10-Q 1 q209_form10q.htm FORM 10-Q q209_form10q.htm


 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM 10-Q
(Mark One)
 
   
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2009
 
OR
   
[  ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
   
For the transition period from ___________ to __________
   
 
Commission
File
Number
_______________
Exact Name of
Registrant
as specified
in its charter
_______________
 
State or other
Jurisdiction of
Incorporation
______________
 
IRS Employer
Identification
Number
___________
       
1-12609
PG&E Corporation
California
94-3234914
1-2348
Pacific Gas and Electric Company
California
94-0742640
 
Pacific Gas and Electric Company
77 Beale Street
P.O. Box 770000
San Francisco, California 94177
________________________________________
PG&E Corporation
One Market, Spear Tower
Suite 2400
San Francisco, California 94105
______________________________________
Address of principal executive offices, including zip code
 
Pacific Gas and Electric Company
(415) 973-7000
________________________________________
PG&E Corporation
(415) 267-7000
______________________________________
Registrant's telephone number, including area code
 
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  [X] Yes     [  ] No
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). [X] Yes     [  ] No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
PG&E Corporation:
[X] Large accelerated filer
[  ] Accelerated Filer
 
[  ] Non-accelerated filer
[  ] Smaller reporting company
Pacific Gas and Electric Company:
[  ] Large accelerated filer
[  ] Accelerated Filer
 
[X] Non-accelerated filer
[  ] Smaller reporting company
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:
[  ] Yes [X] No
   
Pacific Gas and Electric Company:
[  ] Yes [X] No
 
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
   
Common Stock Outstanding as of July 31, 2009:
 
   
PG&E Corporation
370,687,258
Pacific Gas and Electric Company
264,374,809
   

 
 

 

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2009
TABLE OF CONTENTS

PART I.
FINANCIAL INFORMATION
PAGE
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
PG&E Corporation
 
   
3
   
4
   
6
 
Pacific Gas and Electric Company
 
   
8
   
9
   
11
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
Organization and Basis of Presentation
13
 
New and Significant Accounting Policies
13
 
Regulatory Assets, Liabilities, and Balancing Accounts
18
 
Debt
21
 
Equity
22
 
Earnings Per Share
23
 
Derivatives and Hedging Activities
24
 
Fair Value Measurements
27
 
Related Party Agreements and Transactions
30
 
Resolution of Remaining Chapter 11 Disputed Claims
31
 
Commitments and Contingencies
31
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
 
 
38
 
40
 
42
 
47
 
50
 
51
 
52
 
52
 
52
 
54
 
55
 
55
 
57
 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
58
CONTROLS AND PROCEDURES
58
 
PART II.
OTHER INFORMATION
 
LEGAL PROCEEDINGS
59
RISK FACTORS
59
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
59
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
60
OTHER INFORMATION
62
EXHIBITS
63


 
 

 

PART I.  FINANCIAL INFORMATION


 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
   
(Unaudited)
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in millions, except per share amounts)
 
2009
   
2008
   
2009
   
2008
 
Operating Revenues
                       
Electric
  $ 2,554     $ 2,645     $ 4,980     $ 5,159  
Natural gas
    640       933       1,645       2,152  
Total operating revenues
    3,194       3,578       6,625       7,311  
Operating Expenses
                               
Cost of electricity
    883       1,097       1,766       2,124  
Cost of natural gas
    188       487       745       1,262  
Operating and maintenance
    1,038       991       2,097       2,027  
Depreciation, amortization, and decommissioning
    429       419       848       821  
Total operating expenses
    2,538       2,994       5,456       6,234  
Operating Income
    656       584       1,169       1,077  
Interest income
    17       33       26       59  
Interest expense
    (178 )     (185 )     (359 )     (372 )
Other income, net
    22       5       40       10  
Income Before Income Taxes
    517       437       876       774  
Income tax provision
    125       140       240       250  
Net Income
    392       297       636       524  
Preferred stock dividend requirement of subsidiary
    4       4       7       7  
Income Available for Common Shareholders
  $ 388     $ 293     $ 629     $ 517  
Weighted Average Common Shares Outstanding, Basic
    368       356       366       355  
Weighted Average Common Shares Outstanding, Diluted
    369       357       367       356  
Net Earnings Per Common Share, Basic
  $ 1.03     $ 0.80     $ 1.68     $ 1.42  
Net Earnings Per Common Share, Diluted
  $ 1.02     $ 0.80     $ 1.67     $ 1.42  
Dividends Declared Per Common Share
  $ 0.42     $ 0.39     $ 0.84     $ 0.78  
   
See accompanying Notes to the Condensed Consolidated Financial Statements.
 


 
3

 

CONDENSED CONSOLIDATED BALANCE SHEETS

   
(Unaudited)
 
   
Balance At
 
(in millions)
 
June 30, 2009
   
December 31, 2008
 
ASSETS
           
Current Assets
           
Cash and cash equivalents
  $ 338     $ 219  
Restricted cash
    1,285       1,290  
Accounts receivable:
               
Customers (net of allowance for doubtful accounts of $77 million in 2009 and $76 million in 2008)
    1,481       1,751  
Accrued unbilled revenue
    757       685  
Regulatory balancing accounts
    1,304       1,197  
Inventories:
               
Gas stored underground and fuel oil
    107       232  
Materials and supplies
    204       191  
Income taxes receivable
    171       120  
Prepaid expenses and other
    781       718  
Total current assets
    6,428       6,403  
Property, Plant, and Equipment
               
Electric
    29,580       27,638  
Gas
    10,387       10,155  
Construction work in progress
    1,523       2,023  
Other
    13       17  
Total property, plant, and equipment
    41,503       39,833  
Accumulated depreciation
    (13,904 )     (13,572 )
Net property, plant, and equipment
    27,599       26,261  
Other Noncurrent Assets
               
Regulatory assets
    5,969       5,996  
Nuclear decommissioning funds
    1,740       1,718  
Other
    461       482  
Total other noncurrent assets
    8,170       8,196  
TOTAL ASSETS
  $ 42,197     $ 40,860  

See accompanying Notes to the Condensed Consolidated Financial Statements.

