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 1934For
      the quarterly period ended September 30, 2009
              
              OR[  ]
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
              SECURITIES
      EXCHANGE ACT OF 1934For
      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
            94-32349141-2348
            Pacific
      Gas and Electric Company
            California
            94-0742640Pacific
      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 codePacific
      Gas and Electric Company
              (415)
      973-7000
              ________________________________________
            PG&E
      Corporation
              (415)
      267-7000
              ______________________________________Registrant's
      telephone number, including area codeIndicate
      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     [  ]
      NoIndicate
      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     [  ]
      NoIndicate
      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 companyPacific
      Gas and Electric Company:
            [  ]Large
      accelerated filer
            [  ]Accelerated Filer[X]Non-accelerated
      filer
            [  ]Smaller
      reporting companyIndicate
      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]NoPacific
      Gas and Electric Company:
            [  ]Yes [X]NoIndicate
      the number of shares outstanding of each of the issuer's classes of common
      stock, as of the latest practicable date.Common
      Stock Outstanding as of October 27, 2009:PG&E
      Corporation
            370,960,212Pacific
      Gas and Electric Company
            264,374,809














PG&E
CORPORATION AND


PACIFIC
GAS AND ELECTRIC COMPANY,


FORM
10-Q


FOR
THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009


TABLE
OF CONTENTS





PART
      I.
            FINANCIAL
      INFORMATION
            PAGEITEM 1.
            CONDENSED
      CONSOLIDATED FINANCIAL STATEMENTSPG&E
      CorporationCondensed Consolidated
      Statements of Income
            3Condensed Consolidated Balance
      Sheets
            4Condensed Consolidated
      Statements of Cash Flows
            6Pacific
      Gas and Electric CompanyCondensed Consolidated
      Statements of Income
            8Condensed Consolidated
      Balance Sheets
            9Condensed Consolidated
      Statements of Cash Flows
            11NOTES
      TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTSNOTE 1:
            Organization and Basis of Presentation
            13NOTE 2:
            New and Significant Accounting Policies
            13NOTE 3:
            Regulatory Assets, Liabilities, and Balancing
      Accounts
            18NOTE 4:
            Debt
            22NOTE 5:
            Equity
            23NOTE 6:
            Earnings Per Share
            23NOTE 7:
            Derivatives and Hedging Activities
            25NOTE 8:
            Fair Value Measurements
            29NOTE 9:
            Related Party Agreements and
Transactions
            33NOTE 10:
            Resolution of Remaining Chapter 11 Disputed
      Claims
            33NOTE 11:
            Commitments and Contingencies
            34ITEM 2.
            MANAGEMENT'S
      DISCUSSION AND ANALYSIS OF FINANCIAL
              CONDITION
      AND RESULTS OF OPERATIONSOverview
            41Forward-Looking
      Statements
            43Results of
      Operations
            44Liquidity and Financial
      Resources
            51Contractual
      Commitments
            55Capital
      Expenditures
            55Off-Balance Sheet
      Arrangements
            56Contingencies
            56Regulatory
      Matters
            56Risk Management
      Activities
            60Critical Accounting
      Policies
            61New Accounting
      Policies
            61Accounting Pronouncements
      Issued But Not Yet Adopted
            63ITEM 3.
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
            65ITEM 4.
            CONTROLS AND PROCEDURES
            65PART
      II.
            OTHER
      INFORMATIONITEM 1.
            LEGAL PROCEEDINGS
            66ITEM 1A.
            RISK FACTORS
            66ITEM 2.
            UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
      PROCEEDS
            66ITEM 5.
            OTHER INFORMATION
            67ITEM 6.
            EXHIBITS
            68








2





PART
I.  FINANCIAL INFORMATION


ITEM
1: CONDENSED CONSOLIDATED FINANCIAL STATEMENTS





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




3




PG&E
CORPORATION


CONDENSED CONSOLIDATED BALANCE SHEETS





(Unaudited)Balance
      At(in
      millions)
            
            September
      30,
                2009
            
            
            December
      31, 2008ASSETSCurrent
      AssetsCash
      and cash equivalents
            
            $
            700
            
            
            $
            219Restricted
      cash
            
            
            569
            
            
            
            1,290Accounts
      receivable:Customers
      (net of allowance for doubtful accounts of $68 million in 2009 and $76
      million in 2008)
            
            
            1,609
            
            
            
            1,751Accrued
      unbilled revenue
            
            
            807
            
            
            
            685Regulatory
      balancing accounts
            
            
            882
            
            
            
            1,197Inventories:Gas
      stored underground and fuel oil
            
            
            141
            
            
            
            232Materials
      and supplies
            
            
            204
            
            
            
            191Income
      taxes receivable
            
            
            58
            
            
            
            120Prepaid
      expenses and other
            
            
            640
            
            
            
            718Total
      current assets
            
            
            5,610
            
            
            
            6,403Property,
      Plant, and EquipmentElectric
            
            
            29,875
            
            
            
            27,638Gas
            
            
            10,524
            
            
            
            10,155Construction
      work in progress
            
            
            1,767
            
            
            
            2,023Other
            
            
            15
            
            
            
            17Total
      property, plant, and equipment
            
            
            42,181
            
            
            
            39,833Accumulated
      depreciation
            
            
            (13,997
            )
            
            
            (13,572
            )Net
      property, plant, and equipment
            
            
            28,184
            
            
            
            26,261Other
      Noncurrent AssetsRegulatory
      assets
            
            
            5,931
            
            
            
            5,996Nuclear
      decommissioning funds
            
            
            1,870
            
            
            
            1,718Income
      taxes receivable
            
            
            506
            
            
            
            -Other
            
            
            450
            
            
            
            482Total
      other noncurrent assets
            
            
            8,757
            
            
            
            8,196TOTAL
      ASSETS
            
            $
            42,551
            
            
            $
            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)
            
            September
      30,
                2009
            
            
            December
      31, 2008LIABILITIES
      AND EQUITYCurrent
      LiabilitiesShort-term
      borrowings
            
            $
            500
            
            
            $
            287Long-term
      debt, classified as current
            
            
            342
            
            
            
            600Energy
      recovery bonds, classified as current
            
            
            382
            
            
            
            370Accounts
      payable:Trade
      creditors
            
            
            864
            
            
            
            1,096Disputed
      claims and customer refunds
            
            
            816
            
            
            
            1,580Regulatory
      balancing accounts
            
            
            629
            
            
            
            730Other
            
            
            370
            
            
            
            343Interest
      payable
            
            
            794
            
            
            
            802Income
      taxes payable
            
            
            589
            
            
            
            -Deferred
      income taxes
            
            
            172
            
            
            
            251Other
            
            
            1,491
            
            
            
            1,567Total
      current liabilities
            
            
            6,949
            
            
            
            7,626Noncurrent
      LiabilitiesLong-term
      debt
            
            
            9,839
            
            
            
            9,321Energy
      recovery bonds
            
            
            928
            
            
            
            1,213Regulatory
      liabilities
            
            
            4,152
            
            
            
            3,657Pension
      and other postretirement benefits
            
            
            2,221
            
            
            
            2,088Asset
      retirement obligations
            
            
            1,545
            
            
            
            1,684Income
      taxes payable
            
            
            -
            
            
            
            35Deferred
      income taxes
            
            
            4,321
            
            
            
            3,397Deferred
      tax credits
            
            
            90
            
            
            
            94Other
            
            
            2,092
            
            
            
            2,116Total
      noncurrent liabilities
            
            
            25,188
            
            
            
            23,605Commitments
      and ContingenciesEquityShareholders’
      EquityPreferred
      stock, no par value, authorized 80,000,000 shares, $100 par value,
      authorized 5,000,000 shares, none issued
            
            
            -
            
            
            
            -Common
      stock, no par value, authorized 800,000,000 shares, issued 370,877,751
      common and 670,552 restricted shares in 2009 and issued 361,059,116 common
      and 1,287,569 restricted shares in 2008
            
            
            6,265
            
            
            
            5,984Reinvested
      earnings
            
            
            4,097
            
            
            
            3,614Accumulated
      other comprehensive loss
            
            
            (200
            )
            
            
            (221
            )Total
      shareholders’ equity
            
            
            10,162
            
            
            
            9,377Noncontrolling
      Interest – Preferred Stock of Subsidiary
            
            
            252
            
            
            
            252Total
      equity
            
            
            10,414
            
            
            
            9,629TOTAL
      LIABILITIES AND EQUITY
            
            $
            42,551
            
            
            $
            40,860





See
accompanying Notes to the Condensed Consolidated Financial
Statements.




5




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




6




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




7




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




8





PACIFIC
GAS AND ELECTRIC COMPANY


CONDENSED CONSOLIDATED BALANCE SHEETS





(Unaudited)Balance
      At(in
      millions)
            
            September
      30,
                2009
            
            
            December
      31,
                2008ASSETSCurrent
      AssetsCash
      and cash equivalents
            
            $
            511
            
            
            $
            52Restricted
      cash
            
            
            569
            
            
            
            1,290Accounts
      receivable:Customers
      (net of allowance for doubtful accounts of $68 million in 2009 and $76
      million in 2008)
            
            
            1,609
            
            
            
            1,751Accrued
      unbilled revenue
            
            
            807
            
            
            
            685Related
      parties
            
            
            2
            
            
            
            2Regulatory
      balancing accounts
            
            
            882
            
            
            
            1,197Inventories:Gas
      stored underground and fuel oil
            
            
            141
            
            
            
            232Materials
      and supplies
            
            
            204
            
            
            
            191Income
      taxes receivable
            
            
            63
            
            
            
            25Prepaid
      expenses and other
            
            
            635
            
            
            
            705Total
      current assets
            
            
            5,423
            
            
            
            6,130Property,
      Plant, and EquipmentElectric
            
            
            29,875
            
            
            
            27,638Gas
            
            
            10,524
            
            
            
            10,155Construction
      work in progress
            
            
            1,767
            
            
            
            2,023Total
      property, plant, and equipment
            
            
            42,166
            
            
            
            39,816Accumulated
      depreciation
            
            
            (13,983
            )
            
            
            (13,557
            )Net
      property, plant, and equipment
            
            
            28,183
            
            
            
            26,259Other
      Noncurrent AssetsRegulatory
      assets
            
            
            5,931
            
            
            
            5,996Nuclear
      decommissioning funds
            
            
            1,870
            
            
            
            1,718Related
      parties receivable
            
            
            26
            
            
            
            27Income
      taxes receivable
            
            
            518
            
            
            
            -Other
            
            
            365
            
            
            
            407Total
      other noncurrent assets
            
            
            8,710
            
            
            
            8,148TOTAL
      ASSETS
            
            $
            42,316
            
            
            $
            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)
            
            September
      30,
                2009
            
            
            December
      31,
                2008LIABILITIES
      AND SHAREHOLDERS’ EQUITYCurrent
      LiabilitiesShort-term
      borrowings
            
            $
            500
            
            
            $
            287Long-term
      debt, classified as current
            
            
            95
            
            
            
            600Energy
      recovery bonds, classified as current
            
            
            382
            
            
            
            370Accounts
      payable:Trade
      creditors
            
            
            864
            
            
            
            1,096Disputed
      claims and customer refunds
            
            
            816
            
            
            
            1,580Related
      parties
            
            
            14
            
            
            
            25Regulatory
      balancing accounts
            
            
            629
            
            
            
            730Other
            
            
            371
            
            
            
            325Interest
      payable
            
            
            777
            
            
            
            802Income
      tax payable
            
            
            612
            
            
            
            53Deferred
      income taxes
            
            
            177
            
            
            
            257Other
            
            
            1,289
            
            
            
            1,371Total
      current liabilities
            
            
            6,526
            
            
            
            7,496Noncurrent
      LiabilitiesLong-term
      debt
            
            
            9,491
            
            
            
            9,041Energy
      recovery bonds
            
            
            928
            
            
            
            1,213Regulatory
      liabilities
            
            
            4,152
            
            
            
            3,657Pension
      and other postretirement benefits
            
            
            2,170
            
            
            
            2,040Asset
      retirement obligations
            
            
            1,545
            
            
            
            1,684Income
      taxes payable
            
            
            -
            
            
            
            12Deferred
      income taxes
            
            
            4,353
            
            
            
            3,449Deferred
      tax credits
            
            
            90
            
            
            
            94Other
            
            
            2,057
            
            
            
            2,064Total
      noncurrent liabilities
            
            
            24,786
            
            
            
            23,254Commitments
      and ContingenciesShareholders’
      EquityPreferred
      stock without mandatory redemption provisions:Nonredeemable,
      5.00% to 6.00%, outstanding 5,784,825 shares
            
            
            145
            
            
            
            145Redeemable,
      4.36% to 5.00%, outstanding 4,534,958 shares
            
            
            113
            
            
            
            113Common
      stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809
      shares in 2009 and 2008
            
            
            1,322
            
            
            
            1,322Additional
      paid-in capital
            
            
            3,022
            
            
            
            2,331Reinvested
      earnings
            
            
            6,597
            
            
            
            6,092Accumulated
      other comprehensive loss
            
            
            (195
            )
            
            
            (216
            )Total
      shareholders’ equity
            
            
            11,004
            
            
            
            9,787TOTAL
      LIABILITIES AND SHAREHOLDERS’ EQUITY
            
            $
            42,316
            
            
            $
            40,537





See
accompanying Notes to the Condensed Consolidated Financial
Statements.




