XNYS:PCG PG&E Corp Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C., 20549

FORM 10-Q

(Mark One)

  [X]   

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

SECURITIES EXCHANGE ACT OF 1934

    
   For the quarterly period ended June 30, 2012     
   OR     
  [  ]   

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

SECURITIES EXCHANGE ACT OF 1934

    

For the transition period from                  to                 

 

Commission        

File

Number

 

  

Exact Name of        

Registrant

as specified in

its charter

 

 

State or other            

Jurisdiction of

Incorporation

 

  

IRS Employer        
Identification
Number

 

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

Pacific Gas and Electric Company                                

77 Beale Street

P.O. Box 770000

San Francisco, California 94177

 

 

PG&E Corporation

77 Beale Street                                                         

P.O. Box 770000

San Francisco, California 94177

 

  
Address of principal executive offices, including zip code   

Pacific Gas and Electric Company                                

(415) 973-7000

 

 

PG&E Corporation                                                   

(415) 267-7000

 

  
Registrant’s telephone number, including area code   
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  [X] Yes    [  ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PG&E Corporation   [X]   Yes [  ] No           
Pacific Gas and Electric Company:   [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      [  ] Accelerated Filer
    [X] Non-accelerated filer      [  ] Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:   [  ] Yes [X] No
Pacific Gas and Electric Company:   [  ] Yes [X] No
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common Stock Outstanding as of July 25, 2012:           
PG&E Corporation   426,462,616           
Pacific Gas and Electric Company   264,374,809           

 

 


Table of Contents

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

TABLE OF CONTENTS

 

PART I.

  FINANCIAL INFORMATION      PAGE   
ITEM 1.   CONDENSED CONSOLIDATED FINANCIAL STATEMENTS   
  PG&E Corporation   
      Condensed Consolidated Statements of Income      3   
      Condensed Consolidated Statements of Comprehensive Income      4   
      Condensed Consolidated Balance Sheets      5   
      Condensed Consolidated Statements of Cash Flows      7   
  Pacific Gas and Electric Company   
      Condensed Consolidated Statements of Income      9   
      Condensed Consolidated Statements of Comprehensive Income      10   
      Condensed Consolidated Balance Sheets      11   
      Condensed Consolidated Statements of Cash Flows      13   
  NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS   
  NOTE 1:   Organization and Basis of Presentation      14   
  NOTE 2:   Significant Accounting Policies      14   
  NOTE 3:   Regulatory Assets, Liabilities, and Balancing Accounts      17   
  NOTE 4:   Debt      21   
  NOTE 5:   Equity      22   
  NOTE 6:   Earnings Per Share      22   
  NOTE 7:   Derivatives      23   
  NOTE 8:   Fair Value Measurements      26   
  NOTE 9:   Resolution of Remaining Chapter 11 Disputed Claims      32   
  NOTE 10:   Commitments and Contingencies      32   
ITEM 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   
  Overview      42   
  Cautionary Language Regarding Forward-Looking Statements      44   
  Results of Operations      47   
  Liquidity and Financial Resources      52   
  Contractual Commitments      57   
  Capital Expenditures      57   
  Natural Gas Matters      57   
  Regulatory Matters      61   
  Environmental Matters      63   
  Off-Balance Sheet Arrangements      65   
  Contingencies      65   
  Risk Management Activities      66   
  Critical Accounting Policies      67   
ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      68   
ITEM 4.   CONTROLS AND PROCEDURES      68   
PART II.   OTHER INFORMATION   
ITEM 1.   LEGAL PROCEEDINGS      69   
ITEM 1A.   RISK FACTORS      70   
ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS      70   
ITEM 5.   OTHER INFORMATION      70   
ITEM 6.   EXHIBITS      71   
SIGNATURES      72   

 

2


Table of Contents

PART I.  FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     (Unaudited)  
         Three Months Ended    
June  30,
           Six Months Ended      
June 30,
 
(in millions, except per share amounts)    2012      2011      2012      2011  

Operating Revenues

           

Electric

     $ 2,931         $ 2,889          $ 5,703          $ 5,506    

Natural gas

     662         795         1,531         1,775   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating revenues

     3,593         3,684         7,234         7,281   
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Expenses

           

Cost of electricity

     962          906          1,821          1,794    

Cost of natural gas

     132         258         475         766   

Operating and maintenance

     1,426          1,237          2,794          2,463    

Depreciation, amortization, and decommissioning

     606         591         1,190         1,082   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

     3,126         2,992         6,280         6,105   
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Income

     467         692         954         1,176   

Interest income

                               

Interest expense

     (176)         (174)         (350)         (351)   

Other income, net

     32          21          58          38    
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Before Income Taxes

     326         542         666         868   

Income tax provision

     87          176          191          300    
  

 

 

    

 

 

    

 

 

    

 

 

 

Net Income

     239         366         475         568   

Preferred stock dividend requirement of subsidiary

                           
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Available for Common Shareholders

     $ 235         $ 362         $ 468         $ 561   
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted Average Common Shares Outstanding, Basic

     423         399         419         397   
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted Average Common Shares Outstanding, Diluted

     425         400         421         399   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net Earnings Per Common Share, Basic

     $ 0.56         $ 0.91         $ 1.12         $ 1.41   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net Earnings Per Common Share, Diluted

     $ 0.55         $ 0.91         $ 1.11         $ 1.41   
  

 

 

    

 

 

    

 

 

    

 

 

 

Dividends Declared Per Common Share

     $ 0.46         $ 0.46         $ 0.91         $ 0.91   
  

 

 

    

 

 

    

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     (Unaudited)  
         Three Months Ended    
June  30,
           Six Months Ended      
June 30,
 
(in millions)    2012      2011      2012      2011  

Net Income

     $ 239         $ 366         $ 475         $ 568   
  

 

 

    

 

 

    

 

 

    

 

 

 

Other Comprehensive Income

           

Pension and other postretirement benefit plans

           

Unrecognized prior service credit (net of income tax of $5 and $6 in the three months ended June 30, 2012 and 2011, respectively, and $10 and $11 in the six months ended June 30, 2012 and 2011, respectively)

                   12         19   

Unrecognized net gain (net of income tax of $15 and $5 in the three months ended June 30, 2012 and 2011, respectively, and $26 and $11 in the six months ended June 30, 2012 and 2011, respectively)

     19                40         15   

Unrecognized net transition obligation (net of income tax of $2 and $2 in the three months ended June 30, 2012 and 2011, respectively, and $4 and $4 in the six months ended June 30, 2012 and 2011, respectively)

                           

Transfer to regulatory account (net of income tax of $15 and $8 in the three months ended June 30, 2012 and 2011, respectively, and $30 and $18 in the six months ended June 30, 2012 and 2011, respectively)

     (21)         (12)         (42)         (24)   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other comprehensive income

                   18         18   
  

 

 

    

 

 

    

 

 

    

 

 

 

Comprehensive Income

     247         375         493         586   

Preferred stock dividend requirement of subsidiary

                           
  

 

 

    

 

 

    

 

 

    

 

 

 

Comprehensive Income Attributable to Common Shareholders

     $ 243         $ 371         $ 486         $ 579   
  

 

 

    

 

 

    

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     (Unaudited)  
     Balance At  
(in millions)            June 30,        
2012
         December 31,    
2011
 

ASSETS

     

Current Assets

     

Cash and cash equivalents

     $ 292         $ 513   

Restricted cash ($71 and $51 related to energy recovery bonds at June 30, 2012 and December 31, 2011, respectively)

     381         380   

Accounts receivable

     

Customers (net of allowance for doubtful accounts of $82 and $81 at June 30, 2012 and December 31, 2011, respectively)

     937         992   

Accrued unbilled revenue

     747          763    

Regulatory balancing accounts

     1,351         1,082   

Other

     412          839    

Regulatory assets ($109 and $336 related to energy recovery bonds at June 30, 2012 and December 31, 2011, respectively)

     793         1,090   

Inventories

     

Gas stored underground and fuel oil

     129         159   

Materials and supplies

     286          261    

Income taxes receivable

     32         183   

Other

     180         218   
  

 

 

    

 

 

 

Total current assets

     5,540         6,480   
  

 

 

    

 

 

 

Property, Plant, and Equipment

     

Electric

     37,283         35,851   

Gas

     12,206         11,931   

Construction work in progress

     1,858         1,770   

Other

            15   
  

 

 

    

 

 

 

Total property, plant, and equipment

     51,348         49,567   

Accumulated depreciation

     (16,446)         (15,912)   
  

 

 

    

 

 

 

Net property, plant, and equipment

     34,902         33,655   
  

 

 

    

 

 

 

Other Noncurrent Assets

     

Regulatory assets

     6,534         6,506   

Nuclear decommissioning trusts

     2,106         2,041   

Income taxes receivable

     385         386   

Other

     648         682   
  

 

 

    

 

 

 

Total other noncurrent assets

     9,673         9,615   
  

 

 

    

 

 

 

TOTAL ASSETS

     $ 50,115         $ 49,750   
  

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     (Unaudited)  
     Balance At  
(in millions, except share amounts)            June 30,        
2012
         December 31,    
2011
 

LIABILITIES AND EQUITY

     

Current Liabilities

     

Short-term borrowings

     $ 1,079          $ 1,647    

Long-term debt, classified as current

             50    

Energy recovery bonds, classified as current

     223          423    

Accounts payable

     

Trade creditors

     1,000          1,177    

Disputed claims and customer refunds

     164          673    

Regulatory balancing accounts

     587          374    

Other

     443          420    

Interest payable

     851          843    

Income taxes payable

     112          110    

Deferred income taxes

     166          196    

Other

     1,732          1,836    
  

 

 

    

 

 

 