 
4

 

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

   
(Unaudited)
 
   
Balance At
 
 
(in millions, except share amounts)
 
June 30, 2009
   
December 31, 2008
 
LIABILITIES AND EQUITY
           
Current Liabilities
           
Short-term borrowings
  $ 743     $ 287  
Long-term debt, classified as current
    252       600  
Energy recovery bonds, classified as current
    378       370  
Accounts payable:
               
Trade creditors
    863       1,096  
Disputed claims and customer refunds
    1,552       1,580  
Regulatory balancing accounts
    611       730  
Other
    367       343  
Interest payable
    842       802  
Deferred income taxes
    424       251  
Other
    1,400       1,567  
Total current liabilities
    7,432       7,626  
Noncurrent Liabilities
               
Long-term debt
    9,933       9,321  
Energy recovery bonds
    1,031       1,213  
Regulatory liabilities
    3,838       3,657  
Pension and other postretirement benefits
    2,177       2,088  
Asset retirement obligations
    1,539       1,684  
Income taxes payable
    9       35  
Deferred income taxes
    3,816       3,397  
Deferred tax credits
    91       94  
Other
    2,133       2,116  
Total noncurrent liabilities
    24,567       23,605  
Commitments and Contingencies
               
Equity
               
Shareholders’ Equity
               
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued
    -       -  
Common stock, no par value, authorized 800,000,000 shares, issued 368,841,539 common and 673,491 restricted shares in 2009 and issued 361,059,116 common and 1,287,569 restricted shares in 2008
    6,219       5,984  
Reinvested earnings
    3,934       3,614  
Accumulated other comprehensive loss
    (207 )     (221 )
Total shareholders’ equity
    9,946       9,377  
Noncontrolling Interest – Preferred Stock of Subsidiary
    252       252  
Total equity
    10,198       9,629  
TOTAL LIABILITIES AND EQUITY
  $ 42,197     $ 40,860  

See accompanying Notes to the Condensed Consolidated Financial Statements.



 
5

 


 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
   
(Unaudited)
 
   
Six Months Ended
 
   
June 30,
 
(in millions)
 
2009
   
2008
 
Cash Flows from Operating Activities
           
Net income
  $ 636     $ 524  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, amortization, and decommissioning
    944       902  
Allowance for equity funds used during construction
    (47 )     (32 )
Deferred income taxes and tax credits, net
    377       346  
Other changes in noncurrent assets and liabilities
    (46 )     493  
Effect of changes in operating assets and liabilities:
               
Accounts receivable
    198       (68 )
Inventories
    113       (57 )
Accounts payable
    (143 )     121  
Income taxes receivable/payable
    161       21  
Regulatory balancing accounts, net
    (228 )     (351 )
Other current assets
    10       431  
Other current liabilities
    (224 )     (79 )
Other
    3       (3 )
Net cash provided by operating activities
    1,754       2,248  
Cash Flows from Investing Activities
               
Capital expenditures
    (2,077 )     (1,712 )
Proceeds from sale of assets
    5       12  
Decrease (increase) in restricted cash
    15       (7 )
Proceeds from nuclear decommissioning trust sales
    954       636  
Purchases of nuclear decommissioning trust investments
    (985 )     (665 )
Other
    7       -  
Net cash used in investing activities
    (2,081 )     (1,736 )
Cash Flows from Financing Activities
               
Net repayments under revolving credit facility
    -       (250 )
Net repayments of commercial paper, net of discount of $3 million in 2009 and $2 million in 2008
    (47 )     (114 )
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009
    499       -  
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $16 million in 2009 and $2 million in 2008
    884       598  
Long-term debt matured or repurchased
    (600 )     (454 )
Energy recovery bonds matured
    (174 )     (165 )
Common stock issued
    182       82  
Common stock dividends paid
    (286 )     (267 )
Other
    (12 )     10  
Net cash provided by (used in) financing activities
    446       (560 )
Net change in cash and cash equivalents
    119       (48 )
Cash and cash equivalents at January 1
    219       345  
Cash and cash equivalents at June 30
  $ 338     $ 297  



 
6

 


Supplemental disclosures of cash flow information
           
Cash received (paid) for:
           
Interest, net of amounts capitalized
  $ (298 )   $ (260 )
Income taxes, net
    201       60  
Supplemental disclosures of noncash investing and financing activities
               
Common stock dividends declared but not yet paid
  $ 155     $ 140  
Capital expenditures financed through accounts payable
    245       180  
Noncash common stock issuances
    39       6  
                 
See accompanying Notes to the Condensed Consolidated Financial Statements.
 


 
7

 


 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
   
(Unaudited)
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in millions)
 
2009
   
2008
   
2009
   
2008
 
Operating Revenues
                       
Electric
  $ 2,554     $ 2,645     $ 4,980     $ 5,159  
Natural gas
    640       933       1,645       2,152  
Total operating revenues
    3,194       3,578       6,625       7,311  
Operating Expenses
                               
Cost of electricity
    883       1,097       1,766       2,124  
Cost of natural gas
    188       487       745       1,262  
Operating and maintenance
    1,037       991       2,096       2,027  
Depreciation, amortization, and decommissioning
    429       418       848       820  
Total operating expenses
    2,537       2,993       5,455       6,233  
Operating Income
    657       585       1,170       1,078  
Interest income
    17       33       26       57  
Interest expense
    (166 )     (178 )     (339 )     (358 )
Other income, net
    15       7       36       26  
Income Before Income Taxes
    523       447       893       803  
Income tax provision
    132       134       263       254  
Net Income
    391       313       630       549  
Preferred stock dividend requirement
    4       4       7       7  
Income Available for Common Stock
  $ 387     $ 309     $ 623     $ 542  
   
See accompanying Notes to the Condensed Consolidated Financial Statements.
 




