XASE:PCG.PR.E Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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 March 31, 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

1-2348

    

PG&E Corporation

Pacific Gas and Electric Company

         California

California

      94-3234914

94-0742640

        
                            

Pacific Gas and Electric Company

77 Beale Street

P.O. Box 770000

San Francisco, California 94177             

       

PG&E Corporation

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 April 24, 2012:

  

PG&E Corporation

   422,320,110

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 MARCH 31, 2012

TABLE OF CONTENTS

 

PART I.  

FINANCIAL INFORMATION

     PAGE   
ITEM 1.  

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
 

PG&E Corporation

  
      Condensed Consolidated Statements of Income      2   
      Condensed Consolidated Statements of Comprehensive Income      3   
      Condensed Consolidated Balance Sheets      4   
      Condensed Consolidated Statements of Cash Flows      6   
  Pacific Gas and Electric Company   
      Condensed Consolidated Statements of Income      7   
      Condensed Consolidated Statements of Comprehensive Income      8   
      Condensed Consolidated Balance Sheets      9   
      Condensed Consolidated Statements of Cash Flows      11   
 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
 

NOTE 1: Organization and Basis of Presentation

     12   
 

NOTE 2: Significant Accounting Policies

     12   
 

NOTE 3: Regulatory Assets, Liabilities, and Balancing Accounts

     15   
 

NOTE 4: Debt

     18   
 

NOTE 5: Equity

     19   
 

NOTE 6: Earnings Per Share

     20   
 

NOTE 7: Derivatives

     20   
 

NOTE 8: Fair Value Measurements

     23   
 

NOTE 9: Resolution of Remaining Chapter 11 Disputed Claims

     28   
 

NOTE 10: Commitments and Contingencies

     29   
ITEM 2.  

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

  
 

Overview

     38   
 

Cautionary Language Regarding Forward-Looking Statements

     40   
 

Results of Operations

     43   
 

Liquidity and Financial Resources

     47   
 

Contractual Commitments

     52   
 

Capital Expenditures

     52   
 

Natural Gas Matters

     52   
 

Regulatory Matters

     56   
 

Environmental Matters

     58   
 

Off-Balance Sheet Arrangements

     60   
 

Contingencies

     60   
 

Risk Management Activities

     60   
 

Critical Accounting Policies

     62   
ITEM 3.  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     63   
ITEM 4.  

CONTROLS AND PROCEDURES

     63   
PART II.  

OTHER INFORMATION

  
ITEM 1.  

LEGAL PROCEEDINGS

     64   
ITEM 1A.  

RISK FACTORS

     65   
ITEM 2.  

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     65   
ITEM 5.  

OTHER INFORMATION

     66   
ITEM 6.  

EXHIBITS

     67   

SIGNATURES

     68   

 

1


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
March 31,
 
(in millions, except per share amounts)    2012     2011  

Operating Revenues

    

Electric

     $ 2,772       $ 2,617  

Natural gas

     869       980  
  

 

 

   

 

 

 

Total operating revenues

     3,641       3,597  
  

 

 

   

 

 

 

Operating Expenses

    

Cost of electricity

     859       888  

Cost of natural gas

     343       508  

Operating and maintenance

     1,368       1,226  

Depreciation, amortization, and decommissioning

     584       491  
  

 

 

   

 

 

 

Total operating expenses

     3,154       3,113  
  

 

 

   

 

 

 

Operating Income

     487       484  

Interest income

     1       2  

Interest expense

     (174     (177

Other income, net

     26       17  
  

 

 

   

 

 

 

Income Before Income Taxes

     340       326  

Income tax provision

     104       124  
  

 

 

   

 

 

 

Net Income

     236       202  

Preferred stock dividend requirement of subsidiary

     3       3  
  

 

 

   

 

 

 

Income Available for Common Shareholders

     $ 233       $ 199  
  

 

 

   

 

 

 

Weighted Average Common Shares Outstanding, Basic

     414       396  
  

 

 

   

 

 

 

Weighted Average Common Shares Outstanding, Diluted

     416       397  
  

 

 

   

 

 

 

Net Earnings Per Common Share, Basic

     $ 0.56       $ 0.50  
  

 

 

   

 

 

 

Net Earnings Per Common Share, Diluted

     $ 0.56       $ 0.50  
  

 

 

   

 

 

 

Dividends Declared Per Common Share

     $ 0.46       $ 0.46  
  

 

 

   

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

2


Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     (Unaudited)  
     Three Months
Ended March 31,
 
(in millions)    2012     2011  

Net Income

     $ 236       $ 202  
  

 

 

   

 

 

 

Other comprehensive income

    

Pension and other postretirement benefit plans

    

Unrecognized prior service credit (net of income tax of $5 in 2012 and 2011)

     6       10  

Unrecognized net gain (net of income tax of $11 and $6 in 2012 and 2011, respectively)

     21       7  

Unrecognized net transition obligation (net of income tax of $2 in 2012 and 2011)

     4       4  

Transfer to regulatory account (net of income tax of $15 and $8 in 2012 and 2011, respectively)

     (21     (12
  

 

 

   

 

 

 

Other comprehensive income

     10       9  
  

 

 

   

 

 

 

Comprehensive income

     246       211  

Preferred stock dividend requirement of subsidiary

     3       3  
  

 

 

   

 

 

 

Comprehensive income attributable to common shareholders

     $ 243       $ 208  
  

 

 

   

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

3


Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

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

ASSETS

    

Current Assets

    

Cash and cash equivalents

     $ 257       $ 513  

Restricted cash ($56 and $51 related to energy recovery bonds at March 31, 2012 and December 31, 2011)

     385       380  

Accounts receivable

    

Customers (net of allowance for doubtful accounts of $80 and $81 at

March 31, 2012 and December 31, 2011)

     926       992  

Accrued unbilled revenue

     614       763  

Regulatory balancing accounts

     1,425       1,082  

Other

     817       839  

Regulatory assets ($227 and $336 related to energy recovery bonds at

March 31, 2012 and December 31, 2011)

     1,024       1,090  

Inventories

    

Gas stored underground and fuel oil

     97       159  

Materials and supplies

     273       261  

Income taxes receivable

     154       183  

Other

     194       218  
  

 

 

   

 

 

 

Total current assets

     6,166       6,480  
  

 

 

   

 

 

 

Property, Plant, and Equipment

    

Electric

     36,329       35,851  

Gas

     12,015       11,931  

Construction work in progress

     2,011       1,770  

Other

     1       15  
  

 

 

   

 

 

 

Total property, plant, and equipment

     50,356       49,567  

Accumulated depreciation

     (16,107     (15,912
  

 

 

   

 

 

 

Net property, plant, and equipment

     34,249       33,655  
  

 

 

   

 

 

 

Other Noncurrent Assets

    

Regulatory assets

     6,565       6,506  

Nuclear decommissioning trusts

     2,134       2,041  

Income taxes receivable

     412       386  

Other

     662       682  
  

 

 

   

 

 

 

Total other noncurrent assets

     9,773       9,615  
  

 

 

   

 

 

 

TOTAL ASSETS

     $ 50,188       $ 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)    March 31,
2012
    December 31,
2011
 

LIABILITIES AND EQUITY

    

Current Liabilities

    

Short-term borrowings

     $ 1,401       $ 1,647  

Long-term debt, classified as current

     50       50  

Energy recovery bonds, classified as current

     321       423  

Accounts payable

    

Trade creditors

     873       1,177  

Disputed claims and customer refunds

     658       673  

Regulatory balancing accounts

     641       374  

Other

     494       420  

Interest payable

     798       843  

Income taxes payable

     110       110  

Deferred income taxes

     160       196  

Other

     1,769       1,836  
  

 

 

   

 

 

 

Total current liabilities

     7,275       7,749  
  

 

 

   

 

 

 

Noncurrent Liabilities

    

Long-term debt

     11,767       11,766  

Regulatory liabilities

     4,927       4,733  

Pension and other postretirement benefits

     3,464       3,396  

Asset retirement obligations

     1,620       1,609  

Deferred income taxes

     6,190       6,008  

Other

     2,133       2,136  
  

 

 

   

 

 

 

Total noncurrent liabilities

     30,101       29,648  
  

 

 

   

 

 

 

Commitments and Contingencies (Note 10)

    

Equity

    

Shareholders’ Equity

    

Preferred stock

     —          —     

Common stock, no par value, authorized 800,000,000 shares, 421,777,738 shares outstanding at March 31, 2012 and 412,257,082 shares outstanding at December 31, 2011

     8,011       7,602  

Reinvested earnings

     4,752       4,712  

Accumulated other comprehensive loss

     (203     (213
  

 