Total current liabilities

     6,357          7,749    
  

 

 

    

 

 

 

Noncurrent Liabilities

     

Long-term debt

     12,166          11,766    

Regulatory liabilities

     5,008          4,733    

Pension and other postretirement benefits

     3,517          3,396    

Asset retirement obligations

     1,641          1,609    

Deferred income taxes

     6,272          6,008    

Other

     2,100          2,136    
  

 

 

    

 

 

 

Total noncurrent liabilities

     30,704          29,648    
  

 

 

    

 

 

 

Commitments and Contingencies (Note 10)

     

Equity

     

Shareholders’ Equity

     

Preferred stock

               

Common stock, no par value, authorized 800,000,000 shares,
425,996,481 shares outstanding at June 30, 2012 and
412,257,082 shares outstanding at December 31, 2011

     8,204          7,602    

Reinvested earnings

     4,793          4,712    

Accumulated other comprehensive loss

     (195)         (213)   
  

 

 

    

 

 

 

Total shareholders’ equity

     12,802          12,101    

Noncontrolling Interest – Preferred Stock of Subsidiary

     252          252    
  

 

 

    

 

 

 

Total equity

     13,054          12,353    
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

     $ 50,115          $ 49,750    
  

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     (Unaudited)  
         Six Months Ended    
June 30,
 
(in millions)         2012                2011       

Cash Flows from Operating Activities

     

Net income

     $ 475         $ 568   

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

     

Depreciation, amortization, and decommissioning

     1,190         1,082   

Allowance for equity funds used during construction

     (53)         (41)   

Deferred income taxes and tax credits, net

     234         397   

Other

     137         138   

Effect of changes in operating assets and liabilities:

     

Accounts receivable

     13         (82)   

Inventories

             

Accounts payable

     (125)         162   

Income taxes receivable/payable

     153         66   

Other current assets and liabilities

     74         (202)   

Regulatory assets, liabilities, and balancing accounts, net

     (115)         (324)   

Other noncurrent assets and liabilities

     186         140   
  

 

 

    

 

 

 

Net cash provided by operating activities

     2,174         1,905   
  

 

 

    

 

 

 

Cash Flows from Investing Activities

     

Capital expenditures

     (2,219)         (1,897)   

(Increase) Decrease in restricted cash

     (1)         198   

Proceeds from sales and maturities of nuclear decommissioning trust investments

     666         1,007   

Purchases of nuclear decommissioning trust investments

     (716)         (969)   

Other

     64         (44)   
  

 

 

    

 

 

 

Net cash used in investing activities

     (2,206)         (1,705)   
  

 

 

    

 

 

 

Cash Flows from Financing Activities

     

Borrowings under revolving credit facilities

             150   

Repayments under revolving credit facilities

             (75)   

Net (payments) issuances of commercial paper, net of discount of $2 in 2012 and in 2011

     (566)         265   

Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2012 and $2 in 2011

     394         298   

Long-term debt matured or repurchased

     (50)         (500)   

Energy recovery bonds matured

     (200)         (191)   

Common stock issued, net of issuance costs of $2 in 2012 and $1 in 2011

     561         257   

Common stock dividends paid

     (368)         (349)   

Other

     40          
  

 

 

    

 

 

 

Net cash used in financing activities

     (189)         (141)   
  

 

 

    

 

 

 

Net change in cash and cash equivalents

     (221)         59   

Cash and cash equivalents at January 1

     513         291   
  

 

 

    

 

 

 

Cash and cash equivalents at June 30

     $ 292         $ 350   
  

 

 

    

 

 

 

Supplemental disclosures of cash flow information

     

Cash received (paid) for:

     

Interest, net of amounts capitalized

     $ (319)         $ (330)   

Income taxes, net

     114          

 

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Supplemental disclosures of noncash investing and financing activities

     

Common stock dividends declared but not yet paid

   $  194       $  183   

Capital expenditures financed through accounts payable

     256         229   

Noncash common stock issuances

     12         12   

Terminated capital leases

     136           

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     (Unaudited)  
           Three Months Ended      
June 30,
           Six Months Ended      
June 30,
 
(in millions)           2012                    2011                    2012                    2011         

Operating Revenues

           

Electric

     $ 2,930         $ 2,888         $ 5,701         $ 5,504   

Natural gas

     662         795         1,531         1,775   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating revenues

     3,592         3,683         7,232         7,279   
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Expenses

           

Cost of electricity

     962         906         1,821         1,794   

Cost of natural gas

     132         258         475         766   

Operating and maintenance

     1,425         1,228         2,791         2,454   

Depreciation, amortization, and decommissioning

     606         592         1,190         1,082   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

     3,125         2,984         6,277         6,096   
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Income

     467         699         955         1,183   

Interest income

                           

Interest expense

     (171)         (169)         (339)         (340)   

Other income, net

     22         16         45         33   
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Before Income Taxes

     320         548         664         880   

Income tax provision

     93         189         206         320   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net Income

     227         359         458         560   

Preferred stock dividend requirement

                           
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Available for Common Stock

     $ 223         $ 355         $ 451         $ 553   
  

 

 

    

 

 

    

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     (Unaudited)  
          Three Months Ended     
June  30,
           Six Months Ended      
June 30,
 
(in millions)          2012                  2011                  2012                  2011        

Net Income

     $ 227         $ 359         $ 458         $ 560   
  

 

 

    

 

 

    

 

 

    

 

 

 

Other Comprehensive Income

           

Pension and other postretirement benefit plans

           

Unrecognized prior service credit (net of income tax of $5 and

$6 in the three months ended June 30, 2012 and 2011,

respectively, and $10 and $11 in the six months ended June 30,

2012 and 2011, respectively)

                   12         19   

Unrecognized net gain (net of income tax of $15 and $5 in the

three months ended June 30, 2012 and 2011, respectively, and

$26 and $11 in the six months ended June 30, 2012 and 2011,

respectively)

     19                40         15   

Unrecognized net transition obligation (net of income tax of $2

and $2 in the three months ended June 30, 2012 and 2011,

respectively, and $4 and $4 in the six months ended June 30,

2012 and 2011, respectively)

                           

Transfer to regulatory account (net of income tax of $15 and $8

in the three months ended June 30, 2012 and 2011, respectively,

and $30 and $18 in the six months ended June 30, 2012 and

2011, respectively)

     (21)         (12)         (42)         (24)   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other comprehensive income

                   18         18   
  

 

 

    

 

 

    

 

 

    

 

 

 

Comprehensive Income

     $ 235         $ 368         $ 476         $ 578   
  

 

 

    

 

 

    

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     (Unaudited)  
     Balance At  
(in millions)              June 30,           
2012
               December 31,           
2011
 

ASSETS

     

Current Assets

     

Cash and cash equivalents

     $ 45         $ 304   

Restricted cash ($71 and $51 related to energy recovery bonds at
June 30, 2012 and December 31, 2011, respectively)

     381         380   

Accounts receivable

     

Customers (net of allowance for doubtful accounts of $82 and $81 at
June 30, 2012 and December 31, 2011, respectively)

     937         992   

Accrued unbilled revenue

     747         763   

Regulatory balancing accounts

     1,351         1,082   

Other

     476         840   

Regulatory assets ($109 and $336 related to energy recovery bonds at
June 30, 2012 and December 31, 2011, respectively)

     793         1,090   

Inventories

     

Gas stored underground and fuel oil

     129         159   

Materials and supplies

     286         261   

Income taxes receivable

     28         242   

Other

     177         213   
  

 

 

    

 

 

 

Total current assets

     5,350         6,326   
  

 

 

    

 

 

 

Property, Plant, and Equipment

     

Electric

     37,283         35,851   

Gas

     12,206         11,931   

Construction work in progress

     1,858         1,770   
  

 

 

    

 

 

 

Total property, plant, and equipment

     51,347         49,552   

Accumulated depreciation

     (16,446)         (15,898)   
  

 

 

    

 

 

 

Net property, plant, and equipment

     34,901         33,654   
  

 

 

    

 

 

 

Other Noncurrent Assets

     

Regulatory assets

     6,534         6,506   

Nuclear decommissioning trusts

     2,106         2,041   

Income taxes receivable

     383         384   

Other

     337         331   
  

 

 

    

 

 

 

Total other noncurrent assets

     9,360         9,262   
  

 

 

    

 

 

 

TOTAL ASSETS

     $ 49,611         $ 49,242   
  

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     (Unaudited)  
     Balance At  
(in millions, except share amounts)              June 30,           
2012
           December 31,      
2011
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

     

Current Liabilities

     

Short-term borrowings

     $ 1,079         $ 1,647   

Long-term debt, classified as current

             50   

Energy recovery bonds, classified as current

     223         423   

Accounts payable

     

Trade creditors

     1,000         1,177   

Disputed claims and customer refunds

     164         673   

Regulatory balancing accounts

     587         374   

Other

     458         417   

Interest payable

     846         838   

Income taxes payable

     120         118   

Deferred income taxes

     169         199   

Other

     1,523         1,628   
  

 

 

    

 

 

 

Total current liabilities

     6,169         7,544   
  

 

 

    

 

 

 

Noncurrent Liabilities

     

Long-term debt

     11,817         11,417   

Regulatory liabilities

     5,008         4,733   

Pension and other postretirement benefits

     3,443         3,325   

Asset retirement obligations

     1,641         1,609   

Deferred income taxes

     6,432         6,160   

Other

     2,040         2,070   
  

 

 

    

 

 

 

Total noncurrent liabilities

     30,381         29,314   
  

 

 

    

 

 

 

Commitments and Contingencies (Note 10)

     

Shareholders’ Equity

     

Preferred stock

     258         258   

Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809
shares outstanding at June 30, 2012 and December 31, 2011