 
8

 

CONDENSED CONSOLIDATED BALANCE SHEETS

   
(Unaudited)
 
   
Balance At
 
 
(in millions)
 
June 30, 2009
   
December 31, 2008
 
ASSETS
           
Current Assets
           
Cash and cash equivalents
  $ 158     $ 52  
Restricted cash
    1,285       1,290  
Accounts receivable:
               
Customers (net of allowance for doubtful accounts of $77 million in 2009 and $76 million in 2008)
    1,481       1,751  
Accrued unbilled revenue
    757       685  
Related parties
    1       2  
Regulatory balancing accounts
    1,304       1,197  
Inventories:
               
Gas stored underground and fuel oil
    107       232  
Materials and supplies
    204       191  
Income taxes receivable
    120       25  
Prepaid expenses and other
    775       705  
Total current assets
    6,192       6,130  
Property, Plant, and Equipment
               
Electric
    29,580       27,638  
Gas
    10,387       10,155  
Construction work in progress
    1,523       2,023  
Total property, plant, and equipment
    41,490       39,816  
Accumulated depreciation
    (13,893 )     (13,557 )
Net property, plant, and equipment
    27,597       26,259  
Other Noncurrent Assets
               
Regulatory assets
    5,969       5,996  
Nuclear decommissioning funds
    1,740       1,718  
Related parties receivable
    26       27  
Income taxes receivable
    18       -  
Other
    382       407  
Total other noncurrent assets
    8,135       8,148  
TOTAL ASSETS
  $ 41,924     $ 40,537  

See accompanying Notes to the Condensed Consolidated Financial Statements.

 
9

 

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

   
(Unaudited)
 
   
Balance At
 
(in millions, except share amounts)
 
June 30, 2009
   
December 31, 2008
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
           
Current Liabilities
           
Short-term borrowings
  $ 743     $ 287  
Long-term debt, classified as current
    -       600  
Energy recovery bonds, classified as current
    378       370  
Accounts payable:
               
Trade creditors
    863       1,096  
Disputed claims and customer refunds
    1,552       1,580  
Related parties
    11       25  
Regulatory balancing accounts
    611       730  
Other
    366       325  
Interest payable
    836       802  
Income tax payable
    -       53  
Deferred income taxes
    430       257  
Other
    1,201       1,371  
Total current liabilities
    6,991       7,496  
Noncurrent Liabilities
               
Long-term debt
    9,585       9,041  
Energy recovery bonds
    1,031       1,213  
Regulatory liabilities
    3,838       3,657  
Pension and other postretirement benefits
    2,127       2,040  
Asset retirement obligations
    1,539       1,684  
Income taxes payable
    3       12  
Deferred income taxes
    3,859       3,449  
Deferred tax credits
    91       94  
Other
    2,093       2,064  
Total noncurrent liabilities
    24,166       23,254  
Commitments and Contingencies
               
Shareholders’ Equity
               
Preferred stock without mandatory redemption provisions:
               
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares
    145       145  
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares
    113       113  
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2009 and 2008
    1,322       1,322  
Additional paid-in capital
    2,986       2,331  
Reinvested earnings
    6,403       6,092  
Accumulated other comprehensive loss
    (202 )     (216 )
Total shareholders’ equity
    10,767       9,787  
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
  $ 41,924     $ 40,537  

See accompanying Notes to the Condensed Consolidated Financial Statements.



 
10

 


 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
   
(Unaudited)
 
   
Six Months Ended
 
   
June 30,
 
(in millions)
 
2009
   
2008
 
Cash Flows from Operating Activities
           
Net income
  $ 630     $ 549  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, amortization, and decommissioning
    932       902  
Allowance for equity funds used during construction
    (47 )     (32 )
Deferred income taxes and tax credits, net
    368       316  
Other changes in noncurrent assets and liabilities
    (34 )     480  
Effect of changes in operating assets and liabilities:
               
Accounts receivable
    199       (66 )
Inventories
    113       (57 )
Accounts payable
    (140 )     123  
Income taxes receivable/payable
    64       57  
Regulatory balancing accounts, net
    (228 )     (351 )
Other current assets
    10       429  
Other current liabilities
    (220 )     (73 )
Other
    3       (3 )
Net cash provided by operating activities
    1,650       2,274  
Cash Flows from Investing Activities
               
Capital expenditures
    (2,077 )     (1,712 )
Proceeds from sale of assets
    5       12  
Decrease (increase) in restricted cash
    15       (7 )
Proceeds from nuclear decommissioning trust sales
    954       636  
Purchases of nuclear decommissioning trust investments
    (985 )     (665 )
Net cash used in investing activities
    (2,088 )     (1,736 )
Cash Flows from Financing Activities
               
Net repayments under revolving credit facility
    -       (250 )
Net repayments of commercial paper, net of discount of $3 million in 2009 and $2 million in 2008
    (47 )     (114 )
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009
    499       -  
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008
    538       598  
Long-term debt matured or repurchased
    (600 )     (454 )
Energy recovery bonds matured
    (174 )     (165 )
Preferred stock dividends paid
    (7 )     (7 )
Common stock dividends paid
    (312 )     (284 )
Equity contribution
    653       50  
Other
    (6 )     16  
Net cash provided by (used in) financing activities
    544       (610 )
Net change in cash and cash equivalents
    106       (72 )
Cash and cash equivalents at January 1
    52       141  
Cash and cash equivalents at June 30
  $ 158     $ 69  

 
11

 


Supplemental disclosures of cash flow information
           
Cash received (paid) for:
 
 
       
Interest, net of amounts capitalized
  $ (286 )   $ (246 )
Income taxes, net
    70       60  
Supplemental disclosures of noncash investing and financing activities
               
Capital expenditures financed through accounts payable
  $ 245     $ 180  
                 
See accompanying Notes to the Condensed Consolidated Financial Statements.
 


 
12

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)


PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses.  PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California.  The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage.  The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”).

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility.  Therefore, the Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries, as well as the accounts of variable interest entities for which the Utility absorbs a majority of the risk of loss or gain.  All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements.  PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial condition and results of operations for the periods presented.  The information at December 31, 2008 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 Annual Report on Form 10-K for the year ended December 31, 2008.  PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2008, together with the information incorporated by reference into such report, is referred to in this quarterly report on Form 10-Q as the “2008 Annual Report.”

The accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.  Any significant changes to those policies or new significant policies are described in Note 2 below.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict.  Some of the more critical estimates and assumptions, discussed further below in these notes, relate to the Utility’s regulatory assets and liabilities, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters.  Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable.  A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

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


Significant Accounting Policies

Consolidation of Variable Interest Entities

PG&E Corporation and the Utility are required to consolidate any entity in which it has control.  In most cases, control can be determined based on majority ownership in accordance with the provisions of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” (“ARB 51”), as interpreted by other standards.  However, for certain entities control is difficult to discern based on voting equity interests only.  These entities are referred to as variable interest entities (“VIEs”) based on Financial Accounting Standards Board (“FASB”) Interpretation No. (“FIN”) 46 (revised December 2003), “Consolidation of Variable Interest Entities.”  Characteristics of a VIE include equity investment at risk that is not sufficient to permit the entity to finance its activities without additional subordinated financial support from other parties or equity investors that lack any of the characteristics of a controlling financial interest.  The primary beneficiary, defined as the entity that absorbs a majority of the expected losses of the VIE, receives a majority of the expected residual returns of the VIE, or both, is required to consolidate the VIE.
 
The Utility’s exposure to VIEs relates to entities with which it has a power purchase agreement.  For those entities, the Utility commonly assesses operational risk, commodity price risk, credit risk, and tax benefit risk on a qualitative basis to determine whether the Utility is a primary beneficiary of the entity and required to consolidate the entity.  This qualitative assessment also typically involves comparing the contract life to the economic life of the plant to consider the significance of the commodity price risk that the Utility might absorb.  As of June 30, 2009, the Utility is not the primary beneficiary of any entities with which it has power purchase agreements.

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

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

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

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

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

 
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Asset Retirement Obligations

PG&E Corporation and the Utility account for ARO in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) and FIN 47, “Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143.”  SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made.  In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset.

A reconciliation of the changes in the ARO liability is as follows:

 (in millions)
     
ARO liability at December 31, 2008
  $ 1,684  
Revision in estimated cash flows
    (172
Accretion
    49  
Liabilities settled
    (22
ARO liability at June 30, 2009
  $ 1,539  

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

Share-Based Compensation

The following tables provide a summary of total compensation expense for PG&E Corporation and the Utility for share-based compensation awards for the three and six months ended June 30, 2009 and 2008:

   
PG&E Corporation
   
Utility
 
   
Three Months Ended
June 30,
   
Three Months Ended
June 30,
 
(in millions)
 
2009
   
2008
   
2009
   
2008
 
Stock options
  $ -     $ -     $ -     $ -  
Restricted stock
    3       5       2       3  
Restricted stock units (1)
    1       -       1       -  
Performance shares
    6       12       5       8  
Total compensation expense (pre-tax)
  $ 10     $ 17     $ 8     $ 11  
Total compensation expense (after-tax)
  $ 6     $ 10     $ 5     $ 7  
                                 
(1) Beginning January 1, 2009, PG&E Corporation awarded restricted stock units (“RSUs”) instead of restricted stock as permitted by the PG&E Corporation 2006 Long-Term Incentive Plan. RSUs are hypothetical shares of stock that will generally vest in 20% increments on the first business day of March in 2010, 2011, and 2012, with the remaining 40% vesting on the first business day of March 2013. Each vested RSU is settled for one share of PG&E Corporation common stock. Additionally, upon settlement, RSUs recipients receive payment for the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.
 

   
PG&E Corporation
   
Utility
 
   
Six Months Ended
June 30,
   
Six Months Ended
June 30,
 
(in millions)
 
2009
   
2008
   
2009
   
2008
 
Stock options
  $ -     $ 1     $ -     $ 1  
Restricted stock
    5       14       4       9  
Restricted stock units (1)
    7       -       4       -  
Performance shares
    22       8       15       4  
Total compensation expense (pre-tax)
  $ 34     $ 23     $ 23     $ 14  
Total compensation expense (after-tax)
  $ 20     $ 14     $ 14     $ 8  
                                 
(1) Beginning January 1, 2009, PG&E Corporation awarded RSUs instead of restricted stock as permitted by the PG&E Corporation 2006 Long-Term Incentive Plan. RSUs are hypothetical shares of stock that will generally vest in 20% increments on the first business day of March in 2010, 2011, and 2012, with the remaining 40% vesting on the first business day of March 2013. Each vested RSU is settled for one share of PG&E Corporation common stock. Additionally, upon settlement, RSUs recipients receive payment for the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.
 

 
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Pension and Other Postretirement Benefits

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

The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three and six months ended June 30, 2009 and 2008 are as follows:
 
   
Pension Benefits
   
Other Benefits
 
   
Three Months Ended
June 30,
   
Three Months Ended
June 30,
 
(in millions)
 
2009
   
2008
   
2009
   
2008
 
Service cost for benefits earned
  $ 67     $ 59     $ 7     $ 7  
Interest cost
    155       144       21       20  
Expected return on plan assets
    (145 )     (175 )     (17 )     (24 )
Amortization of transition obligation
    -       -       7       7  
Amortization of prior service cost
    12       12       4       4  
Amortization of unrecognized (gain) loss
    24       -       1       (4 )
     Net periodic benefit cost
    113       40       23       10  
     Less: transfer to regulatory account (1)
    (72 )     1       -       -  
     Total
  $ 41     $ 41     $ 23     $ 10  
                                 
(1) For the three months ended June 30, 2009 and 2008, the Utility recorded $72 million as an addition to the existing pension regulatory asset and $1 million as an addition to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.
 

   
Pension Benefits
   
Other Benefits
 
   
Six Months Ended
June 30,
   
Six Months Ended
June 30,
 
(in millions)
 
2009
   
2008
   
2009
   
2008
 
Service cost for benefits earned
  $ 133     $ 118     $ 15     $ 15  
Interest cost
    310       287       42       40  
Expected return on plan assets
    (290 )     (349 )     (34 )     (47 )
Amortization of transition obligation
    -       -       13       12  
Amortization of prior service cost
    23       24       8       8  
Amortization of unrecognized (gain) loss
    49       -       2       (8 )
     Net periodic benefit cost
    225       80       46       20  
     Less: transfer to regulatory account (1)
    (143 )     2       -       -  
     Total
  $ 82     $ 82     $ 46     $ 20  
                                 
(1) For the six months ended June 30, 2009 and 2008, the Utility recorded $143 million as an addition to the existing pension regulatory asset and $2 million as an addition to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.
 