 

   

 

 

 

Total shareholders’ equity

     12,560       12,101  

Noncontrolling Interest – Preferred Stock of Subsidiary

     252       252  
  

 

 

   

 

 

 

Total equity

     12,812       12,353  
  

 

 

   

 

 

 

TOTAL LIABILITIES AND EQUITY

     $ 50,188       $ 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)  
     Three Months Ended
March 31,
 
(in millions)    2012     2011  

Cash Flows from Operating Activities

    

Net income

     $ 236       $ 202  

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

    

Depreciation, amortization, and decommissioning

     584       491  

Allowance for equity funds used during construction

     (27     (20

Deferred income taxes and tax credits, net

     146       99  

Other

     73       44  

Effect of changes in operating assets and liabilities:

    

Accounts receivable

     221       35  

Inventories

     50       65  

Accounts payable

     (213     182  

Income taxes receivable/payable

     29       34  

Other current assets and liabilities

     (70     (205

Regulatory assets, liabilities, and balancing accounts, net

     (171     (10

Other noncurrent assets and liabilities

     73       171  
  

 

 

   

 

 

 

Net cash provided by operating activities

     931       1,088  
  

 

 

   

 

 

 

Cash Flows from Investing Activities

    

Capital expenditures

     (1,094     (945

(Increase) decrease in restricted cash

     (5     132  

Proceeds from sales and maturities of nuclear decommissioning trust investments

     351       726  

Purchases of nuclear decommissioning trust investments

     (370     (735

Other

     25       (61
  

 

 

   

 

 

 

Net cash used in investing activities

     (1,093     (883
  

 

 

   

 

 

 

Cash Flows from Financing Activities

    

Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011

     (245     415  

Long-term debt matured

     —          (500

Energy recovery bonds matured

     (102     (97

Common stock issued

     387       82  

Common stock dividends paid

     (182     (174

Other

     48       18  
  

 

 

   

 

 

 

Net used in financing activities

     (94     (256
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     (256     (51

Cash and cash equivalents at January 1

     513       291  
  

 

 

   

 

 

 

Cash and cash equivalents at March 31

     $ 257       $ 240  
  

 

 

   

 

 

 

Supplemental disclosures of cash flow information

    

Cash received (paid) for:

    

Interest, net of amounts capitalized

     $ (204     $ (215

Supplemental disclosures of noncash investing and financing activities

    

Common stock dividends declared but not yet paid

     $ 193       $ 181  

Capital expenditures financed through accounts payable

     276       174  

Noncash common stock issuances

     6       6  

Terminated capital leases

     136       -   

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

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Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     (Unaudited)  
      Three Months Ended
March 31,
 
(in millions)    2012     2011  

Operating Revenues

    

Electric

     $ 2,771       $ 2,616  

Natural gas

     869       980  
  

 

 

   

 

 

 

Total operating revenues

     3,640       3,596  
  

 

 

   

 

 

 

Operating Expenses

    

Cost of electricity

     859       888  

Cost of natural gas

     343       508  

Operating and maintenance

     1,366       1,226  

Depreciation, amortization, and decommissioning

     584       490  
  

 

 

   

 

 

 

Total operating expenses

     3,152       3,112  
  

 

 

   

 

 

 

Operating Income

     488       484  

Interest income

     1       2  

Interest expense

     (168     (171

Other income, net

     23       17  
  

 

 

   

 

 

 

Income Before Income Taxes

     344       332  

Income tax provision

     113       131  
  

 

 

   

 

 

 

Net Income

     231       201  

Preferred stock dividend requirement

     3       3  
  

 

 

   

 

 

 

Income Available for Common Stock

     $ 228       $ 198  
  

 

 

   

 

 

 

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 March 31,
 
(in millions)    2012     2011  

Net income

     $ 231       $ 201  
  

 

 

   

 

 

 

Other comprehensive income (loss)

    

Pension and other postretirement benefit plans

    

Unrecognized prior service credit (net of income tax of $5 in 2012 and 2011)

     6       10  

Unrecognized net gain (net of income tax of $11 and $6 in 2012 and 2011, respectively)

     21       7  

Unrecognized net transition obligation (net of income tax of $2 in 2012 and 2011)

     4       4  

Transfer to regulatory account (net of income tax of $15 and $8 in 2012 and 2011, respectively)

     (21     (12
  

 

 

   

 

 

 

Other comprehensive income

     10       9  
  

 

 

   

 

 

 

Comprehensive income

     $ 241       $ 210  
  

 

 

   

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

8


Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

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

ASSETS

    

Current Assets

    

Cash and cash equivalents

     $ 45       $ 304  

Restricted cash ($56 and $51 related to energy recovery bonds at March 31, 2012 and December 31, 2011, respectively)

     385       380  

Accounts receivable

    

Customers (net of allowance for doubtful accounts of $80 and $81 at March 31, 2012 and December 31, 2011)

     926       992  

Accrued unbilled revenue

     614       763  

Regulatory balancing accounts

     1,425       1,082  

Other

     821       840  

Regulatory assets ($227 and $336 related to energy recovery bonds at March 31, 2012 and December 31, 2011, respectively)

     1,024       1,090  

Inventories

    

Gas stored underground and fuel oil

     97       159  

Materials and supplies

     273       261  

Income taxes receivable

     212       242  

Other

     188       213  
  

 

 

   

 

 

 

Total current assets

     6,010       6,326  
  

 

 

   

 

 

 

Property, Plant, and Equipment

    

Electric

     36,329       35,851  

Gas

     12,015       11,931  

Construction work in progress

     2,011       1,770  
  

 

 

   

 

 

 

Total property, plant, and equipment

     50,355       49,552  

Accumulated depreciation

     (16,106     (15,898
  

 

 

   

 

 

 

Net property, plant, and equipment

     34,249       33,654  
  

 

 

   

 

 

 

Other Noncurrent Assets

    

Regulatory assets

     6,565       6,506  

Nuclear decommissioning trusts

     2,134       2,041  

Income taxes receivable

     413       384  

Other

     330       331  
  

 

 

   

 

 

 

Total other noncurrent assets

     9,442       9,262  
  

 

 

   

 

 

 

TOTAL ASSETS

     $ 49,701       $ 49,242  
  

 

 

   

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.

 

9


Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

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

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current Liabilities

    

Short-term borrowings

     $ 1,401       $ 1,647  

Long-term debt, classified as current

     50       50  

Energy recovery bonds, classified as current

     321       423  

Accounts payable

    

Trade creditors

     873       1,177  

Disputed claims and customer refunds

     658       673  

Regulatory balancing accounts

     641       374  

Other

     522       417  

Interest payable

     788       838  

Income taxes payable

     118       118  

Deferred income taxes

     165       199  

Other

     1,562       1,628  
  

 

 

   

 

 

 

Total current liabilities

     7,099       7,544  
  

 

 

   

 

 

 

Noncurrent Liabilities

    

Long-term debt

     11,418       11,417  

Regulatory liabilities

     4,927       4,733  

Pension and other postretirement benefits

     3,391       3,325  

Asset retirement obligations

     1,620       1,609  

Deferred income taxes

     6,347       6,160  

Other

     2,071       2,070  
  

 

 

   

 

 

 

Total noncurrent liabilities

     29,774       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 March 31, 2012 and December 31, 2011

     1,322       1,322  

Additional paid-in capital

     4,181       3,796  

Reinvested earnings

     7,259       7,210  

Accumulated other comprehensive loss

     (192     (202
  

 

 

   

 

 

 

Total shareholders’ equity

     12,828       12,384  
  

 

 

   

 

 

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

     $ 49,701       $ 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)  
     Three Months Ended  
     March 31,  
(in millions)    2012     2011  

Cash Flows from Operating Activities

    

Net income

     $ 231       $ 201  

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

    

Depreciation, amortization, and decommissioning

     584       490  

Allowance for equity funds used during construction

     (27     (20

Deferred income taxes and tax credits, net

     153       99  

Other

     57       29  

Effect of changes in operating assets and liabilities:

    

Accounts receivable

     218       69  

Inventories

     50       65  

Accounts payable

     (182     190  

Income taxes receivable/payable

     30       34  

Other current assets and liabilities

     (69     (196

Regulatory assets, liabilities, and balancing accounts, net

     (171     (10

Other noncurrent assets and liabilities

     75       144  
  

 

 

   

 

 

 

Net cash provided by operating activities

     949       1,095  
  

 

 

   

 

 

 

Cash Flows from Investing Activities

    

Capital expenditures

     (1,094     (945

(Increase) decrease in restricted cash

     (5     132  

Proceeds from sales and maturities of nuclear decommissioning trust investments

     351       726  

Purchases of nuclear decommissioning trust investments

     (370     (735

Other

     3       7  
  

 