10








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




11





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




12








NOTES
TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)





NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION





PG&E
Corporation is a holding company whose primary purpose is to hold interests in
energy-based businesses.  PG&E Corporation conducts its business
principally through Pacific Gas and Electric Company (“Utility”), a public
utility operating in northern and central California.  The Utility
engages 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 (“VIEs”) 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.




NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES





Significant
Accounting Policies





Consolidation
of Variable Interest Entities





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




13





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





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





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





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





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





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





Asset
Retirement Obligations





See Note 2 of the Notes to the
Consolidated Financial Statements in the 2008 Annual Report for a discussion of
PG&E Corporation’s and the Utility’s accounting policy for ARO.  A
reconciliation of the changes in the ARO liability is as follows:





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





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.





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 nine months ended
September 30, 2009 and 2008 were as follows:




14




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





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





There was
no material difference between PG&E Corporation’s and the Utility’s
consolidated net periodic benefit costs for the three and nine months ended
September 30, 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 Statement of Financial Accounting Standards
(“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging
Activities - an amendment of FASB Statement No. 133” (“SFAS No.
161”).  SFAS No. 161 requires an entity to provide qualitative
disclosures about its objectives and strategies for using derivative instruments
and quantitative disclosures that detail the fair value amounts of, and gains
and losses on, derivative instruments.  SFAS No. 161 also requires
disclosures about credit risk-related contingent features of derivative
instruments.  (See Note 7 of the Notes to the Condensed Consolidated
Financial Statements.)




15




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





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





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





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





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





On January 1, 2009, PG&E
Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5,
“Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party
Credit Enhancement” (“EITF 08-5”).  EITF 08-5 clarifies the unit of
account in determining the fair value of a liability.  Specifically,
it requires an entity to exclude any third-party credit enhancements 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 the Business
Combinations Topic of the Financial Accounting Standards Board (“FASB”)
Accounting Standards Codification (“ASC”).  However, the investor in
an equity method investment could be required to recognize a liability for the
related contingent consideration features if the fair value of the investor’s
share of the investee’s net assets exceeds the investor’s initial
costs.  An equity method investor is required to recognize
other-than-temporary impairments of an equity method investment and shall
account for a share issuance by an investee as if the investor had sold a
proportionate share of its investment.  Any gain or loss to the
investor resulting from an investee’s share issuance shall be recognized in
earnings.  Adoption of EITF 08-6 did not have a material impact on
PG&E Corporation’s or the Utility’s Condensed Consolidated Financial
Statements.





Subsequent
Events





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





Interim
Disclosures about Fair Value of Financial Instruments





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




16




Recognition
and Presentation of Other-Than-Temporary Impairments





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





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





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





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





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





Accounting
Pronouncements Issued But Not Yet Adopted





Employers’
Disclosures about Postretirement Benefit Plan Assets





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





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





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




17





Amendments
to FASB Interpretation No. 46(R)





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





NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING
ACCOUNTS





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





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





Regulatory
Assets





Long-Term
Regulatory Assets





Long-term
regulatory assets are composed of the following:





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





The
regulatory asset for pension benefits represents the cumulative differences
between amounts recognized for ratemaking purposes and amounts recognized in
accordance with GAAP, which also includes amounts that otherwise would be fully
recorded to Accumulated other comprehensive loss in the Condensed Consolidated
Balance Sheets.  (See Note 14 of the Notes to the Consolidated
Financial Statements in the 2008 Annual Report.)





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





18





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





In connection with the Chapter 11
Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of
costs related to the Utility’s retained generation assets. The individual
components of these regulatory assets are amortized over the respective lives of
the underlying generation facilities, consistent with the period over which the
related revenues are recognized.  The weighted average remaining life
of the assets is 16 years.





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





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





The regulatory assets for unamortized
loss, net of gain, on reacquired debt represent costs related to debt reacquired
or redeemed prior to maturity with associated discount and debt issuance
costs.  These costs are expected to be recovered over the remaining
original amortization period of the reacquired debt over the next 17 years, and
these costs will be fully recovered by 2026.





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





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





At September 30, 2009, “Other”
primarily consisted of regulatory assets relating to ARO costs recorded in
accordance with GAAP, which are probable of future recovery through the
ratemaking process, as well as costs associated with the replacement of the
steam generators in the Utility’s two nuclear generating units at the Diablo
Canyon Power Plant (“Diablo Canyon”), as approved by the CPUC for future
recovery.  At December 31, 2008, “Other” primarily consisted of
regulatory assets relating to ARO costs, as well as scheduling coordinator costs
that the Utility incurred beginning in 1998 in its capacity as scheduling
coordinator for its then-existing wholesale electric transmission
customers.





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





Current
Regulatory Assets





At
September 30, 2009 and December 31, 2008, the Utility had current regulatory
assets of $421 million and $355 million, respectively, consisting primarily of
the current portion of price risk management regulatory assets.  Price
risk management regulatory assets represent the deferral of unrealized losses
related to price risk management derivative instruments with terms of less than
one year.  (See Note 7 of the Notes to the Condensed Consolidated
Financial Statements.)  Current regulatory assets are included in
Prepaid expenses and other in the Condensed Consolidated Balance
Sheets.




19





Regulatory
Liabilities





Long-Term
Regulatory Liabilities





Long-term
regulatory liabilities are composed of the following:





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





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





The
regulatory liability for public purpose programs represents amounts received
from customers designated for public purpose program costs that are expected to
be incurred in the future.  For example, these regulatory liabilities
include revenues collected from customers to pay for costs that the Utility
expects to incur in the future under the California Solar Initiative to promote
the use of solar energy in residential homes and commercial, industrial, and
agricultural properties.





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





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





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





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





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





Current
Regulatory Liabilities





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





Regulatory
Balancing Accounts





The
Utility uses regulatory balancing accounts to accumulate differences between
actual billed and unbilled revenues and the Utility’s authorized revenue
requirements for the period.  The Utility also uses regulatory
balancing accounts to accumulate differences between incurred costs and actual
billed and unbilled revenues, as well as differences between incurred costs and
authorized revenue meant to recover those costs.  Under-collections
that are probable of recovery through regulated rates are recorded as regulatory
balancing account assets.  Over-collections that are probable of being
credited to customers are recorded as regulatory balancing account
liabilities.





20





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





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





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





The
energy recovery 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
September 30, 2009 and December 31, 2008, “Other” includes the California
Alternate Rates for Energy balancing account, which records the revenue
shortfall associated with the low-income customer assistance
program.  Participation in the program is generally impacted by
economic conditions.  Program spending increases as more customers
participate in the programs, resulting in an under-collection.  At
December 31, 2008, “Other” also included incentive awards earned by the Utility
for implementing customer energy efficiency programs.





21





NOTE 4: DEBT





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 September 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 ofFloating 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
September 30, 2009, the interest rate on the Floating Rate Senior Notes was
1.25%.





Pollution
Control Bonds





The
California Pollution Control Financing Authority and the California
Infrastructure and Economic Development Bank (“CIEDB”), serving as conduit
issuer, have issued various series of tax-exempt pollution control bonds for the
benefit of the Utility.





On
September 1, 2009, the CIEDB issued $149 million of tax-exempt pollution control
bonds series 2009 A and B due on November 1, 2026 and $160 million of tax-exempt
pollution control bonds series 2009 C and D due on December 1,
2016.  The proceeds were used to repurchase the corresponding series
of 2008 pollution control bonds.  The series 2009 bonds, issued at par
with an initial rate of 0.20%, are variable rate demand notes with interest
resetting daily and backed by direct-pay letters of credit.  Unlike
the series 2008 bonds, interest earned on the series 2009 bonds is not subject
to the alternative minimum tax (“AMT”).  A provision in the American
Recovery and Reinvestment Act of 2009 allows certain tax-exempt bonds that are
subject to AMT to be reissued or refunded in 2009 or 2010 as tax-exempt bonds
that are not subject to AMT.  As a result, the series 2009 bonds were
issued at a lower interest rate, reducing the Utility’s interest
expense.





Credit
Facility and Short-Term Borrowings





At
September 30, 2009, the Utility had $273 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 September 30, 2009, the Utility had no commercial paper
outstanding.





Energy
Recovery Bonds





PG&E
Energy Recovery Funding LLC, 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 $1.3billion at September 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.





22





NOTE 5: EQUITY





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





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





For the
nine months ended September 30, 2009, PG&E Corporation contributed equity of
$688 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 nine months ended September
30, 2009, the Utility paid common stock dividends totaling $468 million to
PG&E Corporation.





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





During the nine months ended September
30, 2009, the Utility paid cash dividends totaling $10 million to holders of its
outstanding series of preferred stock.  On September 16, 2009, the
Board of Directors of the Utility declared a cash dividend totaling $3 million
on its outstanding series of preferred stock, payable on November 15, 2009 to
shareholders of record on October 30, 2009.





NOTE 6: EARNINGS PER SHARE





Earnings
per common share (“EPS”) is calculated utilizing the “two-class” method, by
dividing the sum of distributed earnings to common shareholders and
undistributed earnings allocated to common shareholders by the weighted average
number of common shares outstanding during the period.  In applying
the two-class method, undistributed earnings are allocated to both common shares
and participating securities.  PG&E Corporation’s 9.5% Convertible
Subordinated Notes (“Convertible Subordinated Notes”) are entitled to receive
pass-through dividends and meet the criteria of participating
securities.  All of the participating securities participate in
dividends on a 1:1 basis with shares of common stock.





23





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





Three
      Months Ended
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,(in
      millions, except per share amounts)
            
            2009
            
            
            2008
            
            
            2009
            
            
            2008BasicIncome
      Available for Common Shareholders
            
            $
            318
            
            
            $
            304
            
            
            $
            947
            
            
            $
            821Less:
      distributed earnings to common shareholders
            
            
            156
            
            
            
            140
            
            
            
            465
            
            
            
            419Undistributed
      earnings
            
            $
            162
            
            
            $
            164
            
            
            $
            482
            
            
            $
            402Allocation
      of undistributed earnings to common shareholdersDistributed
      earnings to common shareholders
            
            $
            156
            
            
            $
            140
            
            
            $
            465
            
            
            $
            419Undistributed
      earnings allocated to common shareholders
            
            
            155
            
            
            
            156
            
            
            
            461
            
            
            
            382Total
      common shareholders earnings
            
            $
            311
            
            
            $
            296
            
            
            $
            926
            
            
            $
            801Weighted
      average common shares outstanding, basic
            
            
            370
            
            
            
            357
            
            
            
            367
            
            
            
            356Convertible
      Subordinated Notes
            
            
            16
            
            
            
            19
            
            
            
            17
            
            
            
            19Weighted
      average common shares outstanding and participating
    securities
            
            
            386
            
            
            
            376
            
            
            
            384
            
            
            
            375Net
      earnings per common share, basicDistributed
      earnings, basic (1)
            
            $
            0.42
            
            
            $
            0.39
            
            
            $
            1.27
            
            
            $
            1.18Undistributed
      earnings, basic
            
            
            0.42
            
            
            
            0.44
            
            
            
            1.26
            
            
            
            1.07Total
            
            $
            0.84
            
            
            $
            0.83
            
            
            $
            2.53
            
            
            $
            2.25(1)
      Distributed earnings, basic may differ from actual per share amounts paid
      as dividends, as the EPS computation under GAAP requires the use of the
      weighted average, rather than the actual, number of shares
      outstanding.





