased by $56$4 million, or 34%4%, for the three months ended September 30, 2009, and $47 million, or 11%, for the nine months ended September 30, 2009,2010, as compared to the same periodsperiod in 2008.2009. The effective tax rates for the three months ended September 30, 2010 and 2009 were 29% and 2008 were 23.8% and 34.1%24%, respectively. The effective tax rate for the three months ended September 30, 2010 increased as compared to the same period in 2009 when the Utility recognized (1) state tax benefits arising from accounting method changes and (2) the benefits of various audit settlements at higher levels than 2010 settlements.

The Utility’s income tax provision increased by $124 million, or 33% for the nine months ended September 30, 2010, as compared to the same period in 2009. The effective tax rates for the nine months ended September 30, 2010 and 2009 were 37% and 2008 were 27.6% and 32.6%28%, respectively. The lower effective tax ratesrate for the three and nine months ended September 30, 2009 were primarily due to an increase in the amount of tax benefits recognized in 20092010 increased as compared to the amount ofsame period in 2009 when the Utility (1) recognized state tax benefits arising from accounting method changes, (2) recognized the benefits of various audit settlements at higher levels than 2010 settlements, and (3) received a federal tax refund. The effective tax rate also increased due to the reversal of a deferred tax asset in the first quarter of 2010 that had previously been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012 which was eliminated as part of the federal healthcare legislation passed during the three and nine months ended September 30, 2008.March 2010. (See Note 1110 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters.”)


50

PG&E Corporation, Eliminations, and Other


Operating Revenues and Expenses


PG&E Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to its 9.50% Convertible Subordinated Notes and 5.75%5.8% Senior Notes, and is not allocated to affiliates.


There were no material changes to PG&E Corporation’s operating income in the three and nine months ended September 30, 2009,2010, as compared to the same periods in 2008.


Other Income (Expense), Net

PG&E Corporation’s other income (expense), net increased by $19 million, or 158%, for the three months ended September 30, 2009, and $39 million, or 139%, for the nine months ended September 30, 2009 primarily due to investment-related gains as a result of improved market performance.

2009.

LIQUIDITY AND FINANCIAL RESOURCES


Overview


The Utility’s ability to fund operations depends on the levels of its operating cash flowflows and access to the capital markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal demand for electricity and natural gas, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. On May 7, 2009, the CPUC increased the Utility’sThe Utility has short-term borrowing authority by $1.5 billion, for an aggregate authority of $4.0 billion, including $500 million that is restricted tofor use in certain contingencies.


PG&E Corporation’s ability to fund operations, and capital expenditures, make scheduled principal and interest payments, refinance debt, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, fund capital investments, and make dividend paymentspay dividends primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital markets.


Credit Facilities


At December 31, 2008, PG&E Corporation had a $200 million revolving credit facility, and the Utility had a $2.0 billion revolving credit facility.  Commitments from Lehman Brothers Bank, FSB (“Lehman Bank”) represented $13 million, or 7%, and $60 million, or 3%, of the total borrowing capacity under PG&E Corporation’s and the Utility’s revolving credit facilities, respectively.  On April 27, 2009, PG&E Corporation and the Utility amended their revolving credit facilities and removed Lehman Bank as a lender.  As a result, PG&E Corporation now has a $187 million revolving credit facility, and the Utility has a $1.94 billion revolving credit facility.  The Utility’s revolving credit facility also provides liquidity support for commercial paper issued under the Utility’s $1.75 billion commercial paper program.
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The following table summarizes PG&E Corporation’s and the Utility’s outstanding commercial paper and revolving credit facilities at September 30, 2009:


(in millions)  At September 30, 2009 
Authorized BorrowerFacilityTermination Date Facility Limit  Letters of Credit Outstanding  Cash Borrowings  Commercial Paper Backup  Availability 
PG&E CorporationRevolving credit facilityFebruary 2012 $187(1)  $-  $-  $-  $187 
UtilityRevolving credit facilityFebruary 2012  1,940(2)   273   -   -   1,667 
Total credit facilities $2,127  $273  $-  $-  $1,854 
                      
(1) Includes an $87 million sublimit for letters of credit and $100 million sublimit for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.
 
(2) Includes a $921 million sublimit for letters of credit and $200 million sublimit for swingline loans.
 

PG&E Corporation’s and2010:

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

PG&E Corporation

   February 2012     $  187(1)   $ -     $ 90     N/A     $ 97  

Utility

   February 2012     1,940(2)   289     400     $ 586     665  

Utility

   February 2012     750(3)   N/A     -     -     750  
       

Total credit facilities

  

   $  2,877    $ 289     $ 490     $ 586     $ 1,512  
       
    

(1) Includes an $87 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.

(2) Includes a $921 million sublimit for letters of credit and a $200 million commitment for swingline loans.

(3) Includes a $75 million commitment for swingline loans.

   

  

  

In the Utility’snine months ended September 30, 2010, the average outstanding commercial paper balance was $745 million. There were no borrowings outstanding under the $1.9 billion revolving credit facilities includeuntil September 29, 2010, at which time $400 million was borrowed to pay down the then outstanding commercial paper balance. The $400 million borrowing was repaid on October 29, 2010.

On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. The Utility will use $500 million of the credit capacity under the credit agreement to support its electric procurement hedging activities. This credit capacity replaced the $500 million Floating Rate Senior Notes that matured on June 10, 2010. The remaining credit capacity of $250 million will be used for general working capital purposes. The credit agreement contains covenants that are usual and customary covenants for credit facilities of theirthis type, including covenants limiting liens, to those permitted under the senior note indenture, mergers, substantial asset sales, of all or substantially all of the Utility’s assets, and other fundamental changes. In addition, both PG&E CorporationBoth the $750 million and the $1.9 billion revolving credit facilities require that the Utility are required to maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65%, and as of the end of each fiscal quarter. In addition, the $1.9 billion revolving credit facility agreement requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting securitiescapital stock of the Utility.

At September 30, 2009,2010, PG&E Corporation and the Utility were in compliance with all covenants.


2009covenants under each of the revolving credit facilities listed in the table above.

2010 Financings


In March 2009, PG&E Corporation and

On April 1, 2010, the Utility issued $350$250 million and $550 million, respectively,principal amount of senior unsecured notes.  Proceeds5.8% Senior Notes due March 1, 2037. The proceeds from the senior notes offeringsthis issuance were used to finance capital expenditures, for general working capital, and to repay a portion of outstanding commercial paper thatpaper.

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility had issuedin 2008. The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to pay $600 millionmandatory tender on April 2, 2012 at a price of senior unsecured notes that matured100% 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 MarchApril 1 2009.  and October 1.

On June 11, 2009,September 15, 2010, the Utility issued $500$550 million of floating3.5% Senior Notes due October 1, 2020. The proceeds from this issuance were used to repay a portion of outstanding commercial paper.

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

On October 12, 2010, the Utility issued $250 million principal amount of Floating Rate Senior Notes due June 10, 2010.October 11, 2011. The net proceeds were used to repay outstanding commercial paper that was issued to satisfy margin calls and collateral requirements related to the Utility’s electric procurement commodity hedging activities.  On September 1, 2009, the California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank (“CIEDB”) issued $309 million of tax-exempt pollution control bonds series 2009 A through D for the benefit of the Utility.  The Utility used the proceeds it received from the CIEDB to repurchase the corresponding series of 2008 pollution control bonds.  The series 2009 bonds, issued at par with an initial rate of 0.20%, are variable rate demand notes with interest resetting daily and backed by direct-pay letters of credit.  Unlike the series 2008 bonds, interest earned on the series 2009 bonds is not subject to the alternative minimum tax (“AMT”).  A provision in the American Recovery and Reinvestment Act of 2009 allows certain tax-exempt bonds that are subject to AMT to be reissued or refunded in 2009 or 2010 as tax-exempt bonds that are not subject to AMT.  As a result, the series 2009 bonds were issued at a lower interest rate, reducing the Utility’s interest expense.


In addition,

PG&E Corporation issued 8,569,4753,766,678 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, (“DRSPP”), generating $211$141 million of cash throughduring the nine months ended September 30, 2009.  Also in 2009,2010. 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 at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding at September 30, 2010, and the conversion had no impact on cash.

PG&E Corporation also contributed $688$170 million of cash to the Utility during the nine months ended September 30, 2010 to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity ratio authorized by the CPUC.


Future Financing Needs


The amount and timing of the Utility’s future financing needs will depend on various factors, including the conditions in the capital markets, the timing and amount of forecasted capital expenditures, and the amount of cash internally generated through normal business operations, among other factors.  The Utility’s future financing needs will also depend on the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay.pay, the timing and amount of payments made to third parties in connection with the San Bruno Accident and the timing and amount of related insurance recoveries, the conditions in the capital markets, and other factors. (See NoteNotes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.)


PG&E Corporation may issue debt or equity in the future to fund equity contributions to the Utility’s operating expensesUtility and capital expendituresto fund investments to the extent that internally generated funds are not available.  Assuming that sufficient. As of September 30, 2010, PG&E Corporation made certain tax equity investments (see “PG&E Corporation” below) and may fund similar investments in the future, resulting in additional financing needs. On November 4, 2010, PG&E Corporation entered into an Equity Distribution Agreement under which various investment banks will act as PG&E Corporation’s sales agents with respect to offerings from time to time of shares of PG&E Corporation common stock having an aggregate value of up to $400 million. The sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the New York Stock Exchange, or otherwise at market prices prevailing at the time of the sale or at prices related to the prevailing market prices, or at negotiated prices.

PG&E Corporation and the Utility canhave had continued access to the capital markets on reasonable terms PG&E Corporation and the Utilitycontinue to believe that the Utility’s cash flowflows from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, make payments to third parties related to the San Bruno Accident, and finance future capital expenditures.


expenditures and investments.

Dividends


During the nine months ended September 30, 2009, the Utility paid common stock dividends totaling $468 million to PG&E Corporation.


During the nine months ended September 30, 2009,2010, PG&E Corporation paid common stock dividends totaling $435$492 million, net of $18$12 million that was reinvested in additional shares of common stock by participants in the DRSPP.Dividend Reinvestment and Stock Purchase Plan. On September 16, 2009,15, 2010, the Board of Directors of PG&E Corporation declared a dividenddividends of $0.42$0.455 per share, totaling $156$180 million, which waswere paid on October 15, 20092010 to shareholders ofon record onas of September 30, 2009.

2010.

During the nine months ended September 30, 2009,2010, the Utility paid cashcommon stock dividends totaling $10$537 million to PG&E Corporation.

During the nine months ended September 30, 2010, the Utility paid dividends totaling $11 million to holders of its outstanding series of preferred stock. On September 16, 2009,15, 2010, the Board of Directors of the Utility declared a cash dividenddividends totaling $3 million on its outstanding series of preferred stock, payable on November 15, 2009,2010, to shareholders on record as of record on October 30, 2009.29, 2010.