 
There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three and six months ended June 30, 2009 and 2008.
 
Adoption of New Accounting Pronouncements

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

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

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

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

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

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

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

On January 1, 2009, PG&E Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”).  EITF 08-5 clarifies the unit of account in determining the fair value of a liability under SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (“SFAS No. 107”), or SFAS No. 133.  Specifically, it requires an entity to exclude any third-party credit enhancements that are issued with, and are inseparable from, a debt instrument from the fair value measurement of that debt instrument.  Adoption of EITF 08-5 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Equity Method Investment Accounting

On January 1, 2009, PG&E Corporation and the Utility adopted EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”).  EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost.  Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than SFAS No. 141 (revised 2007), “Business Combinations.”  However, the investor in an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the investor’s share of the investee’s net assets exceeds the investor’s initial costs.  An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment.  Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings.  Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.
 
Subsequent Events

On June 30, 2009, PG&E Corporation and the Utility adopted SFAS No. 165, “Subsequent Events” (“SFAS No. 165”).  SFAS No. 165 does not significantly change the prior accounting practice for subsequent events except for the requirement to disclose the date through which an entity has evaluated subsequent events and the basis for that date.  PG&E Corporation and the Utility have evaluated material subsequent events through August 5, 2009, the issue date of PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.  Other than this disclosure, adoption of SFAS No. 165 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Interim Disclosures about Fair Value of Financial Instruments

On June 30, 2009, PG&E Corporation and the Utility adopted FASB Staff Position (“FSP”) SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This FSP amends SFAS No. 107 and Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” to require disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods.  An entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and where the carrying amount is classified in the Condensed Consolidated Balance Sheets.  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)

Recognition and Presentation of Other-Than-Temporary Impairments

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP SFAS 115-2 and SFAS 124-2”).  Under this FSP, to assess whether an other-than-temporary impairment exists for a debt security, an entity must (1) evaluate the likelihood of liquidating the debt security prior to recovering its cost basis and (2) determine if any impairment of the debt security is related to credit losses.  In addition, this FSP requires enhanced disclosures of other-than-temporary impairments on debt and equity securities in the financial statements.  Recognition and measurement guidance for other-than-temporary impairments of equity securities is not amended by this FSP.   Adoption of FSP SFAS 115-2 and SFAS 124-2 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.
 
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Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP SFAS 157-4”).  This FSP amends SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), to provide guidance on estimating fair value when the volume or the level of activity for an asset or a liability has significantly decreased or when transactions are not orderly, when compared with normal market conditions.  In particular, this FSP calls for adjustments to quoted prices or historical transaction data when estimating fair value in such circumstances.  Guidance to identify such circumstances is also provided.  Furthermore, this FSP requires fair value measurement disclosures made pursuant to SFAS No. 157 to be categorized by major security type, i.e., based on the nature and risks of the security.  (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)  Other than this change, adoption of FSP SFAS 157-4 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Accounting Pronouncements Issued But Not Yet Adopted

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP SFAS 132(R)-1”).  FSP SFAS 132(R)-1 amends and expands the disclosure requirements of SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits — an amendment of FASB Statements No. 87, 88, and 106.”  An entity is required to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets.  Additionally, quantitative disclosures are required showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets that are measured using significant unobservable inputs.  FSP SFAS 132(R)-1 is effective prospectively for PG&E Corporation and the Utility for the annual period ending December 31, 2009 and for subsequent annual periods.  PG&E Corporation and the Utility will include the expanded disclosures described above in PG&E Corporation’s and the Utility’s Consolidated Financial Statements for such annual periods.
 
Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140

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

Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”).  SFAS No. 167 amends FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities” (“FIN 46R”), regarding when and how to determine, or re-determine, whether an entity is a VIE.  In addition, SFAS No. 167 replaces FIN 46R’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach.  Furthermore, SFAS No. 167 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE.  SFAS No. 167 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010.  PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 167.

The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles - a replacement of FASB Statement No. 162

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles - a replacement of FASB Statement No. 162” (“SFAS No. 168”).  SFAS No. 168 nullifies SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” and defines authoritative GAAP for nongovernmental entities to be only comprised of the FASB Accounting Standards CodificationTM (“Codification”) and, for SEC registrants, guidance issued by the SEC.  The Codification is a reorganization and compilation of all then-existing authoritative GAAP for nongovernmental entities, except for guidance issued by the SEC.  PG&E Corporation and the Utility anticipate that adopting SFAS No. 168 will only change the referencing convention of GAAP in PG&E Corporation’s and the Utility’s Notes to the Condensed Consolidated Financial Statements.  SFAS No. 168 is effective prospectively for PG&E Corporation and the Utility beginning on July 1, 2009.

 
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The Utility accounts for the financial effects of regulation in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”), which applies to regulated entities whose rates are designed to recover the cost of providing service.  SFAS No. 71 applies to all of the Utility’s operations.

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

To the extent portions of the Utility’s operations cease to be subject to SFAS No. 71, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
 
Regulatory Assets

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

   
Balance At
 
 
(in millions)
 
June 30,
2009
   
December 31,
2008
 
Pension benefits
  $ 1,696     $ 1,624  
Energy recovery bonds
    1,322       1,487  
Deferred income tax
    913       847  
Utility retained generation
    772       799  
Price risk management
    410       362  
Environmental compliance costs
    392       385  
Unamortized loss, net of gain, on reacquired debt
    213       225  
Regulatory assets associated with plan of reorganization
    88       99  
Contract termination costs
    75       82  
Other
    88       86  
Total long-term regulatory assets
  $ 5,969     $ 5,996  

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized in accordance with GAAP and amounts recognized for ratemaking purposes, which also includes amounts that otherwise would be fully recorded to Accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets in accordance with SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

The regulatory asset for energy recovery bonds (“ERBs”) represents the refinancing of the settlement regulatory asset established under the December 19, 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility’s Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”) proceeding (“Chapter 11 Settlement Agreement”).  The regulatory asset is amortized over the life of the bond, consistent with the period over which the related billed revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.