     1,322         1,322   

Additional paid-in capital

     4,362         3,796   

Reinvested earnings

     7,303         7,210   

Accumulated other comprehensive loss

     (184)         (202)   
  

 

 

    

 

 

 

Total shareholders’ equity

     13,061         12,384   
  

 

 

    

 

 

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

     $ 49,611         $ 49,242   
  

 

 

    

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

  

 

 

 
     (Unaudited)  

 

 

(in millions)

       Six Months Ended    
June 30,
 
        2012                2011       

Cash Flows from Operating Activities

     

Net income

     $ 458         $ 560   

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

     

Depreciation, amortization, and decommissioning

     1,190         1,082   

Allowance for equity funds used during construction

     (53)         (41)   

Deferred income taxes and tax credits, net

     242         408   

Other

     108         115   

Effect of changes in operating assets and liabilities:

     

Accounts receivable

     (50)         (1)   

Inventories

             

Accounts payable

     (107)         140   

Income taxes receivable/payable

     216         66   

Other current assets and liabilities

     78         (186)   

Regulatory assets, liabilities, and balancing accounts, net

     (115)         (324)   

Other noncurrent assets and liabilities

     202         114   
  

 

 

    

 

 

 

Net cash provided by operating activities

     2,174         1,934   
  

 

 

    

 

 

 

Cash Flows from Investing Activities

     

Capital expenditures

     (2,219)         (1,897)   

(Increase) Decrease in restricted cash

     (1)         198   

Proceeds from sales and maturities of nuclear decommissioning trust investments

     666         1,007   

Purchases of nuclear decommissioning trust investments

     (716)         (969)   

Other

     11         11   
  

 

 

    

 

 

 

Net cash used in investing activities

     (2,259)         (1,650)   
  

 

 

    

 

 

 

Cash Flows from Financing Activities

     

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

     (566)         265   

Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2012 and $2 in 2011 $2 in 2011

     394         298   

Long-term debt matured or repurchased

     (50)         (500)   

Energy recovery bonds matured

     (200)         (191)   

Preferred stock dividends paid

     (7)         (7)   

Common stock dividends paid

     (358)         (358)   

Equity contribution

     565         255   

Other

     48         13   
  

 

 

    

 

 

 

Net cash used in financing activities

     (174)         (225)   
  

 

 

    

 

 

 

Net change in cash and cash equivalents

     (259)         59   

Cash and cash equivalents at January 1

     304         51   
  

 

 

    

 

 

 

Cash and cash equivalents at June 30

     $ 45         $ 110   
  

 

 

    

 

 

 

Supplemental disclosures of cash flow information

     

Cash received (paid) for:

     

Interest, net of amounts capitalized

     $ (309)         $ (319)   

Income taxes, net

     111          

Supplemental disclosures of noncash investing and financing activities

     

Capital expenditures financed through accounts payable

     $ 256         $ 229   

Terminated capital leases

     136           

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company that conducts its business through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

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

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2011 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 2011 Annual Report on Form 10-K filed with the SEC on February 16, 2012. PG&E Corporation’s and the Utility’s combined 2011 Annual Report on Form 10-K, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2011 Annual Report.” This quarterly report should be read in conjunction with the 2011 Annual Report.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations (“ARO”), and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. Actual results could differ materially from those estimates.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”) and contributory postretirement medical plans for eligible employees and retirees and their eligible dependents and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code of 1986, as amended (“Code”), as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

 

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The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2012 and 2011 were as follows:

 

    Pension Benefits      Other Benefits  
    Three Months Ended
June 30,
     Three Months Ended
June 30,
 
(in millions)           2012                      2011                      2012                      2011          

Service cost for benefits earned

    $ 98         $ 82         $ 11         $ 11   

Interest cost

    165         164         21         23   

Expected return on plan assets

    (150)         (167)         (20)         (20)   

Amortization of transition obligation

                            

Amortization of prior service cost

                          

Amortization of unrecognized loss

    32         12                 
 

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic benefit cost

    150         100         26         27   

Less: transfer to regulatory account (1)

    (75)         (36)                   
 

 

 

    

 

 

    

 

 

    

 

 

 

Total

    $ 75          $ 64         $ 26         $ 27   
 

 

 

    

 

 

    

 

 

    

 

 

 

 

          
(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in future rates.   

 

     Pension Benefits      Other Benefits  
     Six Months Ended
June 30,
     Six Months Ended
June 30,
 
(in millions)            2012                      2011                      2012                      2011          

Service cost for benefits earned

     $ 197         $ 164         $ 23         $ 22   

Interest cost

     329         328         42         46   

Expected return on plan assets

     (299)         (334)         (39)         (40)   

Amortization of transition obligation

                     12         12   

Amortization of prior service cost

     10         18         12         12   

Amortization of unrecognized loss

     63         24                 
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic benefit cost

     300         200         53         54   

Less: transfer to regulatory account (1)

     (150)         (72)                   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     $ 150         $ 128         $ 53         $ 54   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

           
(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in future rates.   

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

During 2012, the Pacific Gas and Electric Company Retirement Plan was amended to offer a new cash balance benefit formula. Eligible employees hired after December 31, 2012 will be covered by the new formula. Eligible employees hired before January 1, 2013 will have a one-time opportunity to elect to be covered by the new formula going forward, beginning on January 1, 2014. As long as pension benefit costs continue to be recoverable through customer rates, PG&E Corporation and the Utility anticipate that this amendment will have no impact on net income.

Variable Interest Entities

PG&E Corporation and the Utility are required to consolidate the financial results of any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, there are certain entities known as variable interest entities (“VIE”s) for which control is difficult to discern based on ownership or voting interests alone. A VIE is an entity that 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 in a VIE if it has the obligation to absorb expected losses or the right to receive expected gains that could potentially be significant to the VIE and if it has any decision-making rights associated with the activities that are most significant to the VIE’s economic performance, including the power to design the VIE. An enterprise that has a controlling financial interest in a VIE is known as the VIE’s primary beneficiary and is required to consolidate the VIE.

In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE. If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.

 

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Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility subject to the terms of a power purchase agreement. In determining whether the Utility is the primary beneficiary of any of these VIEs, it assesses whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms 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, as well as an analysis of the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility does not provide any 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 any decision-making rights associated with the design of these VIEs, nor does the Utility have the power to direct the activities that are most significant to the economic performance of these VIEs such as dispatch rights, operating and maintenance activities, or re-marketing activities of the power plant after the termination of the VIEs’ respective power purchase agreement with the Utility. Since the Utility was not the primary beneficiary of any of these VIEs at June 30, 2012, it did not consolidate any of them.

The Utility continued to consolidate the financial results of PG&E Energy Recovery Funding LLC (“PERF”), another VIE, at June 30, 2012, since the Utility is the primary beneficiary of PERF. PERF was formed in 2005 as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERB”s) in connection with the settlement agreement entered into among 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”). The Utility has a controlling financial interest in PERF since the Utility is exposed to PERF’s losses and returns through the Utility’s 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an activity that was significant to PERF’s economic performance. The assets of PERF were $279 million at June 30, 2012 and primarily consisted of assets related to ERBs, which are included in other current assets – regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $223 million at June 30, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. PERF is expected to be dissolved in 2013, after the ERBs mature. (See Note 4 below.)

At June 30, 2012, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Condensed Consolidated Balance Sheets. At June 30, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $191 million in benefits and customer payments. In determining whether PG&E Corporation is the primary beneficiary of any of these VIEs, it assesses which of the variable interest holders has control over these companies’ significant economic activities, such as the design of the companies, vendor selection, construction, customer selection, and re-marketing activities after the termination of customer leases. PG&E Corporation determined that these companies control these activities, while its financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies. Since PG&E Corporation was not the primary beneficiary of any of these VIEs at June 30, 2012, it did not consolidate any of them.

Adoption of New Accounting Standards

Amendments to Fair Value Measurement Requirements

On January 1, 2012, PG&E Corporation and the Utility adopted an accounting standards update (“ASU”) that requires additional fair value measurement disclosures. For fair value measurements that use significant unobservable inputs, quantitative disclosures of the inputs and qualitative disclosures of the valuation processes are required. For items not measured at fair value in the balance sheet but whose fair value is disclosed, disclosures of the fair value hierarchy level, the fair value measurement techniques used, and the inputs used in the fair value measurements are required. In addition, the ASU permits an entity to measure the fair value of a portfolio of financial instruments based on the portfolio’s net position, if the portfolio has met certain criteria. Furthermore, the ASU refines when an entity should, and should not, apply certain premiums and discounts to a fair value measurement. The adoption of the ASU is reflected in Note 8 below and did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Presentation of Comprehensive Income

On January 1, 2012, PG&E Corporation and the Utility adopted ASUs that require an entity to present either (1) a single statement of comprehensive income or loss or (2) a separate statement of comprehensive income or loss that immediately follows a statement of income or loss. A single statement of comprehensive income or loss is comprised of a statement of income or loss with other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss appended.

 

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A separate statement of comprehensive income or loss is comprised of net income or loss, other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss. Furthermore, the ASUs prohibit an entity from presenting other comprehensive income and losses in a statement of equity only. The adoption of the ASUs resulted in the addition of the Condensed Consolidated Statements of Comprehensive Income to PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

As a regulated entity, the Utility’s rates are designed to recover the costs of providing service. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory liabilities.

The Utility tracks differences between customer billings and the Utility’s authorized revenue requirements for revenue that is independent, or “decoupled,” from the volume of electricity and natural gas sales. The Utility also tracks differences between incurred costs and customer billings or authorized revenue requirements meant to recover those costs. These differences are recorded to regulatory balancing accounts that represent amounts expected to be collected from or refunded to customers. Regulatory balancing accounts that are not expected to be collected from or refunded to customers over the next 12 months are included in other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets.