In
calculating diluted EPS, PG&E Corporation applies the if-converted method to
reflect the dilutive effect of the Convertible Subordinated Notes to the extent
that the impact is dilutive when compared to basic EPS.  In addition,
PG&E Corporation applies the treasury stock method of reflecting the
dilutive effect of outstanding stock-based compensation in the calculation of
diluted EPS.  The following is a reconciliation of PG&E
Corporation’s income available for common shareholders and weighted average
shares of common stock outstanding for calculating diluted earnings per share
for three and nine months ended September 30, 2009:





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





Stock
options to purchase 7,285 and 11,935 shares of PG&E Corporation common stock
were excluded from the computation of diluted EPS for the three and nine months
ended September 30, 2009, respectively, because the exercise prices of these
options were greater than the average market price of PG&E Corporation
common stock during these periods.





The
following is a reconciliation of PG&E Corporation’s income available for
common shareholders and weighted average shares of common stock outstanding for
calculating diluted earnings per share for three and nine months ended September
30, 2008:




24




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





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





NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES





Use
of Derivative Instruments





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





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





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





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





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





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





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




25





Commodity-Related
Price Risk





Commodity-related
price risk management activities that meet the definition of a derivative are
recorded at fair value on the Condensed Consolidated Balance
Sheets.  Certain commodity-related price risk management activities
reduce the cash flow variability associated with fluctuating commodity
prices.  Prior to September 2009, the Utility designated qualifying
derivative transactions as cash flow hedges for accounting
purposes.  As long as the ratemaking mechanisms discussed above remain
in place and the Utility’s risk management activities are carried out in
accordance with CPUC directives, the Utility expects to fully recover from
customers, in rates, all costs related to commodity-related price risk-related
derivative instruments.  Therefore, all unrealized gains and losses
associated with the fair value of these derivative instruments, including those
designated as cash flow hedges, are deferred and recorded within the Utility’s
regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.
(See Note 3 of the Notes to the Condensed Consolidated Financial
Statements.)  Net realized gains or losses on derivative instruments
related to price risk for commodities are recorded in the cost of electricity or
the cost of natural gas with corresponding increases or decreases to regulatory
balancing accounts for recovery from customers.  As of September 30,
2009, the Utility de-designated all cash flow hedge
relationships.  Due to the regulatory accounting treatment described
above, the de-designation of cash flow hedge relationships had no impact on
Income Available for Common Shareholders or the Condensed Consolidated Balance
Sheet.





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





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





Electricity
Procurement





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





A portion
of the Utility’s third-party power purchase agreements contain market-based
pricing terms.  In order to reduce the cash flow variability
associated with fluctuating electricity prices, 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.





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 third quarter of 2009,
the Utility acquired CRRs through both allocation and auction.





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





Natural
Gas Procurement (Electric Portfolio)





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




26





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 manages its winter exposure to variable natural gas prices in accordance
with its CPUC-approved annual core portfolio hedging implementation
plan.  Accordingly, the Utility has entered into various financial
instruments, such as swaps and options, intended to reduce the uncertainty
associated with fluctuating natural gas purchase prices.  These
financial instruments are considered derivative instruments that are recorded at
fair value within the Condensed Consolidated Balance Sheets.





Other
Risk





At
September 30, 2009, PG&E Corporation had $247 million of Convertible
Subordinated Notes outstanding scheduled to mature on June 30, 2010.  
The holders of the Convertible Subordinated Notes are entitled to receive
“pass-through dividends” determined by multiplying the cash dividend paid by
PG&E Corporation per share of common stock by a number equal to the
principal amount of the Convertible Subordinated Notes divided by the conversion
prices.  The dividend participation rights associated with the
Convertible Subordinated Notes are embedded derivative instruments and,
therefore, must be bifurcated from the Convertible Subordinated Notes and
recorded at fair value in PG&E Corporation’s Condensed Consolidated
Financial Statements.  Changes in fair value of the dividend
participation rights are recognized in PG&E Corporation’s Condensed
Consolidated Statements of Income as non-operating expense or income (in Other
income (expense), net).





Volume
of Derivative Activity





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





Contract
      Volumes (1)Underlying
      Product
            Instruments
            
            Less
      Than 1 Year
            
            
            Greater
      Than 1 Year But Less Than 3 Years
            
            
            Greater
      Than 3 Years But Less Than 5 Years
            
            
            Greater
      Than 5 Years (2)Natural
      Gas (3)
      (MMBtus (4))
            Forwards,
      Futures, and Swaps
            
            
            331,103,829
            
            
            
            192,707,140
            
            
            
            21,277,500
            
            
            
            -Options
            
            
            136,232,644
            
            
            
            86,837,080
            
            
            
            -
            
            
            
            -Electricity
      (Megawatt-hours)
            Forwards,
      Futures, and Swaps
            
            
            3,508,656
            
            
            
            7,644,024
            
            
            
            5,093,912
            
            
            
            4,768,447Options
            
            
            9,400
            
            
            
            11,450
            
            
            
            110,980
            
            
            
            557,512Congestion
      Revenue Rights
            
            
            55,374,468
            
            
            
            64,267,318
            
            
            
            59,648,715
            
            
            
            107,581,890PG&E
      Corporation Equity
              (Shares)
            Dividend
      Participation Rights
            
            
            16,370,789
            
            
            
            -
            
            
            
            -
            
            
            
            -(1)
      Amounts shown reflect the total gross derivative volumes by commodity type
      that are expected to settle in each time period.(2)Derivatives
      in this category expire between 2014 and 2022.(3)Amounts shown are for the combined positions of the electric and
      core gas portfolios.(4)Million British Thermal Units.




27




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.  The net balances include outstanding cash
collateral associated with derivative positions.





At
September 30, 2009, PG&E Corporation’s and the Utility’s outstanding
derivative balances were as follows:





(in
      millions)
            
            Gross Derivative Balance(1)
            
            
            Netting (2)
            
            
            Cash Collateral(2)
            
            
            Total
      Derivative BalancesCommodity Risk(PG&E
      Corporation and Utility)Current
      Assets – Prepaid expenses and other
            
            $
            48
            
            
            $
            (9
            )
            
            $
            63
            
            
            $
            102Other
      Noncurrent Assets – Other
            
            
            120
            
            
            
            (40
            )
            
            
            21
            
            
            
            101Current
      Liabilities – Other
            
            
            (253
            )
            
            
            9
            
            
            
            84
            
            
            
            (160
            )Noncurrent
      Liabilities – Other
            
            
            (379
            )
            
            
            40
            
            
            
            29
            
            
            
            (310
            )Total
      commodity risk
            
            $
            (464
            )
            
            $
            -
            
            
            $
            197
            
            
            $
            (267
            )Other Risk Instruments(3)(PG&E
      Corporation Only)Current
      Liabilities – Other
            
            $
            (20
            )
            
            $
            -
            
            
            $
            -
            
            
            $
            (20
            )Total
      derivatives
            
            $
            (484
            )
            
            $
            -
            
            
            $
            197
            
            
            $
            (287
            )(1)See Note 8 of the Notes to the Condensed Consolidated Financial
      Statements for a discussion of the valuation techniques used to calculate
      the fair value of these instruments.(2)
      Positions, by counterparty, are netted where the intent and legal right to
      offset exist in accordance with master netting agreements.(3)
      This category relates to the dividend participation rights of PG&E
      Corporation’s Convertible Subordinated Notes.





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





For the
nine month period ended September 30, 2009, the gains and losses recorded on
PG&E Corporation’s and the Utility’s derivative instruments were as
follows:





(in
      millions)Commodity
      Risk
              (PG&E
      Corporation and Utility)Unrealized
      gain/(loss) - Regulatory assets andliabilities (1)
            
            $
            32Realized
      gain/(loss) - Cost of electricity(2)
            
            
            (558
            )Realized
      gain/(loss)- Cost of natural gas (2)
            
            
            (30
            )Total
      commodity risk instruments
            
            $
            (556
            )Other Risk
      Instruments(3)
              (PG&E
      Corporation Only)Other
      income, net
            
            $
            1Total
      other risk instruments
            
            $
            1(1)
      Unrealized gains and losses on commodity risk-related derivative
      instruments are recorded to regulatory assets or liabilities, rather than
      being recorded to the Condensed Consolidated Statements of
      Income. These amounts exclude the impact of cash collateral
      postings.(2)
      These amounts are fully passed through to customers in
      rates. Accordingly, net income was not impacted by realized amounts
      on these instruments.(3)
      This category relates to dividend participation rights of PG&E
      Corporation’s Convertible Subordinated Notes.




28





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





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





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





(in
      millions)Derivatives
      in a liability position with credit-risk-relatedcontingencies that are not fully
      collateralized
            
            $
            (541
            )Related
      derivatives in an asset position
            
            
            57Collateral
      posting in the normal course of business relatedto these derivatives
            
            
            70Net position of derivative
      contracts/additional collateral posting requirements(1)
            
            $
            (414
            )(1)
      This calculation excludes the impact of closed but unpaid positions, as
      their settlement is not impacted by any of the Utility’s
      credit-risk-related contingencies.





NOTE 8: FAIR VALUE MEASUREMENTS





PG&E
Corporation and the Utility determine the fair value of certain assets and
liabilities based on assumptions that market participants would use in pricing
the assets or liabilities.  PG&E Corporation and the Utility
utilize a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value and give precedence to observable inputs
in determining fair value.  An instrument’s level within the hierarchy
is based on the lowest level of any significant input to the fair value
measurement.  See Note 12 of the Notes to the Consolidated Financial
Statements in the 2008 Annual Report for further discussion of fair value
measurements.





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





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




29




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





PG&E
Corporation’s and the Utility’s fair value measurements incorporate various
factors, such as nonperformance and credit risk adjustments.  At
September 30, 2009, the nonperformance and credit risk adjustment represented 1%
of the net price risk management value.  PG&E Corporation and the
Utility utilize a mid-market pricing convention (the midpoint between bid and
ask prices) as a practical expedient in valuing the majority of its derivative
assets and liabilities at fair value.





Financial
Instruments





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





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





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





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




30





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





The
following table provides a summary of the fair value of the investments held in
the Utility’s nuclear decommissioning trusts:





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





The cost
of debt and equity securities sold is determined by specific
identification.  The following table provides a summary of the
activity for the debt and equity securities:





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





In
general, investments held in the nuclear decommissioning trust are exposed to
various risks, such as interest rate, credit, and market volatility
risks.  Due to the level of risk associated with certain investment
securities, it is reasonably possible that changes in the market values of
investment securities could occur in the near term, and such changes could
materially affect the trusts’ fair value.





Level
3 Rollforward





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




31




PG&E
      Corporation Only
            
            
            PG&E
      Corporation and the Utility(in
      millions)
            
            Money
      Market
            
            
            Dividend
      Participation Rights
            
            
            Price
      Risk Management Instruments
            
            
            Nuclear Decommission-ing Trusts
      Equity Securities(1)
            
            
            Long-Term
      Disability Equity Securities
            
            
            Long-Term
      Disability Corp. Debt Securities
            
            
            Other
            
            
            TotalAsset
      (Liability) Balance as of January 1, 2009
            
            $
            12
            
            
            $
            (42
            )
            
            $
            (156
            )
            
            $
            5
            
            
            $
            54
            
            
            $
            24
            
            
            $
            (2
            )
            
            $
            (105
            )Realized
      and unrealized gains (losses):Included
      in earnings
            
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            11
            
            
            
            3
            
            
            
            -
            
            
            
            15Included
      in regulatory assets and liabilities or balancing accounts
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            (2
            )
            
            
            (2
            )Purchases,
      issuances, and settlements
            
            
            (7
            )
            
            
            21
            
            
            
            -
            
            
            
            -
            
            
            
            (45
            )
            
            
            74
            
            
            
            -
            
            
            
            43Transfers
      in to Level 3
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Asset
      (Liability) Balance as of September 30, 2009
            
            $
            5
            
            
            $
            (20
            )
            
            $
            (157
            )
            
            $
            6
            
            
            $
            20
            
            
            $
            101
            
            
            $
            (4
            )
            
            $
            (49
            )(1)
      Excludes deferred taxes on appreciation of investment
    value.