The regulatory assets for deferred income tax represent deferred income tax benefits previously passed through to customers and are offset by deferred income tax liabilities.  Tax benefits to customers have been passed through, as the CPUC requires utilities under its jurisdiction to follow the “flow-through” method of passing certain tax benefits to customers.  The “flow-through” method ignores the effect of deferred taxes on rates.  Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 years.

In connection with the Chapter 11 Settlement Agreement in 2004, the Utility recognized a one-time noncash gain of $1.2 billion related to the recovery of the Utility’s retained generation regulatory assets.  The Utility amortizes the individual components of these regulatory assets consistent with the period over which the related revenues are recognized over the respective lives of the underlying generation facilities.  The weighted average remaining life of the assets is 16 years.

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

 
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The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation liabilities that the Utility expects to recover in future rates as actual remediation costs are incurred.  The Utility expects to recover these costs over the next 30 years.  (See Note 11 of the Notes to the Condensed Consolidated Financial Statements.)

The regulatory assets for unamortized loss, net of gain, on reacquired debt represents costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs.  These costs are expected to be recovered over the remaining original amortization period of the reacquired debt over the next 17 years, and these costs will be fully recovered by 2026.
 
Regulatory assets associated with the Utility’s plan of reorganization include costs incurred in financing the Utility’s plan of reorganization under Chapter 11 and costs to oversee the environmental enhancement projects of the Pacific Forest and Watershed Land Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization.  The Utility expects to recover these costs over the remaining periods ranging from 4 to 25 years, and these costs should be fully recovered by 2034.

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

At June 30, 2009, “Other” primarily consisted of regulatory assets relating to ARO costs recorded in accordance with GAAP, which are probable of future recovery through the ratemaking process, as well as cost associated with the Steam Generator Replacement Project at the Utility’s Diablo Canyon Power Plant, as approved by the CPUC for future recovery.  At December 31, 2008, “Other” primarily consisted of regulatory assets relating to ARO costs, as well as scheduling coordinator costs that the Utility incurred beginning in 1998 in its capacity as scheduling coordinator for its then existing wholesale transmission customers.

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

Current Regulatory Assets

At June 30, 2009 and December 31, 2008, the Utility had current regulatory assets of $547 million and $355 million, respectively, consisting primarily of the current component of price risk management regulatory assets.  Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of less than one year.  (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)  Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.

Regulatory Liabilities

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

   
Balance At
 
 
(in millions)
 
June 30,
2009
   
December 31,
2008
 
Cost of removal obligation
  $ 2,841     $ 2,735  
Public purpose programs
    445       442  
Recoveries in excess of asset retirement obligation
    348       226  
Price risk management
    82       81  
Gateway Generating Station
    66       67  
Environmental remediation insurance recoveries
    38       52  
Other
    18       54  
Total long-term regulatory liabilities
  $ 3,838     $ 3,657  

Cost of removal regulatory liabilities represent revenues collected for asset removal costs that the Utility expects to incur in the future, less actual costs incurred.

Public purpose program regulatory liabilities represent revenues designated for public purpose program costs that are expected to be incurred in the future.  Public purpose program regulatory liabilities include the California Solar Initiative program’s revenue that was collected from customers to pay for costs that the Utility expects to incur in the future to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

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

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

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

Regulatory liabilities associated with environmental remediation insurance recoveries are refunded to customers as a reduction to rates, as costs are incurred for hazardous substance remediation.

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

Current Regulatory Liabilities

At June 30, 2009 and December 31, 2008, the Utility had current regulatory liabilities of $278 million and $313 million, respectively, primarily consisting of regulatory liabilities for the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates.  Current regulatory liabilities are included in Current Liabilities – Other in the Condensed Consolidated Balance Sheets.

Regulatory Balancing Accounts

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period.  The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs.  Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets.  Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities.  The CPUC does not allow the Utility to offset regulatory balancing account assets against regulatory balancing account liabilities in the Condensed Consolidated Balance Sheets.

The Utility’s current regulatory balancing accounts represent the amount expected to be refunded to or received from the Utility’s customers through authorized rate adjustments within the next 12 months.  Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in Other Noncurrent Assets – Regulatory assets and Noncurrent Liabilities – Regulatory liabilities in the Condensed Consolidated Balance Sheets.
 
Current Regulatory Balancing Accounts, net

   
Receivable (Payable)
 
   
Balance At
 
(in millions)
 
June 30, 2009
   
December 31, 2008
 
Utility generation
  $ 493     $ 164  
Distribution revenue adjustment mechanism
    249       40  
Modified transition cost
    220       214  
Transmission revenue
    156       173  
Energy resource recovery
    1       384  
DWR power charge collection
    (92 )     (83 )
Public purpose programs
    (138 )     (263 )
Energy recovery bonds
    (164 )     (231 )
Other
    (32 )     69  
Total regulatory balancing accounts, net
  $ 693     $ 467  

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 Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales.  During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates.  During the warmer months of summer, the under-collection generally decreases due to higher rates and electric usage that cause an increase in generation revenues.
 
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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 recognizes revenue evenly over the year even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales.  During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates.  During the warmer months of summer, the under-collection generally decreases due to higher rates and electric usage that cause an increase in distribution revenues.

The modified transition cost balancing account is used to track the recovery of ongoing competition transition charges (“CTC”), primarily consisting of above-market costs associated with power purchase contracts that were being collected in CPUC-approved rates on or before December 20, 1995 (including costs incurred by the Utility with CPUC approval to restructure, renegotiate, or terminate the contracts).  The recovery of ongoing CTC can continue for the term of the contract.  The amount of above-market costs associated with the eligible power purchase contracts is determined each year in the energy resource recovery account (“ERRA”) forecast proceeding by comparing the ongoing CTC-eligible contract costs to a CPUC-approved market benchmark to determine whether there are stranded costs associated with these contracts.