 

   

 

 

 

Net cash used in investing activities

     (1,115     (815
  

 

 

   

 

 

 

Cash Flows from Financing Activities

    

Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011

     (245     415  

Long-term debt matured

     -        (500

Energy recovery bonds matured

     (102     (97

Preferred stock dividends paid

     (3     (4

Common stock dividends paid

     (179     (179

Equity contribution

     385       65  

Other

     51       21  
  

 

 

   

 

 

 

Net cash used in financing activities

     (93     (279
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     (259     1  

Cash and cash equivalents at January 1

     304       51  
  

 

 

   

 

 

 

Cash and cash equivalents at March 31

     $ 45       $ 52  
  

 

 

   

 

 

 

Supplemental disclosures of cash flow information

    

Cash received (paid) for:

    

Interest, net of amounts capitalized

     $ (204     $ (215

Supplemental disclosures of noncash investing and financing activities

    

Capital expenditures financed through accounts payable

     $ 276       $ 174  

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 (“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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Net periodic benefit cost as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 is as follows:

 

     Pension Benefits     Other Benefits  
     Three Months Ended
March 31,
    Three Months Ended
March 31,
 
(in millions)    2012     2011     2012     2011  

Service cost for benefits earned

   $ 99     $ 82     $ 12     $ 11  

Interest cost

     164       164       21       23  

Expected return on plan assets

     (149     (167     (19     (20

Amortization of transition obligation

     -        -        6       6  

Amortization of prior service cost

     5       9       6       6  

Amortization of unrecognized loss

     31       12       1       1  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit cost

     150       100       27       27  

Less: transfer to regulatory account (1)

     (75     (36     -        -   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $  75     $  64     $  27     $  27  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

  (1) 

The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, respectively, to a regulatory account

  as the amounts are probable of recovery from customers in future rates.

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

Variable Interest Entities

PG&E Corporation and the Utility evaluate whether any entity is a variable interest entity (“VIE”) that could require consolidation. PG&E Corporation and the Utility use a qualitative approach to determine who has a controlling financial interest in a VIE and perform ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on ownership or voting interests alone. These entities are referred to as VIEs. 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 if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE’s economic performance. An enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility assesses whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns, as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders, 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. For each variable interest, the Utility assesses whether it has the power to direct the activities of the power plant that most directly impact the VIE’s economic performance.

The Utility can hold a variable interest in entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. 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 the power to direct the activities that are most significant to these VIE’s economic performance. This assessment considers any decision-making rights associated with designing the VIE, dispatch rights, operating and maintenance activities, and re-marketing activities of the power plant after the end of the power purchase agreement with the Utility. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at March 31, 2012, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

 

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The Utility continued to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at March 31, 2012, as the Utility is the primary beneficiary of PERF. In 2005, PERF was formed as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERB”s) in connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the remaining disputed claims made by electricity suppliers in 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 $382 million at March 31, 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 $321 million at March 31, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.)

As of March 31, 2012, PG&E Corporation affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Condensed Consolidated Balance Sheets. As of March 31, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $160 million in benefits and customer payments. PG&E Corporation holds a variable interest in these companies as a result of these agreements. PG&E Corporation was not the primary beneficiary of and did not consolidate any of these companies at March 31, 2012. In making this determination, PG&E Corporation evaluated which party has control over these companies’ significant economic activities such as designing the companies, vendor selection, construction, customer selection, and re-marketing activities at the end of customer leases, and determined that these activities are under the control of these companies. PG&E Corporation’s financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies.

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, provided that 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 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. A separate statement of comprehensive income or loss immediately follows a statement of income or loss and 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.

 

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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 records differences between customer billings and the Utility’s authorized revenue requirements since a significant portion of recovery is independent, or “decoupled,” from the volume of electricity and natural gas sales. The Utility also records differences between incurred costs and customer billings or authorized revenue requirements meant to recover those costs. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively.

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

Regulatory Assets

Current Regulatory Assets

At March 31, 2012 and December 31, 2011, the Utility had current regulatory assets of $1,024 million and $1,090 million, respectively, primarily consisting of price risk management regulatory assets, the Utility’s retained generation regulatory assets, the electromechanical meters regulatory asset, and the ERB regulatory asset. The current portion of price risk management regulatory assets of $488 million represents the expected future recovery of unrealized losses related to price risk management derivative instruments over the next 12 months. (See Note 7 below.) The Utility expects to recover these losses as part of its energy procurement costs as they are realized over the next 12 months. 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 $50 million represents the net book value of electromechanical meters expected to be recovered over the next 12 months. (See “Long-Term Regulatory Assets” below). The ERB regulatory asset of $227 million represents the refinancing of a regulatory asset provided for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The Utility expects to fully recover this asset by the end of 2012, when the ERBs mature.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

 

     Balance at  
(in millions)    March 31, 2012      December 31, 2011  

Pension benefits

   $ 2,939      $ 2,899  

Deferred income taxes

     1,483        1,444  

Utility retained generation

     598        613  

Environmental compliance costs

     535        520  

Price risk management

     354        339  

Electromechanical meters

     234        247  

Unamortized loss, net of gain, on reacquired debt

     157        163  

Other

     265        281  
  

 

 

    

 

 

 

Total long-term regulatory assets

   $  6,565      $  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, which 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.)

 

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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 1 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 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 expected future recovery of unrealized losses related to price risk management derivative instruments beyond the next 12 months. The Utility expects to recover these losses as they are realized over the next 10 years. (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. The Utility expects to fully recover these costs by 2026.

At March 31, 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, costs that the Utility incurred in terminating a 30-year power purchase agreement that are amortized and collected in rates through September 2014, and costs incurred related to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004 and are 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.

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2012 and December 31, 2011, the Utility had current regulatory liabilities of $83 million and $161 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers under electricity supplier settlement agreements. (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 are composed of the following:

 

     Balance at  
(in millions)    March 31, 2012      December 31, 2011  

Cost of removal obligations

     $ 3,524        $ 3,460  

Recoveries in excess of AROs

     707        611  

Public purpose programs

     526        499  

Other

     170        163  
  

 

 

    

 

 

 

Total long-term regulatory liabilities

     $ 4,927        $ 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.

 

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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 that are expected to be incurred in the future, 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 March 31, 2012 and December 31, 2011, “other” primarily consisted of regulatory liabilities related to the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered into with Mirant Corporation and price risk management regulatory liabilities representing the expected future refund to customers of unrealized gains related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.)

Regulatory Balancing Accounts

The Utility’s current regulatory balancing accounts represent the amounts expected to be collected from or refunded to customers through authorized rate adjustments over the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund 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.

Current Regulatory Balancing Accounts, Net

 

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

Distribution revenue adjustment mechanism

     $ 422       $ 223  

Utility generation

     412       241  

Public purpose programs

     96       97  

Hazardous substance

     56       57  

Gas fixed cost

     (101     16  

Energy recovery bonds

     (108     (105

Energy procurement

     (129     (48

Other

     136       227  
  

 

 

   

 

 

 

Total regulatory balancing accounts, net

     $ 784       $ 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 public purpose programs balancing accounts are primarily used to record and recover the authorized public purpose program revenue requirements and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of energy efficiency programs, low-income energy efficiency programs, research, development, and demonstration programs, and renewable energy programs.

 

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The hazardous substance balancing accounts are used to record and recover hazardous substance remediation costs. A CPUC-approved ratemaking mechanism authorizes the Utility to recover 90% of such costs for certain sites. The balance represents eligible costs incurred by the Utility that are expected to be recovered over the next 12 months. (See Note 10 below.)

The gas fixed cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other gas distribution-related authorized 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 the 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 electric rates are set to recover such expected costs.

At March 31, 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.

NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At March 31, 2012, PG&E Corporation had neither cash borrowings nor letters of credit outstanding under its $300 million revolving credit facility.

At March 31, 2012, the Utility had no cash borrowings and $367 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

At March 31, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

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 March 31, 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 0.19% to 0.22%. At March 31, 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 0.12% to 0.17%.

On April 2, 2012, the Utility repurchased all of the $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 March 31, 2012, the Utility had $1.1 billion of commercial paper outstanding.

 

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Other Short-Term Borrowings

At March 31, 2012, the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes, due November 20, 2012, was 0.94%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion to refinance a regulatory asset provided for in the Chapter 11 Settlement Agreement. The proceeds of the ERBs were used by PERF to purchase from the Utility the right (known as “recovery property”) to be paid a specified amount from a dedicated rate component (“DRC”) to be collected from the Utility’s electricity customers. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility’s electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF for payment of principal, interest, and miscellaneous expenses associated with the ERBs.