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





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





PG&E
      Corporation Only
            
            
            PG&E
      Corporation and the Utility(in
      millions)
            
            Money
      Market
            
            
            Dividend
      Participation Rights
            
            
            Price
      Risk Management Instruments
            
            
            Nuclear Decommission-ing Trusts
      Equity Securities(1)
            
            
            Long-term
      Disability Equity Securities
            
            
            Long-term
      Disability Corp. Debt Securities
            
            
            Other
            
            
            TotalAsset
      (Liability) Balance as of July 1, 2009
            
            $
            5
            
            
            $
            (27
            )
            
            $
            (189
            )
            
            $
            5
            
            
            $
            57
            
            
            $
            24
            
            
            $
            (3
            )
            
            $
            (128
            )Realized
      and unrealized gains (losses):Included
      in earnings
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            8
            
            
            
            2
            
            
            
            -
            
            
            
            10Included
      in regulatory assets and liabilities or balancing accounts
            
            
            -
            
            
            
            -
            
            
            
            32
            
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            32Purchases,
      issuances, and settlements
            
            
            -
            
            
            
            7
            
            
            
            -
            
            
            
            -
            
            
            
            (45
            )
            
            
            75
            
            
            
            -
            
            
            
            37Transfers
      in to Level 3
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Asset
      (Liability) Balance as of September 30, 2009
            
            $
            5
            
            
            $
            (20
            )
            
            $
            (157
            )
            
            $
            6
            
            
            $
            20
            
            
            $
            101
            
            
            $
            (4
            )
            
            $
            (49
            )(1)
      Excludes deferred taxes on appreciation of investment
    value.





Earnings for the period were impacted
by a $10 million unrealized gain relating to assets or liabilities still held at
September 30, 2009.




PG&E
Corporation and the Utility did not have any nonrecurring financial measurements
requiring disclosure at September 30, 2009.




32




NOTE 9: RELATED PARTY AGREEMENTS AND TRANSACTIONS





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





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





Three
      Months Ended
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,(in
      millions)
            
            2009
            
            
            2008
            
            
            2009
            
            
            2008Utility
      revenues from:Administrative
      services provided to
              PG&E
      Corporation
            
            $
            2
            
            
            $
            -
            
            
            $
            4
            
            
            $
            2Utility
      expenses from:Administrative
      services received from PG&E Corporation
            
            $
            14
            
            
            $
            34
            
            
            $
            47
            
            
            $
            86Utility
      employee benefit due to PG&E Corporation
            
            
            4
            
            
            
            5
            
            
            
            13
            
            
            
            16





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





NOTE 10: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED
CLAIMS





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





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





While the
FERC and judicial proceedings have been pending, the Utility entered into a
number of settlements with various electricity suppliers to resolve some of
these disputed claims and to resolve the Utility’s refund claims against these
electricity suppliers.  These settlement agreements provide that the
amounts payable by the parties are, in some instances, subject to adjustment
based on the outcome of the various refund offset and interest issues being
considered by the FERC.  The proceeds from these settlements, after
deductions for contingencies based on the outcome of the various refund offset
and interest issues being considered by the FERC, will continue to be refunded
to customers in rates.  Additional settlement discussions with other
electricity suppliers are ongoing.  Any net refunds, claim offsets, or
other credits that the Utility receives from energy suppliers through resolution
of the remaining disputed claims, either through settlement or the conclusion of
the various FERC and judicial proceedings, will also be credited to
customers.





On August
26, 2009, following the approval by the FERC, the bankruptcy court presiding
over the PX’s bankruptcy case, and the bankruptcy court that retains
jurisdiction over the Utility’s Chapter 11 proceeding, the Utility paid $700
million to the PX from the Utility’s escrow account to reduce the Utility’s
liability for the remaining net disputed claims. The following table presents
the changes in the remaining disputed claims liability and interest accrued from
December 31, 2008 to September 30, 2009:




33




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





At
September 30, 2009, the Utility’s net disputed claims liability was $1,005
million, consisting of $816 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
$683 million (classified on the Condensed Consolidated Balance Sheets within
Interest payable) offset by accounts receivable from the CAISO and the PX of
$494 million (classified on the Condensed Consolidated Balance Sheets within
Accounts receivable – Customers).





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





PG&E
Corporation and the Utility are unable to predict when the FERC or judicial
proceedings that are still pending will be resolved, and the amount of any
potential refunds that the Utility may receive or the amount of disputed claims,
including interest that the Utility will be required to pay.





NOTE 11: COMMITMENTS AND CONTINGENCIES





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





Commitments





Utility





Third-Party
Power Purchase Agreements





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





(in
      millions)2009
            
            $
            5352010
            
            
            2,1652011
            
            
            2,1112012
            
            
            2,2112013
            
            
            2,209Thereafter
            
            
            36,141Total
            
            $
            45,372





Payments
made by the Utility under power purchase agreements amounted to $1,809 million
and $3,631 million for the nine months ended September 30, 2009 and September
30, 2008, respectively.  The amounts above do not include payments
related to the DWR purchases for the benefit of the Utility’s customers, as the
Utility only acts as an agent for the DWR.




34




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





(in
      millions)2009
            
            $
            112010
            
            
            502011
            
            
            502012
            
            
            502013
            
            
            50Thereafter
            
            
            206Total
      fixed capacity payments
            
            
            417Less:
      Amount representing interest
            
            
            95Present
      value of fixed capacity payments
            
            $
            322





Minimum
lease payments associated with the lease obligation are included in Cost of
electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated
Statements of Income.  The timing of the Utility’s recognition of the
lease expense conforms to the ratemaking treatment for the Utility’s recovery of
the cost of electricity.  The QF contracts that are treated as capital
leases expire between April 2014 and September 2021.





Capacity
payments are based on the QF’s total available capacity and contractual capacity
commitment.  Capacity payments may be adjusted if the QF exceeds or
fails to meet performance requirements specified in the applicable power
purchase agreement.





Natural Gas Supply and
Transportation Commitments





The
Utility purchases natural gas directly from producers and marketers in both
Canada and the United States to serve its core customers.  The
contract lengths and natural gas sources of the Utility’s portfolio of natural
gas procurement contracts can fluctuate based on market
conditions.  The Utility also contracts for natural gas transportation
to transport natural gas from the points at which the Utility takes delivery
(typically in Canada and the southwestern United States) to the points at which
the Utility’s natural gas transportation system begins.





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





(in
      millions)2009
            
            $
            3412010
            
            
            6102011
            
            
            1242012
            
            
            492013
            
            
            42Thereafter
            
            
            157Total
            
            $
            1,323





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





Nuclear
Fuel Agreements





The
Utility has entered into several purchase agreements for nuclear
fuel.  These agreements have terms ranging from 1 to 16 years and are
intended to ensure long-term fuel supply.  The contracts for uranium
and for conversion and enrichment services provide for 100% coverage of reactor
requirements through 2013, while contracts for fuel fabrication services provide
for 100% coverage of reactor requirements through 2011.  The Utility
relies on a number of international producers of nuclear fuel in order to
diversify its sources and provide security of supply.  Pricing terms
are also diversified, ranging from market-based prices to base prices that are
escalated using published indices.  New agreements are primarily based
on forward market pricing and will begin to impact nuclear fuel costs starting
in 2010.




35




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





(in
      millions)2009
            
            $
            1532010
            
            
            1082011
            
            
            1002012
            
            
            902013
            
            
            118Thereafter
            
            
            1,226Total
            
            $
            1,795





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





Contingencies





PG&E
Corporation





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





Utility





Application
to Recover Hydroelectric Facility Divestiture Costs





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





Spent
Nuclear Fuel Storage Proceedings





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





The
Utility believes that the existing spent fuel pools at Diablo Canyon, which
include newly constructed temporary storage racks, have sufficient capacity to
enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1
and 2011 for Unit 2.  Because the DOE failed to develop a permanent
storage site, the Utility obtained a permit from the Nuclear Regulatory
Commission (“NRC”) to build an on-site dry cask storage facility to store spent
fuel through at least 2024.  The construction of the dry cask storage
facility is complete and the movement of spent nuclear fuel to dry cask storage
began in June 2009.





After
various parties appealed the NRC’s issuance of the permit, the U.S. Court of
Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006
requiring the NRC to issue a supplemental environmental assessment report on the
potential environmental consequences in the event of a terrorist attack at
Diablo Canyon, as well as to review other contentions raised by the appealing
parties related to potential terrorism threats.  In August 2007, the
NRC staff issued a final supplemental environmental assessment report concluding
that there would be no significant environmental impacts from potential
terrorist acts directed at the Diablo Canyon storage facility.




36





In
October 2008, the NRC rejected the final contention that had been made during
the appeal.  The appellant has filed a petition for review of the
NRC’s order in the Ninth Circuit.  On December 31, 2008, the appellate
court granted the Utility’s request to intervene in the
proceeding.  The Utility’s brief on appeal was filed on April 8,
2009.  No date has been set for oral argument.





As a
result of the DOE’s failure to build a national repository for nuclear waste,
the Utility and other nuclear power plant owners sued the DOE to recover costs
that they incurred to build on-site spent nuclear fuel storage
facilities.  The Utility seeks to recover $92 million of costs that it
incurred through 2004.  After several years of litigation, the DOE now
concedes that the Utility is entitled to recover approximately $82 million of
these costs, but the DOE continues to dispute the remaining
amount.  The trial to determine the appropriate method to calculate
the amounts owed to the Utility began on October 15, 2009.  The
Utility also will seek to recover costs incurred after 2004 to build on-site
storage facilities.





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





Energy
Efficiency Programs and Incentive Ratemaking





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





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





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




Nuclear
Insurance





The
Utility has several types of nuclear insurance for the two nuclear operating
units at Diablo Canyon and for its retired nuclear generation facility at
Humboldt Bay Unit 3.  The Utility has insurance coverage for property
damages and business interruption losses as a member of Nuclear Electric
Insurance Limited (“NEIL”).  NEIL is a mutual insurer owned by
utilities with nuclear facilities.  NEIL provides property damage and
business interruption coverage of up to $3.24 billion per incident for Diablo
Canyon.  In addition, NEIL provides $131 million of property damage
insurance for Humboldt Bay Unit 3.  Under this insurance, if any
nuclear generating facility insured by NEIL suffers a catastrophic loss causing
a prolonged outage, the Utility may be required to pay an additional premium of
up to $39.7 million per one-year policy term.




37





NEIL also
provides coverage for damages caused by acts of terrorism at nuclear power
plants.  Under the Terrorism Risk Insurance Program Reauthorization
Act of 2007 (“TRIPRA”), acts of terrorism may be “certified” by the Secretary of
the Treasury.  For a certified act of terrorism, NEIL can obtain
compensation from the federal government and will provide up to the full policy
limits to the Utility for an insured loss.  If one or more
non-certified acts of terrorism cause property damage covered under any of the
nuclear insurance policies issued by NEIL to any NEIL member, the maximum
recovery under all those nuclear insurance policies may not exceed $3.24 billion
within a 12-month period plus the additional amounts recovered by NEIL for these
losses from reinsurance.  (TRIPRA extends the Terrorism Risk Insurance
Act of 2002 through December 31, 2014.)





Under the
Price-Anderson Act, public liability claims from a nuclear incident are limited
to $12.5 billion.  As required by the Price-Anderson Act, the Utility
purchased the maximum available public liability insurance of $300 million for
Diablo Canyon.  The balance of the $12.5 billion of liability
protection is covered by a loss-sharing program among utilities owning nuclear
reactors.  Under the Price-Anderson Act, owner participation in this
loss-sharing program is required for all owners of nuclear reactors that are
licensed to operate, designed for the production of electrical energy, and have
a rated capacity of 100 MW or higher.  If a nuclear incident results
in costs in excess of $300 million, then the Utility may be responsible for up
to $117.5 million per reactor, with payments in each year limited to a maximum
of $17.5 million per incident until the Utility has fully paid its share of the
liability.  Since Diablo Canyon has two nuclear reactors, each with a
rated capacity of over 100 MW, the Utility may be assessed up to $235 million
per incident, with payments in each year limited to a maximum of $35 million per
incident.  Both the maximum assessment per reactor and the maximum
yearly assessment are adjusted for inflation at least every five
years.  The next scheduled adjustment is due on or before October 29,
2013.





In
addition, the Utility has $53.3 million of liability insurance for Humboldt Bay
Unit 3 and has a $500 million indemnification from the NRC for public liability
arising from nuclear incidents, covering liabilities in excess of the $53.3
million of liability insurance.