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

Regulatory Assets

Current Regulatory Assets

At June 30, 2012 and December 31, 2011, the Utility had current regulatory assets of $793 million and $1,090 million, respectively, primarily consisting of the price risk management regulatory asset, the ERB regulatory asset, the Utility’s retained generation regulatory assets, and the electromechanical meters regulatory asset. The current portion of the price risk management regulatory asset of $367 million represents the unrealized losses related to price risk management derivative instruments expected to be recovered as they are realized over the next 12 months as part of the Utility’s energy procurement costs. (See Note 7 below.) The ERB regulatory asset of $109 million represents the refinancing of a regulatory asset provided for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The Utility expects to recover this asset fully by the end of 2012 when the ERBs mature. The current portion of the Utility’s retained generation regulatory assets of $62 million represents the amortization of the underlying generation facilities expected to be recovered over the next 12 months. (See “Long-Term Regulatory Assets” below.) The current portion of the electromechanical meters regulatory asset of $51 million represents the net book value of electromechanical meters expected to be recovered over the next 12 months. (See “Long-Term Regulatory Assets” below.)

 

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Long-Term Regulatory Assets

Long-term regulatory assets were composed of the following:

 

     Balance at  
(in millions)          June 30, 2012              December 31, 2011    

Pension benefits

     $ 2,978         $ 2,899   

Deferred income taxes

     1,520         1,444   

Utility retained generation

     582         613   

Environmental compliance costs

     557         520   

Price risk management

     259         339   

Electromechanical meters

     221         247   
Unamortized loss, net of gain, on reacquired debt      152          163   

Other

     265         281   
  

 

 

    

 

 

 

Total long-term regulatory assets

     $ 6,534         $ 6,506   
  

 

 

    

 

 

 

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP and also includes amounts that otherwise would be recorded to accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 12 of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.)

The regulatory asset for deferred income taxes represents 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. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover the regulatory asset over the average plant depreciation lives of one to 44 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 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 13 years.

The regulatory asset for environmental compliance costs represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. The Utility expects to recover these costs over the next 32 years, as the environmental compliance work is performed. (See Note 10 below.)

The regulatory asset for price risk management represents the unrealized losses related to price risk management derivative instruments expected to be recovered as they are realized over the next 10 years as part of the Utility’s energy procurement costs. (See Note 7 below.)

The regulatory asset for electromechanical meters represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. The Utility expects to recover the regulatory asset over the next four years.

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of 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 14 years, which is the remaining amortization period of the reacquired debt.

At June 30, 2012 and December 31, 2011, “other” primarily consisted of regulatory assets related to ARO expenses for the decommissioning of the Utility’s fossil fuel-fired generation facilities that are probable of future recovery through rates and costs incurred related to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004, which are being amortized and collected in rates through April 2034.

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 regulatory assets for retained generation, regulatory assets for electromechanical meters, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

 

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Regulatory Liabilities

Current Regulatory Liabilities

At June 30, 2012 and December 31, 2011, the Utility had current regulatory liabilities of $90 million and $161 million, respectively, primarily consisting of amounts that it expects to refund to customers under the electricity supplier settlement agreements over the next 12 months. (See Note 9 below.) Current regulatory liabilities are included within current liabilities – other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities were composed of the following:

 

     Balance at  
(in millions)          June 30, 2012              December 31, 2011    

Cost of removal obligations

     $ 3,555         $ 3,460   

Recoveries in excess of AROs

     669         611   

Public purpose programs

     607         499   

Other

     177         163   
  

 

 

    

 

 

 

Total long-term regulatory liabilities

     $ 5,008         $ 4,733   
  

 

 

    

 

 

 

The regulatory liability for cost of removal obligations represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

The regulatory liability for recoveries in excess of AROs represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility’s nuclear power facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. The regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments. (See Note 8 below.)

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the utility meter.

At June 30, 2012 and December 31, 2011, “other” primarily consisted of the regulatory liability related to the gain associated with the Utility’s acquisition of the permits and other assets of the Gateway Generating Station as part of the settlement that the Utility entered into with Mirant Corporation and the price risk management regulatory liability representing the unrealized gains associated with price risk management derivative instruments expected to be refunded to customers as they are realized beyond the next 12 months as part of the Utility’s energy procurement costs. (See Note 7 below.)

 

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Regulatory Balancing Accounts

 

     Receivable (Payable)  
     Balance at  
(in millions)          June 30, 2012              December 31, 2011    

Distribution revenue adjustment mechanism

     $ 428         $ 223   

Utility generation

     361         241   

Hazardous substance

     56         57   

Public purpose programs

     45         97   

Gas fixed cost

     (30)         16   

Energy recovery bonds

     (83)         (105)   

Energy procurement

     (161)         (48)   

Other

     148         227   
  

 

 

    

 

 

 

Total regulatory balancing accounts, net

     $ 764         $ 708   
  

 

 

    

 

 

 

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 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 recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of electricity sales. During the colder months of winter, there is generally an under-collection in these balancing accounts due to a lower volume of electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to a higher volume of electricity sales and higher rates.

The hazardous substance balancing accounts are used to record and recover hazardous substance remediation costs that are eligible for recovery through a CPUC-approved ratemaking mechanism. (See Note 10 below.)

The public purpose programs balancing accounts are primarily used to record and recover the authorized revenue requirements associated with administering public purpose programs as well as incentive awards earned by the Utility for achieving regulatory targets in the customer energy efficiency program. The public purpose programs primarily consist of energy efficiency programs, low-income energy efficiency programs, demand response programs, research, development, and demonstration programs, and renewable energy programs.

The gas fixed-cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other authorized gas distribution-related costs. Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of gas sales. During the colder months of winter, there is generally an over-collection in this balancing account primarily due to higher natural gas sales. During the warmer months of summer, there is generally an under-collection primarily due to lower natural gas sales.

The ERBs balancing account is used to record and refund to customers the net refunds, claim offsets, and other credits received by the Utility from electricity suppliers related to Chapter 11 disputed claims and to record and recover authorized ERB servicing costs. (See Note 9 below.)

The Utility is generally authorized to recover 100% of its prudently incurred 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 over the following year. The Utility’s energy rates are set to recover such expected costs.

At June 30, 2012 and December 31, 2011, “other” consisted of various balancing accounts, such as the SmartMeterTM advanced metering project balancing account, which tracks the recovery of the related authorized revenue requirements and costs, and balancing accounts that track the recovery of authorized meter reading costs.

 

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NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At June 30, 2012, PG&E Corporation had no cash borrowings or letters of credit outstanding under its $300 million revolving credit facility.

At June 30, 2012, the Utility had no cash borrowings and $363 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

Utility

Senior Notes

On April 16, 2012, the Utility issued $400 million principal amount of 4.45% Senior Notes due April 15, 2042.

Pollution Control Bonds

At June 30, 2012, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.14% to 0.23%. At June 30, 2012, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.13% to 0.15%.

On April 2, 2012, the Utility repurchased the entire $50 million principal amount of pollution control bonds Series 2010 E that were subject to mandatory tender on that same date. The Utility will hold the bonds until they are remarketed to investors or retired.

Commercial Paper Program

At June 30, 2012, the Utility had $825 million of commercial paper outstanding.

Other Short-Term Borrowings

At June 30, 2012, the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes, due November 20, 2012, was 0.92%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs to refinance a regulatory asset provided for in the Chapter 11 Settlement Agreement. PERF used the proceeds to purchase from the Utility the right (known as “recovery property”) to be paid a specified amount collected through the Utility’s electric rates. The Utility remits the amount collected to PERF for payment of principal, interest, and miscellaneous expenses associated with the ERBs. The Utility will no longer collect the electric rate component related to the ERBs after they mature, which will occur by December 31, 2012.

At June 30, 2012, the total amount of ERB principal outstanding was $223 million.

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

 

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NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2012 were as follows:

 

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

Balance at December 31, 2011

     $12,353         $12,384   

Comprehensive income

     493         476   

Common stock issued

     573           

Share-based compensation expense

     29          

Common stock dividends declared

     (387)         (358)   

Preferred stock dividend requirement

             (7)   

Preferred stock dividend requirement of subsidiary

     (7)           

Equity contributions

             565   
  

 

 

    

 

 

 

Balance at June 30, 2012

     $ 13,054         $ 13,061   
  

 

 

    

 

 

 

During the six months ended June 30, 2012, PG&E Corporation issued 3,253,982 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans for total cash proceeds of $124 million.

During the six months ended June 30, 2012, PG&E Corporation issued 4,303,576 shares of its common stock under the Equity Distribution Agreement executed in November 2011 for cash proceeds of $183 million, net of fees and commissions of $2 million. At June 30, 2012, PG&E Corporation had the ability to issue an additional $115 million of its common stock under the Equity Distribution Agreement.

On March 20, 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.

During the six months ended June 30, 2012, PG&E Corporation contributed equity of $565 million to the Utility to maintain the Utility’s CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

NOTE 6: EARNINGS PER SHARE

PG&E Corporation’s basic earnings per common share (“EPS”) is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-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 common shares outstanding for calculating diluted EPS:

 

           Three Months Ended      
June 30,
           Six Months Ended      
June 30,
 
(in millions, except per share amounts)    2012      2011      2012      2011  

Income available for common shareholders

     $ 235         $ 362         $ 468         $ 561   

Weighted average common shares outstanding, basic

     423         399         419         397   

Add incremental shares from assumed conversions:

           

Employee share-based compensation

                           
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average common shares outstanding, diluted

     425         400         421         399   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total earnings per common share, diluted

     $ 0.55         $ 0.91         $ 1.11         $ 1.41   
  

 

 

    

 

 

    

 

 

    

 

 

 

For each of the periods presented above, options and securities that were antidilutive were immaterial.