At March 31, 2012, the total amount of ERB principal outstanding was $321 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.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 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

     246       241  

Common stock issued

     393       -   

Share-based compensation expense

     16       -   

Common stock dividends declared

     (193     (179

Preferred stock dividend requirement

     -        (3

Preferred stock dividend requirement of subsidiary

     (3     -   

Equity contributions

     -        385  
  

 

 

   

 

 

 

Balance at March 31, 2012

     $ 12,812       $ 12,828  
  

 

 

   

 

 

 

During the three months ended March 31, 2012, PG&E Corporation issued 3,363,617 shares of its common stock under the Equity Distribution Agreement executed in November 2011, its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercises of employee stock options for total cash proceeds of $133 million, net of fees and commissions of $1 million. At March 31, 2012, PG&E Corporation had the ability to issue an additional $219 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 three months ended March 31, 2012, PG&E Corporation contributed equity of $385 million to the Utility to maintain its CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

 

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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  
     March 31,  
(in millions, except per share amounts)    2012      2011  
Diluted              

Income available for common shareholders

   $ 233      $ 199   

Weighted average common shares outstanding, basic

     414        396   

Add incremental shares from assumed conversions:

     

Employee share-based compensation

     2        1   
  

 

 

    

 

 

 

Weighted average common shares outstanding, diluted

     416        397   
  

 

 

    

 

 

 

Total earnings per common share, diluted

   $  0.56      $  0.50   
  

 

 

    

 

 

 

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

NOTE 7: DERIVATIVES

Use of Derivative Instruments

The Utility and PG&E Corporation, mainly through its ownership of the Utility, face market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives reduce the volatility of commodity costs on behalf of its customers. 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.

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.

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 mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover, 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 qualifying 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.

 

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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 enters into financial swap contracts to effectively fix the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices. These financial swaps are 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 (“CRR”s). 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.

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.

 

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Volume of Derivative Activity

At March 31, 2012, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives were as follows:

 

          Contract Volume (1)  

Underlying Product

  

Instruments

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

Natural Gas (3)

(MMBtus (4))

  

Forwards and

Swaps

     439,441,427         166,878,481         4,280,000         -   
  

Options

     231,380,020         280,200,000         -         -   

Electricity

(Megawatt-hours)

  

Forwards and

Swaps

     4,141,223         4,696,221         2,009,505         3,421,832   
  

Options

     1,248,000         140,510         239,233         218,013   
  

Congestion

Revenue Rights

     75,532,338         73,123,024         73,190,271         54,209,541   

 

(1) 

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

(2) 

Derivatives in this category expire between 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.

At March 31, 2012, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

 

     Gross  Derivative
Balance
            Netting             Cash Collateral      Total  Derivative
Balance
 
(in millions)    Commodity Risk (PG&E Corporation and the Utility)  

Current assets – other

     $ 42       $ (27     $ 97        $ 112  

Other noncurrent assets – other

     96       (43     -         53  

Current liabilities – other

     (515     27       318        (170

Noncurrent liabilities – other

     (397     43       101        (253
  

 

 

   

 

 

   

 

 

    

 

 

 

Total commodity risk

     $ (774     $ -        $ 516        $ (258
  

 

 

   

 

 

   

 

 

    

 

 

 

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

 

$0000.0 $0000.0 $0000.0 $0000.0
     Gross  Derivative
Balance
            Netting             Cash Collateral      Total  Derivative
Balance
 
(in millions)    Commodity Risk (PG&E Corporation and the Utility)  

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
  

 

 

   

 

 

   

 

 

    

 

 

 

 

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

 

     Commodity Risk
(PG&E  Corporation and Utility)
 
     Three months ended March 31,  
(in millions)    2012     2011  

Unrealized (loss) gain – regulatory assets and liabilities (1)

     $ (54     $ 137  

Realized loss – cost of electricity (2)

     (151     (136

Realized loss – cost of natural gas (2)

     (22     (55
  

 

 

   

 

 

 

Total commodity risk instruments

     $ (227     $ (54
  

 

 

   

 

 

 

 

(1) Unrealized gains and losses on derivatives are deferred 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 recovered from 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. As of March 31, 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 immediately additional cash to collateralize fully some of its net liability derivative positions.

At March 31, 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

     $ (134

Related derivatives in an asset position

     2  

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

     33  
  

 

 

 

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

     $ (99
  

 

 

 

 

(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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Table of Contents

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 March 31, 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

     $ 206         $ -         $ -         $ -        $ 206         $ 206        $ -         $ -         $ -        $ 206  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Nuclear decommissioning trusts

                           

U.S. equity securities

     925        9        -         -        934        841        8        -         -        849  

Non-U.S. equity securities

     358        -         -         -        358        323        -         -         -        323  

U.S. government and agency securities

     734        138        -         -        872        744        156        -         -        900  

Municipal securities

     -         68        -         -        68        -         58        -         -        58  

Other fixed-income securities

     -         150        -         -        150        -         99        -         -        99  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total nuclear decommissioning trusts (2)

     2,017        365        -         -        2,382        1,908        321        -         -        2,229  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Price risk management instruments (Note 7)

                           

Electricity

     -         68        67        27       162        -         92        69        8       169  

Gas

     -         3        -         -        3        -         6        -         (3     3  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total price risk management instruments

     -         71        67        27       165        -         98        69        5       172  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Rabbi trusts

                           

Fixed-income securities

     -         26        -         -        26        -         25        -         -        25  

Life insurance contracts

     -         68        -         -        68        -         67        -         -        67  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total rabbi trusts

     -         94        -         -        94        -         92        -         -        92  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Long-term disability trust

                           

U.S. equity securities

     5        13        -         -        18        13        15        -         -        28  

Non-U.S. equity securities

     -         15        -         -        15        -         9        -         -        9  

Fixed-income securities

     -         142        -         -        142        -         145        -         -        145  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total long-term disability trust

     5        170        -         -        175        13        169        -         -        182  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

     $ 2,228        $ 700        $ 67        $ 27       $ 3,022        $ 2,127        $ 680        $ 69        $ 5       $ 2,881  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Liabilities:

                           

Price risk management instruments (Note 7)

                           

Electricity

     $ 436        $ 284        $ 166        $ (471 )     $ 415        $ 411        $ 289        $ 143        $ (441     $ 402  

Gas

     15        11        -         (18 )     8        31        13        -         (32     12  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities

     $ 451        $ 295        $ 166        $ (489     $ 423        $ 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 $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

 

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Table of Contents

Valuation Techniques

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

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 generally valued using unadjusted prices in an active market for identical assets 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 in active markets for identical securities 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 either exchange-traded or over-the-counter traded. (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 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.

 

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Table of Contents

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 months ended March 31, 2012.

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 or significant unobservable inputs derived from internally-developed models. Unobservable inputs include forward electricity prices. Historical prices include CRR auction prices. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable 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
March 31, 2012
   

Valuation Technique

  

Unobservable Input

  

Range

Fair Value Measurement

   Assets      Liabilities          

Congestion revenue rights

     $ 67        $ (8   Market approach    CRR auction prices    $ (6.30) - $ 5.10

Power purchase agreements

     $ -         $ (158   Discounted cash flow    Forward prices    $ 2.00 - $ 61.05

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2012 and 2011.

 

     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)

     (25     87  
  

 

 

   

 

 

 

Liability balance as of March 31

     $ (99     $ (312
  

 

 

   

 

 

 

 

(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.

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 March 31, 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 March 31, 2012 and December 31, 2011.

 

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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):

 

     March 31, 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         $ 382         $ 349         $ 380   

Utility

     10,546         12,412         10,545         12,543   

Energy recovery bonds (Note 4)

     321         327         423         433   

Nuclear Decommissioning Trust Investments

The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the day-to-day investing activities of the trusts are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or 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. There is no impact on the Utility’s earnings or accumulated other comprehensive income. (See Note 3 above.)

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 March 31, 2012

          

Equity securities

          

U.S.

     $ 319        $ 616        $ (1     $ 934  

Non-U.S.