Severance
Costs





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





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





Environmental
Matters





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





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




38





The
Utility had an undiscounted and gross environmental remediation liability of
$597 million at September 30, 2009 and $568 million at December 31, 2008.
 The $597 million accrued at September 30, 2009 consists
of:





·
            $49
      million for remediation at the Utility’s natural gas compressor site
      located near Hinkley, California;·
            $156
      million for remediation at the Utility’s natural gas compressor site
      located in Topock, Arizona, near the California border;·
            $86
      million related to remediation at divested generation
      facilities;·
            $246
      million related to remediation costs for the Utility’s generation and
      other facilities, third-party disposal sites, and manufactured gas plant
      sites owned by the Utility or third parties (including those sites that
      are the subject of remediation orders by environmental agencies or claims
      by the current owners of the former manufactured gas plant sites);
      and·
            $60
      million related to remediation costs for fossil decommissioning
      sites.





Of the
$597 million environmental remediation liability, $146 million has been included
in prior rate setting proceedings and the Utility expects that an additional
amount of $366 million will be recoverable in future rates.  The
Utility also recovers its costs from insurance carriers and from other third
parties whenever possible.  Any amounts collected in excess of the
Utility’s ultimate obligations may be subject to refund to
customers.  Environmental remediation associated with the Hinkley
natural gas compressor site is not recoverable from customers.





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





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





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





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




39




Tax
Matters





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





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





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





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





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





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





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





For a
discussion of unrecognized tax benefits, see Note 10 of the Notes to the
Consolidated Financial Statements in the 2008 Annual Report.  During
the three months ended September 30, 2009, PG&E Corporation increased the
gross amount of unrecognized tax benefits by $531 million due to the events
described above.   If the full amount were recognized,
approximately $50 million would reduce PG&E Corporation’s effective tax rate
with the remaining balance representing the probable deferral of taxes to later
years. Further, it is reasonably possible that unrecognized tax benefits could
decrease in the next 12 months by an amount ranging from $0 to $30 million for
PG&E Corporation and the Utility.





Legal
Matters





PG&E
Corporation and the Utility are subject to various laws and regulations and, in
the normal course of business, PG&E Corporation and the Utility are named as
parties in a number of claims and lawsuits.





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




The
accrued liability for legal matters is included in PG&E Corporation’s and
the Utility’s Current Liabilities – Other in the Condensed Consolidated Balance
Sheets, and totaled $51 million at September 30, 2009 and $72 million at
December 31, 2008.  After consideration of these accruals, PG&E
Corporation and the Utility do not expect that losses associated with legal
matters would have a material adverse impact on their financial condition and
results of operations.




40


MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND


RESULTS
OF OPERATIONS





OVERVIEW





PG&E
Corporation, incorporated in California in 1995, is a holding company whose
primary purpose is to hold interests in energy-based
businesses.  PG&E Corporation conducts its business principally
through Pacific Gas and Electric Company (“Utility”), a public utility operating
in northern and central California.  The Utility engages in the
businesses of electricity and natural gas distribution; electricity generation,
procurement, and transmission; and natural gas procurement, transportation, and
storage.  PG&E Corporation became the holding company of the
Utility and its subsidiaries on January 1, 1997.  Both PG&E
Corporation and the Utility are headquartered in San Francisco,
California.





The
Utility served 5.1 million electricity distribution customers and 4.3 million
natural gas distribution customers at September 30, 2009.  The Utility
had $42.3 billion in assets at September 30, 2009 and generated revenues of $9.9
billion in the nine months ended September 30, 2009.





The
Utility is regulated primarily by the California Public Utilities Commission
(“CPUC”) and the Federal Energy Regulatory Commission (“FERC”).  The
Utility generates revenues mainly through the sale and delivery of electricity
and natural gas at rates set by the CPUC and the FERC.  Rates are set
to permit the Utility to recover its authorized “revenue requirements” from
customers.  Revenue requirements are designed to allow the Utility an
opportunity to recover its reasonable costs of providing utility services,
including a return of, and a fair rate of return on, its investment in Utility
facilities (“rate base”).  Pending regulatory proceedings that could
result in rate changes and affect the Utility’s revenues are discussed in
PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for
the year ended December 31, 2008, which, together with the information
incorporated by reference into such report, is referred to in this quarterly
report as the “2008 Annual Report.”  Significant developments that
have occurred since the 2008 Annual Report was filed with the Securities and
Exchange Commission (“SEC”) are discussed in this Quarterly Report on Form
10-Q.





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




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





PG&E
Corporation’s diluted earnings per common share (“EPS”) was $0.83 for each of
the three months ended September 30, 2009 and 2008.  For the nine
months ended September 30, 2009, PG&E Corporation’s diluted EPS was $2.49
compared to $2.24 for the same period in 2008.  PG&E Corporation’s
income available for common shareholders for the three months ended September
30, 2009 increased by $14 million, or 5%, to $318 million, compared to $304
million for the same period in 2008.  For the nine months ended
September 30, 2009, income available for common shareholders increased by $126
million, or 15%, to $947 million, compared to $821 million for the same period
in 2008.





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




41




The increase in diluted EPS and income
available for common shareholders for the nine months ended September 30, 2009,
as compared to the same period in 2008, is attributable to (1) an
increase of $73 million, after tax, representing the Utility’s ROE
earned on higher authorized capital investments, (2) an increase of $28
million, after tax, due to the recovery of previously incurred costs related to
the Utility’s hydroelectric generation facilities, (3) a benefit of $11 million,
after-tax, as compared to the same period in the prior year when the
Utility incurred costs to oppose certain legislation and municipalization
efforts, (4) a tax benefit of $66 million associated with
the settlement of tax refund claims involving the 1998 and 1999 tax years,
and (5) a benefit of $24 million, after tax, as compared to the same period in
the prior year when the Utility incurred higher storm and outage
expenses.  These increases were partially offset by (1) a $39 million,
after tax, decrease attributable to employee severance costs, and (2) a $32
million, after tax, decrease attributable to costs to perform accelerated
natural gas leak surveys and associated remedial work.





Key
Factors Affecting Results of Operations and Financial Condition





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





·
            The Outcome of Regulatory
      Proceedings and the Impact of Ratemaking
      Mechanisms.  Most of the Utility’s revenue requirements
      are set based on its costs of service in proceedings such as the General
      Rate Case (“GRC”) filed with the CPUC and transmission owner (“TO”) rate
      cases filed with the FERC.  (See “Regulatory Matters”
      below.)  The Utility intends to file its 2011-2013 GRC
      application with the CPUC before the end of 2009 to request an increase in
      authorized electric distribution, gas distribution, and electric
      generation revenue requirements.  On September 18, 2009, the
      Utility requested the CPUC to determine the rates, and terms and
      conditions of the Utility’s gas transmission and storage services
      beginning January 1, 2011.  The Utility also files separate
      applications requesting the CPUC or the FERC to authorize additional
      revenue requirements for specific capital expenditure projects, such as
      new power plants, gas or electric transmission facilities, installation of
      an advanced metering infrastructure, and reliability or system
      infrastructure improvements.  (See “Capital Expenditures”
      below.)  The Utility’s revenues will also be affected by
      incentive ratemaking, such as the CPUC’s customer energy efficiency
      shareholder incentive mechanism.  In addition, the CPUC has
      authorized the Utility to recover 100% of its reasonable electric fuel and
      energy procurement costs and has established a timely rate adjustment
      mechanism to recover such costs.  As a result, the Utility’s
      revenues and costs can be affected by volatility in the prices of natural
      gas and electricity.  (See “Risk Management Activities”
      below.)·
            Capital
      Structure and Return on Common Equity.The Utility’s current
      CPUC-authorized capital structure includes a 52% common equity component,
      which will remain in effect through 2012.  The CPUC has
      authorized the Utility to set rates targeted to earn an ROE of 11.35% on
      the equity component of its electric and natural gas distribution and
      electric generation rate base through 2010.  The Utility’s cost
      of capital for 2011 and 2012 will change only if the annual adjustment
      mechanism established by the CPUC is triggered.  If the
      adjustment is triggered, the Utility’s authorized cost of capital would be
      adjusted effective January 1 of the following year.  The Utility
      can also apply for an adjustment to either its capital structure or its
      cost of capital at any time in the event of extraordinary circumstances.(See “Regulatory
      Matters” below.)·
            The Ability of the Utility to
      Control Costs While Improving Operational Efficiency and
      Reliability.  The Utility’s revenue requirements are
      generally set at a level to allow the Utility the opportunity to recover
      its basic forecasted operating expenses, as well as to earn an ROE and
      recover depreciation, tax, and interest expense associated with authorized
      capital expenditures.  Differences in the amount or timing of
      forecasted and actual operating expenses and capital expenditures can
      affect the Utility’s ability to earn its authorized rate of return and the
      amount of PG&E Corporation’s income available for common
      shareholders.  The Utility also seeks to make the amount and
      timing of its capital expenditures consistent with budgeted amounts and
      timing.  When capital expenditures are higher than authorized
      levels, the Utility incurs associated depreciation, property tax, and
      interest expense but does not recover revenues to fully offset these
      expenses or earn an ROE until the increased capital expenditures are added
      to rate base in future rate cases.  Items that could cause
      higher expenses than provided for in the last GRC primarily relate to the
      Utility’s efforts to maintain its aging electric and natural gas systems
      infrastructure, to improve the reliability and safety of its electric and
      natural gas system, and to improve its information technology
      infrastructure, support, and security.  The Utility continually
      seeks to achieve operational efficiencies and improve reliability while
      creating future sustainable cost savings to offset these higher
      anticipated expenses.  In connection with these efforts, the
      Utility has accrued severance costs, including severance costs related to
      the reduction of approximately 2% of the Utility’s workforce, in the three
      months ended September 30, 2009.  (See “Results of Operations”
      below.)·
            Timing and Amount of Debt and
      Equity Financing.  The timing and amount of the Utility’s
      future financing needs will depend on various factors, including the
      conditions in the capital markets, the amount and timing of scheduled
      principal and interest payments on long-term debt, the amount and timing
      of planned capital expenditures, and the amount and timing of interest
      payments related to the remaining disputed claims that were made by
      electricity suppliers in the Utility’s proceeding under Chapter 11 of the
      U.S. Bankruptcy Code (“Chapter 11”).  (See Note 10 of the Notes
      to the Condensed Consolidated Financial Statements.)  The amount
      of the Utility’s short-term financing will vary depending on the level of
      operating cash flows, seasonal demand for electricity and natural gas,
      volatility in electricity and natural gas prices, and collateral
      requirements related to price risk management activities, among other
      factors.  In order to maintain the Utility’s CPUC-authorized
      capital structure, PG&E Corporation contributed $688 million of equity
      to the Utility during 2009.  The timing and amount of future
      equity contributions to the Utility will affect the timing and amount of
      any future equity or debt issuances by PG&E
      Corporation.  (See “Liquidity and Financial Resources”
      below.)





42





FORWARD-LOOKING STATEMENTS





This
combined quarterly report on Form 10-Q contains forward-looking statements that
are necessarily subject to various risks and uncertainties.  These
statements are based on current estimates, expectations, and projections about
future events and assumptions regarding these events and management’s knowledge
of facts as of the date of this report.  These forward-looking
statements relate to, among other matters, estimated capital expenditures,
estimated environmental remediation liabilities, estimated tax liabilities, the
anticipated outcome of various regulatory and legal proceedings, estimated
future cash flows, and the level of future equity or debt issuances, and are
also identified by words such as “assume,” “expect,” “intend,” “plan,”
“project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,”
“may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar
expressions.  PG&E Corporation and the Utility are not able to
predict all the factors that may affect future results.  Some of the
factors that could cause future results to differ materially from those
expressed or implied by the forward-looking statements, or from historical
results, include, but are not limited to:





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





43





For more
information about the significant risks that could affect the outcome of these
forward-looking statements and PG&E Corporation’s and the Utility’s future
financial condition and results of operations, see the discussion in the section
entitled “Risk Factors” in the 2008 Annual Report and the discussion below under
Part II. Other Information, Item 1A. Risk Factors.  PG&E
Corporation and the Utility do not undertake an obligation to update
forward-looking statements, whether in response to new information, future
events, or otherwise.




RESULTS OF OPERATIONS





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





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




44




Utility





The
following presents the Utility’s operating results for the three and nine months
ended September 30, 2009 and 2008.