Utility


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Utility

Operating Activities


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


The Utility’s cash flows from operating activities for the nine months ended September 30, 20092010 and 20082009 were as follows:


  Nine Months Ended 
  
September 30,
 
(in millions) 
2009
  
2008
 
Net income $983  $870 
Adjustments to reconcile net income to net cash provided by operating activities:        
Depreciation, amortization, and decommissioning  1,439   1,388 
Allowance for equity funds used during construction  (71)  (51)
Deferred income taxes and tax credits, net  274   470 
Other changes in noncurrent assets and liabilities  95   55 
Effect of changes in operating assets and liabilities:        
Accounts receivable  20   (179)
Inventories  78   (153)
Accounts payable  (151)  (85)
Disputed claims and customer refunds  (700)  - 
Income taxes receivable/payable  534   208 
Regulatory balancing accounts, net  226   (94)
Other current assets  26   (125)
Other current liabilities  (62)  (80)
Other  3   (4)
Net cash provided by operating activities $2,694  $2,220 

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

Net income

   $  868    $  983  

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

   

Depreciation, amortization, and decommissioning

   1,580    1,439  

Allowance for equity funds used during construction

   (89  (71

Deferred income taxes and tax credits, net

   332    274  

Other changes in noncurrent assets and liabilities

   (286  95  

Effect of changes in operating assets and liabilities:

   

Accounts receivable

   (240  20  

Inventories

   (65  78  

Accounts payable

   15    (151

Disputed claims and customer refunds

   -    (700

Income taxes receivable/payable

   241    534  

Regulatory balancing accounts, net

   (14  226  

Other current assets

   28    26  

Other current liabilities

   (33  (62

Other

   14    3  
         

Net cash provided by operating activities

   $  2,351    $  2,694  
         

In the nine months ended September 30, 2009,2010, net cash provided by operating activities increaseddecreased by $474$343 million compared to the same period in 2008,2009 primarily due to the collectionan increase of $1.2 billion in rates to recover an under-collection in the Utility’s energy resource recovery balancing account that was incurred in 2008 due to higher than expected energy procurement costs.  (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.)  The increase in operating cash flows also reflects a decline of $224$523 million in net collateral paid by the Utility related to price risk management activities in 2009.2010. Collateral payables and receivables are included in Otherother changes in noncurrent assets and liabilities, Otherother current assets, and Otherother current liabilities in the table above. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The decrease also reflects $384 million of additional net collateral paid by the Utility relatedtax refunds received in 2009 compared to price risk management2010. The remaining decreases in cash flows from operating activities fluctuates based onconsisted of miscellaneous other changes in the Utility’s net credit exposure to counterparties, which primarily depends on electricityoperating assets and gas price movement.


Operating cash flows were also favorably impacted by $297 millionliabilities due to the timing and amount of tax payments and various tax settlements.  (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters.”)

Increasesdifferences.

Decreases in operating cash flows were partially offset by a $700 million payment to the California Power Exchange (“PX”) to reduce the Utility’s liability for the remaining net disputed claims (see Note 10 of the Notes to the Condensed Consolidated Financial Statements), a refund of $230 million received by the Utility in 2008 from the California Energy Commission (“CEC”)2009 with no similar refundpayment in 2009, and the subsequent return of $172 million of the CEC refund to customers through September 30, 2009.2010. (See Note 39 of the Notes to the Condensed Consolidated Financial Statements.)


Various factors can affect the Utility’s future operating cash flows, including the timing of cash collateral payments and receipts related to price risk management activity. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure to counterparties which primarily depends on electricity and gas price movement.


The Utility’s operating cash flows also will be impacted by electricity procurement costs and the timing of rate adjustments authorized to recover these costs. On October 15, 2009, theThe CPUC authorized the Utilityhas established a balancing account mechanism to adjust the Utility’s electric rates to refund $424 million to customers for an over-collection inwhenever the forecasted aggregate over-collections or under-collections of the Utility’s energy resource recovery balancing account by December 31, 2009.electric procurement costs for the current year exceed 5% of the Utility’s prior-year generation revenues, excluding generation revenues for DWR contracts. The Utility also will update its forecasted 20102011 electricity procurement costs in late November 20092010 for inclusion in the annual electric true-up proceeding, which will adjust electric and gas rates on January 1, 20102011 to (1) reflect over-over and under-collections in the Utility’s major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC and the FERC.


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Additionally, effective on June 1, 2010, the Utility began a program to provide expedited rate relief to customers. The program, which will continue through the end of 2010, includes a reduction in system bundled average electric rates coupled with a rebalancing of the residential rate tiers to reduce rates in the highest tiers. The rate reduction is expected to reduce 2010 retail electric billings by $268 million. To provide this reduction, the Utility has accelerated the refund of various over-collections that otherwise would not be reflected in adjusted rates until January 2011 and the Utility has suspended collection of the authorized revenue requirement for the currently under-spent funds in the California Solar Initiative Program. The rate relief program will have no impact on net income for the Utility.

Investing Activities


The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals and

the occurrence of storms and other events causing outages or damage to the Utility’s infrastructure, and the completion of electricity and natural gas reliability improvements projects.  Net cashinfrastructure. Cash used in investing activities also includeincludes the proceeds offrom sales and maturities of nuclear decommissioning trust assetsinvestments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.


The Utility’s cash flows from investing activities for the nine months ended September 30, 20092010 and 20082009 were as follows:


  Nine Months Ended 
  
September 30,
 
(in millions) 
2009
  
2008
 
Capital expenditures $(3,022) $(2,691)
Decrease (increase) in restricted cash  732   (3)
Proceeds from nuclear decommissioning trust sales  1,177   1,121 
Purchases of nuclear decommissioning trust investments  (1,219)  (1,161)
Other  7   21 
Net cash used in investing activities $(2,325) $(2,713)

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

Capital expenditures

   $  (2,794  $ (3,022

Decrease in restricted cash

   61    732  

Proceeds from sales and maturities of nuclear decommissioning trust investments

   962    1,177  

Purchases of nuclear decommissioning trust investments

   (1,001  (1,219

Other

   15    7  
         

Net cash used in investing activities

   $  (2,757)    $ (2,325
         

Net cash used in investing activities decreasedincreased by $388$432 million in the nine months ended September 30, 20092010 compared to the same period in 2008.2009. This decreaseincrease was primarily due to a $700 million decrease in the restricted cash balance that resulted from aan August 2009 payment to the PX to reduce the Utility’s liability for the remaining net disputed claims, (seewith no similar payment in 2010. (See Note 109 of the Notes to the Condensed Consolidated Financial Statements),Statements.)

This increase was partially offset by an increasea decrease of $331$228 million in capital expenditures for installingmainly due to weather conditions in the SmartMeter™ advanced metering infrastructure, generation facility spending, replacingfirst half of 2010 as compared to the same period in 2009 which delayed construction as work was shifted to emergency response; permitting, materials, and expanding gashardware purchase delays with no similar delays in 2009; and electric distribution systems, and improvinga larger decrease in 2010 than in 2009 in the electric transmission infrastructure. (See “Capital Expenditures” below.)


amount of new customer connections as a result of the continuing economic slowdown.

Future cash flows used in investing activities are largely dependent on the timing and amount of futureexpected capital expenditures. (See “Capital Expenditures” below and in the 20082009 Annual Report.Report for further discussion of expected spending and significant capital projects.)


Financing Activities


The Utility’s cash flows from financing activities for the nine months ended September 30, 20092010 and 20082009 were as follows:


  Nine Months Ended 
  
September 30,
 
(in millions) 
2009
  
2008
 
Net borrowings under revolving credit facility $-  $283 
Net (repayment) issuance of commercial paper, net of discount of $3 million in 2009 and $9 million in 2008  (290)  524 
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009  499   - 
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008  847   693 
Long-term debt matured or repurchased  (909)  (454)
Energy recovery bonds matured  (273)  (260)
Preferred stock dividends paid  (10)  (10)
Common stock dividends paid  (468)  (426)
Equity contribution  688   90 
Other  6   (31)
Net cash provided by financing activities $90  $409 
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           Nine Months Ended         
September 30,
 
(in millions)  2010  2009 

Borrowings under revolving credit facilities

   $  400    $  300  

Repayments under revolving credit facilities

   -    (300

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

   251    (290

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

   -    499  

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

   838    847  

Short-term debt matured

   (500  -  

Long-term debt matured or repurchased

   (95  (909

Energy recovery bonds matured

   (285  (273

Preferred stock dividends paid

   (11  (10

Common stock dividends paid

   (537  (468

Equity contribution

   170    688  

Other

   (40  6  
         

Net cash provided by financing activities

   $  191    $  90  
         

In the nine months ended September 30, 2009,2010, net cash provided by financing activities decreasedincreased by $319$101 million compared to the same period in 2008 mainly due to less net borrowings under the Utility’s revolving credit facility in 2009.  No commercial paper was outstanding at September 30, 2009 as the Utility received sufficient positive cash flows from income tax refunds and equity infusions, compared to net borrowings of $283 million in 2008. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.


PG&E Corporation


With the exception

As of dividend payments, interest, common stock issuance, the senior notes issuance of $350 million in March 2009, the receipt ofSeptember 30, 2010, PG&E Corporation’s affiliates had entered into four tax refunds of $139 million,equity agreements with privately held companies to fund residential and transactions betweencommercial retail solar energy installations. Under these agreements, PG&E Corporation will provide payments of up to $300 million, and in return, receive the Utility,benefits of local rebates, federal investment tax credits, and a share of these entities’ customer payments. As of September 30, 2010, PG&E Corporation had nomade total payments of $100 million under these tax equity agreements. PG&E Corporation’s financial exposure for these arrangements is primarily limited to its lease payments and investment contributions to these entities.

In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the nine months ended September 30, 2010 and 2009; dividend payments, interest, common stock issuance, the issuance of 5.75% Senior Notes in the principal amount of $350 million in March 2009, net tax refunds of $139 million in 2009, and 2008.


transactions between PG&E Corporation and the Utility.

CONTRACTUAL COMMITMENTS


PG&E Corporation and the Utility enter into contractual commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of electricity and natural gas for customers, purchases of transportation capacity, natural gas and electricity to support customer demand,purchases of renewable energy, and the purchase of fuel and transportation to support the Utility’s generation activities. In addition(Refer to those commitments disclosed in the 20082009 Annual Report, the Liquidity and those arising from normal business activities, PG&E Corporation’s and the Utility’s commitments at September 30, 2009 include $350 million of 5.75% Senior Notes issued by PG&E Corporation due April 1, 2014, $550 million of 6.25% Senior Notes issued by the Utility due March 1, 2039, and $500 million of Floating Rate Senior Notes issued by the Utility due June 10, 2010.  (See the 2008 Annual ReportFinancial Resources section above and Notes 4 10, and 1110 of the Notes to the Condensed Consolidated Financial Statements.)


CAPITAL EXPENDITURES


Depending on conditions in the capital markets, the Utility forecasts that it will make various capital investments in its electric and gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet already authorized growth.  

Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, and TO rate cases, and gas transmission and storage rate cases.  The Utility intends to file a GRC application with the CPUC before the end of 2009 to request an increase in authorized revenue requirements to recover capital expenditures forecast to be made in 2011 through 2013. (See “Regulatory Matters” below.) In addition, theThe Utility requests authorization to collectalso collects additional revenue requirements to recover capital expenditures related to specific projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric transmissiondistribution projects, and the SmartMeterTM advanced metering infrastructure. The Utility’s proposals for significant capital projects that have been submitted for CPUC approval are discussed in the 2009 Annual Report. Recent developments in authorized or proposed capital projects since the 2009 Annual Report was filed are discussed below.


Proposed

Electric Distribution Reliability Program (Cornerstone Improvement Program)


On February 23, 2009, a ruling was issued that establishes a schedule for the CPUC’s consideration of the Utility’s request for approval of a proposed six-year electric distribution reliability improvement program. On March 17, 2009, the Utility filed revised forecasts of proposed capital expenditures totaling $2.0 billion, a decrease from the original forecast of $2.3 billion, and proposed operating and maintenance expenses totaling $59 million, a slight increase from the original forecast of $43 million, over the six-year period ofJune 24, 2010, through 2016.  Hearings were completed in August 2009, and a final decision is scheduled to be issued in January 2010.


SmartMeter™ Program

The Utility has been installing an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility’s electric and gas customers.  This infrastructure results in substantial cost savings associated with billing customers for energy usage, and enables the Utility to measure usage of electricity on a time-of-use basis and to charge time-differentiated rates.  The main goal of time-differentiated rates is to encourage customers to reduce energy consumption during peak demand periods and to reduce procurement costs.  Advanced meters can record usage in time intervals and be read remotely.  The Utility expects to complete the majority of the installation throughout its service territory by the end of 2012.

The CPUC has authorized the Utility to recover the $2.2 billion estimated SmartMeter™ project cost, including an estimated capital cost of $1.8 billion.  In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed $2.2 billion without a reasonableness review by the CPUC.  The remaining 10% will not be recoverable in rates.  If additional costs exceed the $100 million threshold, the Utility may request recovery of the additional costs, subject to a reasonableness review.  Through September 30, 2009, the Utility has spent an aggregate of $1.2 billion, including capital costs of $1.0 billion, to install the SmartMeterTM system.
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The Utility’s ability to recognize the expected benefits of its SmartMeterTM advanced metering infrastructure remains subject to a number of risks, including whether the Utility incurs additional advanced metering project costs that the CPUC does not find reasonable or that are not recoverable in rates, whether the project is implemented on schedule, whether the Utility can successfully integrate the new advanced metering system with its billing and other computer information systems, and whether the new technology performs as intended.

Diablo Canyon Steam Generator Replacement Project

In November 2005, the CPUC authorized the Utility to replacerecover capital expenditures of $357 million expected to be incurred beginning in 2010 and continuing through 2013 to implement electric distribution reliability improvement projects designed to decrease the steam generators at the two nuclear operating units at Diablo Canyon (Units 1frequency and 2) and recover costsduration of up to $706 million from customers without further reasonableness review.electricity outages. The Utility installed fourhad requested that the CPUC approve a more comprehensive six-year reliability improvement program at an estimated capital cost of $2.0 billion. The CPUC determined that the Utility had not demonstrated the need for the entirety of the new steam generators in Unit 2 during 2008requested capital expenditure amount and completed installationauthorized a scaled-back three-year program to implement portions of the remaining new generators for Unit 1Utility’s proposed program. The CPUC also noted that any future investment in reliability projects can be considered in the Utility’s 2014 General Rate Case and subsequent general rate cases. The CPUC adopted the Utility’s proposal to set rates based on the adopted cost forecasts with a balancing account to accumulate any difference in revenue requirement based on recorded costs compared to the adopted forecast. The Utility is required to file annual reports (by March 7, 2009.  Project costs totaled approximately $690 million.

Proposed 1) to describe work performed during the previous calendar year and to include a forecast of work to be performed in the current year.

New Generation Facilities


Request for Long-Term

Proposed Oakley Generation Resources


OnFacility

In September 30, 2009, the Utility requested that the CPUC approve several agreements executed by the Utility following the completion of its April 1, 2008 request for offers of new long-term generation resources to meet forecasted customer demand, as forecasted in the Utility’s 2007-2016 long-term electricity procurement plan previously approved by the CPUC.  One of theincluding three power purchase agreements submittedand an agreement for a third party to the CPUC proposes thatdevelop and construct a new 586 megawatt (“MW”) natural gas-fired facility in Oakley, California that would be developed and constructed by a third party and then transferred to the Utility after commercial operation begins.upon completion. The initial estimated on-line date for the Oakley facility was June 2014. On July 29, 2010, the CPUC approved the power purchase agreements but the CPUC denied the Utility’s request for approval of the proposed Oakley generation facility would be operationally flexible, enablingfinding that the Utility to increase its use of renewable power by balancing the fluctuating output of wind and solar resources.  Thenew facility is expectednot needed to be built in Oakley, Californiameet forecasted customer demand. The Utility and completed in 2014.  (The remaining agreements submitted to the CPUC are power purchase agreements.)


Proposed Renewable Energy Development

In its February 24, 2009 application,developer revised their agreement and on August 23, 2010, the Utility has requested that the CPUC modify its prior decision and approve the Oakley project, with a guaranteed commercial availability date of June 2016. On November 2, 2010, a proposed decision was issued by the assigned CPUC administrative law judge that would deny the Utility’s request. Also on November 2, 2010, an alternate proposed decision was issued by a CPUC commissioner that would approve the Oakley project with a commercial availability date of June 2016. The Utility is unable to predict the outcome of this matter.

Humboldt Bay Generating Station

As of September 30, 2010, the Utility has incurred $227 million to construct a 163 MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life. The CPUC has authorized the Utility to recover associated capital costs of $239 million for the construction. Humboldt Bay commenced commercial operations in the third quarter of 2010.

Colusa Generating Station

As of September 30, 2010, the Utility has incurred capital costs of $644 million to construct a 657 MW combined cycle generating facility located in Colusa County, California. The CPUC has authorized the Utility to recover capital costs of $673 million for the construction of the facility. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations by the end of 2010.

New Renewable Energy Development

On April 22, 2010, the CPUC approved the Utility’s proposed five-year program for the development and construction of up to 250 MW of Utility-owned generating facilities using solar photovoltaic technology,(“PV”) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be deployed over a perioddeveloped by third parties. The Utility has been authorized to build 50 MW of five years, to helputility-owned PV facilities each year of the program. If the Utility meet its obligation under California lawbuilds less than 50 MW in a program year, it may roll forward no more than 10 MW of un-deployed capacity to increasebe developed in a subsequent program year. The first year of the amount of electricity provided to customers from renewable generation resources.  five-year program began on October 11, 2010.

The CPUC is expectedhas authorized the Utility to issue a final decisionrecover its actual capital costs to develop utility-owned PV facilities, subject to an aggregate price cap of up to $1.5 billion based on the maximum 250 MW authorized to be developed by the Utility. The CPUC also established an incentive mechanism that allows the Utility shareholders to retain 10% of the savings if the average capital cost per-kilowatt of the new Utility-owned PV facilities is less than a specified maximum amount per kilowatt. The remaining 90% of any such savings would be passed through to customers. As the Utility’s applicationnew PV facilities begin commercial operation, the project costs would be included in early 2010.


the Utility’s rate base and the Utility would be entitled to earn a rate of return on the additional rate base.

PG&E Corporation

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Williams Gas Pipeline Company, LLC, have been jointly pursuing the development of the proposed Pacific Connector Gas Pipeline, an interstate gas transmission pipeline that would connect with the proposed liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon being developed by Fort Chicago Energy Partners, L.P. as lead investor. The construction of the pipeline is dependent upon the construction of the LNG terminal. In December 2009, the FERC issued an order to authorize construction and operation of the LNG terminal and the pipeline. There are additional federal, state, and local permits and authorizations that must be obtained before construction can proceed. In addition, commitments must be obtained from LNG suppliers and shippers under long-term contracts of sufficient volumes to justify moving forward with construction of the LNG terminal and the pipeline. The desire of LNG suppliers to make such commitments is dependent on the world market for LNG, the price in various markets compared to the U.S. price, and the overall level of supply and demand for LNG. In the U.S., the gas supply landscape has changed considerably since the LNG terminal and pipeline were first contemplated. Enhanced drilling techniques have increased access to shale gas and created significant gas reserves which may decrease the need for LNG sourced natural gas. As such, PG&E Corporation cannot predict whether construction of the proposed LNG terminal and associated pipeline will occur nor whether PG&E Corporation will continue to invest in the proposed pipeline project.

OFF-BALANCE SHEET ARRANGEMENTS


PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.


CONTINGENCIES


PG&E Corporation and the Utility have significant contingencies,contingencies; including Chapter 11 disputed claims, claims arising from the San Bruno Accident, tax matters, legal matters, and environmental matters, which are discussed in Notes 109 and 1110 of the Notes to the Condensed Consolidated Financial Statements.


REGULATORY MATTERS


This section of MD&A discusses significant regulatory developments that have occurred in significant pending regulatory proceedings discussed in the 2008 Annual Report and significant new pending regulatory proceedings that were initiated since the 20082009 Annual Report was filed with the SEC.  The outcome of these proceedings could have a significant effect on PG&E Corporation’s and the Utility’s results of operations and financial condition.

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2011 General Rate Case Application


On October 21, 2009,15, 2010, the Utility, together with the CPUC’s Division of Ratepayer Advocates (“DRA”) notified the Utility that the DRA had conditionally accepted the Utility’s draft 2011 GRC application that the Utility filed on July 20, 2009., The Utility must wait 60 days before filing the GRC application.  Assuming the Utility timely meets the DRA’s conditions, the Utility intends to file the applicationReform Network (“TURN”), Aglet Consumer Alliance and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the endparties in the Utility’s 2011 GRC. The proposed settlement agreement will be subject to public comment in the GRC proceeding and then considered by the full CPUC. In the GRC, the Utility requested an overall increase in electric distribution, gas distribution and utility-owned generation revenue requirements of 2009.  $1.1 billion over currently authorized amounts effective January 1, 2011.

Revenue Requirements

The Utility intends to requestsettlement agreement proposes that the CPUC issueUtility’s total 2011 revenue requirements be increased by $395 million, including $103 million related to depreciation rate changes. In addition, the settlement agreement proposes to (1) establish a final decision bynew balancing account for meter reading costs outside of the endGRC that offsets $113 million requested in the GRC application and (2) remove $30 million of 2010.  Ifrequested revenue requirements from the decision is delayed, the Utility will, consistent with CPUC practiceGRC for consideration in prior GRCs, request the CPUC to issue an order directing thatother ratemaking proceedings. Furthermore, approximately $44 million of the revenue requirement changes incorporatedthe Utility requested in the CPUC’s decisionGRC application remains subject to litigation in the case will be effective asGRC.