     197        162         (1     358  

Debt securities

          

U.S. government and agency securities

     787        86         (1     872  

Municipal securities

     66        3         (1     68  

Other fixed-income securities

     147        3         -        150  
  

 

 

    

 

 

    

 

 

   

 

 

 

Total

     $ 1,516        $ 870        $ (4     $ 2,382  
  

 

 

    

 

 

    

 

 

   

 

 

 

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 $248 million and $188 million at March 31, 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 March 31, 2012  

Less than 1 year

     $ 29   

1–5 years

     408   

5–10 years

     264   

More than 10 years

     389   
  

 

 

 

Total maturities of debt securities

     $ 1,090   
  

 

 

 

 

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

 

     Three Months Ended  
(in millions)    March 31, 2012     March 31, 2011  

Proceeds from sales and maturities of nuclear decommissioning trust investments

     $ 351       $ 726  

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

     7       20  

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

     (3     (4

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. Hearings at the FERC commenced on April 11, 2012 to address the Utility’s and other electricity purchasers’ refund claims for the May through September 2000 period. The Utility is unable to determine the outcome of the hearings at this time.

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. The settlement amounts, net of deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, are refunded to customers in rates. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

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

The following table presents the changes in the remaining net disputed claims liability:

 

(in millions)       

Balance at December 31, 2011

   $  848  

Interest accrued

     7  

Less: electricity supplier settlements

     (23
  

 

 

 

Balance at March 31, 2012

   $  832  
  

 

 

 

At March 31, 2012, the Utility’s remaining net disputed claims liability was $832 million, consisting of $658 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $668 million (classified on the Condensed Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within accounts receivable – other).

On April 10, 2012, the PX and the Utility reached an agreement that provides the Utility with the legal right to offset the Utility’s remaining disputed claims with the Utility’s accounts receivable from the CAISO and the PX. In future periods, the Utility will present the net amount of these balances on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds.

 

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

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 future expected payments related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility have 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 March 31, 2012, the undiscounted future expected payment obligations were as follows:

 

(in millions)       

2012

     $ 1,810   

2013

     2,860   

2014

     3,010   

2015

     3,007   

2016

     2,917   

Thereafter

     32,120   
  

 

 

 

Total

     $ 45,724   
  

 

 

 

Costs incurred by the Utility under power purchase agreements amounted to $435 million and $587 million for the three months ended March 31, 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 three months ended March 31, 2012, the Utility terminated several agreements with total minimum lease payments of approximately $136 million. As of March 31, 2012, future minimum lease payments associated with capital leases were approximately $115 million.

 

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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 March 31, 2012, the Utility’s undiscounted future expected payment obligations were as follows:

 

(in millions)       

2012

     $ 475   

2013

     331   

2014

     196   

2015

     187   

2016

     153   

Thereafter

     974   
  

 

 

 

Total

     $ 2,316   
  

 

 

 

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $378 million and $433 million for the three months ended March 31, 2012 and 2011, respectively.

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 March 31, 2012, the undiscounted future expected payment obligations were as follows:

 

(in millions)       

2012

     $ 67   

2013

     86   

2014

     127   

2015

     193   

2016

     147   

Thereafter

     1,011   
  

 

 

 

Total

     $ 1,631   
  

 

 

 

Payments for nuclear fuel amounted to $19 million and $29 million for the three months ended March 31, 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 March 31, 2012, the future minimum commitment for this operating lease was approximately $67 million.

 

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Contingencies

PG&E Corporation

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

Utility

Spent Nuclear Fuel Storage Proceedings

Under federal law, the U.S. Department of Energy (“DOE”) was required to dispose of spent nuclear fuel and high-level radioactive waste from electric utilities with commercial nuclear power plants no later than January 31, 1998, in exchange for fees paid by the utilities. The DOE failed to meet its contractual obligation to dispose of nuclear waste from the Utility’s nuclear generating facility at Diablo Canyon and its retired 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.

The Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, the U.S. Court of Federal Claims awarded the Utility $89 million on March 30, 2010. On February 21, 2012, the Federal Circuit Court of Appeals denied the DOE’s appeal from May 2010 and affirmed the $89 million award. The deadline for the DOE to petition for a rehearing of the Court’s decision is May 21, 2012. The Utility has not recorded any receivable for the award as of March 31, 2012.

Additionally, on August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred at least $205 million of such costs since 2005. Any amounts recovered from the DOE will be refunded to customers.

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 $40 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.

 

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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.

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 $36 million at March 31, 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.

Pending CPUC Investigations and Enforcement Matters

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. On March 12, 2012, the CPUC’s Consumer Protection and Safety Division (“CPSD”) filed testimony that consisted of reports by 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

 

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integrity management program. On March 30, 2012, the CPSD filed supplemental testimony to address additional recordkeeping items and to list specific violations the CPSD alleges that the Utility committed based on the findings of the consultants’ reports. The Utility’s responses to the CPSD’s reports are due on June 25, 2012. 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.

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. On April 2, 2012, in its second response to the CPUC investigation, the Utility reported that 159 miles of pipeline (as compared to 162 miles previously reported) had a current class location designation that was higher than reflected in the Utility’s Geographic Information System. Most of these misclassifications were attributable to the Utility’s failure to correctly identify development or well-defined areas near the pipeline. The Utility had also previously determined it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. The Utility also reported that it could not confirm that all transmission lines were patrolled as required by the Utility’s procedures and that the Utility has begun a system-wide review of patrol records for all transmission pipelines. Evidentiary hearings are scheduled for August 2012. See “Penalties Conclusion” below.

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

In December 2011, the CPUC delegated authority to its staff 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. Since the citation program was adopted, the Utility has filed 12 self-reports with the CPUC. In one of these self-reports, the Utility reported that it failed to conduct periodic leak surveys because the Utility had not included 16 gas distribution maps in its leak survey schedule. In response to this self-report, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million. On April 19, 2012, the CPUC denied the Utility’s appeal of the $17 million penalty and concluded that the CPSD had appropriately determined the number of violations. The Utility was ordered to pay the penalty within 30 days. The CPSD has not yet taken action with respect to the Utility’s other self-reports, including a follow-up report stating that the Utility had not considered an additional 46 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) 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 statutory penalty has increased to a maximum of $50,000 per day, per violation. (Under the CPUC’s delegation of authority, the CPSD is required to impose the maximum statutory penalty.) The CPUC and CPSD have wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including 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 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.

 

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PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties of at least $200 million on the Utility as a result of these investigations and the Utility’s self-reports and have accrued this amount as of March 31, 2012 and December 31, 2011. (The amount accrued included the $17 million penalty described above.) In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the CPSD’s reports; the Utility’s self-reports to the CPUC; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. The ultimate amount of penalties imposed on the Utility will be affected by many factors, including how many violations the CPUC will find the Utility has committed; whether the penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD issues additional citations based on the Utility’s self-reports; and 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.

The Utility’s estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes 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. The Utility is cooperating with the investigation. 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

Approximately 110 lawsuits involving third-party claims for personal injury and property damage in connection with the San Bruno accident, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 380 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The judge overseeing the coordinated San Bruno accident civil litigation has set a trial date of July 23, 2012 for the first of these lawsuits.

On April 6, 2012, PG&E Corporation and the Utility filed various motions to request that the Court dismiss certain claims, including plaintiffs’ claims for punitive damages, based upon a lack of evidence to support such claims. Plaintiffs’ oppositions to the motions are due on June 8, 2012. The court will hold a hearing on June 22, 2012 to consider the motions.

As of March 31, 2012, the Utility has incurred a cumulative charge of $375 million for third-party claims and estimates that it is reasonably possible it will incur up to an additional $225 million, 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. As more information becomes known, 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 in the period during which they are recorded. 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  

Less: Payments

     (34)   
  

 

 

 

Balance at March 31, 2012

     $ 243  
  

 

 

 

 

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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 $11 million for insurance recoveries during the three months ended March 31, 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.

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.

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

     77  

Amounts not recoverable in customer rates

     81  

Less: Payments

     (22)   
  

 

 

 

Balance at March 31, 2012

     $ 921  
  

 

 

 

The $921 million accrued at March 31, 2012 consisted of the following:

 

   

$218 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California (“Hinkley natural gas compressor site”), as described below;

 

   

$240 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

 

   

$80 million related to a remediation liability that the Utility retained after selling certain fossil fuel-fired generation facilities in 1998 and 1999;

 

   

$168 million related to remediation costs for the Utility’s generation facilities (other than remediation costs for fossil fuel-fired generation), other facilities, and for third-party disposal sites;

 

   

$165 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

 

   

$50 million related to remediation costs for decommissioning fossil fuel-fired generation facilities and sites.

 

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Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Hinkley natural gas compressor site. 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 October 2011, the Regional Board ordered the Utility to provide an interim and permanent replacement water system for certain resident households that have domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion background level. Following the issuance of this order, the Utility filed a petition with the California State Water Resources Control Board (“State Board”) to contest certain provisions of the order. On April 9, 2012, the Utility informed the Regional Board that the Utility would provide 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 expects to begin implementing this program later in 2012. The Utility will continue the program until the State of California has adopted a drinking water standard specifically for hexavalent chromium or for up to five years at which time the program will be evaluated. The Utility has requested the Regional Board’s acknowledgement that the Utility’s program complies with the October 2011 order.