Electric
Operating Revenues





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





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





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





The
Utility’s total electric operating revenues decreased by $250 million, or 9%, in
the three months ended September 30, 2009 and $429 million, or 5%, in the nine
months ended September 30, 2009, compared to the same period in 2008, due to the
following factors:





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





These
decreases were partially offset by the following:





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




45





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





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





Revenue
requirements associated with new or expanded public purpose, energy efficiency,
and demand response programs will also result in increased electric operating
revenues.  In addition, future electric operating revenues are
affected by changes in the Utility’s electricity procurement costs, as discussed
under “Cost of Electricity” below.  Finally, the Utility may recognize
additional incentive revenues to the extent that it achieves the CPUC’s energy
efficiency goals.  (See “Regulatory Matters” below.)





Cost
of Electricity





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





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





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





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





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





46





The
Utility’s future cost of electricity also may be affected by federal or state
legislation or rules that may be adopted to regulate the emissions of greenhouse
gases from the Utility’s electricity generating facilities or the generating
facilities from which the Utility procures electricity.  In
particular, costs are likely to increase in the future when California’s
statewide greenhouse gas emissions reduction law is implemented.





Natural
Gas Operating Revenues





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





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





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





The Utility’s total natural gas
operating revenues decreased by $189 million, or 24%, in the three months ended
September 30, 2009 and by $696 million, or 24%, in the nine months ended
September 30, 2009, compared to the same periods in 2008, primarily due to
decreases in the total cost of natural gas of $217 million in the three months
ended September 30, 2009 and $734 million in the nine months ended September 30,
2009.  (See “Cost of Natural Gas” below.)  This decrease was
partially offset by the following:





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





The
Utility’s future natural gas operating revenues will be affected by changes in
the cost of natural gas, natural gas throughput volume, previously authorized
increases in 2010 revenue requirements, and the amount of incentive revenues
that the Utility may receive to the extent that it achieves the CPUC’s energy
efficiency goals.  The Utility’s future natural gas operating revenues
will also be affected by the outcome of the Utility’s application in its Gas
Transmission and Storage rate case in which the Utility has requested the CPUC
to establish revenue requirements for natural gas transmission and storage
services for 2011 through 2014.  (See “Regulatory Matters”
below.)





Cost
of Natural Gas




The
Utility’s cost of natural gas includes the purchase costs of natural gas,
transportation costs on interstate pipelines and intrastate pipelines, and gas
storage costs, but excludes the transportation costs for large commercial and
industrial (or “non-core”) customers, which are 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 Notes 7
and 8 of the Notes to the Condensed Consolidated Financial
Statements.)




47




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





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





The
Utility’s total cost of natural gas decreased in the three and nine months ended
September 30, 2009 by $217 million, or 62%, and by $734 million, or 46%,
respectively, compared to the same periods in 2008, primarily due to decreases
in the market price of natural gas.





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 gas may be affected by federal or state legislation or
rules to regulate the emissions of greenhouse gases from the Utility’s natural
gas transportation and distribution facilities and from natural gas consumed by
the Utility’s customers.





Operating
and Maintenance





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





The
Utility’s operating and maintenance expenses increased by $65 million, or 7%, in
the three months ended September 30, 2009, primarily due to a net increase in
employee severance costs of $50 million.  (This amount includes an
accrual of $57 million for severance costs related to the reduction of
approximately 2% of the Utility’s workforce.)  In addition, the
Utility incurred a $27 million increase in costs to perform accelerated natural
gas leak surveys and associated remedial work, as compared to the same period in
2008.  (The Utility targets completing the accelerated portion of this
survey work by the second quarter of 2010.)  The Utility also incurred
a $20 million increase in employee benefit costs (primarily driven by rising
healthcare costs) and a $6 million increase in property taxes.  These
increases were partially offset by a $20 million decrease in CAISO collateral
costs, which are passed through to customers, related to the new day-ahead
market, an $8 million decrease in public purpose program expenses, a $4 million
decrease in uncollectible customer accounts, and a $6 million decrease in other
miscellaneous operating and maintenance expenses.





The
Utility’s operating and maintenance expenses increased by $134 million, or 4%,
in the nine months ended September 30, 2009 compared to the same period in 2008,
primarily due to a net increase in employee severance costs of $65 million, a
$54 million increase in costs to perform accelerated natural gas leak surveys
and associated remedial work, a $46 million increase in employee benefit costs
(primarily driven by rising healthcare costs), and an increase of $20 million in
the accrual for employee vacation pay, as compared to the same period in
2008.  In addition, there was a $15 million increase in property
taxes, an increase of $8 million in the Utility’s uncollectible customer
accounts as a result of economic conditions and rising unemployment in the
Utility’s service territory, and a $23 million increase in other miscellaneous
operating and maintenance expenses.  These increases were partially
offset by decreases in public purpose program expenses of $59 million, and
decreases in labor costs of $38 million compared to those incurred in 2008 as a
result of the January 2008 winter storm.




48





The
Utility anticipates that it will incur higher costs in the future to improve the
safety and reliability of its electric and natural gas system infrastructure and
to maintain its aging electric distribution system.  The Utility also
expects that it will incur higher expenses in future periods to obtain permits
or comply with permitting requirements, including costs associated with renewing
FERC licenses for the Utility’s hydroelectric generation
facilities.  To help offset these increased costs, the Utility intends
to continue its efforts to identify and implement initiatives to achieve
operational efficiencies and to create future sustainable cost
savings.





Depreciation,
Amortization, and Decommissioning





The
Utility’s depreciation, amortization, and decommissioning expenses increased by
$31 million, or 7%, in the three months ended September 30, 2009 and $59
million, or 5%, in the nine months ended September 30, 2009, as compared to the
same periods in 2008.  Depreciation expense increased by $25 million
and $82 million in the three and nine months ended September 30, 2009,
respectively, primarily due to authorized capital additions and depreciation
rate changes.  In addition, amortization expense related to the energy
recovery bonds (“ERBs”) increased by $6 million in the three and nine months
ended September 30, 2009 compared to the same periods in 2008 primarily due to
increased recovery rates.  These increases were partially offset by a
decrease in decommissioning expense of $22 million in the nine months ended
September 30, 2009, as compared to the same period in 2008.  In
addition, miscellaneous amortization and decommissioning expenses decreased $7
million in the nine months ended September 30, 2009, as compared to the same
period in 2008.





The
Utility’s depreciation expense for the remainder of 2009 and 2010 is expected to
increase as a result of an overall increase in capital expenditures and
implementation of depreciation rates authorized by the
CPUC.  Depreciation expenses in subsequent years will be determined
based on rates set by the CPUC in the 2011 GRC and the 2011 Gas Transmission and
Storage rate case, and by the FERC in future TO rate cases.





Interest
Income





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





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





The
decrease in the nine months ended September 30, 2009 compared to the same period
in 2008 was partially offset by an increase of $12 million in the nine months
ended September 30, 2009 for the recovery of interest on previously incurred
costs related to the hydroelectric generation facilities.  (See
“Regulatory Matters” below.)





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





Interest
Expense





In the three and nine months ended
September 30, 2009, interest expense decreased $8 million, or 5%, and $27
million, or 5%, respectively, as compared to the same periods in 2008 primarily
due to the following factors:




49




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





These
decreases were partially offset by additional interest expense of $26 million in
the three months ended September 30, 2009, and $81 million in the nine months
ended September 30, 2009, primarily related to $1.8 billion in senior notes that
were issued in the fourth quarter of 2008 and March 2009.





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





Other
Income (Expense), Net





The Utility’s other income (expense),
net increased by $18 million, or 900%, in the three months ended September 30,
2009 and $28 million, or 117%, in the nine months ended September 30, 2009,
compared to the same periods in 2008 when the Utility incurred costs to oppose
certain legislation and municipalization efforts.  In addition, there
was an increase in the Utility’s allowance for funds used during construction
primarily due to an increase in spending related to various projects, including
the Colusa and Humboldt Bay Generating Stations.  This increase was
partially offset when the Gateway Generating Station and Diablo Canyon steam
generators replacement projects became operative in 2009 and 2008,
respectively.





Income
Tax Provision





The
Utility’s income tax provision decreased by $56 million, or 34%, for the three
months ended September 30, 2009, and $47 million, or 11%, for the nine months
ended September 30, 2009, as compared to the same periods in
2008.  The effective tax rates for the three months ended September
30, 2009 and 2008 were 23.8% and 34.1%, respectively.  The effective
tax rates for the nine months ended September 30, 2009 and 2008 were 27.6% and
32.6%, respectively.  The lower effective tax rates for the three and
nine months ended September 30, 2009 were primarily due to an increase in the
amount of tax benefits recognized in 2009 as compared to the amount of tax
benefits recognized during the three and nine months ended September 30,
2008. (See Note 11
of the Notes to the Condensed Consolidated Financial Statements for a discussion
of “Tax Matters.”)





50





PG&E
Corporation, Eliminations, and Other





Operating
Revenues and Expenses





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





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





Other
Income (Expense), Net





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





LIQUIDITY AND FINANCIAL RESOURCES





Overview





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





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





Credit
Facilities





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




51




The
following table summarizes PG&E Corporation’s and the Utility’s outstanding
commercial paper and credit facilities at September 30, 2009:





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





PG&E
Corporation’s and the Utility’s revolving credit facilities include usual and
customary covenants for credit facilities of their type, including covenants
limiting liens to those permitted under the senior note indenture, mergers,
sales of all or substantially all of the Utility’s assets, and other fundamental
changes.  In addition, both PG&E Corporation and the Utility are
required to maintain a ratio of total consolidated debt to total consolidated
capitalization of at most 65%, and PG&E Corporation must own, directly or
indirectly, at least 80% of the common stock and at least 70% of the voting
securities of the Utility.  At September 30, 2009, PG&E
Corporation and the Utility were in compliance with all covenants.





2009
Financings





In March
2009, PG&E Corporation and the Utility issued $350 million and $550 million,
respectively, of senior unsecured notes.  Proceeds from the senior
notes offerings were used to finance capital expenditures, for general working
capital, and to repay outstanding commercial paper that the Utility had issued
to pay $600 million of senior unsecured notes that matured on March 1,
2009.  On June 11, 2009, the Utility issued $500 million of floating
rate senior unsecured notes due June 10, 2010.  The net proceeds were
used to repay outstanding commercial paper that was issued to satisfy margin
calls and collateral requirements related to the Utility’s electric procurement
commodity hedging activities.  On September 1, 2009, the California
Pollution Control Financing Authority and the California Infrastructure and
Economic Development Bank (“CIEDB”) issued $309 million of tax-exempt pollution
control bonds series 2009 A through D for the benefit of the
Utility.  The Utility used the proceeds it received from the CIEDB to
repurchase the corresponding series of 2008 pollution control
bonds.  The series 2009 bonds, issued at par with an initial rate of
0.20%, are variable rate demand notes with interest resetting daily and backed
by direct-pay letters of credit.  Unlike the series 2008 bonds,
interest earned on the series 2009 bonds is not subject to the alternative
minimum tax (“AMT”).  A provision in the American Recovery and
Reinvestment Act of 2009 allows certain tax-exempt bonds that are subject to AMT
to be reissued or refunded in 2009 or 2010 as tax-exempt bonds that are not
subject to AMT.  As a result, the series 2009 bonds were issued at a
lower interest rate, reducing the Utility’s interest expense.





In
addition, PG&E Corporation issued 8,569,475 shares of common stock upon
exercise of employee stock options and under its 401(k) plan and Dividend
Reinvestment and Stock Purchase Plan (“DRSPP”), generating $211 million of cash
through September 30, 2009.  Also in 2009, PG&E Corporation
contributed $688 million of cash to the Utility to ensure that the Utility had
adequate capital to fund its capital expenditures and to maintain the 52% common
equity ratio authorized by the CPUC.





Future
Financing Needs





The
amount and timing of the Utility’s future financing needs will depend on various
factors, including the conditions in the capital markets, the timing and amount
of forecasted capital expenditures, and the amount of cash internally generated
through normal business operations, among other factors.  The
Utility’s future financing needs will also depend on the timing of the
resolution of the Chapter 11 disputed claims and the amount of interest on these
claims that the Utility will be required to pay.  (See Note 10 of the
Notes to the Condensed Consolidated Financial Statements.)