The following table shows the differences, based on cost category, between the amount of January 1, 2011, even ifrevenue requirements included in the decision is issued subsequentGRC application and the amount proposed in the settlement agreement:

(in millions)

   Amounts Included  
in the GRC

Application
    Amounts Proposed  
in the Settlement
Agreement
  Difference 

Operations and maintenance

  $ 1,437    $ 1,308    $ (129

Customer services

  498    329    (169

Administrative and general

  857    768    (89

Less: Revenue credits

  (151  (149  2  

Franchise fees and uncollectible customer accounts, taxes (other than income taxes), and other adjustments

  188    120    (68

Depreciation, return, and income taxes

  3,817    3,601    (216
            

Total Revenue Requirements

  $ 6,646    $ 5,977    $ (669
            

The following paragraphs describe the revenue requirement reductions proposed in the settlement agreement compared to that date.


Unlike the currentamounts included in the GRC which setapplication:

The $129 million reduction in revenue requirements for a four-year period (2007 through 2010), it is expected that the next GRC will set revenue requirements for the Utility’s electric and natural gas distribution operations and electric generation operations formaintenance costs reflects a three-year period (2011 through 2013).  The Utility’s broad goals in this GRC are to fund continued investments in safe and reliable service, meet the economic needs of the communities served by the Utility, and work toward a greener, smarter energy future consistent with state and national goals for long-term environmental sustainability.


The critical driver of the Utility’s request in this GRC will be the need to invest in energy infrastructure to meet customers’ expectations for service quality.  Over the three years covered by this rate case (2011-2013), the Utility estimates it will need to spend an average of about $2.7 billion in capital expenditures annually on these infrastructure improvements, especially replacement of gas and electric systems that are reaching the end of their useful lives.  The Utility also needs adequate funds to continue to safely operate, maintain, and upgrade generation plants to serve growing demand.

In the 2011 GRC, the CPUC will determine the amount of authorized base revenues that the Utility may collect from its customers to recover its basic business and operational costs for gas and electric distribution and electric generation operations for the period from 2011 through 2013.  These revenue requirements are determined based on alower forecast of costs for 2011.  among other things, customer assistance services related to new customer connections, vegetation management, and development of utility-owned renewable generation.

The draft$169 million reduction in revenue requirements for customer services costs reflects the reduction of costs related to customer retention and economic development efforts, information technology, dynamic pricing, and meter reading. While the Utility’s GRC application indicatesrequested recovery of $113 million for meter reading costs in 2011, the settlement agreement proposes that these costs will instead be recovered via a new balancing account. The balancing account would track and recover incurred meter reading costs, subject to a cap of $76 million, and the Utility also would retain the cost savings attributable to decreased meter reading costs due to the installation of SmartMeter™ devices. The total of the balancing account recovery plus retained cost savings is estimated to approximate the $113 million originally requested.

The $89 million reduction in administrative and general reflects lower funding for various PG&E Corporation and Utility corporate service functions and lower funding for employee incentive compensation. The Utility also agreed to seek recovery of $5 million of costs incurred in connection with the sale of property in another proceeding rather than the GRC.

The $68 million reduction in revenue requirements relating to franchise fees and uncollectible customer accounts, taxes (other than income), and other adjustments, includes $44 million related to return and income taxes on the Utility’s unrecovered investment in conventional electric meters that have been replaced by SmartMeterTM devices. The parties have agreed that this part of the Utility’s request will be litigated as part of the GRC proceeding. If the Utility is successful, the $44 million will be added back to the Utility’s 2011 electric distribution revenue requirement. The settlement agreement also would adopt a higher uncollectible revenue factor that would be used in another CPUC proceeding to determine the amount of revenue the Utility can collect to offset uncollectible customer accounts. This is expected to result in additional revenues of approximately $4 million.

The $216 million reduction in revenue requirements for depreciation, return, and income taxes consists of a $105 million decrease driven by lower depreciation rates and a $111 million decrease related to lower capital expenditures and other rate base adjustments. About $49 million of the $111 million reduction is related to the treatment of nuclear fuel and fuel oil inventory balances. Under the settlement agreement, the Utility agreed to continue recovering carrying costs on these balances at short-term interest rates (estimated to be $1 million per year based on current rates) through the energy resource recovery balancing account (“ERRA”) in accordance with the current regulatory treatment of these costs, rather than as part of the authorized GRC rate base. Another $20 million of the reduction relates to costs to implement the California Independent System Operator’s Market Redesign and Technology Update (“MRTU”). Consistent with the settlement agreement, the Utility plans to request aseek recovery of MRTU-related costs through the ERRA or other proceedings.

In summary, the settlement agreement proposes revenue increaserequirements of $3.2 billion for 2011 ofelectric distribution (as compared to $3.5 billion included in the GRC application), $1.1 billion or 6.5%for natural gas distribution (as compared to $1.3 billion included in the GRC application), aboveand $1.7 billion for electric generation operations (as compared to $1.8 billion included in the 2010 total revenue forecast.


GRC application).

Attrition Year Revenues

The Utility plans to request that the CPUC adopt new flexible cost recovery mechanisms by establishing balancing accountssettlement agreement provides for several categories of costs that are subject to a high degree of volatility based on economic conditions and other uncontrollable factors, including costs incurred to establish new customer connections, uncollectible accounts, and employee healthcare costs.   


The Utility also has indicated that it will seek a ratemaking mechanism for 2012 and 2013 designed to increase the Utility’s authorized revenues in years between GRCs to reflect increases in rate base due to capital investments in infrastructure, and increases in wages and expenses.  The proposed mechanism also would require revenue requirements to be adjusted to reflect changes in franchise, payroll, income, or property tax rates, as well as new taxes or fees imposed by governmental agencies.  The Utility estimates that this mechanism would result in a revenue requirementan attrition increase of $244$180 million to the authorized 2011 revenues in 2012 and an additional increase of $326$185 million in 2013. On a comparable basis, the Utility had requested an attrition mechanism estimated to provide increases of approximately $262 million in 2012 and approximately $334 million in 2013.

Balancing Accounts

The settlement agreement proposes to establish a new “one-way” balancing account for the Utility would adviseto recover up to approximately $20 million per year for costs associated with the Utility’s natural gas distribution integrity management program. If these costs are not spent during the GRC period, the unspent funds must be refunded to customers. With the exception of this proposed new one-way balancing account and the proposed meter reading balancing account discussed above, the settlement agreement proposes to retain the existing balancing account structure without any substantial changes.

Capital Additions and Rate Base

The settlement agreement is consistent with capital expenditures for 2011-2013, averaging $2.2 billion to $2.3 billion per year for the portions of the Utility’s business addressed in the GRC. Proposed capital expenditures are lower than the amount included in the Utility’s GRC application, which averaged $2.7 billion per year, based on a lower forecast for new customer connections and lower capital expenditures for hydroelectric generation facilities, information technology systems, and fleet replacement. The ultimate amounts of capital expenditures will depend on a number of factors, including the level of operations and maintenance, administrative and general, and other costs.

The settlement agreement proposes a 2011 annual average rate base of $16.6 billion for the portions of the Utility’s business reviewed in the GRC compared with the Utility’s request of $17.2 billion. The difference of approximately $600 million is based on the reduction of capital expenditures described above, the removal of MRTU-related capital expenditures, the continued funding of nuclear fuel and fuel oil inventory through the ERRA proceeding rather than through rate base, and the adjustment of deferred taxes to reflect the Utility’s updated estimate of the impact of 2009 bonus depreciation.

Schedule

In order to allow settlement discussions to proceed, the CPUC suspended the procedural schedule for the GRC, which had previously provided for a final decision in December 2010. It is possible that the CPUC will not issue a decision until after the end of the actual amountyear. On August 6, 2010, the Utility filed a motion requesting that, regardless of these proposed increases in October 2011 and October 2012 for years 2012 and 2013, respectively.


the timing of a CPUC decision, any revenue requirement change be effective on January 1, 2011. That motion remains pending before the CPUC.

PG&E Corporation and the Utility are unable to predict what amount of revenue requirementswhether the CPUC will authorize forapprove the period from 2011 through 2013, when a final decision in this proceeding will be received, or how the final decision will impact their financial condition or results of operations.


settlement agreement.

Electric Transmission Owner Rate Cases


On June 18, 2009,July 27, 2010, the FERC approved aan uncontested settlement thatof the Utility’s 12th TO rate case. The settlement sets the Utility’s annual retail transmission base revenue requirement at $776$875 million effective March 1, 2009.  (For purposes of determining wholesale transmission2010. Retail electric rates this retailwere adjusted on June 1, 2010 to reflect the revenue requirement is adjusted to $763.5 million.)  As part ofadopted in the settlement and the Utility has reserved the difference between revenues collected in the rates requested by the Utility in its TO rate application, from March 1, 2010 until May 31, 2010, and the rates agreed to in the settlement. As a result, the settlement will not impact the Utility’s results of operations or financial condition. The Utility will refund any over-collected amounts to customers, with interest, through an adjustment to rates in 2011.


On July 30, 2009,28, 2010, the Utility filed an application with the FERC requesting an annual retail transmission revenue requirement of $946 million.  (For purposes of determining wholesale transmission rates, this retail revenue requirement request has been adjusted to $932 million.)$1.0 billion. The proposed rates represent an increase of $170$150 million over current authorized revenue requirements. On September 30, 2009,2010, the FERC accepted the Utility’s application makingand also permitted the proposed rates to become effective on March 1, 20102011, subject to refund following the conclusion of hearings and the outcome of judge-supervised settlement discussions.

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Energy Efficiency Programs

On June 17, 2010, the FERC issued a notice of proposed rulemaking and Incentive Ratemaking


established a proceeding to examine, among other issues, whether to change the FERC’s existing policy that provides incumbent traditional public utilities a “right of first refusal” to own, construct, and operate transmission facilities within their respective service territories. The CPUC previously established an incentive ratemaking mechanism applicable torules that the California investor-owned utilities’ implementation of their energy efficiency programs fundedFERC adopts in this proceeding may introduce additional competition from merchant or independent transmission project developers for the 2006-2008 and 2009-2011 program cycles.  On December 18, 2008, based on their first interim claims, the CPUC awarded interim incentive earnings to the utilities for their 2006-2007 program performance.  In the fourth quarterconstruction of 2008, the Utility recognized a CPUC award of $41.5 million for the Utility’s energy efficiency program performance in 2006-2007.  Under the existing incentive ratemaking mechanism, the maximum amount of revenuecertain transmission facilities that do not exist today. The rules that the Utility could earn and the maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.   

On January 29, 2009, the CPUC established a new rulemaking proceeding to modify the existing incentive ratemaking mechanism for programs beginning in 2009 and future years, toFERC may adopt a new framework to review the utilities’ 2006-2008 program performance for the second interim claim, and to conduct a final review of the utilities’ performance over the 2006-2008 program period.  On May 21, 2009, the Utility, San Diego Gas & Electric Company, Southern California Gas Company, and the Natural Resources Defense Council jointly requested that the CPUC approve a proposed settlement to resolve the utilities’ second interim claims and their final 2006-2008 true-up incentive claims.  On July 10, 2009, the Utility submitted calculations, based on the methodology included in the proposed settlement, indicating that the Utility would be entitled to earn the remaining amount of the maximum incentives that could be earned for the 2006-2008 period.  Based on the holdback amount proposed in the settlement, the Utility would be entitled to receive $76.6 million in incentive earnings and an additional $61.9 million would be held back and subject to verification in the final 2006-2008 true-up process to be completed in 2010.  The assigned administrative law judge has ruled that there will be no hearings on the settlement proposal.