 

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NOTE 7: DERIVATIVES

Use of Derivative Instruments

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; and

 

   

option contracts that provide the Utility with the right to buy a commodity at a predetermined price and option contracts that require payments from counterparties if market prices exceed a predetermined price.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The CPUC allows the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the costs related to price risk management activities.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the current ratemaking mechanism discussed above remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses 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 or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements for 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 derivatives. The Utility elects the normal purchase and sale exception for eligible derivatives.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce volatility in customer rates, the Utility may enter into financial swap contracts or financial option contracts, or both, to effectively fix or cap, or both, the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices. These financial contracts would be considered derivatives.

Electric Transmission Congestion Revenue Rights

The California electric transmission grid, controlled by the California Independent System Operator (“CAISO”), is subject to transmission constraints when there is insufficient transmission capacity to supply the market. The CAISO imposes congestion charges on market participants to manage transmission congestion. The revenue generated from congestion charges is allocated to holders of congestion revenue rights (“CRRs”). CRRs allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities, such as the Utility, are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The Utility participates in the allocation and auction phases of the annual and monthly CRR processes. CRRs are considered derivatives.

 

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Natural Gas Procurement (Electric Fuels Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through physical natural gas commodity purchases to fuel natural gas generating facilities, and electricity procurement contracts indexed to natural gas prices. To reduce the volatility in customer rates, the Utility purchases financial instruments, such as swaps and options, and enters into fixed-price forward contracts for natural gas, to reduce future cash flow variability from fluctuating natural gas prices. These instruments are considered derivatives.

Natural Gas Procurement (Core Gas Supply Portfolio)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller commercial customers known as “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 natural gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply and demand. The Utility purchases financial instruments, such as swaps and options, as part of its core winter hedging program in order to manage customer exposure to high natural gas prices during peak winter months. These financial instruments are considered derivatives.

Volume of Derivative Activity

At June 30, 2012, the volume of PG&E Corporation’s and the Utility’s outstanding derivatives was as follows:

 

          Contract Volume (1)  

Underlying Product

  

    Instruments    

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

Natural Gas (3)

(MMBtus (4))

   Forwards and Swaps      415,332,102          156,732,291          5,680,000            
  

Options

     256,620,196          277,662,141          7,000,000            

Electricity

(Megawatt-hours)

   Forwards and Swaps      5,010,023          4,314,021          2,009,505          3,081,447    
   Options              174,559          239,233          183,964    
   Congestion Revenue Rights      58,606,638          73,139,741          73,207,008          44,412,837    

 

              

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

(2)  Derivatives in this category expire between 2017 and 2022.

(3) Amounts shown are for the combined positions of the electric fuels 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, derivatives are presented on a net basis by counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral associated with derivative positions.

 

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At June 30, 2012, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

 

     Commodity Risk  
(in millions)      Gross Derivative  
Balance
                Netting                      Cash Collateral           Total Derivative  
Balance
 

Current assets – other

     $ 52         $ (32)         $ 96         $ 116    

Other noncurrent assets – other

     101         (50)         -          51    

Current liabilities – other

     (399)         32         212         (155)    

Noncurrent liabilities – other

     (309)         50         37         (222)    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity risk

     $ (555)         $ -          $ 345         $ (210)    
  

 

 

   

 

 

   

 

 

   

 

 

 

At December 31, 2011, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

 

    Commodity Risk  
(in millions)     Gross Derivative  
Balance
                Netting                      Cash Collateral           Total Derivative  
Balance
 

Current assets – other

    $ 54         $ (39)         $ 103         $ 118    

Other noncurrent assets – other

    113         (59)         -          54    

Current liabilities – other

    (489)         39         274         (176)    

Noncurrent liabilities – other

    (398)         59         101         (238)    
 

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity risk

    $ (720)         $ -          $ 478         $ (242)    
 

 

 

   

 

 

   

 

 

   

 

 

 

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

 

     Commodity Risk  
     Three months ended June 30,     Six months ended June 30,  
(in millions)    2012     2011     2012     2011  

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

     $ 219         $ 21         $ 165         $ 158    

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

     (125)         (122)         (275)         (258)    

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

     (5)         (6)         (27)         (61)    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity risk instruments

   $  89         $ (107)         $ (137)         $ (161)    
  

 

 

   

 

 

   

 

 

   

 

 

 

 

        

(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 derivatives are included 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 derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 2012, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to collateralize fully some of its net liability derivative positions.

 

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At June 30, 2012, the additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

 

(in millions)       

Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized

     $ (443)    

 

Related derivatives in an asset position

     75    

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

     209    
  

 

 

 

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

     $ (159)    
  

 

 

 

 

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

NOTE 8: FAIR VALUE MEASUREMENTS

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

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

Level 2 – 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.

 

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

 

    Fair Value Measurements  
    At June 30, 2012     At December 31, 2011  
(in millions)    Level 1       Level 2       Level 3       Netting (1)       Total       Level 1       Level 2       Level 3       Netting (1)       Total   

 

Assets:

                   

Money market investments

    $ 245       $ -        $ -        $ -        $ 245       $ 206       $ -        $ -        $ -        $ 206  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Nuclear decommissioning trusts

                   

U.S. equity securities

    891        8        -        -        899        841        8        -        -        849   

Non-U.S. equity securities

    330        -        -        -        330       323        -        -        -        323  

U.S. government and agency securities

    709        142        -        -        851        744        156        -        -        900   

Municipal securities

    -        57       -        -        57        -        58        -        -        58   

Other fixed-income securities

    -        179        -        -        179        -        99        -        -        99   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total nuclear decommissioning trusts (2)

    1,930       386       -        -        2,316        1,908       321       -        -        2,229  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Price risk management instruments (Note 7)

                   

Electricity

    -        75       70       20       165        -        92       69       8       169  

Gas

    -        6        2        (6     2        -        6        -        (3     3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total price risk management instruments

    -        81       72       14       167        -        98        69       5       172  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Rabbi trusts

                   

Fixed-income securities

    -        27       -        -        27       -        25        -        -        25  

Life insurance contracts

    -        69        -        -        69        -        67        -        -        67   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total rabbi trusts

    -        96       -        -        96        -        92       -        -        92  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Long-term disability trust

                   

U.S. equity securities

    4       13       -        -        17       13       15       -        -        28  

Non-U.S. equity securities

    -        13        -        -        13        -        9        -        -        9   

Fixed-income securities

    -        136       -        -        136        -        145       -        -        145  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total long-term disability trust

    4       162       -        -        166        13       169       -        -        182  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

    $ 2,179       $ 725       $ 72       $ 14       $ 2,990       $ 2,127       $ 680       $ 69       $ 5       $ 2,881  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities:

                   

Price risk management instruments (Note 7)

                   

Electricity

    $ 312        $ 220        $ 152        $ (315     $ 369        $ 411        $ 289        $ 143        $ (441     $ 402   

Gas

    14       10       -        (16     8       31       13       -        (32     12  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

    $ 326       $ 230       $ 152       $ (331     $ 377       $ 442        $ 302       $ 143       $ (473     $ 414  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

                   

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Excludes $210 million and $188 million at June 30, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

  

   

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.

 

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Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high quality, short-term, diversified money market instruments, such as U.S. Treasury bills, U.S. agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are valued using unadjusted prices for identical assets in an active market and are thus classified as Level 1. Money market funds are recorded as cash and cash equivalents in PG&E Corporation’s Condensed Consolidated Balance Sheets.

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 composed primarily of equity securities, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Equity securities primarily include investments in common stock, which are valued based on unadjusted prices for identical securities in active markets and are classified as Level 1. Equity securities also include commingled funds composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world, which are classified as Level 2. Price quotes for the assets held by these funds are readily observable and available.

Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2. Under a market approach, fair values are determined based on evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. (See Note 7 above.)

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Forwards and swaps transacted in the over-the-counter market that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.

Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Over-the-counter options are classified as Level 3 and are valued using a standard option pricing model, which includes forward prices for the underlying commodity, time value at a risk-free rate, and volatility. For periods where market data is not available, the Utility extrapolates observable data using internal models.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. CRRs are valued based on prices observed in the CAISO auction, which are discounted at the risk-free rate. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions. CRRs are classified as Level 3.

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no transfers between levels for the three and six months ended June 30, 2012.

 

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Level 3 Measurements and Sensitivity Analysis

The Utility’s Market and Credit Risk Management department is responsible for determining the fair value of the Utility’s price risk management derivatives. Market and Credit Risk Management reports to the Chief Risk Officer of the Utility. Market and Credit Risk Management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments. These models use pricing inputs from brokers and historical data. The Market and Credit Risk Management department and the Controller’s organization collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and fair value of Level 3 instruments are reviewed period over period and compared with market conditions to determine reasonableness. Valuation models and techniques are reviewed periodically.

CRRs and power purchase agreements are valued using historical prices and significant unobservable inputs, respectively, derived from internally developed models. Historical prices include CRR auction prices. Unobservable inputs include forward electricity prices. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.)

 

(in millions)    Fair Value at
June 30, 2012
      Valuation Technique      Unobservable Input             Range           

Fair Value Measurement

      Assets          Liabilities            

 

Congestion revenue rights

     $ 70           $ (8)        Market approach    CRR auction prices      $ (6.11) - $ 92.13     

 

Power purchase agreements

     $ -           $ (144)        Discounted cash flow    Forward prices      $ 6.74 - $ 63.54     

Level 3 Reconciliation

The following tables present the reconciliations for Level 3 price risk management instruments, net, for the three and six months ended June 30, 2012 and 2011.