PG&E
Corporation may issue debt or equity in the future to fund the Utility’s
operating expenses and capital expenditures to the extent that internally
generated funds are not available.  Assuming that PG&E Corporation
and the Utility can access the capital markets on reasonable terms, PG&E
Corporation and the Utility believe that the Utility’s cash flow from
operations, existing sources of liquidity, and future financings will provide
adequate resources to fund operating activities, meet anticipated obligations,
and finance future capital expenditures.





Dividends





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





During
the nine months ended September 30, 2009, PG&E Corporation paid common stock
dividends totaling $435 million, net of $18 million that was reinvested in
additional shares of common stock by participants in the DRSPP.  On
September 16, 2009, the Board of Directors of PG&E Corporation declared a
dividend of $0.42 per share, totaling $156 million, which was paid on October
15, 2009 to shareholders of record on September 30, 2009.





During the nine months ended September
30, 2009, the Utility paid cash dividends totaling $10 million to holders of its
outstanding series of preferred stock.  On September 16, 2009, the
Board of Directors of the Utility declared a cash dividend totaling $3 million
on its outstanding series of preferred stock, payable on November 15, 2009, to
shareholders of record on October 30, 2009.





52





Utility





Operating
Activities





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





The
Utility’s cash flows from operating activities for the nine months ended
September 30, 2009 and 2008 were as follows:





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





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





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





Increases
in operating cash flows were partially offset by a $700 million payment to the
California Power Exchange (“PX”) to reduce the Utility’s liability for the
remaining net disputed claims (see Note 10 of the Notes to the Condensed
Consolidated Financial Statements), a refund of $230 million received by the
Utility in 2008 from the California Energy Commission (“CEC”) with no similar
refund in 2009, and the subsequent return of $172 million of the CEC refund to
customers through September 30, 2009.  (See Note 3 of the Notes to the
Condensed Consolidated Financial Statements.)





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





The
Utility’s operating cash flows also will be impacted by electricity procurement
costs and the timing of rate adjustments authorized to recover these
costs.  On October 15, 2009, the CPUC authorized the Utility to adjust
electric rates to refund $424 million to customers for an over-collection in the
Utility’s energy resource recovery balancing account by December 31,
2009.  The Utility also will update its forecasted 2010 electricity
procurement costs in late November 2009 for inclusion in the annual electric
true-up proceeding, which will adjust electric and gas rates on January 1, 2010
to (1) reflect over- and under-collections in the Utility’s major electric and
gas balancing accounts, and (2) implement various other electricity and gas
revenue requirement changes authorized by the CPUC and the FERC.





53





Investing
Activities





The
Utility’s investing activities consist of construction of new and replacement
facilities necessary to deliver safe and reliable electricity and natural gas
services to its customers.  Cash used in investing activities depends
primarily upon the amount and timing of the Utility’s capital expenditures,
which can be affected by many factors, including the timing of regulatory
approvals, the occurrence of storms and other events causing outages or damage
to the Utility’s infrastructure, and the completion of electricity and natural
gas reliability improvements projects.  Net cash used in investing
activities also include the proceeds of sales of nuclear decommissioning trust
assets largely offset by the amount of cash used to purchase new nuclear
decommissioning trust investments.





The
Utility’s cash flows from investing activities for the nine months ended
September 30, 2009 and 2008 were as follows:





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





Net cash
used in investing activities decreased by $388 million in the nine months ended
September 30, 2009 compared to the same period in 2008.  This decrease
was primarily due to a $700 million decrease in the restricted cash balance that
resulted from a payment to the PX to reduce the Utility’s liability for the
remaining net disputed claims (see Note 10 of the Notes to the Condensed
Consolidated Financial Statements), partially offset by an increase of $331
million in capital expenditures for installing the SmartMeterTM advanced metering
infrastructure, generation facility spending, replacing and expanding gas and
electric distribution systems, and improving the electric transmission
infrastructure. (See “Capital Expenditures” below.)





Future
cash flows used in investing activities are largely dependent on the timing and
amount of future capital expenditures.  (See “Capital Expenditures”
below and in the 2008 Annual Report.)





Financing
Activities





The
Utility’s cash flows from financing activities for the nine months ended
September 30, 2009 and 2008 were as follows:





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




54




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





PG&E
Corporation





With the exception of dividend
payments, interest, common stock issuance, the senior notes issuance of $350
million in March 2009, the receipt of tax refunds of $139 million, and
transactions between PG&E Corporation and the Utility, PG&E Corporation
had no material cash flows on a stand-alone basis for the nine months ended
September 30, 2009 and 2008.





CONTRACTUAL COMMITMENTS





PG&E
Corporation and the Utility enter into contractual commitments in connection
with business activities.  These future obligations primarily relate
to financing arrangements (such as long-term debt, preferred stock, and certain
forms of regulatory financing), purchases of transportation capacity, natural
gas and electricity to support customer demand, and the purchase of fuel and
transportation to support the Utility’s generation activities.  In
addition to those commitments disclosed in the 2008 Annual Report and those
arising from normal business activities, PG&E Corporation’s and the
Utility’s commitments at September 30, 2009 include $350 million of 5.75% Senior
Notes issued by PG&E Corporation due April 1, 2014, $550 million of 6.25%
Senior Notes issued by the Utility due March 1, 2039, and $500 million of
Floating Rate Senior Notes issued by the Utility due June 10,
2010.  (See the 2008 Annual Report and Notes 4, 10, and 11 of the
Notes to the Condensed Consolidated Financial Statements.)





CAPITAL EXPENDITURES





Depending
on conditions in the capital markets, the Utility forecasts that it will make
various capital investments in its electric and gas transmission and
distribution infrastructure to maintain and improve system reliability, safety,
and customer service; to extend the life of or replace existing infrastructure;
and to add new infrastructure to meet already authorized growth.  Most
of the Utility’s revenue requirements to recover forecasted capital expenditures
are authorized in the GRC and TO rate cases.  The Utility intends to
file a GRC application with the CPUC before the end of 2009 to request an
increase in authorized revenue requirements to recover capital expenditures
forecast to be made in 2011 through 2013.  (See “Regulatory Matters”
below.)  In addition, the Utility requests authorization to collect
additional revenue requirements to recover capital expenditures related to
specific projects such as new power plants, gas or electric transmission
projects, and the SmartMeterTM
advanced metering infrastructure.





Proposed
Electric Distribution Reliability Program (Cornerstone Improvement
Program)





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





SmartMeterTM
Program





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





The CPUC has authorized the Utility to
recover the $2.2 billion estimated SmartMeterTM project cost, including an
estimated capital cost of $1.8 billion.  In addition, the Utility can
recover in rates 90% of up to $100 million in costs that exceed $2.2 billion
without a reasonableness review by the CPUC.  The remaining 10% will
not be recoverable in rates.  If additional costs exceed the $100
million threshold, the Utility may request recovery of the additional costs,
subject to a reasonableness review.  Through September 30, 2009, the
Utility has spent an aggregate of $1.2 billion, including capital costs of $1.0
billion, to install the SmartMeterTM
system.




55





The
Utility’s ability to recognize the expected benefits of its SmartMeterTM
advanced metering infrastructure remains subject to a number of risks, including
whether the Utility incurs additional advanced metering project costs that the
CPUC does not find reasonable or that are not recoverable in rates, whether the
project is implemented on schedule, whether the Utility can successfully
integrate the new advanced metering system with its billing and other computer
information systems, and whether the new technology performs as
intended.





Diablo
Canyon Steam Generator Replacement Project





In
November 2005, the CPUC authorized the Utility to replace the steam generators
at the two nuclear operating units at Diablo Canyon (Units 1 and 2) and recover
costs of up to $706 million from customers without further reasonableness
review.  The Utility installed four of the new steam generators in
Unit 2 during 2008 and completed installation of the remaining new generators
for Unit 1 on March 7, 2009.  Project costs totaled approximately $690
million.





Proposed
New Generation Facilities





Request
for Long-Term Generation Resources





On
September 30, 2009, the Utility requested that the CPUC approve several
agreements executed by the Utility following the completion of its April 1, 2008
request for offers of new long-term generation resources to meet customer demand
as forecasted in the Utility’s 2007-2016 long-term electricity procurement plan
previously approved by the CPUC.  One of the agreements submitted to
the CPUC proposes that a 586 megawatt (“MW”) natural gas-fired facility be
developed and constructed by a third party and then transferred to the Utility
after commercial operation begins.  The proposed facility would be
operationally flexible, enabling the Utility to increase its use of renewable
power by balancing the fluctuating output of wind and solar
resources.  The facility is expected to be built in Oakley, California
and completed in 2014.  (The remaining agreements submitted to the
CPUC are power purchase agreements.)





Proposed
Renewable Energy Development





In its
February 24, 2009 application, the Utility has requested that the CPUC approve
the Utility’s proposed development and construction of up to 250 MW of
Utility-owned generating facilities using solar photovoltaic technology, to be
deployed over a period of five years, to help the Utility meet its obligation
under California law to increase the amount of electricity provided to customers
from renewable generation resources.  The CPUC is expected to issue a
final decision on the Utility’s application in early 2010.





OFF-BALANCE SHEET ARRANGEMENTS





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





CONTINGENCIES





PG&E
Corporation and the Utility have significant contingencies, including Chapter 11
disputed claims, tax matters, and environmental matters, which are discussed in
Notes 10 and 11 of the Notes to the Condensed Consolidated Financial
Statements.





REGULATORY MATTERS





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




56





2011
General Rate Case Application





On
October 21, 2009, the CPUC’s Division of Ratepayer Advocates (“DRA”) notified
the Utility that the DRA had conditionally accepted the Utility’s draft 2011 GRC
application that the Utility filed on July 20, 2009.  The Utility must
wait 60 days before filing the GRC application.  Assuming the Utility
timely meets the DRA’s conditions, the Utility intends to file the application
with the CPUC by the end of 2009.  The Utility intends to request that
the CPUC issue a final decision by the end of 2010.  If the decision
is delayed, the Utility will, consistent with CPUC practice in prior GRCs,
request the CPUC to issue an order directing that the revenue requirement
changes incorporated in the CPUC’s decision in the case will be effective as of
January 1, 2011, even if the decision is issued subsequent to that
date.





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





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





In the
2011 GRC, the CPUC will determine the amount of authorized base revenues that
the Utility may collect from its customers to recover its basic business and
operational costs for gas and electric distribution and electric generation
operations for the period from 2011 through 2013.  These revenue
requirements are determined based on a forecast of costs for
2011.  The draft application indicates that the Utility plans to
request a revenue increase for 2011 of $1.1 billion, or 6.5%, above the 2010
total revenue forecast.





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





The
Utility also has indicated that it will seek a ratemaking mechanism for 2012 and
2013 designed to increase the Utility’s authorized revenues in years between
GRCs to reflect increases in rate base due to capital investments in
infrastructure, and increases in wages and expenses.  The proposed
mechanism also would require revenue requirements to be adjusted to reflect
changes in franchise, payroll, income, or property tax rates, as well as new
taxes or fees imposed by governmental agencies.  The Utility estimates
that this mechanism would result in a revenue requirement increase of $244
million in 2012 and an additional increase of $326 million in
2013.  The Utility would advise the CPUC of the actual amount of these
proposed increases in October 2011 and October 2012 for years 2012 and 2013,
respectively.





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





Electric
Transmission Owner Rate Cases





On June
18, 2009, the FERC approved a settlement that sets the Utility’s annual retail
transmission base revenue requirement at $776 million, effective March 1,
2009.  (For purposes of determining wholesale transmission rates, this
retail revenue requirement is adjusted to $763.5 million.)  As part of
the settlement, the Utility will refund any over-collected amounts to customers,
with interest, through an adjustment to rates in 2011.





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





57





Energy
Efficiency Programs and Incentive Ratemaking





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





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





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





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





Spent
Nuclear Fuel





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





The
Utility believes that the existing spent fuel pools at Diablo Canyon, which
include newly constructed temporary storage racks, have sufficient capacity to
enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1
and 2011 for Unit 2.  Because the DOE failed to develop a permanent
storage site, the Utility obtained a permit from the Nuclear Regulatory
Commission (“NRC”) to build an on-site dry cask storage facility to store spent
fuel through at least 2024.  The construction of the dry cask storage
facility is complete and the movement of spent nuclear fuel to dry cask storage
began in June 2009.