In accordance with the process established by the current incentive ratemaking mechanism, on October 15, 2009, the CPUC approved a second verification report issued by the CPUC's Energy Division relating to the second interim claims for the utilities’ 2006-2008 program performance.  The report calculates potential incentive amounts for the Utility, based on different energy savings assumptions and measurement methods, that range up to $20.6 million with up to an additional $33.4 million to be held back pending completion of the 2006-2008 true-up process in 2010.  In addition, on September 3 and October 1, 2009, the CPUC’s Energy Division released additional incentive award scenarios, including scenarios based on the proposed settlement, that result in a wide range of potential financial outcomes.  It is uncertain what effect, if any, the issuance of the verification report or the scenarios will have on the likelihood of the proposed settlement becoming effective.  Whether the proposed settlement will be approved and the amounts of any interim and final claims that may be awarded to the Utility are uncertain at this time.

On July 2, 2009, the utilities re-filed their applications containing their proposed 2009-2011 energy efficiency programs and budgets with the CPUC.  On September 24, 2009, the CPUC modified the utilities’ 3-year cycles to cover 2010-2012 energy efficiency programs and authorized funding for these programs.  The CPUC authorized the Utility to collect $1.3 billion to fund its programs, a 42% increase over 2006-2008 authorized funding levels.  Consequently, the Utility will continue to collect bridge funding of approximately $435 million for the Utility’s 2009 energy efficiency programs, as previously authorized by the CPUC.

Spent Nuclear Fuel

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.  The DOE failed to develop a permanent storage site by January 31, 1998.

The Utility believes that the existing spent fuel pools at Diablo Canyon, which include newly constructed temporary storage racks, have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2.  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 through at least 2024.  The construction of the dry cask storage facility is complete and the movement of spent nuclear fuel to dry cask storage began in June 2009.

After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats.  In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.
In October 2008, the NRC rejected the final contention that had been made during the appeal.  The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit.  On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding.  The Utility’s brief on appeal was filed on April 8, 2009.  No date has been set for oral argument.
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As a result of the DOE’s failure to build a national 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 seeks to recover $92 million of costs that it incurred through 2004.  After several years of litigation, the DOE now concedes that the Utility is entitled to recover approximately $82 million of these costs, but the DOE continues to dispute the remaining amount.  The trial to determine the appropriate method to calculate the amounts owed to the Utility began on October 15, 2009.  The Utility also will seek to recover costs incurred after 2004 to build on-site storage facilities

PG&E Corporation and the Utility are unable to predict the amount and timing of any recoveries that the Utility will receive from the DOE.  Amounts recovered from the DOE will be credited to customers through rates.

Application to Recover Hydroelectric Facility Divestiture Costs

On April 16, 2009, the CPUC approved a decision to authorize the Utility to recover $47 million of costs, including $12 million of interest, that the Utility incurred in connection with its efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001.  These efforts were undertaken as required by the CPUC in connection with the proposed divestiture of the facilities to further the development of a competitive generation market in California.  The CPUC subsequently withdrew this requirement.  The Utility continues to own its hydroelectric generation assets.  The Utility expects that the rate adjustments necessary to recover these authorized costs will be combined with other rate adjustments in the Utility’s annual electric rate true-up proceeding.  These rate changes are expected to become effective in January 2010.

Retirement Plan Contribution Application

On September 10, 2009, the CPUC approved the all-party settlement among the Utility, the DRA, and the Coalition of California Utility Employees to resolve the Utility’s March 2, 2009 application to allow the Utility to recover amounts necessary for the Utility’s pension plan trust to attain fully funded status.  Under the adopted settlement and based on projections to reach fully funded status by 2018, the Utility’s authorized pension-related revenue requirements would be $140.5 million, $177.2 million, and $215.7 million in 2011, 2012, and 2013, respectively.  The Utility would request revenue requirements after 2013 in a separate proceeding.  In addition, the settlement will allow the Utility to request an increase in revenue requirements if the ratio of trust assets to trust obligations falls below 85%.

The differences between pension benefit costs recognized in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and amounts recognized for ratemaking purposes are recorded as a regulatory asset or liability as amounts are probable of recovery from customers.  (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.)  Therefore, the settlement is not expected to impact net income in future periods.

Cost of Capital Proceeding

On October 15, 2009, the CPUC approved a decision that maintains the Utility’s authorized cost of capital, including a ROE of 11.35%, through 2010.  The decision approves a joint request made by the Utility and the DRA to avoid imposing a rate increase corresponding to an increasetransmission investment in the Utility’s ROE during a time of economic hardship.  The Utility believes that this increase may otherwise have been triggered as of January 1, 2010 by the cost of capital adjustment mechanism previously adopted by the CPUC on May 29, 2008.  The Utility’s capital structure, including a 52% equity component, will be maintained through 2012.

In addition, as requested by the Utility and the DRA, the CPUC extended the cost of capital adjustment mechanism through 2012.  The cost of capital adjustment mechanism will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Services utility bond index increases or decreases by more than 1% as compared to the applicable benchmark.  Finally, the CPUC agreed to defer the due date for the Utility’s next full cost of capital application from April 20, 2010 until April 20, 2012, so that any resulting changes would become effective on January 1, 2013.

2011.

2011 Gas Transmission and Storage Rate Case


On September 18, 2009, the Utility filed an application with the CPUC to initiate

In the Utility’s 2011 Gas Transmissiongas transmission and Storagestorage rate case, so that the CPUC canwill determine the rates and terms and conditions of the Utility’s gas transmission and storage services for a four-year period beginning January 1, 2011.  The rates,2011 and termscontinuing through 2014.

Proposed Settlement Agreement

On August 20, 2010, the Utility and conditions ofother parties, including TURN and the Utility’s gas transmission and storage services for 2008 through 2010 were set byDRA, requested the terms ofCPUC to approve a CPUC-approved all-partyproposed settlement agreement, known as the Gas Accord IV that was approved byV Settlement Agreement (“Gas Accord V”), to set the CPUC in September 2007.Utility’s gas transmission and storage rates and associated revenue requirements, as well as the market structure, for 2011 through 2014. The Utility proposes to continueproposed Gas Accord V also would extend a majority of the Gas Accord IV’s terms and conditions of natural gas transportation and storage services.


(See the 2009 Annual Report for a discussion of the Gas Accord IV.) The Utility has requested thatCPUC’s approval of the CPUC approveproposed Gas Accord V is subject to the resolution of several objections raised by San Diego Gas & Electric Company and Southern California Gas Company regarding their rights and obligations under the proposed agreement.

The Gas Accord V proposes a 2011 natural gas transmission and storage revenue requirement of $529.1$514 million, an increase of $67.3$52 million over the 2010 adopted revenue requirement. The Utility also seeks attrition increasesproposed revenue requirement for 2012 is $541 million, $565 million for 2013, and 2014$582 million for 2014. The Gas Accord V proposes average annual capital expenditures of $32.4 million, $30.7$174 million and $22.6average annual depreciation costs of $112 million. The Gas Accord V provides for a 2011 operating and maintenance expense level of $105 million respectively.


which would increase at an annual average rate of 2% for 2012 through 2014.

Under the Utility’s proposal, a substantial portionproposed Gas Accord V, approximately 45% of the authorized revenue requirements, primarily those costs allocated to residential and small commercialcore customers, (called “core” customers) would continue to be assured of recovery through balancing account mechanisms and/orand fixed reservation charges.  The Utility has proposed to simplify the current rate structure by, among other changes, setting rates for core and “non-core” customers based on forecast demand. The Utility’s ability to recover its remaining revenue requirements would continue to depend on throughput volumes gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. To reduce the Utility’s financial risk of non-recovery on these remaining revenue requirements, the proposed settlement agreement includes a revenue sharing mechanism. An under-collection or over-collection of the remaining revenue requirements associated with these factors,backbone transmission services (35% of authorized revenue requirement) would be shared equally between the Utility has proposed to share equally withand customers (both core and non-core). Customers would be allocated 75% of any under-collection or over-collection of natural gasremaining revenue requirements associated with local transmission andservices (13% of authorized revenue requirement). Customers also would be allocated 75% of any over-collection in

remaining revenue requirements associated with storage services (7% of authorized revenue requirements.requirement), but the Utility would be at risk for 100% of a net under-collection. The Utility has proposedGas Accord V provides for additional cost recovery mechanisms for costs that are difficult to forecast, such as the cost of electricity used to operate natural gas compressor stations and costs that are determined in other Utility regulatory proceedings.

Safety Phase

On October 15, 2010, an additional phase was added to complythe Utility’s 2011 Gas Transmission and Storage Rate Case to address the Utility’s natural gas pipeline safety, integrity, and reliability measures and the Utility’s emergency response procedures used in its natural gas transmission and storage operations. This new “safety phase” will focus on ensuring the safety and reliability of the Utility’s natural gas transmission and storage system. The CPUC will review and consider the types of protocols and procedures that the Utility should have in place or that the CPUC should immediately order to ensure the safe operation of the Utility’s gas transmission and storage operations over the next four years. The ruling notes that the new safety phase is distinct from the NTSB’s and the CPUC’s pending investigations into the cause of the San Bruno Accident, any proceedings that may be opened as a result of the CPUC’s investigation, and any federal or state legislation that may be adopted. Opening comments on the safety phase issues are due November 22, 2010, with greenhouse gas regulations.


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The Utility hasreply comments due on December 27, 2010. A proposed decision on these issues is expected in February or March 2011.

Request to Make Rate Changes Effective on January 1, 2011

On October 8, 2010, the parties requested that the CPUC issue a final decision by December 21, 2010 to allow the end of 2010.Utility to adjust 2011 rates (upward or downward) from the date the CPUC issues a final decision on the Gas Accord V assuming the final decision is issued after January, 1, 2011. If the CPUC does not issue a decision on this request by January 1, 2011, the terms of the Gas Accord IV provide that the interim transmission and storage rates beginning January 1, 2011 will equal the rates in effect on December 31, 2010, plus a two percent escalator for local transmission rates.

Procedural Schedule

The CPUC’s procedural schedule calls for the CPUC to issue a final decision on the Gas Accord V and the litigated issues on or before March 10, 2011. It is expected that the CPUC’s procedural schedule for the safety phase will be set in early January 2011.

PG&E Corporation and the Utility are unable to predict whether or when the CPUC will approve the proposed Gas Accord V. PG&E Corporation and the Utility are also unable to predict what actions the CPUC may require the Utility to take as a result of the new safety phase and whether the costs the Utility incurs to take such actions would be recoverable in whole or part.