The Regional Board is also evaluating the Utility’s final groundwater remediation plan that proposes 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 that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

As of March 31, 2012, $218 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 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 Contingencies

Although the Utility has provided for known environmental 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.

Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review for certain approved sites (excluding any remediation costs associated with the Hinkley natural gas compressor site). The Utility expects to recover $427 million through this ratemaking mechanism. The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The Utility expects to recover $50 million through this ratemaking mechanism and an additional $99 million from other ratemaking mechanisms. Finally, the Utility also recovers these costs

 

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from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

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 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.

The 2005 through 2007 tax years are currently under Appeals with the IRS. PG&E Corporation expects to complete the Appeals process in 2012. PG&E Corporation believes that the final resolution of open audits will not have a material impact on its financial condition or results of operations.

PG&E Corporation and the Utility are unable to determine the potential 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 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at March 31, 2012.

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

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 continued to be negatively affected by the ongoing regulatory proceedings and investigations related to its natural gas pipeline operations that were commenced following the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”). The outcome of these matters, as well as the outcome of the civil litigation related to the San Bruno accident, is expected to have a material impact on PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows. As discussed below, other factors, including changes in the estimated costs of environmental remediation associated with the Utility’s natural gas compressor stations, 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 it will incur total natural gas pipeline-related costs ranging from $450 million to $550 million in 2012 that may not be recoverable through rates, including $104 million incurred during the three months ended March 31, 2012. 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 Rulemaking Proceeding” below.) PG&E Corporation and the Utility also continue to believe 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 accrued. Additionally, it is reasonably possible that the Utility may incur additional charges of up to $225 million for third-party claims related to the San Bruno accident. (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 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 Ability of the Utility to Control Operating Costs and Capital Expenditures.  The Utility’s revenue requirements are generally set by the CPUC and the FERC 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 return on equity (“ROE”). In addition to the additional expenses related to

 

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natural gas matters described above, the Utility forecasts that it will incur expenses in each of 2012 and 2013 that are materially higher than amounts assumed under the 2011 General Rate Case (“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. These higher forecasted expenses will negatively affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows. During the three months ended March 31, 2012, the Utility increased its environmental remediation liability related to its natural gas compressor station located near Hinkley, California (“Hinkley natural gas compressor site”) by $75 million and agreed to contribute $70 million to the City of San Bruno to support the city and community’s recovery efforts. These additional expenses, which are not recoverable through rates, negatively affected PG&E Corporation’s and the Utility’s financial results.

 

   

Authorized Rate of Return, Capital Structure, and Financing.  Future changes in the Utility’s CPUC-authorized ROE and capital structure will affect the amount of the Utility’s net income and the amount of PG&E Corporation’s income available for common shareholders. The Utility’s 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, and its authorized ROE of 11.35% will remain in effect through 2012. On April 20, 2012, the Utility filed an application to request that the CPUC authorize the Utility’s capital structure and rates of return beginning on January 1, 2013. (See “2013 Cost of Capital Proceeding” below.) The Utility’s financing needs will be affected by various factors, including changes to its authorized capital structure and rates of return, and the timing and amount of capital expenditures, operating expenses, and collateral requirements. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. Charges incurred by the Utility that are not recoverable through customer rates increase the Utility’s equity needs. Additional equity issued by PG&E Corporation could have a dilutive effect on future earnings per common share. 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.)

 

   

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. 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 for the next several years. In July 2012, the Utility expects to submit a draft of its GRC application to the CPUC for the period beginning January 1, 2014. (See “2014 General Rate Case” below.) From time to time, the Utility also files separate applications with the CPUC requesting authority to recover costs for other projects, such as the Utility’s proposed pipeline safety enhancement plan in August 2011. (See “Natural Gas Matters – CPUC Rulemaking Proceeding” below.) The Utility’s revenues will be affected by whether and when the CPUC authorizes the Utility to recover these costs. 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. The Utility’s recovery of these costs is often subject to compliance and audit proceedings conducted by the CPUC which may result in the disallowance of costs previously recorded for recovery. The outcome of these proceedings can be affected by many factors, including general economic conditions, the level of customer rates, regulatory policies, and political considerations.

 

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Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three Months Ended March 31, 2012

PG&E Corporation’s income available for common shareholders increased by $34 million, or 17%, from $199 million for the three months ended March 31, 2011 to $233 million for the three months ended March 31, 2012. 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 months ended March 31, 2012:

 

(in millions)           Earnings              Earnings Per
    Common Share    
(Diluted)
 

Income Available for Common Shareholders – March 31, 2011

    $ 199          $ 0.50    

Timing of rate case decisions in 2011

    57          0.14    

Storm and outage expenses

    28          0.07    

Litigation and regulatory matters

    22          0.05    

Increase in rate base earnings

    22          0.05    

Gas transmission revenues

    8          0.02    

Natural gas matters

    (66)          (0.15)    

Environmental-related costs

    (42)          (0.10)    

Other

    5          0.01    

Increase in shares outstanding (1)

    -           (0.03)    
 

 

 

    

 

 

 

Income Available for Common Shareholders – March 31, 2012

    $ 233          $ 0.56    
 

 

 

    

 

 

 

 

    

 

(1)  Represents the impact of a higher number of shares outstanding at March 31, 2012, compared to the number of shares outstanding at March 31, 2011. PG&E Corporation issues shares to fund its equity contributions to the Utility that are used by the Utility to maintain its capital structure and fund operations, including expenses related to natural gas matters. This has no dollar impact on earnings.

       

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

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

 

   

the outcomes of pending and future investigations, enforcement matters, and regulatory proceedings related to the San Bruno accident and the safety of the Utility’s natural gas system; the ultimate amount of third-party claims associated with the San Bruno accident that are not recovered through insurance; the ultimate amount of any civil or criminal penalties, or punitive damages, if any, the Utility may incur related to these matters, and the ultimate amount of costs the Utility incurs for natural gas matters that are not recovered through rates;

 

   

the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities (in addition to investigations or proceedings related to the San Bruno accident and natural gas matters);

 

   

whether PG&E Corporation and the Utility are able to repair the reputational harm that they have suffered which, in part, will depend on their ability to implement the recommendations made by the National Transportation Safety Board (“NTSB”) and the CPUC’s independent review panel and comply with new state and federal regulations applicable to natural gas pipeline operations; whether additional deficiencies are identified in the Utility’s operating practices and procedures or corporate culture; developments that may occur in the various investigations of the San Bruno accident and natural gas matters; the decisions, findings, or orders issued in connection with these investigations, including the amount

 

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of civil or criminal penalties that may be imposed on the Utility; developments that may occur in the civil litigation related to the San Bruno accident; and the extent of service disruptions that may occur due to changes in pipeline pressure as the Utility continues to inspect and test pipelines;

 

   

the adequacy and price of electricity and natural gas supplies, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and the availability and price of nuclear fuel used in the two nuclear generation units at Diablo Canyon;

 

   

explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, labor disruptions, and similar events, as well as acts of terrorism, war, or vandalism, including cyber-attacks, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies; and subject the Utility to third-party liability for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;

 

   

the impact of storms, tornadoes, floods, drought, earthquakes, tsunamis, wildland and other fires, pandemics, solar events, electromagnetic events, and other natural disasters, which affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

 

   

the potential impacts of climate change, the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases (“GHG”s), and whether the Utility is able to recover associated compliance costs, including the cost of emission allowances and offsets, that the Utility may incur under cap-and-trade regulations;

 

   

changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline in the Utility’s service area, general and regional economic and financial market conditions, the development of alternative energy technologies including self-generation and distributed generation technologies, or other reasons;

 

   

the occurrence of unplanned outages at the Utility’s generation facilities and the ability of the Utility to procure replacement electricity if certain generation facilities were unavailable;

 

   

the results of seismic studies the Utility is conducting that could affect the Utility’s ability to continue operating Diablo Canyon or renew the operating licenses for Diablo Canyon; the impact of the recently issued NRC orders to implement various recommendations made by the NRC’s task force following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan; and the impact of new legislation, regulations, or policies that may be adopted in the future to address the operations, security, safety, or decommissioning of nuclear facilities, the storage of spent nuclear fuel, seismic design, cooling water intake, or other issues;

 

   

the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the outcome of proceedings and investigations relating to the Utility’s natural gas operations affects the Utility’s ability to make distributions to PG&E Corporation in the form of dividends or share repurchases;