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

The Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs through the ERRA.  The Utility files annual forecasts of energy procurement costs that it expects to incur during the following year, and rates are set to recover such expected costs.  The ERRA tracks actual electric costs, as well as fuel and energy procurement costs, excluding the costs incurred under contracts entered into by the California Department of Water Resources (“DWR”) to purchase energy allocated to the Utility’s customers.
 
The DWR power charge collection balancing account tracks the difference between the amounts collected from customers by the Utility on behalf of the DWR, and the amounts remitted to the DWR for energy delivered to customers on behalf of the Utility.

The public purpose program balancing accounts primarily track the recovery of the authorized public purpose program revenue requirement and the actual cost of such programs.  The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs.  A refund of $230 million from the California Energy Commission for unspent renewable program funding previously collected is being returned to customers through lower rates throughout 2009.

The energy recovery bonds balancing account records certain benefits and costs associated with ERBs that are provided to, or received from, customers.  In addition, this account ensures that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility after the second series of ERBs were issued.

At June 30, 2009, “Other” primarily consisted of the gas purchase and distribution balancing accounts that track actual gas costs and recoveries, as well as the difference between the authorized and recovered gas base revenue requirement.  At December 31, 2008, “Other” consisted of the customer energy efficiency (“CEE”) incentive account that records any incentive awards earned by the Utility for implementing CEE programs, as well as a FERC-mandated balancing account for reliability services that ensures the participating transmission owner neither under-recovers nor over-recovers the reliability services costs from customers.


PG&E Corporation

Senior Notes

On March 12, 2009, PG&E Corporation issued $350 million principal amount of 5.75% Senior Notes due April 1, 2014.

Credit Facility

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

Utility

Senior Notes

On March 6, 2009, the Utility issued $550 million principal amount of 6.25% Senior Notes due March 1, 2039.

On June 11, 2009, the Utility issued $500 million principal amount of Floating Rate Senior Notes due June 10, 2010.  The interest rate for the Floating Rate Senior Notes is equal to the three-month London Interbank Offered Rate plus 0.95% and will reset quarterly beginning on September 10, 2009.  At June 30, 2009, the interest rate on the Floating Rate Senior Notes was 1.60%.
 
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Credit Facility and Short-Term Borrowings

At June 30, 2009, the Utility had $303 million of letters of credit outstanding under the Utility’s $1.94 billion revolving credit facility.  The Utility amended its revolving credit facility on April 27, 2009 to remove Lehman Bank as a lender.  Prior to the amendment, the total borrowing capacity under the revolving credit facility was $2.0 billion, including a commitment from Lehman Bank that represented $60 million, or 3%, of the total.

The revolving credit facility also provides liquidity support for commercial paper offerings.  At June 30, 2009, the Utility had $243 million of commercial paper outstanding at an average yield of 0.68%.

Recovery Bonds

PG&E Energy Recovery Funding LLC (“PERF”), a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion in 2005.  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.  The total amount of ERB principal outstanding was $1.4 billion at June 30, 2009.

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


PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2009 were as follows:

   
PG&E Corporation
   
Utility
 
(in millions)
 
Total
Equity
   
Total
Shareholders’ Equity
 
Balance at December 31, 2008
  $ 9,629     $ 9,787  
Net income
    636       630  
Common stock issued
    221       -  
Share-based compensation amortization
    12       -  
Common stock dividends declared and paid
    (154 )     (312 )
Common stock dividends declared but not yet paid
    (155 )     -  
Preferred stock dividend requirement
    -       (7 )
Preferred stock dividend requirement of subsidiary
    (7 )     -  
Tax benefit from employee stock plans
    2       2  
Other comprehensive income
    14       14  
Equity contribution
    -       653  
Balance at June 30, 2009
  $ 10,198     $ 10,767  

For the six months ended June 30, 2009, PG&E Corporation contributed equity of $653 million to the Utility in order to maintain the 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

Dividends

During the six months ended June 30, 2009, the Utility paid common stock dividends totaling $312 million to PG&E Corporation.

During the six months ended June 30, 2009, PG&E Corporation paid common stock dividends totaling $286 million, net of $11 million that was reinvested in additional shares of common stock by participants in the PG&E Corporation Dividend Reinvestment and Stock Purchase Plan.  On June 17, 2009, the Board of Directors of PG&E Corporation declared a dividend of $0.42 per share, totaling $155 million, which was paid on July 15, 2009 to shareholders of record on June 30, 2009.

During the six months ended June 30, 2009, the Utility paid cash dividends totaling $7 million to holders of its outstanding series of preferred stock.  On June 17, 2009, the Board of Directors of the Utility declared a cash dividend totaling $3 million on its outstanding series of preferred stock, payable on August 15, 2009 to shareholders of record on July 31, 2009.

 
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Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, by dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period.  In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities.  PG&E Corporation’s Convertible Subordinated Notes are entitled to receive pass-through dividends and meet the criteria of a participating security.  All PG&E Corporation’s participating securities participate in dividends on a 1:1 basis with shares of common stock.
 
The following is a reconciliation of PG&E Corporation’s net income and weighted average shares of common stock outstanding for calculating basic and diluted net income per share:

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in millions, except per share amounts)
 
2009
   
2008
   
2009
   
2008
 
Income Available for Common Shareholders
  $ 388     $ 293     $ 629     $ 517  
Less: distributed earnings to common shareholders
    155       139       309       278  
Undistributed earnings
  $ 233     $ 154     $ 320     $ 239  
Common shareholders earnings
                               
Basic
                               
Distributed earnings to common shareholders
  $ 155     $ 139     $ 309     $ 278  
Undistributed earnings allocated to common shareholders
    223       146       306       227  
Total common shareholders earnings, basic
  $ 378     $ 285     $ 615     $ 505  
Diluted
                               