Finally, the costs contemplated under the Gas Accord V do not include potential costs associated with the Utility’s proposed Pipeline 2020 program of initiatives, announced on October 12, 2010, to work with regulators and industry experts to strengthen the natural gas system over the next decade. The program is expected to focus on the modernization of critical pipeline infrastructure, the use of automatic or remotely operated shut-off valves, the development of industry-leading best practices, and enhancing public safety. As part of this program, the Utility plans to create a new non-profit entity to research and develop next-generation pipeline inspection and diagnostic tools. The Utility will provide $10 million to fund this new entity at no cost to customers.

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.

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

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

The CPUC’s rulemaking proceeding to consider modifications to the existing incentive ratemaking mechanism that would apply to future energy efficiency program cycles is still pending. It is uncertain when the CPUC will issue a decision in this proceeding.

Direct Access

As authorized by California Senate Bill 695, on March 11, 2010, the CPUC adopted a plan to approvere-open “direct access” on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.

2009 Energy Resource Recovery Account Compliance Proceeding

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through ERRA, a balancing account that tracks the difference between (1) billed/unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility’s authorized procurement plans. To determine rates used to collect ERRA revenues, each year the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements and generation fuel expense and approves a forecasted revenue requirement. The CPUC also performs an annual compliance review of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans.

The Utility’s 2009 ERRA compliance review proceeding is currently pending before the CPUC. On July 9, 2010, the DRA filed testimony to recommend that the CPUC disallow $176 million of costs that the DRA estimates the Utility incurred in 2009 to buy power during 110 outages of the Utility’s own generation facilities. The DRA argued that since the Utility did not present evidence of the reasonableness of its outage management activities and the related replacement costs in its initial application and testimony, these costs should be disallowed. On August 4, 2010, the CPUC administrative law judge overseeing the proceeding granted the Utility’s request to strike the DRA’s testimony. The CPUC is expected to issue a final decision in this proceeding by December 31, 2010.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2009 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. (In July 2010, PG&E Corporation and the Utility posted their annual Corporate Responsibility and Sustainability Report athttp://www.pgecorp.com. This report includes the Utility’s third-party verified GHG emissions data for 2008. This report is not incorporated by reference into this quarterly report.)

Recent developments since the 2009 Annual Report was filed are discussed below.

Climate Change

AB 32 requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. (See “Environmental Matters” in the 2009 Annual Report.) On November 2, 2010, California voters defeated a ballot initiative, Proposition 23, to suspend AB 32.

In December 2008, the California Air Resources Board (“CARB”), the state agency charged with setting and monitoring GHG and other emission limits, adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program.

On September 23, 2010, the CARB adopted regulations that require virtually all load-serving entities, including the Utility, to increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. Regulated load-serving entities are allowed to use an unlimited number of tradable renewable energy credits (“RECs”) to comply. (A tradable REC refers to a certificate of proof of the procurement of the

green attributes unbundled from the associated energy. The certificate may be transferred to any third party and resold.) The CARB can impose penalties for failure to meet the targets but it is unclear how the penalties would be calculated or whether the total penalties are subject to an annual maximum. For example, the CPUC has established an annual maximum penalty of $25 million for failure to meet the existing renewable portfolio standard (“RPS”) established under California law. Further, the CARB did not adopt “flexible compliance rules” such as those used by the CPUC to determine compliance with current RPS requirements. The CARB has directed its staff to modify the regulations to address concerns about the potential for excessive penalties. It is uncertain when the modified final regulations will be issued.

In addition, on October 28, 2010, the CARB issued proposed cap-and-trade regulations and proposed amendments to the existing regulation for the mandatory reporting of GHG emissions. Following a 45-day public comment period, these regulations will be presented for the CARB’s consideration in mid-December 2010. If adopted by the CARB and approved by the Office of Administrative Law, the regulations would set an annual cap on GHG emissions from 2012 to 2020 and allow companies to buy and sell emission allowances or offsets to meet the applicable cap. Some emission allowances would be allocated to the electric sector utilities at no cost for the benefit of their customers. The price of other emission allowances would be subject to a price collar. The CARB has indicated that the natural gas and transportation-fuel sectors will not be included in the cap-and-trade program until 2015. The ultimate financial impact of the new rates effective Januarycap-and-trade system will depend on various factors, including the quantity of allowances that are freely allocated to utilities for customer benefit, the actual market price of emissions allowances over time, the availability of emission offsets, and the extent to which California’s cap-and-trade program is linked to other state, regional or national programs.

Renewable Energy Resources

Current California law establishes a RPS that requires California retail sellers of electricity, such as the Utility, to increase their deliveries of renewable energy (such as biomass, hydroelectric facilities with a capacity of 30 MW or less, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from these eligible renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. For the year ended December 31, 2009, the Utility’s RPS-eligible renewable resource deliveries equaled 14.4% of its total retail electricity sales. Most of the renewable energy that was delivered was purchased by the Utility from third parties, mainly under agreements with qualifying facility generators, irrigation districts, and other bilateral contracts. As of September 30, 2010, the Utility believes it will meet the RPS mandate for 2010 through reliance on the CPUC’s flexible compliance rules. On September 1, 2011,2010, the September 2007California Legislature failed to pass Senate Bill 722 which proposed to establish a 33% RPS by 2020. Additional legislation may be considered and adopted in the future. In addition, as described above, the CARB has adopted regulations imposing a 33% renewable energy standard to be met by 2020 to help reduce GHG emissions as required by AB 32.

Uncertainty still exists regarding whether RECs can be used to comply with the current RPS requirements. The

CPUC issued a decision in March 2010 which, among other provisions, imposes a price cap of fifty dollars per tradable REC, and permits investor-owned utilities to use tradable RECs to comply with up to 25% of their annual RPS procurement target in any year and carry over any excess RECs for compliance in future years. For purposes of computing the annual limit, the CPUC decision approvingclassifies power-purchase contracts with out-of-state renewable generation facilities as RECs. Most of the Gas Accord IVUtility’s power-purchase contracts with out-of-state renewable generation facilities would be included in the computation of the 25% limit, negatively affecting the Utility’s ability to meet the RPS. The CPUC stayed its decision in May 2010 after various parties, including the Utility, requested the CPUC to modify the decision. A proposed decision has been issued which, if adopted by the CPUC, would lift the stay, reaffirm the price cap, increase the REC limit to 30%, and exclude power-purchase contracts for out-of state-renewable resources from the 30% limit if the contracts had been executed and approved by the CPUC before March 11, 2010. The proposed decision provides that the ratesannual 30% limit and termsprice cap would expire automatically on December 31, 2013. On October 25, 2010, an alternate proposed decision was issued that, if approved by the CPUC, would lift the stay, reaffirm the price cap and conditions of serviceannual 25% limit on REC transactions as approved in effectthe CPUC’s March 2010 decision, and reinstate provisions in the March 2010 decision that would increase the REC usage cap if approved contracts as of December 31, 2010, willthe effective date of that decision would cause a utility to be over the cap. Otherwise, if a utility subsequently exceeds the cap, the utility may bank forward the deliveries to a year in which the cap is not exceeded. Furthermore, the alternate proposed decision would require the annual limit and price cap to remain in effect until it is superseded by a CPUC decision or an act of California Legislature. If the alternate proposed decision is approved, renewable energy contracts submitted after May 6, 2010 (the date the stay becomes effective) must be re-filed to comply with an automatic 2% escalationthe CPUC’s March 2010 decision. It is uncertain when the CPUC will take action on the proposed decisions.

Water Quality

There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. Although the U.S. EPA will not issue draft revised regulations until February 2011, on May 4, 2010, the California Water Resources Control Board (“Water Board”) adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the “wholly out of proportion” test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be “wholly unreasonable.” If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. (See Note 16 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for more information.) Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the Water Board’s policy by December 31, 2024.

Remediation

The Utility has been, and may be, required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements, for a discussion of estimated environmental remediation liabilities.)

OTHER MATTERS

SmartMeterTM Technology

The CPUC has authorized the Utility to recover $2.2 billion in estimated project costs, including $1.8 billion of capital expenditures to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory by the end of 2012. As of September 30, 2010, the Utility has incurred $1.9 billion in connection with its SmartMeter™ program. In light of unanticipated cost pressures, including those relating to customer-related communications and outreach issues that have arisen since the summer of 2009, the Utility forecasts that total costs may exceed $2.2 billion. The CPUC also has authorized the Utility to recover in rates 90% of up to $100 million in costs that exceed $2.2 billion without a reasonableness review. Costs incurred by the Utility in

excess of $2.3 billion would be subject to a reasonableness review for recovery. The Utility is unable to predict whether it will incur a material amount of costs in excess of these authorized amounts and whether the Utility would be able to recover such additional costs through rates.

Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes. These meters will allow the implementation of “dynamic pricing” rates that are designed to reflect the higher cost of electricity during periods of high demand. The CPUC has ordered the Utility to implement certain dynamic pricing rates for some customer classes by February 2011. The Utility has requested that the CPUC extend the date to November 2011 to allow the Utility more time to develop the web-based tools necessary for customers to evaluate the new rates.

As of September 30, 2010, the Utility has 6.9 million meters installed. Based on the tests that the Utility has performed, more than 99% of the meters perform accurately as designed and within expectations. The Utility has not found any material design defects, but has found, as is to be expected with any new technology applied on this scale, that a small percentage of January 1, 2011.


the meters recorded inaccurate energy usage, were not properly installed, or were affected by issues relating to the meter’s data storage capabilities or wireless communication features. When issues are identified, the Utility is taking prompt action with the technology and services vendors to remediate the issues. The Utility has implemented new pre-installation quality control procedures. The Utility also has increased its customer education and outreach efforts, including posting weekly data reports on its website to inform customers and the public about the findings of the Utility’s assessment.

On June 17, 2010, the City and County of San Francisco (“CCSF”) filed a petition requesting the CPUC to temporarily suspend the installation of additional SmartMeter™ devices until the CPUC has completed its independent assessment. CCSF also filed a motion requesting expedited treatment of its petition. Several municipalities filed pleadings in support of CCSF’s petition. On September 2, 2010, the CPUC released the report of its independent consultant that was engaged by the CPUC to assess the Utility’s SmartMeter™ program, including meter and billing accuracy, customer complaints, end-to-end operational processes, and overall program planning and performance. The consultant’s evaluation report found that the Utility’s SmartMeter™ devices and related billing processes perform accurately and as designed. On September 22, 2010, a CPUC administrative law judge denied CCSF’s request for expedited treatment of its petition and requested the parties to submit comments on CCSF’s petition in light of the consultant’s report. On October 15, 2010, the Utility filed comments urging the CPUC to dismiss CCSF’s petitiongiven the reports’ findings on meter and billing accuracy. Other parties have requested that the CPUC take additional steps before concluding its investigation.

The CPUC is also considering two additional requests from private groups to halt the installation of SmartMeter™ devices based on concerns about the health, environmental, and safety impacts of the radio frequency (“RF”) technology on which the Utility’s SmartMeter™ program relies. On October 26, 2010, a proposed decision was issued that, if adopted by the CPUC, would dismiss one of the requests on the basis that the SmartMeter™ devices are licensed and certified by the Federal Communications Commission (“FCC”) and comply with all FCC requirements.