 

     Price Risk Management Instruments  
(in millions)    2012      2011  

Liability balance as of April 1

     $ (99)          $ (312)    

Realized and unrealized gains (losses):

     

Included in regulatory assets and liabilities or balancing accounts (1)

     19           32     
  

 

 

    

 

 

 

Liability balance as of June 30

     $ (80)          $ (280)    
  

 

 

    

 

 

 

 

     
(1) Price risk management activity is recoverable through customer rates. Therefore, net income was not impacted by realized amounts. Unrealized gains and losses are deferred in regulatory liabilities and assets.    

 

     Price Risk Management Instruments  
(in millions)    2012      2011  

Liability balance as of January 1

     $ (74)          $ (399)    

Realized and unrealized gains (losses):

     

Included in regulatory assets and liabilities or balancing accounts (1)

     (6)          119     
  

 

 

    

 

 

 

Liability balance as of June 30

     $ (80)          $ (280)    
  

 

 

    

 

 

 

 

     
(1) Price risk management activity is recoverable through customer rates. Therefore, net income was not impacted by realized amounts. Unrealized gains and losses are deferred in regulatory liabilities and assets.    

 

 

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Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:

 

   

The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at June 30, 2012 and December 31, 2011, as they are short-term in nature or have interest rates that reset daily.

 

   

The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bond loan agreements, PG&E Corporation’s fixed-rate senior notes, and the ERBs issued by PERF were based on quoted market prices at June 30, 2012 and December 31, 2011.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

 

     June 30, 2012      December 31, 2011  
(in millions)      Carrying  
  Amount  
      Level 2 
 Fair Value 
       Carrying  
  Amount  
      Level 2 
 Fair Value 
 
Debt (Note 4)                            

PG&E Corporation

     $ 349          $ 377          $ 349          $ 380    

Utility

     10,894          13,173          10,545          12,543    

Energy recovery bonds (Note 4)

     223          226          423          433    

Nuclear Decommissioning Trust Investments

The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.” As the day-to-day investing activities of the trusts are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Realized gains and losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, through customer rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of ARO. (See Note 3 above.) There is no impact on the Utility’s net income or accumulated other comprehensive income.

 

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The following table provides a summary of available-for-sale investments held in the Utility’s nuclear decommissioning trusts:

 

(in millions)     Amortized  
Cost
    Total
  Unrealized  
Gains
    Total
  Unrealized  
Losses
      Total Fair  
  Value (1)  
 
As of June 30, 2012:                        

Equity securities

       

U.S.

    $ 325          $ 576         $ (2)         $ 899    

Non-U.S.

    197          137          (4)         330     

Debt securities

       

U.S. government and agency securities

    748          104          (1)         851     

Municipal securities

    54         3         -          57    

Other fixed-income securities

    174          5          -          179     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

    $ 1,498         $ 825         $ (7)         $ 2,316    
 

 

 

   

 

 

   

 

 

   

 

 

 

As of December 31, 2011

       

Equity securities

       

U.S.

    $ 334          $ 518          $ (3)         $ 849     

Non-U.S.

    194         131         (2)         323    

Debt securities

       

U.S. government and agency securities

    798         102         -          900    

Municipal securities

    56          2          -          58     

Other fixed-income securities

    96         3         -          99    
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

    $ 1,478         $ 756         $ (5)         $ 2,229    
 

 

 

   

 

 

   

 

 

   

 

 

 
   
(1) Excludes $210 million and $188 million at June 30, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.    

The debt securities mature on the following schedule:

 

(in millions)     As of June 30, 2012   

Less than 1 year

     $    17    

1-5 years

     420    

5-10 years

     250    

More than 10 years

     400    
  

 

 

 

Total maturities of debt securities

     $ 1,087    
  

 

 

 

The following table provides a summary of activity for the debt and equity securities:

 

     Three Months Ended June 30,      Six Months Ended June 30,  
            2012                    2011                    2012                    2011         
(in millions)                            
Proceeds from sales and maturities of securities      $ 315          $ 281          $ 666          $ 1,007    
Gross realized gains on sales of securities held as available-for-sale      7          9          14          29    
Gross realized losses on sales of securities held as available-for-sale      (5)          (3)          (8)          (6)    

 

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NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s Chapter 11 proceeding 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. The FERC held hearings to consider the Utility’s and other electricity purchasers’ refund claims for the May through September 2000 period. The hearings concluded on July 19, 2012, but the FERC has not yet issued a decision.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility entered into a number of settlement agreements 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. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.

On April 10, 2012, the Utility received from the PX a letter stating the mutual intent of both parties to offset the Utility’s remaining disputed claims with its accounts receivable from the CAISO and the PX. Accordingly, the Utility has presented the net amount of remaining disputed claims and accounts receivable on the Condensed Consolidated Balance Sheets at June 30, 2012, reflecting its intent and right to offset these amounts. At December 31, 2011, $494 million was included within accounts receivable – other on the Condensed Consolidated Balance Sheets.

The following table presents the changes in the remaining net disputed claims liability, which includes interest:

 

(in millions)       

Balance at December 31, 2011

   $  848   

Interest accrued

     13   

Less: electricity supplier settlements

     (23)   
  

 

 

 

Balance at June 30, 2012

   $  838   
  

 

 

 

At June 30, 2012, the remaining net disputed claims liability consisted of $164 million of remaining net disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and $674 million of accrued interest (classified on the Condensed Consolidated Balance Sheets within interest payable).

At June 30, 2012 and December 31, 2011, the Utility held $301 million and $320 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

Interest accrues on the remaining net 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, these collections are not held in escrow. If the amount of accrued interest is greater than the amount of interest ultimately determined to be owed on the remaining net disputed claims, the Utility would refund to customers any excess interest collected. The amount of any interest that the Utility may be required to pay will depend on the final determined amount of the remaining net disputed claims and when such interest is paid.

NOTE 10: COMMITMENTS AND CONTINGENCIES

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

 

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Table of Contents

Commitments

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. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s development of new generation facilities to provide the power to be purchased by the Utility under these agreements. The table below excludes expected future payments related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility has not met certain contractual milestones with respect to construction. Based on the Utility’s experience with these types of facilities, the Utility has determined that there is more than a remote chance that contracts could be cancelled until the generation facilities have commenced construction.

At June 30, 2012, the undiscounted future expected payment obligations were as follows:

 

(in millions)       

2012

     $ 1,337    

2013

     2,987    

2014

     3,142    

2015

     3,105    

2016

     2,998    

Thereafter

     32,911    
  

 

 

 

Total

     $ 46,480    
  

 

 

 

Costs incurred by the Utility under power purchase agreements amounted to $978 million and $1.1 billion for the six months ended June 30, 2012 and 2011, respectively.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities are treated as capital leases. During the six months ended June 30, 2012, the Utility terminated several agreements with total minimum lease payments of approximately $136 million. The future minimum lease payments associated with the remaining capital leases were approximately $125 million.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the U.S. to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the U.S. Rocky Mountain supply area, and the southwestern U.S.) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to better meet core customers’ winter peak loads.

At June 30, 2012, the Utility’s undiscounted future expected payment obligations were as follows:

 

(in millions)       

2012

     $ 382   

2013

     426   

2014

     195   

2015

     185   

2016

     152   

Thereafter

     973   
  

 

 

 

Total

     $ 2,313   
  

 

 

 

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $639 million and $929 million for the six months ended June 30, 2012 and 2011, respectively.

 

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Table of Contents

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from one to 14 years and are intended to ensure long-term nuclear fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

At June 30, 2012, the undiscounted future expected payment obligations were as follows:

 

(in millions)       

2012

     $ 46   

2013

     86   

2014

     127   

2015

     193   

2016

     147   

Thereafter

     1,011   
  

 

 

 

Total

     $ 1,610   
  

 

 

 

Payments for nuclear fuel amounted to $40 million and $47 million for the six months ended June 30, 2012 and 2011, respectively.

Other Commitments

In March 2012, the Utility entered into a 10-year facility lease agreement for 250,000 square feet of office space in San Ramon, California. As of June 30, 2012, the future minimum commitment for this operating lease was approximately $67 million.

Contingencies

Legal and Regulatory Contingencies

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. In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.

PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the 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 (or reasonably possible losses in excess of the amounts accrued), are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, penalties, and other legal matters (other than third-party claims and penalties related to natural gas matters discussed below) totaled $42 million at June 30, 2012 and $52 million at December 31, 2011 and are included in PG&E Corporation’s and the Utility’s current liabilities – other in the Condensed Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

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, numerous personal injuries, and extensive property damage. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.

 

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Table of Contents

Pending CPUC Investigations and Enforcement Matters

CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines

On February 24, 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility’s entire gas transmission system. Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law. In March 2012, the CPUC’s Customer Protection and Safety Division (“CPSD”) filed testimony alleging that the Utility committed numerous violations of applicable laws and regulations based on the findings of the CPSD’s records management consultant and an engineering consultant. Among other findings, the consultants’ reports concluded that: the Utility’s recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program. On June 26, 2012, the Utility submitted testimony to the CPUC that disputed many of the CPSD’s findings and allegations, but acknowledged that improvements are needed to its asset management system and recordkeeping practices and outlined the steps being taken in these areas. Evidentiary hearings are scheduled for September 2012 with a final decision expected in February 2013. If the CPUC finds that the Utility has violated any rule, regulation or law, it will schedule a second phase to assess penalties. (See “Penalties Conclusion” below.)