 

   

whether the Utility’s newly installed advanced metering system infrastructure, consisting of electric and gas SmartMeterTM devices and related software systems and wireless communications equipment, continues to function accurately and timely measure customer energy usage and generate billing information; whether the Utility can timely implement “dynamic pricing” retail electric rates that are more closely aligned with real-time wholesale electricity market prices; and whether the Utility can continue to rely on third-party vendors and contractors to maintain and support the advanced metering system infrastructure;

 

   

whether the Utility is able to protect its information technology, operating systems, and networks, including the advanced metering system infrastructure from damage, disruption, or failure caused by cyber-attacks, computer viruses, and other hazards; and whether the Utility’s security measures are sufficient to protect confidential customer, vendor, and financial data contained in such systems and networks from unauthorized access and disclosure;

 

   

the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;

 

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

 

   

the amount of equity issued by PG&E Corporation in the future to fund equity contributions to the Utility to enable the Utility to maintain its authorized capital structure that will primarily depend on the timing and amount of charges and costs the Utility incurs that will not be recoverable through rates or insurance; and the ability of PG&E Corporation, the Utility, and other counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

 

   

the impact of environmental remediation laws, regulations, and orders; the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance; and the ultimate amount of costs the Utility incurs in connection with the Hinkley natural gas compressor site, which are not recoverable through rates or insurance;

 

   

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

 

   

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

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see the discussion in the section entitled “Risk Factors” in the 2011 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

 

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RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011:

 

            Three Months ended March 31,      
(in millions)       2012     2011  
Utility                

Electric operating revenues

      $ 2,771         $ 2,616    

Natural gas operating revenues

      869         980    
   

 

 

   

 

 

 

Total operating revenues

      3,640         3,596    
   

 

 

   

 

 

 

Cost of electricity

      859         888    

Cost of natural gas

      343         508    

Operating and maintenance

      1,366         1,226    

Depreciation, amortization, and decommissioning

      584         490    
   

 

 

   

 

 

 

Total operating expenses

      3,152         3,112    
   

 

 

   

 

 

 

Operating income

      488         484    

Interest income

      1         2    

Interest expense

      (168)         (171)    

Other income, net

      23         17    
   

 

 

   

 

 

 

Income before income taxes

      344         332    

Income tax provision

      113         131    
   

 

 

   

 

 

 

Net Income

      231         201    

Preferred stock dividend requirement

      3         3    
   

 

 

   

 

 

 

Income available for common stock

      $ 228         $ 198    
   

 

 

   

 

 

 

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

     

Operating revenues

      $ 1         $ 1    

Operating expenses

      2         1    
   

 

 

   

 

 

 

Operating loss

      (1)         -     

Interest income

      -          -     

Interest expense

      (6)         (6)    

Other income, net

      3         -     
   

 

 

   

 

 

 

Loss before income taxes

      (4)         (6)    

Income tax benefit

      (9)         (7)    
   

 

 

   

 

 

 

Net Income

      $ 5         $ 1    
   

 

 

   

 

 

 

Consolidated Total

     

Operating revenues

      $ 3,641         $ 3,597    

Operating expenses

      3,154         3,113    
   

 

 

   

 

 

 

Operating income

      487         484    

Interest income

      1         2    

Interest expense

      (174)         (177)    

Other income, net

      26         17    
   

 

 

   

 

 

 

Income before income taxes

      340         326    

Income tax provision

      104         124    
   

 

 

   

 

 

 

Net Income

      236         202    

Preferred stock dividend requirement of subsidiary

      3         3    
   

 

 

   

 

 

 

Income available for common shareholders

      $ 233         $ 199    
   

 

 

   

 

 

 

 

     

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

     

 

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Utility

The following presents the Utility’s operating results for the three months ended March 31, 2012 and 2011. Although the 2011 GRC and GT&S rate case were effective January 1, 2011, final decisions were not issued until the second quarter of 2011. Therefore, approximately $127 million of the total increase in authorized base revenues represents amounts authorized and recorded in the three months ended June 30, 2011, pertaining to the three months ended March 31, 2011.

Electric Operating Revenues

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

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

 

            Three months ended         
        March 31,        
 
(in millions)   2012     2011  

Revenues excluding passed-through costs

    $ 1,575        $ 1,414   

Revenues for recovery of passed-through costs

    1,196        1,202   
 

 

 

   

 

 

 

Total electric operating revenues

    $ 2,771        $ 2,616   
 

 

 

   

 

 

 

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $155 million, or 6%, in the three months ended March 31, 2012, as compared to the same period in 2011. Electric operating revenues, excluding costs passed through to customers, increased by $161 million, primarily due to an increase in base revenues as authorized in the 2011 GRC decision that was issued on May 5, 2011. Of the total increase in authorized base revenues, approximately $100 million represents base revenues that were authorized and recorded in the three months ended June 30, 2011 but pertained to the three months ended March 31, 2011. The increase was partially offset by a decrease in costs that are passed through to customers and do not impact net income, primarily due to decreases in the cost of electricity. (See “Cost of Electricity” below.)

The Utility’s future electric operating revenues, excluding passed-through costs, are expected to increase in the remainder of 2012 and in 2013 as authorized by the CPUC in the 2011 GRC. Additionally, the Utility’s future electric operating revenues will be impacted by the cost of electricity and other costs that are passed through to customers.

Cost of Electricity

The Utility’s cost of electricity includes the costs of power purchased from third parties, transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, and realized gains and losses on price risk management activities. The volume of power the Utility purchases is driven by load, the availability of the Utility’s own generation facilities, and the cost effectiveness of each source of electricity. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of electricity is passed through to customers. The Utility’s cost of electricity excludes non-fuel costs associated with operating the Utility’s own generation facilities and electric transmission system, which are included in operating and maintenance expense in the Condensed Consolidated Statements of Income.

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

 

         Three months ended    
    March 31,    
 
(in millions)    2012     2011  

Cost of purchased power

     $ 776        $ 821   

Fuel used in own generation facilities

     83        67   
  

 

 

   

 

 

 

Total cost of electricity

     $ 859        $ 888   
  

 

 

   

 

 

 

Average cost of purchased power per kWh (1)

     $ 0.075        $ 0.094   
  

 

 

   

 

 

 

Total purchased power (in kWh)

     10,290        8,779   
  

 

 

   

 

 

 

 

    

(1) Kilowatt-hour

    

 

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The Utility’s total cost of electricity decreased by $29 million, or 3%, in the three months ended March 31, 2012 as compared to the same period in 2011. This was caused by a decrease in the cost of purchased power resulting from a decline in the market price of electricity. The Utility increased the amount of power it purchased as a result of lower market prices. The decrease in the cost of electricity due to lower market prices was partially offset by an increase in the cost of fuel used in the Utility’s own electricity generation facilities as compared to the same period in 2011.

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

Natural Gas Operating Revenues

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

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

 

         Three months ended    
    March 31,    
 
(in millions)    2012     2011  

Revenues excluding passed-through costs

     $ 453        $ 404   

Revenues for recovery of passed-through costs

     416        576   
  

 

 

   

 

 

 

Total natural gas operating revenues

     $ 869        $ 980   
  

 

 

   

 

 

 

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $111 million, or 11%, in the three months ended March 31, 2012 as compared to the same period in 2011. This reflects a $160 million decrease in the costs which are passed through to customers and do not impact net income, primarily due to a decrease in the cost of natural gas. Natural gas operating revenues, excluding costs passed through to customers, increased by $49 million, primarily due to additional base revenues as authorized in the 2011 GT&S rate case decision issued in April 2011 and by the 2011 GRC decision issued in May 2011. Of the total increase in authorized base revenues, approximately $27 million represents base revenues that were authorized and recorded in the three months ended June 30, 2011, but pertained to the three months ended March 31, 2011.

The Utility’s operating revenues for natural gas transmission and storage services in 2013 and 2014 will reflect revenue increases that have been authorized by the CPUC in the 2011 GT&S rate case decision. Additionally, the Utility’s revenues for natural gas distribution services in 2013 (excluding passed-through costs) will reflect revenue increases authorized by the CPUC in the 2011 GRC decision. The Utility’s future gas operating revenues also will be impacted by changes in the cost of natural gas, natural gas throughput volume, and other factors.

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage, and transportation of natural gas. The cost of natural gas excludes the cost of transportation on the Utility’s pipeline, which is included in operating and maintenance expense in the Condensed Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of natural gas is passed through to customers.