Distributed earnings to common shareholders
  $ 155     $ 139     $ 309     $ 278  
Undistributed earnings allocated to common shareholders
    223       146       306       227  
Total common shareholders earnings, diluted
  $ 378     $ 285     $ 615     $ 505  
Weighted average common shares outstanding, basic
    368       356       366       355  
9.50% Convertible Subordinated Notes
    17       19       17       19  
Weighted average common shares outstanding and participating securities, basic
    385       375       383       374  
Weighted average common shares outstanding, basic
    368       356       366       355  
Employee share-based compensation
    1       1       1       1  
Weighted average common shares outstanding, diluted
    369       357       367       356  
9.50% Convertible Subordinated Notes
    17       19       17       19  
Weighted average common shares outstanding and participating securities, diluted
    386       376       384       375  
Net earnings per common share, basic
                               
Distributed earnings, basic (1)
  $ 0.42     $ 0.39     $ 0.84     $ 0.78  
Undistributed earnings, basic
    0.61       0.41       0.84       0.64  
Total
  $ 1.03     $ 0.80     $ 1.68     $ 1.42  
Net earnings per common share, diluted
                               
Distributed earnings, diluted
  $ 0.42     $ 0.39     $ 0.84     $ 0.78  
Undistributed earnings, diluted
    0.60       0.41       0.83       0.64  
Total
  $ 1.02     $ 0.80     $ 1.67     $ 1.42  
   
(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding.
 
 
Stock options to purchase 39,049 and 26,592 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three and six months ended June 30, 2009, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these periods.  Stock options to purchase 7,285 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three and six months ended June 30, 2008, respectively.
 
PG&E Corporation reflects the preferred dividends of subsidiaries as other expense for computation of both basic and diluted EPS.

 
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Use of Derivative Instruments

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

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

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

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

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

·  
futures contracts that are exchange-traded contracts that commit the Utility to purchase a commodity or make a cash settlement at a specified price and future date.

  These instruments are not held for speculative purposes and are subject to certain limitations imposed by regulatory requirements.  These instruments enable the Utility to reduce the volatility associated with electricity and natural gas costs incurred by the Utility and charged to its customers through rates.

Commodity-Related Price Risk

As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers in rates all costs related to commodity-related price risk-related derivative instruments.  Therefore, in accordance with the provisions of SFAS No. 71, all unrealized gains and losses associated with the fair value of these derivative instruments, including those designated as cash flow hedges, are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.  Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

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

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities.  The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments under SFAS No. 133 and, therefore, are recorded at fair value within the Condensed Consolidated Balance Sheets.  However, derivative instruments that are eligible for the normal purchase and normal sales exception under SFAS No. 133 are not required to be recorded at fair value.  Derivative instruments that require the physical delivery of commodities, where quantities purchased are expected to be used by the Utility in the normal course of business and meet certain other criteria, are eligible for the normal purchase and normal sales exception.  The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms.  In order to reduce the cash flow risk associated with fluctuating electricity prices, the Utility has entered into financial swap contracts to effectively fix the price of future purchases under those power purchase agreements.  These financial swaps are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.  Some of these contracts have been designated as cash flow hedges in accordance with the requirements of SFAS No. 133.

Electric Transmission Congestion Revenue Rights

The CAISO-controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints.  As a result, the Utility is subject to financial risk associated with the cost of transmission congestion.  The CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Update on April 1, 2009.  The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new day-ahead market.  The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve), and an auction phase (in which CRRs are priced at market and available to all market participants).  In the second quarter of 2009, the Utility acquired CRRs through both allocation and auction.
 
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CRRs are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.

Natural Gas Procurement (Electric Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts.  In order to reduce the risk to future cash flows associated with fluctuating natural gas prices, the Utility purchases financial instruments such as futures, swaps, and options.  These financial instruments are considered derivative instruments and are shown at fair value within the Condensed Consolidated Balance Sheets.

Natural Gas Procurement (Small Commercial and Residential Customers)

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

The Utility has entered into various financial instruments, such as financial swap and option contracts, intended to reduce the cash flow variability associated with fluctuating natural gas purchase prices.  The Utility manages its winter exposure to natural gas prices in accordance with its CPUC-approved annual core portfolio hedging implementation plan.  These contracts are considered derivative instruments that are recorded at fair value within the Condensed Consolidated Balance Sheets.  A portion of these contracts have been designated as cash flow hedges in accordance with the requirements of SFAS No. 133.
 
Other Risk

At June 30, 2009, PG&E Corporation’s Convertible Subordinated Notes had an outstanding value of $252 million and are scheduled to mature on June 30, 2010.   The holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion prices.  The dividend participation rights associated with the Convertible Subordinated Notes are considered to be embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements.  Changes in fair value of the dividend participation rights are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as non-operating expense or income (in Other income, net).

Volume of Derivative Activity

At June 30, 2009, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts were as follows:
 
     
Contract Volumes (1)
 
Underlying Product
Instruments
 
Less Than 1 Year
   
1 Year But Less Than 3 Years
   
3 Years But Less Than 5 Years
   
Over 5 Years (2)
 
Natural Gas (3) (MMBtus (4))
Forwards, Futures, and Swaps
    305,796,371       172,333,439       21,545,000       -  
 
Options
    146,042,523       105,737,360       -       -  
                                   
Electricity (Megawatt-hours)
Forwards, Futures, and Swaps
    3,508,656       7,500,504       5,535,512       5,408,479  
 
Options
    28,076       11,450       70,584       597,908  
 
Congestion Revenue Rights
    55,943,502       59,684,359       59,618,554       116,386,405  
                                   
PG&E Corporation Equity Shares
 
Dividend Participation Rights
    16,702,194       -       -       -  
                                   
(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.
 
(2) Derivatives in this category expire between 2014 and 2022.
 
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.
 
(4) Million British Thermal Units.
 

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists.  In accordance with the provisions of FSP on FIN 39, “Amendment of FIN 39” (“FIN 39-1”), which was adopted January 1, 2008, the net balances include outstanding cash collateral associated with derivative positions.
 
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At June 30, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

   
Gross Balances (1)
                   
(in millions)
 
Derivatives Designated as Cash Flow Hedges (2)
   
Derivatives Not Designated as Hedges
   
Total
   
Netting (3)