CPUC Investigation Regarding Class Location Designations for Pipelines

On November 10, 2011, the CPUC commenced an investigation pertaining to the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure (“MAOP”) up to which a pipeline can be operated. In the CPSD’s May 25, 2012 investigative report, the CPSD cited the Utility’s admissions in previous reports to the CPUC that it had failed to classify pipeline segments properly and document past patrols of transmission lines and concluded that these failures resulted in a total of 3,062 violations of state and federal standards, the durations of which in total exceeded 15 million days. The report urged the CPUC to levy significant penalties on the Utility but did not recommend a specific penalty amount. On July 23, 2012, the Utility submitted testimony in response to the CPSD’s report that acknowledged deficiencies in the Utility’s past class location and patrol processes and described the efforts to improve those processes. The Utility also reported that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility’s gas pipeline property easements and that the Utility plans to undertake a multi-year effort to clear these encroachments. Evidentiary hearings are scheduled for August 2012 with a final decision expected in late 2012 or early 2013. (See “Penalties Conclusion” below.)

CPUC Investigation Regarding San Bruno Accident

On January 12, 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident, as alleged by the CPSD. In its investigation report, the CPSD had alleged that the San Bruno accident was caused by the Utility’s failure to follow accepted industry practice when installing the section of pipe that failed, the Utility’s failure to comply with federal pipeline integrity management requirements, the Utility’s inadequate record keeping practices, deficiencies in the Utility’s data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility’s deficient emergency response actions after the incident, and a systemic failure of the Utility’s corporate culture that emphasized profits over safety. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility’s compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC noted that the CPSD’s investigation is ongoing and the CPSD could raise additional concerns that it could request the CPUC to consider.

On June 26, 2012, the Utility submitted testimony to the CPUC that disputed many of the CPSD’s findings and allegations. The Utility acknowledged its liability for the San Bruno accident and determined that the likely root cause of the pipeline rupture was (1) a missing interior weld on the pipe; (2) a ductile tear likely caused by a hydrostatic test performed in 1956 at too low a pressure to cause the defective weld to fail; and (3) a fatigue crack that grew over time. However, the Utility stated that many of the findings identified in the CPSD’s reports are not deficiencies, or are much less severe than alleged, and do not constitute violations of applicable laws and regulations.

Evidentiary hearings are scheduled for September and October 2012 with a final decision expected in January 2013. (See “Penalties Conclusion” below.)

 

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Other Natural Gas Compliance Matters

In December 2011, the CPUC delegated authority to the CPSD to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices, including the authority to issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. As of July 31, 2012, the Utility has submitted approximately 24 self-reports with the CPUC. In April 2012, the CPUC ordered the Utility to pay a $17 million penalty imposed by the CPSD for one of these self-reports in which the Utility failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) The CPSD has not yet taken action with respect to the Utility’s other self-reports. The CPSD may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. (See “Penalties Conclusion” below.)

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation, for violations of applicable laws, rules, and orders in connection with the pending investigations described above. For violations that are considered to have occurred on or after January 1, 2012, the penalties may be as high as $50,000 per day, per violation. (Under the CPUC’s delegation of authority described above, the CPSD is required to impose the maximum statutory penalty.) The CPUC and the CPSD have wide discretion to determine the number of violations and the length of time the violations existed. The calculation of penalties is generally based on the totality of the circumstances, including such factors as the severity of the violations; the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity.

The CPUC has stated that it is prepared to impose very significant penalties on the Utility if the evidence adduced at hearing establishes that the Utility’s policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

PG&E Corporation and the Utility continue to believe it is probable that the Utility will incur total penalties of at least $200 million in connection with these investigations and the Utility’s self-reports. PG&E Corporation and the Utility have not recorded any additional charges during the six months ended June 30, 2012 and are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. These estimates, and the assumptions on which they are based, are subject to change as the CPUC investigations progress and more information becomes known regarding the number of violations found to have been committed by the Utility; whether penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD will issue additional citations based on the Utility’s self-reports; whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility’s results of operations, financial condition, and cash flows; and the terms of possible settlements (if any) that may be negotiated with the CPUC. Future changes in these estimates or assumptions could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Criminal Investigation

The U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident and have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.

Third-Party Claims

In addition to the investigations and proceedings discussed above, at June 30, 2012, approximately 120 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 400 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The trial date for the first of these cases has been rescheduled from July 23, 2012 to October 9, 2012. The court also postponed until September 4, 2012 the hearing on various motions filed by PG&E Corporation and the Utility to request that the court dismiss certain claims, including the plaintiffs’ claims for punitive damages, based upon a lack of evidence to support such claims.

 

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At June 30, 2012, the Utility has recorded a cumulative charge of $455 million for estimated third-party claims related to the San Bruno accident, including an $80 million charge made during the three and six months ended June 30, 2012, primarily to reflect recent settlements and information exchanged by the parties during the settlement and discovery process. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

The following table presents the changes in third-party claims liability since the San Bruno accident in 2010, which is included in other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

 

(in millions)       

Balance at January 1, 2010

     $ 0    

Loss accrued

     220    

Less: Payments

     (6)    
  

 

 

 

Balance at December 31, 2010

     214     

Additional loss accrued

     155    

Less: Payments

     (92)    
  

 

 

 

Balance at December 31, 2011

     277    

Additional loss accrued

     80     

Less: Payments

     (47)    
  

 

 

 

Balance at June 30, 2012

     $ 310    
  

 

 

 

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted, the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $25 million and $36 million for insurance recoveries during the three and six months ended June 30, 2012. This is in addition to the $99 million recognized for insurance recoveries during 2011. Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of future insurance recoveries.

Spent Nuclear Fuel Storage Proceeding

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities. The DOE has been unable to meet its contractual obligation 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 (“Humboldt Bay Unit 3”). As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024, and a separate facility at Humboldt Bay. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel. Since 2004, the Utility has filed several complaints in the U.S. Court of Federal Claims to recover $92 million of costs that it incurred through 2004 and to recover all costs incurred in periods thereafter. The Utility estimates that it has incurred costs at least $205 million since 2005. The Utility’s complaints have been similar to those filed by other utilities with nuclear facilities.

On June 6, 2012, the Utility and the DOJ requested that the U.S. Attorney General approve a proposed settlement agreement that would award the Utility $266 million for spent fuel storage costs incurred through December 31, 2010. The proposed agreement also would allow the Utility to submit annual claims to recover costs incurred in 2011, 2012 and 2013, which the Utility estimates to be $25 million per year. The agreement does not address costs incurred for spent fuel storage after 2013 and such costs could be the subject of future litigation. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

At June 30, 2012, no receivable related to the proposed settlement was recorded in the Utility’s Condensed Consolidated Financial Statements. The Utility expects that the proposed settlement will be approved in the third quarter of 2012 and that the Utility will receive the payment during the same quarter. Amounts recovered from the DOJ will be refunded to customers through rates in future periods.

 

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Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear generating units at Diablo Canyon and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident ($2.7 billion for property damage and $490 million for business interruption) 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, the Utility may be required to pay an additional premium of up to $44 million per one-year policy term. NRC regulations require that the Utility’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant before any proceeds can be used for decommissioning or plant repair.

NEIL policies also provide coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. If damages are 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. In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.

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

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

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

If the Utility incurs losses in connection with any of its nuclear generation facilities that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Guarantees

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

Environmental Remediation Contingencies

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.

 

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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 the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable 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 following table presents the changes in the environmental remediation liability from December 31, 2011:

 

(in millions)       

Balance at December 31, 2011

     $ 785    

Additional remediation costs accrued:

  

Transfer to regulatory account for recovery

     100     

Amounts not recoverable in customer rates

     96    

Less: Payments

     (61)    
  

 

 

 

Balance at June 30, 2012

     $ 920    
  

 

 

 

The environmental remediation liability is composed of the following:

 

     Balance At  
(in millions)          June 30,      
      2012      
      December 31, 
 2011 
 

Utility-owned natural gas compressor site near Hinkley, California (1)

     $ 210          $ 149   

Utility-owned natural gas compressor site near Topock, Arizona

     240          218   

Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites

     165          133   

Former MGP sites owned by the Utility or third parties

     178          154   

Fossil fuel-fired generation facilities formerly owned by the Utility

     88          81   

Decommissioning fossil fuel-fired generation facilities and sites

     39          50   
  

 

 

    

 

 

 

Total environmental remediation liability

     $ 920          $ 785   
  

 

 

    

 

 

 

 

     
(1) See “Hinkley Natural Gas Compressor Site” below.   

 

 

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The CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility. At June 30, 2012, the Utility expected to recover $573 million through these ratemaking mechanisms. The Utility also recovers environmental remediation costs from insurance carriers and from other third parties whenever possible. Amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers through rates.

Hinkley Natural Gas Compressor Site

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

In June 2012, the Regional Board issued an amended cleanup and abatement order that accepted the Utility’s proposed program to provide whole house replacement systems for approximately 300 resident households located up to one mile from the chromium plume boundary with two options for a replacement water supply. Eligible residents may have an individual water treatment system on the property or, where feasible, have a deeper well installed to draw water from a lower aquifer. Alternatively, eligible residents may choose to have the Utility purchase their properties. The Utility has begun implementing this program and is required to complete implementation by August 31, 2013. The Utility will maintain and operate the whole house replacement systems for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated.

The Regional Board is also evaluating final remediation alternatives submitted by the Utility using a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated it anticipates releasing a draft environmental impact report (“EIR”) in the second half of 2012 and the Utility expects that it will consider certification of the final EIR, which will include the final approved remediation plan, in early 2013.