On October 25, 2010, the Superior Court in Bakersfield, California, granted the Utility’s request to dismiss a class action lawsuit that had alleged that the new meters, wireless network, and software and billing system led to electric bill overcharges. The court agreed with the Utility that the lawsuit should be dismissed because, among other reasons, the CPUC retains exclusive jurisdiction over the issues raised in the lawsuit. The court’s order permits the plaintiffs to file a new lawsuit within 20 days in lieu of appealing the dismissal. In addition, on September 17, 2010, the lawyer that filed the Superior Court class action lawsuit filed an application at the CPUC, on behalf of customers, requesting that the CPUC modify its prior decisions and shift the costs of the Utilitys SmartMeter™ technology upgrade to the Utility.On October 27, 2010, the Utility requested that the CPUC dismiss the application because it improperly seeks to re-litigate issues the CPUC has already decided on.

A California State Senate committee is continuing to investigate and review the deployment of the “smart grid” throughout California, focusing on the Utility’s SmartMeter™ program and the integrity and reliability of new metering technologies and the consumer protections in place with respect to billing, disconnection, and real-time pricing. The Utility has provided all requested information to the committee about the installed meters. The committee is expected to submit its report to the California Senate, including recommendations for appropriate legislation, by November 30, 2010.

In addition, class action complaints have been filed in federal and California state court against the various companies that have supplied SmartMeter™ devices, components, and software to the Utility. (These complaints do not name the Utility as a defendant.) These complaints allege that the new meters report electric consumption in amounts materially greater than the electricity that the class members actually consumed, resulting in electric bill overcharges.

The Utility is continuing to install the new meters. Various municipalities in the Utility’s service territory have approved ordinances to either suspend or prohibit the installation of SmartMeter™ devices primarily based on concerns about the health, environmental, and safety impacts of the RF technology on which the Utility’s SmartMeter™ program relies. The CPUC has stated that such ordinances would interfere with the CPUC’s exclusive jurisdiction over the Utility’s SmartMeter™ program.

The outcome of the matters discussed above may have an effect on the Utility’s ability to recover costs to implement advanced metering if the CPUC finds that the costs are not reasonable or are otherwise disallowed. Further, if the Utility is prohibited from continuing to install the new meters or if the Utility otherwise fails to recognize the expected benefits of its advanced metering infrastructure, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

RISK MANAGEMENT ACTIVITIES


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

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

On July 21, 2010, President Obama signed into law new federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act. PG&E Corporation and the Utility are evaluating the new legislation, and will review future regulations to assess compliance requirements as well as potential impacts on the Utility’s procurement activities and risk management programs.

Price Risk

The Utility is exposed to commodity price risk as a comprehensive discussionresult of PG&E Corporation’s market risk, seeits electricity and natural gas procurement activities, including the section entitled “Risk Management Activities” inprocurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the 2008 Annual Report.


Price Risk

Electricity Procurement

On April 1, 2009, the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) became operative.  Among other features, the MRTU established new day-ahead, hour-ahead, and real-timeUtility can conclude that it is probable that its reasonably incurred wholesale electricity marketsprocurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings but may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility’s natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to bid capsprice and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that increase over time.has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility expects to continue to relysells most of its capacity based on electricity from a diverse mixthe volume of resources, including third-party contracts, amounts allocated under DWR contracts, and its own electricity generation facilities to meet customer demand.  A relatively small proportion ofgas that the Utility’s total customer demand must be met through purchases incustomers actually ship, which exposes the MRTU markets.  As a result, exposureUtility to price volatility in the new MRTU markets is minimal.  The CAISO must implement additional FERC-ordered changes over the next several years.  Market risks, if any, associated with these changes will be assessed as the design and timelines are finalized during the 2009-2010 period.


Natural Gas Transportation and Storage

volumetric risk.

The Utility uses value-at-risk to measure the shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services.services that could impact revenues due to changes in market prices and customer demand. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility’s price exposure. When market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.


The Utility’s value-at-risk calculated under the methodology described above was $17$14 million at September 30, 2009.2010. The Utility’s high, low, and average values-at-risk at September 30, 20092010 were $34$20 million, $9$10 million, and $17$14 million, respectively.


See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of price risk management activities.

Interest Rate Risk


Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At September 30, 2009,2010, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would have an immaterial impact toaffect net income overfor the next twelve months.


12 months by $8 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk


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

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

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The following table summarizes the Utility’s net credit risk exposure to its wholesale customers and counterparties, as well as the Utility’s credit risk exposure to its wholesale customers or counterparties with aaccounting for greater than 10% net credit exposure, atas of September 30, 20092010 and December 31, 2008:


(in millions) 
Gross Credit
Exposure Before Credit Collateral(1)
  Credit Collateral  
Net Credit Exposure(2)
  
Number of
Wholesale
Customers or Counterparties
>10%
  
Net Exposure to
Wholesale
Customers or Counterparties
>10%
 
September 30, 2009 $227  $45  $182   3  $148 
December 31, 2008 $240  $84  $156   2  $107 
                     
(1) Gross credit exposure equals mark-to-market value on financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
 
(2) Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.
 

2009:

(in millions) 

Gross
Credit

Exposure
Before
Credit
Collateral (1)

  Credit
Collateral
  Net Credit
Exposure (2)
  

Number of

Wholesale

Customers or
Counterparties

>10%

  

Net Exposure to

Wholesale

Customers or
Counterparties

>10%

 

September 30, 2010

  $ 189    $ 26    $ 163    2    $ 117  

December 31, 2009

  $ 202    $ 24    $ 178    3    $ 154  
         
(1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.    
(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.   

CRITICAL ACCOUNTING POLICIES


The preparation of Condensed Consolidated Financial Statements in accordance with GAAPU.S. generally accepted accounting principles involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. In addition, management has made significant estimates and assumptions about accruals related to the rupture of a natural gas transmission pipeline owned and operated by the Utility in the City of San Bruno, California on September 9, 2010, as well as accruals for various legal matters. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the 20082009 Annual Report. They include:

regulatory assets and liabilities;


environmental remediation liabilities;

·regulatory assets and liabilities;
·environmental remediation liabilities;
·asset retirement obligations;
·accounting for income taxes; and
·pension and other postretirement plans.

asset retirement obligations;


accounting for income taxes; and

pension and other postretirement plans.

For the periodnine months ended September 30, 2009,2010, there were no changes in the methodology for computing critical accounting estimates no additional accounting estimates met the standards for critical accounting policies, and no material changes to the important assumptions underlying the critical accounting estimates.


Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133

On January 1, 2009, PG&E Corporation and the Utility adopted Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”).  SFAS No. 161 requires an entity to provide qualitative disclosures about its objectives and strategies for using derivative instruments and quantitative disclosures that detail the fair value amounts of, and gains and losses on, derivative instruments.  SFAS No. 161 also requires disclosures about credit risk-related contingent features of derivative instruments.  (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)
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Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51

On January 1, 2009, PG&E Corporation and the Utility adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS No. 160”).  SFAS No. 160 establishes New critical accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary.  SFAS No. 160 defines a “noncontrolling interest,” previously called a “minority interest,” as the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent.  Among other items, SFAS No. 160 requires that an entity (1) include a noncontrolling interest in its consolidated statement of financial position within equity separate from the parent’s equity, (2) report amounts inclusive of both the parent’s and noncontrolling interest’s shares in consolidated net income, and (3) separately report the amounts of consolidated net income attributable to the parent and noncontrolling interest on the consolidated statement of operations.  If a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be measured at fair value, and a gain or loss must be recognized in net income based on such fair value.

PG&E Corporation has reclassified its noncontrolling interest in the Utility from Preferred Stock of Subsidiaries to equity in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 160 for all periods presented.  The Utility had no material noncontrolling interests in consolidated subsidiaries as of September 30, 2009 and December 31, 2008.

PG&E Corporation and the Utility applied the presentation and disclosure requirements of SFAS No. 160 retrospectively.  Other than the change in presentation of noncontrolling interests, adoption of SFAS No. 160 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement

On January 1, 2009, PG&E Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”).  EITF 08-5 clarifies the unit of account in determining the fair value of a liability.  Specifically, it requires an entity to exclude any third-party credit enhancements thatestimates are issued with, and are inseparable from, a debt instrument from the fair value measurement of that debt instrument.  Adoption of EITF 08-5 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Equity Method Investment Accounting

On January 1, 2009, PG&E Corporation and the Utility adopted EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”).  EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost.  Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than the Business Combinations Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”).  However, the investor in an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the investor’s share of the investee’s net assets exceeds the investor’s initial costs.  An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment.  Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings.  Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Subsequent Events

On June 30, 2009, PG&E Corporation and the Utility adopted SFAS No. 165, “Subsequent Events” (“SFAS No. 165”).  SFAS No. 165 does not significantly change the prior accounting practice for subsequent events, except for the requirement to disclose the date through which an entity has evaluated subsequent events and the basis for that date.  PG&E Corporation and the Utility have evaluated material subsequent events through October 29, 2009, the issue date of PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.  Other than this disclosure, adoption of SFAS No. 165 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Interim Disclosures about Fair Value of Financial Instruments

On June 30, 2009, PG&E Corporation and the Utility adopted FASB Staff Position (“FSP”) SFAS 107-1 and Accounting Principles Board (“APB”) 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This FSP requires disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods.  In particular, an entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and to disclose where the carrying amount is classified in the Condensed Consolidated Balance Sheets.  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)
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Recognition and Presentation of Other-Than-Temporary Impairments

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.”  Under this FSP, to assess whether an other-than-temporary impairment exists for a debt security, an entity must (1) evaluate the likelihood of liquidating the debt security prior to recovering its cost basis and (2) determine if any impairment of the debt security is related to credit losses.  In addition, this FSP requires enhanced disclosures of other-than-temporary impairments on debt and equity securities in the financial statements.  However, this FSP does not amend recognition and measurement guidance for other-than-temporary impairments of equity securities.  Adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.”  This FSP provides guidance on estimating fair value when the volume or the level of activity for an asset or a liability has significantly decreased or when transactions are not orderly, when compared with normal market conditions.  In particular, this FSP calls for adjustments to quoted prices or historical transaction data when estimating fair value in such circumstances.  This FSP also provides guidance to identify such circumstances.  Furthermore, this FSP requires fair value measurement disclosures made pursuant to the Fair Value Measurements and Disclosures Topic of the FASB ASC to be categorized by major security type (i.e., based on the nature and risks of the security).  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)  Other than this change, adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles

On July 1, 2009, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-01, “Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles” (“ASU No. 2009-01”).  ASU No. 2009-01 re-defines authoritative GAAP for nongovernmental entities to be only comprised of the FASB Accounting Standards CodificationTM (“Codification”) and, for SEC registrants, guidance issued by the SEC.  The Codification is a reorganization and compilation of all then-existing authoritative GAAP for nongovernmental entities, except for guidance issued by the SEC.  The Codification is amended to effect non-SEC changes to authoritative GAAP.  Adoption of ASU No. 2009-01 only changed the referencing convention of GAAP in PG&E Corporation’s and the Utility’s Notes to the Condensed Consolidated Financial Statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.”  This FSP amends and expands the disclosure requirements of the Compensation - Retirement Benefits Topic of the FASB ASC.  In particular, this FSP requires an entity to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets.  In addition, this FSP requires quantitative disclosures showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets that are measured using significant unobservable inputs.  This FSP is effective prospectively for PG&E Corporation and the Utility for the annual period ending December 31, 2009 and for subsequent annual periods.  PG&E Corporation and the Utility will include the expanded disclosures described above in PG&E Corporation’s and the Utility’s Notes to the Consolidated Financial Statements for the annual period ending December 31, 2009.

Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS No. 166”).  SFAS No. 166 eliminates the concept of a qualifying special-purpose entity and clarifies the requirements for derecognizing a financial asset and for applying sale accounting to a transfer of a financial asset.  In addition, SFAS No. 166 requires an entity to disclose more information about transfers of financial assets, the entity’s continuing involvement, if any, with transferred financial assets, and the entity’s continuing risks, if any, from transferred financial assets.  SFAS No. 166 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010.  PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 166.

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Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”).  SFAS No. 167 amends the Consolidation Topic of the FASB ASC regarding when and how to determine, or re-determine, whether an entity is a variable interest entity (“VIE”).  In addition, SFAS No. 167 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach.  Furthermore, SFAS No. 167 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE.  SFAS No. 167 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010.  PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 167.

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below.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (see “Risk Management Activities” above under Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations).


ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, 2009,2010, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures arewere effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 20092010 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.


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PART II. OTHER INFORMATION


ITEM 1. LEGAL PROCEEDINGS


Complaints Filed

Diablo Canyon Power Plant

On October 1, 2010, the state Water Board adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the California Attorney GeneralWater Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The policy could affect future negotiations between the Water Board and the CityUtility regarding the status of the 2003 settlement agreement concerning a proposed draft Cease and County of San Francisco


The complaint filedDesist Order issued by the California Attorney GeneralWater Board against PG&E Corporation and several of its present and former directors was dismissed on March 10, 2009 and the similar complaint filed by the City and County of San Francisco was dismissed on April 23, 2009.Utility. For more information regardingabout the resolution of these matters,settlement agreement, see “Part I. Item 3. Legal Proceedings” inPG&E Corporation’s and the 2008Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2009 and “PartPart II, Item 1. Legal1, “Legal Proceedings” in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2009.

June 30, 2010. For more information about the state once-through cooling policy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Matters – Water Quality” above.

PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on the Utility’s financial condition or results of operations.

San Bruno Accident

Following the San Bruno Accident, various lawsuits, including two class action lawsuits, have been filed by residents of San Bruno in the San Mateo County Superior Court and San Francisco County Superior Court against PG&E Corporation and the Utility. The class action lawsuits include a demand that the $100 million the Utility announced would be available for assistance be placed under court supervision. These lawsuits allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. Another lawsuit was filed in San Mateo County Superior Court as a purported shareholder derivative lawsuit to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The other lawsuits, including some that have been filed in San Francisco County Superior Court, seek to recover damages for wrongful death, property damage, and personal injury.

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

For more information regarding the San Bruno Accident and the related NTSB and CPUC investigations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Explosion and Fires in San Bruno, California.”

ITEM 1A. RISK FACTORS


A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors” in the 20082009 Annual Report.


The discussionultimate amount of loss the potential impact of climate change appearingUtility bears in connection with the 2008 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors” under the following caption The Utility’s future operations may be impacted by climate change that maySan Bruno Accident could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition and results of operationsoperations. is updated as follows

PG&E Corporation’s and the Utility’s financial statements for the period ended September 30, 2010 reflect a provision of $220 million for estimated third-party claims related to reflect new scientific evidence regarding climate change:


A report issued on June 16, 2009 by the U.S. Global Change Research Program (an interagency effort led by the National OceanicSan Bruno Accident, including personal injury and Atmospheric Administration) states that climate changes caused by rising emissions of carbon dioxideproperty damage claims, damage to infrastructure, emergency response, and other heat-trapping gasesdamage claims. Various lawsuits, including two class action lawsuits, have already been observed infiled by residents of San Bruno against PG&E Corporation and the United States,Utility seeking to recover damages for wrongful death, property damage, and personal injury and seeking other relief. The process for estimating costs associated with third-party claims relating to the San Bruno Accident requires management to exercise significant judgment based on a number of assumptions and subjective factors. The Utility estimates that it may incur as much as $400 million for third-party claims depending on the final outcome of the NTSB and CPUC investigations and the number, nature, and value of third-party claims.

As more information becomes known, including increased frequencyinformation resulting from the NTSB and severity of hot weather, reduced runoff from snow pack,CPUC investigations, management’s estimates and increased sea levels.  Theassumptions regarding the financial impact of eventsthe San Bruno Accident may change. A change in management’s estimates or conditions caused by climate change could range widely, from highly localized to worldwide, and the extent to which the Utility’s operations may be affected is uncertain.  For example, if reduced snowpack decreases the Utility’s hydroelectric generation capacity, there will be a need for additional generation capacity from other sources.  Under certain conditions, the events or conditions caused by climate changeassumptions could result in an adjustment that would have a full or partial disruptionmaterial impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

The Utility maintains liability insurance for damages in the approximate amount of $992 million after a $10 million deductible. PG&E Corporation and the Utility currently consider it likely that most of the ability ofcosts the Utility or one or more entities on which it relies,incurs for third-party claims relating to generate, transmit, transport or distribute electricity or natural gas.  The Utility has been studying the potential effects of climate change on the Utility’s operationsSan Bruno Accident will ultimately be covered by this insurance. However, PG&E Corporation and is developing contingency plans to adapt to those events and conditions that the Utility believes are most likelyunable to occur.  Events or conditions caused by climate change could have a greater impact onpredict the Utility’s operations than has been forecasttiming and could result in lower revenues or increased expenses, or both.  amount of insurance recoveries.

If the CPUC wereUtility records losses in connection with third-party claims related to fail to adjust the Utility’s rates to reflectSan Bruno Accident that materially exceed the impact of events or conditions caused by climate change,amount it has accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected in the reporting periods during which additional charges are recorded depending on whether and when the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals during the same reporting periods.

In addition, the Utility currently anticipates that it will incur additional unbudgeted costs for inspection and maintenance of its natural gas transmission system. The Utility also may incur costs, beyond the amount currently anticipated, in response to NTSB or CPUC orders or requests as the investigations continue. Further, state or federal legislation may be enacted that would require the Utility to incur additional costs by mandating various changes, including changes to its operating practice standards for natural gas transmission operations and safety, use of certain types of inspection methods and equipment, and installations of certain types of valves. If the Utility incurs a material amount of costs that it is unable to recover through rates or offset through operational or other cost savings, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows would be materially and adversely affected.


Finally, if it is determined that the Utility did not comply with applicable statutes, regulations, rules, tariffs, or orders in connection with the San Bruno Accident or in connection with the operations or maintenance of the Utility’s natural gas system, and the Utility is ordered to pay a material amount in customer refunds, penalties, or other amounts, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows would be materially and adversely affected.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


On July 31, 2009,

During the quarter ended September 30, 2010, PG&E Corporation contributedmade equity of $35contributions totaling $40 million to the Utility in order to maintain the 52% common equity target authorized by the CPUCcomponent of its CPUC-authorized capital structure and to ensure that the Utility has adequate capital to fund its capital expenditures. The Utility did not make any sales of unregistered equity securities during the quarter ended September 30, 2010.

Issuer Purchases of Equity Securities


PG&E Corporation common stock:

Period

 Total Number of
Shares
Purchased
  Average Price
Per Share
  Total Number of
Shares
Purchased as
Part of Publicly
Announced Plans
or Programs
  Approximate
Dollar Value of
Shares that May
Yet be Purchased
Under the Plans
or Programs
 

July 1 through July 31, 2010

  496 (1)    $ 42.56    -    $ -  

August 1 through August 31, 2010

  -    -    -    -  

September 1 through September 30, 2010

  -    -    -    -  
                

Total

  496    $ 42.56    -    $ -  
                

    (1) Shares of PG&E Corporation common stock tendered to pay stock option exercise price.

During the quarter ended September 30, 2009, PG&E Corporation issued 331,404 shares of common stock at a conversion price of $15.09 per share in an unregistered offering upon conversion of $5 million principal amount of PG&E Corporation 9.50% Convertible Subordinated Notes originally issued in an unregistered offering in 2002.


During the quarter ended September 30, 2009, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding.  During the third quarter of 2009,2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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ITEM 5. OTHER INFORMATION


Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends


The Utility’s earnings to fixed charges ratio for the nine months ended September 30, 20092010 was 3.19.3.32. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 20092010 was 3.13.3.26. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the Utility’s first preferred stock and its senior notes, respectively.


PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, 20092010 was 2.99.3.10. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-149360 relating to its senior notes.


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ITEM 6. EXHIBITS


           4.1 
3.1Bylaws of PG&E Corporation amendedTenth Supplemental Indenture dated as of September 16, 2009
3.2Bylaws15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric CompanyCompany’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
           4.2Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1)
       *10.1Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of September 16, 200915, 2010
       *10.2 PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010
       *10.3PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011
12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1**    **32.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2**    **32.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
***101.INSXBRL Instance Document
***101.SCHXBRL Taxonomy Extension Schema
***101.CALXBRL Taxonomy Extension Calculation
***101.DEFXBRL Extension Definition
***101.LABXBRL Taxonomy Extension Label
***101.PREXBRL Taxonomy Extension Presentation

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these Exhibitsexhibits are furnished rather than filed with this report.

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***Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company.

SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.



PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)



PACIFIC GAS AND ELECTRIC COMPANY

SARA A. CHERRY

BARBARA L. BARCON 
Barbara L. Barcon

Sara A. Cherry

Vice President, Finance and Chief Financial Officer

(duly authorized officer and principal financial officer)




Dated: October 29, 2009


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November 4, 2010

EXHIBIT INDEX

           4.1 
3.1Bylaws of PG&E Corporation amendedTenth Supplemental Indenture dated as of September 16, 2009
3.2Bylaws15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric CompanyCompany’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
           4.2Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1)
       *10.1Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of September 16, 200915, 2010
       *10.2 PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010
       *10.3PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011
12.1Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1**    **32.1Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2**    **32.2Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
***101.INSXBRL Instance Document
***101.SCHXBRL Taxonomy Extension Schema
***101.CALXBRL Taxonomy Extension Calculation
***101.DEFXBRL Extension Definition
***101.LABXBRL Taxonomy Extension Label
***101.PREXBRL Taxonomy Extension Presentation

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these Exhibitsexhibits are furnished rather than filed with this report.
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***Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company.

72