 

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

 

        Three months ended    
    March 31,    
 
(in millions)   2012     2011  

Cost of natural gas sold

    $ 294        $ 461   

Transportation cost of natural gas sold

    49        47   
 

 

 

   

 

 

 

Total cost of natural gas

    $ 343        $ 508   
 

 

 

   

 

 

 

Average cost per Mcf (1) of natural gas sold

    $ 2.97        $ 4.52   
 

 

 

   

 

 

 

Total natural gas sold (in millions of Mcf)

    99        102   
 

 

 

   

 

 

 

 

   

(1)  One thousand cubic feet

   

The Utility’s total cost of natural gas decreased by $165 million, or 32%, in the three months ended March 31, 2012 as compared to the same period in 2011. The decrease was primarily due to a lower average market price of natural gas during 2012.

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

Operating and Maintenance

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

The Utility’s operating and maintenance expenses (including costs currently passed through to customers) increased by $140 million, or 11%, in the three months ended March 31, 2012, as compared to the same period in 2011. Total costs associated with natural gas matters increased by $112 million, from $51 million in the three months ended March 31, 2011 to $163 million in the three months ended March 31, 2012. The costs for 2012 included $104 million to validate pipeline operating pressures and perform other pipeline-related activities and also included a contribution of $70 million to the City of San Bruno. These expenses were partially offset by $11 million in insurance recoveries for third-party claims related to the San Bruno accident. (See “Natural Gas Matters” below.) The remaining increase in operating and maintenance expense was primarily attributable to additional environmental remediation costs of $75 million associated with the Hinkley natural gas compressor site (see “Environmental Matters” below), which was partially offset by a $48 million decrease in storm-related costs as compared to 2011. The change in costs passed through to customers was immaterial.

The Utility forecasts that it will incur pipeline-related costs associated with its natural gas pipeline system ranging from $450 million to $550 million in 2012 (including $104 million incurred during the three months ended March 31, 2012) which may not be recoverable through rates. (See “Natural Gas Matters – CPUC Rulemaking Proceeding” below.) Future operating and maintenance expense also will be affected by the ultimate amount incurred for third-party claims related to the San Bruno accident, including the amount of punitive damages, if any; related insurance recoveries; and the ultimate amount of civil or criminal penalties that may be imposed on the Utility.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization of plant and regulatory assets, and decommissioning expenses associated with fossil and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $94 million, or 19%, in the three months ended March 31, 2012, as compared to the same period in 2011 primarily due to capital additions and an increase in depreciation rates as authorized by the 2011 GRC and GT&S rate cases.

The Utility’s depreciation expense for future periods is expected to be impacted as a result of capital additions and the implementation of new depreciation rates as authorized by the CPUC in future GRC and GT&S rate cases, and by the FERC in transmission owner (“TO”) rate cases.

 

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Interest Income

The Utility’s interest income decreased by less than $1 million, in the three months ended March 31, 2012, as compared to the same period in 2011.

The Utility’s interest income in future periods will be primarily affected by changes in interest rates, changes in regulatory balancing accounts, and the balance of funds held in escrow pending resolution of the Chapter 11 disputed claims. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

Interest Expense

The Utility’s interest expense decreased by $3 million, or 2%, in the three months ended March 31, 2012, as compared to the same period in 2011, primarily due to an increase in allowance for funds used during construction (“AFUDC”) income related to debt.

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

Other Income, Net

The Utility’s other income, net increased by $6 million in the three months ended March 31, 2012, as compared to the same period in 2011. The increase was primarily due to an increase in AFUDC as the average balance of construction work in progress was higher in 2012 as compared to 2011.

Income Tax Provision

The Utility’s income tax provision decreased by $18 million, or 14%, in the three months ended March 31, 2012, as compared to the same period in 2011. The effective tax rates were 33% and 39% for 2012 and 2011, respectively. The effective tax rate for 2012 decreased as compared to 2011, mainly due to a benefit associated with a loss carryback recorded during the period and non tax-deductible penalties recorded in 2011 with no comparable amount in the current year.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations and make distributions to PG&E Corporation and preferred stockholders depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal load, volatility in energy commodity costs, collateral requirements related to price risk management activities, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure and to fund its capital expenditures. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. The CPUC authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The Utility has short-term borrowing authority of $4.0 billion, including $500 million that is restricted to certain contingencies.

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

 

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Revolving Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and the Utility’s commercial paper program at March 31, 2012:

 

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

PG&E Corporation

  May 2016      $ 300  (1)          $ -         $ -         $ -             $ 300       

Utility

  May 2016      3,000 (2)         367               1,145 (3)         1,488 (3)    
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revolving credit facilities

     $ 3,300            $ 367        $ -         $ 1,145            $ 1,788       
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

          

(1)  Includes a $100 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2)  Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for swingline loans.

(3)  The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

      

     

     

For the three months ended March 31, 2012, there were no borrowings on PG&E Corporation’s and the Utility’s revolving credit facilities. For the three months ended March 31, 2012, the average outstanding commercial paper balance was $1.2 billion and the maximum outstanding balance during the period was $1.4 billion.

The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes. In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. The $300 million revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. At March 31, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

2012 Financings

Utility

On April 16, 2012, the Utility issued $400 million principal amount of 4.45% Senior Notes due April 15, 2042. The proceeds from the issuance were used to repay a portion of outstanding commercial paper and for general corporate purposes.

On April 2, 2012, the Utility repurchased all of the $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.

During the three months ended March 31, 2012, the Utility received equity contributions of $385 million from PG&E Corporation to maintain the 52% equity component of the Utility’s CPUC-authorized capital structure.

PG&E Corporation

During the three months ended March 31, 2012, PG&E Corporation sold 1,934,310 shares of its common stock under the Equity Distribution Agreement executed in November 2011 for cash proceeds of $80 million, net of fees and commissions. At March 31, 2012, PG&E Corporation had the ability to issue an additional $219 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. In addition, during the three months ended March 31, 2012, PG&E Corporation issued 1,429,307 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercises of employee stock options for total cash proceeds of $53 million. PG&E Corporation used the cash proceeds for general corporate purposes and to contribute equity to the Utility.

 

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Future Financing and Liquidity Needs

The amount and timing of the Utility’s future financing and liquidity needs will depend on various factors, including:

 

   

the amount of cash generated through normal business operations;

 

   

the timing and amount of capital expenditures;

 

   

the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay (see Note 9 of the Notes to the Condensed Consolidated Financial Statements);

 

   

the timing and amount of payments, including punitive damages, if any, made to third parties in connection with the San Bruno accident, and the timing and amount of related insurance recoveries;

 

   

the timing and amount of penalties imposed on the Utility in connection with the investigations and enforcement matters pending against the Utility related to the San Bruno accident and the Utility’s natural gas pipeline system;

 

   

the timing and amount of costs associated with the Utility’s natural gas pipeline system, and the amount that is not recoverable through rates (see “Operating and Maintenance” above and “Natural Gas Matters” below);

 

   

the amount of future tax payments (see the discussion of the Tax Relief Act under “Utility – Operating Activities” below); and

 

   

the conditions in the capital and credit markets, and other factors.

PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. On April 20, 2012, the Utility filed an application to begin the cost of capital proceeding in which the CPUC will determine the Utility’s authorized capital structure and rates of return beginning on January 1, 2013. A change in the Utility’s authorized capital structure may impact PG&E Corporation’s and the Utility’s future debt and equity financing needs. (See the “2013 Cost of Capital Proceeding” discussion in “Regulatory Matters” below.)

Additionally, charges incurred by the Utility that are not recoverable through customer rates will increase the Utility’s equity needs. Additional equity issued by PG&E Corporation would increase the number of common shares outstanding, which could have a dilutive effect on future earnings per common share.

Dividends

The following table summarizes dividends paid by PG&E Corporation and the Utility during the three months ended March 31, 2012:

 

(in millions)       
PG&E Corporation       

Common stock dividends paid

     $ 182   

Utility

  

Common stock dividends paid

     $ 179   

Preferred stock dividends paid

     3   

On February 15, 2012, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, totaling $193 million, of which $187 million was paid on April 15, 2012 to shareholders of record on March 30, 2012. The remaining $6 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

On February 15, 2012, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on May 15, 2012, to shareholders of record on April 30, 2012.

As the Utility focuses on improving the safety and reliability of its natural gas and electric operations, and subject to the outcome of the matters described under “Natural Gas Matters” above, PG&E Corporation expects that its Board of Directors will maintain the current annual common stock dividend of $1.82 per share through 2012.

 

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Utility

Operating Activities

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

The Utility’s cash flows from operating activities for the three months ended March 31, 2012 and 2011 were as follows:

 

             Three months ended          
             March 31,           
(in millions)    2012