At June 30, 2012, $210 million was accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley natural gas compressor site, compared to $149 million accrued at December 31, 2011. The increase primarily reflects the Utility’s best estimate of future probable costs associated with providing water replacement systems to eligible residents or purchasing property from eligible residents, as described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers.

Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the number of eligible residents who participate in the Utility’s program or choose to have the Utility purchase their properties, as described above. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Reasonably Possible Environmental Remediation Contingencies

Although the Utility has provided for known environmental remediation obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley natural gas compressor site) 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. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation’s and the Utility’s results of operations during the period in which they are recorded.

 

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Tax Matters

In 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time Internal Revenue Service (“IRS”) audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating its acceptance of the return. The IRS partially accepted the 2008 return, withholding two matters for further review. In December 2010, the IRS accepted the 2009 tax return without change. In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review. The IRS has not completed the CAP audit for 2011.

The most significant of the matters withheld for further review relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. In the fourth quarter 2011, the IRS agreed to allow PG&E Corporation to file claims for 2008-2010 for the repairs method change. The IRS has not completed its review of these claims.

The audits of PG&E Corporation’s tax returns for the 2005 through 2007 tax years are in the final stages of IRS appeal. PG&E Corporation expects to complete the appeals process in 2012.

The IRS is continuing to work with the utility industry to provide consistent repairs deduction guidance for natural gas transmission, natural gas distribution, and electric generation businesses. PG&E Corporation and the Utility expect the IRS to release this guidance in 2012.

PG&E Corporation and the Utility are unable to determine a range of reasonably possible impact of future changes to the unrecognized tax benefits at this time.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility served approximately five million electricity distribution customers and approximately four million natural gas distribution customers at June 30, 2012.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and over the rates and terms and conditions of service governing the Utility on its interstate natural gas transportation contracts. The Utility also is subject to the jurisdiction of other federal, state, and local governmental agencies.

Most of the Utility’s base revenues (“revenue requirements”) that the Utility is authorized to collect through rates are set by the CPUC in the General Rate Case (“GRC”), which occurs generally every three years. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, natural gas transportation and storage services, electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. The Utility’s revenue requirements are generally set at a level to allow the Utility to recover its forecasted operating expenses, to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures, and to provide the Utility an opportunity to earn its authorized rate of return on equity (“ROE”). The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass through to customers, such as electricity procurement costs. From time to time, the Utility also files separate applications with the CPUC requesting authority to recover costs for other projects. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows are affected by the extent to which the Utility is able to timely recover its actual costs through rates and earn its authorized ROE.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. In addition, this quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2011 which contains or incorporates by reference each company’s audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information (“2011 Annual Report”).

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have been materially affected by costs associated with the Utility’s natural gas operations and third-party claims related to the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”). As discussed below, a number of other factors also have had, and may continue to have, a material impact on PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows.

 

   

The Outcome of Matters Related to the Utility’s Natural Gas System. The Utility forecasts that total natural gas pipeline-related costs could be as much as $550 million in 2012 which may not be recoverable through rates, including $128 million and $232 million incurred during the three and six months ended June 30, 2012, respectively. These costs include amounts related to the Utility’s proposed pipeline safety enhancement plan. It is uncertain when the CPUC will act on the Utility’s request to track plan-related costs for potential future recovery, what portion of plan-related costs incurred in 2012 or future years will be recoverable, and when such plan-related costs, if any, will be recovered. (See “Natural Gas Matters – CPUC Gas Safety Rulemaking Proceeding” below.) During the three months ended June 30, 2012, the Utility increased its accrual for third-party claims related to the San Bruno accident by $80 million, and it is reasonably possible that the Utility may incur additional charges of up to $145 million for these claims. PG&E Corporation and the Utility believe it is reasonably possible that the ultimate amount of penalties that the CPUC will impose in connection with the investigations and enforcement matters pending at the CPUC could be materially higher than the $200 million charge recorded in 2011. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) It is also reasonably possible that an ongoing investigation of the San Bruno accident by federal and state

 

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authorities may result in the imposition of civil or criminal penalties on the Utility. PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows will be affected by the scope and timing of the final CPUC-approved pipeline safety enhancement plan, the ultimate amount of pipeline-related costs that are not recovered through rates, the ultimate amount of costs incurred for third-party claims that are not recoverable through insurance, and the ultimate amount of civil or criminal penalties, or punitive damages, if any, the Utility may be required to pay.

 

   

The Timing and Outcome of Ratemaking and Other Regulatory Proceedings. The Utility’s financial results are affected by the timing and outcome of rate case decisions and other proceedings. As described in the 2011 Annual Report, the CPUC and FERC issued decisions in 2011 that determined the majority of the Utility’s base revenue requirements through 2013 or later. On July 2, 2012, the Utility submitted a draft of its 2014 GRC application to the CPUC. In the 2014 GRC, the CPUC will determine the amount of revenue requirements the Utility can collect through rates for its electric generation operations and electric and natural gas distribution from 2014 through 2016. The Utility’s draft application proposes that the CPUC increase the Utility’s authorized base revenues for 2014 by $1.25 billion over the comparable base revenues for 2013 that were previously authorized by the CPUC. (See “Regulatory Matters – 2014 General Rate Case” below). Further, as discussed above, the CPUC is also still considering the Utility’s request for authorization to recover costs incurred under its proposed pipeline safety enhancement plan. (See “Natural Gas Matters – CPUC Gas Safety Rulemaking Proceeding” below.) The outcome of these regulatory proceedings can be affected by many factors, including general economic conditions, the level of customer rates, regulatory policies, and political considerations.

 

   

The Ability of the Utility to Control Operating Costs. The Utility may incur costs that are higher than forecasted costs, or it may incur significant unanticipated costs. In addition to the expenses related to natural gas matters described above, the Utility forecasts that it will incur expenses in 2012 that are approximately $250 million higher than amounts assumed under the 2011 GRC and the 2011 Gas Transmission and Storage (“GT&S”) rate case as the Utility continues to work to improve the safety and reliability of its electric and natural gas operations. The Utility expects to continue to incur these incremental expenses in 2013. These higher forecasted expenses, including $104 million that was incurred in operating and maintenance expense during the six months ended June 30, 2012, will continue to negatively affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the remainder of 2012 and 2013. (See “Results of Operations” below.) The Utility plans to request that the CPUC authorize increased revenue requirements in the 2014 GRC and the 2015 GT&S rate case to allow the Utility to recover the higher level of expenses it anticipates it will incur in 2014 and future years. (See “Regulatory Matters – 2014 General Rate Case” below.) In addition, any future increase in the Utility’s environmental-related liabilities that are not recoverable through rates, such as costs associated with its natural gas compressor station located in Hinkley, California, could also negatively affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows.

 

   

Authorized Rate of Return, Capital Structure, and Financing. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure for its electric and natural gas distribution and electric generation rate base, consisting of 52% common equity and 48% debt and preferred stock. The Utility has incurred costs that are not recoverable through rates, which has increased the Utility’s equity financing needs. During the six months ended June 30, 2012, the Utility received equity contributions from PG&E Corporation of approximately $565 million. PG&E Corporation funded its equity contributions to the Utility primarily through common stock issuances. The Utility’s future equity financing needs will be affected by the ultimate amount of unrecoverable costs and penalties incurred in connection with natural gas matters and the pending investigations discussed above. Additional equity issued by PG&E Corporation in the future to fund further equity contributions to the Utility could have a material dilutive effect on PG&E Corporation’s earnings per common share. In addition, the Utility’s net income and PG&E Corporation’s income available for common shareholders in 2013 and future years may be affected by changes in the Utility’s authorized capital structure and ROE, currently set at 11.35%. (See “2013 Cost of Capital Proceeding” below.) The Utility’s financing needs also will be affected by other factors, including the expiration of the accelerated (or “bonus”) depreciation provisions of the federal Tax Relief Act in 2013, and the timing and amount of the Utility’s capital expenditures, operating expenses, and collateral requirements associated with price risk management activities. PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by changes in their respective credit ratings, the outcome of natural gas matters, general economic and market conditions, and other factors. (See “Liquidity and Financial Resources” below.)

 

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Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three and Six Months Ended June 30, 2012

PG&E Corporation’s income available for common shareholders for the three months ended June 30, 2012 decreased by $127 million, or 35%, to $235 million, compared to $362 million for the same period in 2011. For the six months ended June 30, 2012, income available for common shareholders decreased by $93 million, or 17%, to $468 million, compared to $561 million for the same period in 2011. The following table is a summary reconciliation of the key changes in income available for common shareholders and earnings per common share for the three and six months ended June 30, 2012:

 

     Three Months Ended
June  30,
     Six Months Ended
June  30,
 
(in millions)          Earnings            Earnings Per
    Common Share    
(Diluted)
           Earnings            Earnings Per
  Common  

  Share (Diluted)  
 

Income Available for Common Shareholders – June 30, 2011

     $ 362          $ 0.91          $ 561          $ 1.41    

Natural gas matters

     (64)          (0.15)          (130)          (0.30)    

Timing of rate case decisions in 2011

     (57)          (0.13)          -            -      

Planned incremental work

     (37)          (0.09)          (62)          (0.15)    

Environmental-related costs

     -            -            (42)          (0.10)    

Increase in rate base earnings

     20          0.05          42          0.10    

Storm and outage expenses

     6          0.01          34          0.08    

Gas transmission revenues

     5          0.01          13          0.03    

Litigation and regulatory matters

     2          -            24          0.06    

Other

     (2)          -            28          0.07    

Increase in shares outstanding (1)

     -            (0.06)          -            (0.09)    
  

 

 

    

 

 

    

 

 

    

 

 

 

Income Available for Common Shareholders – June 30, 2012

     $ 235          $ 0.55