After
various parties appealed the NRC’s issuance of the permit, the U.S. Court of
Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006
requiring the NRC to issue a supplemental environmental assessment report on the
potential environmental consequences in the event of a terrorist attack at
Diablo Canyon, as well as to review other contentions raised by the appealing
parties related to potential terrorism threats.  In August 2007, the
NRC staff issued a final supplemental environmental assessment report concluding
that there would be no significant environmental impacts from potential
terrorist acts directed at the Diablo Canyon storage facility.





In
October 2008, the NRC rejected the final contention that had been made during
the appeal.  The appellant has filed a petition for review of the
NRC’s order in the Ninth Circuit.  On December 31, 2008, the appellate
court granted the Utility’s request to intervene in the
proceeding.  The Utility’s brief on appeal was filed on April 8,
2009.  No date has been set for oral argument.




58





As a
result of the DOE’s failure to build a national repository for nuclear waste,
the Utility and other nuclear power plant owners sued the DOE to recover costs
that they incurred to build on-site spent nuclear fuel storage
facilities.  The Utility seeks to recover $92 million of costs that it
incurred through 2004.  After several years of litigation, the DOE now
concedes that the Utility is entitled to recover approximately $82 million of
these costs, but the DOE continues to dispute the remaining
amount.  The trial to determine the appropriate method to calculate
the amounts owed to the Utility began on October 15, 2009.  The
Utility also will seek to recover costs incurred after 2004 to build on-site
storage facilities





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





Application
to Recover Hydroelectric Facility Divestiture Costs





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





Retirement
Plan Contribution Application





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





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





Cost
of Capital Proceeding





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





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





2011
Gas Transmission and Storage Rate Case





On
September 18, 2009, the Utility filed an application with the CPUC to initiate
the Utility’s 2011 Gas Transmission and Storage rate case so that the CPUC can
determine the rates, and terms and conditions of the Utility’s gas transmission
and storage services beginning January 1, 2011.  The rates, and terms
and conditions of the Utility’s gas transmission and storage services for 2008
through 2010 were set by the terms of a CPUC-approved all-party settlement
agreement known as the Gas Accord IV that was approved by the CPUC in September
2007.  The Utility proposes to continue a majority of the Gas Accord
IV’s terms and conditions of natural gas transportation and storage
services.





The
Utility has requested that the CPUC approve a 2011 natural gas transmission and
storage revenue requirement of $529.1 million, an increase of $67.3 million over
the 2010 adopted revenue requirement.  The Utility also seeks
attrition increases for 2012, 2013, and 2014 of $32.4 million, $30.7 million,
and $22.6 million, respectively.





Under the
Utility’s proposal, a substantial portion of the authorized revenue
requirements, primarily those costs allocated to residential and small
commercial customers (called “core” customers) would continue to be assured of
recovery through balancing account mechanisms and/or fixed reservation
charges.  The Utility has proposed to simplify the current rate
structure by, among other changes, setting rates for core and “non-core”
customers based on forecast demand.  The Utility’s ability to recover
its remaining revenue requirements would continue to depend on throughput
volumes, gas prices, and the extent to which non-core customers and other
shippers contract for firm transmission services.  To reduce the
Utility’s financial risk associated with these factors, the Utility has proposed
to share equally with customers any under-collection or over-collection of
natural gas transmission and storage revenue requirements.  The
Utility has proposed additional cost recovery mechanisms for costs that are
difficult to forecast, such as the cost of electricity used to operate natural
gas compressor stations and costs to comply with greenhouse gas
regulations.





59





The
Utility has requested that the CPUC issue a final decision by the end of
2010.  If the CPUC does not issue a final decision by the end of 2010
to approve new rates effective January 1, 2011, the September 2007 CPUC
decision approving the Gas Accord IV provides that the rates and terms and
conditions of service in effect as of December 31, 2010, will remain in
effect, with an automatic 2% escalation in the rates as of January 1,
2011.





RISK MANAGEMENT ACTIVITIES





The
Utility and PG&E Corporation, mainly through its ownership of the Utility,
are exposed to market risk, which is the risk that changes in market conditions
will adversely affect net income or cash flows.  PG&E Corporation
and the Utility categorize market risks as price risk and interest rate
risk.  The Utility is also exposed to credit risk, which is the risk
that counterparties fail to perform their contractual
obligations.  For a comprehensive discussion of PG&E Corporation’s
market risk, see the section entitled “Risk Management Activities” in the 2008
Annual Report.





Price
Risk





Electricity
Procurement





On April
1, 2009, the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) became
operative.  Among other features, the MRTU established new day-ahead,
hour-ahead, and real-time wholesale electricity markets subject to bid caps that
increase over time.  The Utility expects to continue to rely on
electricity from a diverse mix of resources, including third-party contracts,
amounts allocated under DWR contracts, and its own electricity generation
facilities to meet customer demand.  A relatively small proportion of
the Utility’s total customer demand must be met through purchases in the MRTU
markets.  As a result, exposure to price volatility in the new MRTU
markets is minimal.  The CAISO must implement additional FERC-ordered
changes over the next several years.  Market risks, if any, associated
with these changes will be assessed as the design and timelines are finalized
during the 2009-2010 period.





Natural
Gas Transportation and Storage





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





The
Utility’s value-at-risk calculated under the methodology described above was $17
million at September 30, 2009.  The Utility’s high, low, and average
values-at-risk at September 30, 2009 were $34 million, $9 million, and $17
million, respectively.





Interest
Rate Risk





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





Credit
Risk





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




60





The
following table summarizes the Utility’s net credit risk exposure to its
wholesale customers and counterparties, as well as the Utility’s credit risk
exposure to its wholesale customers or counterparties with a greater than 10%
net credit exposure, at September 30, 2009 and December 31, 2008:





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





CRITICAL ACCOUNTING POLICIES





The
preparation of Condensed Consolidated Financial Statements in accordance with
GAAP involves the use of estimates and assumptions that affect the recorded
amounts of assets and liabilities as of the date of the financial statements and
the reported amounts of revenues and expenses during the reporting
period.  The accounting policies described below are considered to be
critical accounting policies, due, in part, to their complexity and because
their application is relevant and material to the financial position and results
of operations of PG&E Corporation and the Utility, and because these
policies require the use of material judgments and estimates.  Actual
results may differ substantially from these estimates.  These policies
and their key characteristics are discussed in detail in the 2008 Annual
Report.  They include:





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





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




NEW ACCOUNTING POLICIES





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





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




61




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





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





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





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





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





On January 1, 2009, PG&E
Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5,
“Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party
Credit Enhancement” (“EITF 08-5”).  EITF 08-5 clarifies the unit of
account in determining the fair value of a liability.  Specifically,
it requires an entity to exclude any third-party credit enhancements 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 the Business
Combinations Topic of the Financial Accounting Standards Board (“FASB”)
Accounting Standards Codification (“ASC”).  However, the investor in
an equity method investment could be required to recognize a liability for the
related contingent consideration features if the fair value of the investor’s
share of the investee’s net assets exceeds the investor’s initial
costs.  An equity method investor is required to recognize
other-than-temporary impairments of an equity method investment and shall
account for a share issuance by an investee as if the investor had sold a
proportionate share of its investment.  Any gain or loss to the
investor resulting from an investee’s share issuance shall be recognized in
earnings.  Adoption of EITF 08-6 did not have a material impact on
PG&E Corporation’s or the Utility’s Condensed Consolidated Financial
Statements.





Subsequent
Events





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





Interim
Disclosures about Fair Value of Financial Instruments





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




62




Recognition
and Presentation of Other-Than-Temporary Impairments





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





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





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





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





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




ACCOUNTING
PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED





Employers’
Disclosures about Postretirement Benefit Plan Assets





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





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





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





63





Amendments
to FASB Interpretation No. 46(R)





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







64






ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK




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







ITEM 4. CONTROLS AND PROCEDURES




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




There
were no changes in internal control over financial reporting that occurred
during the quarter ended September 30, 2009 that have materially affected, or
are reasonably likely to materially affect, PG&E Corporation’s or the
Utility’s internal control over financial reporting.





65







PART
II. OTHER INFORMATION





ITEM 1. LEGAL PROCEEDINGS





Complaints
Filed by the California Attorney General and the City and County of San
Francisco





The
complaint filed by the California Attorney General against PG&E Corporation
and several of its present and former directors was dismissed on March 10, 2009
and the similar complaint filed by the City and County of San Francisco was
dismissed on April 23, 2009.  For more information regarding the
resolution of these matters, see “Part I. Item 3. Legal Proceedings” in the 2008
Annual Report and “Part II, Item 1. Legal Proceedings” in PG&E Corporation’s
and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended
March 31, 2009.





ITEM 1A. RISK FACTORS





A
discussion of the significant risks associated with investments in the
securities of PG&E Corporation and the Utility is set forth under the
heading “Management’s Discussion and Analysis of Financial Condition and Results
of Operations - Risk Factors” in the 2008 Annual Report.





The
discussion of the potential impact of climate change appearing in the 2008
Annual Report under the heading “Management’s Discussion and Analysis of
Financial Condition and Results of Operations - Risk Factors” under the
following caption “The Utility’s
future operations may be impacted by climate change that may have a material
impact on the Utility’s financial condition and results of
operations”is
updated as follows to reflect new scientific evidence regarding climate
change:





A report
issued on June 16, 2009 by the U.S. Global Change Research Program (an
interagency effort led by the National Oceanic and Atmospheric Administration)
states that climate changes caused by rising emissions of carbon dioxide and
other heat-trapping gases have already been observed in the United States,
including increased frequency and severity of hot weather, reduced runoff from
snow pack, and increased sea levels.  The impact of events or
conditions caused by climate change could range widely, from highly localized to
worldwide, and the extent to which the Utility’s operations may be affected is
uncertain.  For example, if reduced snowpack decreases the Utility’s
hydroelectric generation capacity, there will be a need for additional
generation capacity from other sources.  Under certain conditions, the
events or conditions caused by climate change could result in a full or partial
disruption of the ability of the Utility, or one or more entities on which it
relies, to generate, transmit, transport or distribute electricity or natural
gas.  The Utility has been studying the potential effects of climate
change on the Utility’s operations and is developing contingency plans to adapt
to those events and conditions that the Utility believes are most likely to
occur.  Events or conditions caused by climate change could have a
greater impact on the Utility’s operations than has been forecast and could
result in lower revenues or increased expenses, or both.  If the CPUC
were to fail to adjust the Utility’s rates to reflect the impact of events or
conditions caused by climate change, PG&E Corporation’s and the Utility’s
financial condition, results of operations, and cash flows could be materially
adversely affected.





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





On July 31, 2009,
PG&E Corporation contributed equity of $35 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.





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





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







66







ITEM 5. OTHER INFORMATION







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





The
Utility’s earnings to fixed charges ratio for the nine months ended September
30, 2009 was 3.19.  The Utility’s earnings to combined fixed charges
and preferred stock dividends ratio for the nine months ended September 30, 2009
was 3.13.  The statement of the foregoing ratios, together with the
statements of the computation of the foregoing ratios filed as Exhibits 12.1 and
12.2 hereto, are included herein for the purpose of incorporating such
information and Exhibits into the Utility’s Registration Statement Nos. 33-62488
and 333-149361 relating to various series of the Utility’s first preferred stock
and its senior notes, respectively.





PG&E
Corporation’s earnings to fixed charges ratio for the nine months ended
September 30, 2009 was 2.99.  The statement of the foregoing ratio,
together with the statement of the computation of the foregoing ratio filed as
Exhibit 12.3 hereto, is included herein for the purpose of incorporating such
information and Exhibit into PG&E Corporation’s Registration Statement No.
333-149360 relating to its senior notes.







67





ITEM 6. EXHIBITS





3.1
            Bylaws
      of PG&E Corporation amended as of September 16,
20093.2
            Bylaws
      of Pacific Gas and Electric Company amended as of September 16,
      200912.1
            Computation
      of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric
      Company12.2
            Computation
      of Ratios of Earnings to Combined Fixed Charges and Preferred Stock
      Dividends for Pacific Gas and Electric Company12.3
            Computation
      of Ratios of Earnings to Fixed Charges for PG&E
      Corporation31.1
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of PG&E
      Corporation required by Section 302 of the Sarbanes-Oxley Act of
      200231.2
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of Pacific
      Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act
      of 200232.1**
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of PG&E
      Corporation required by Section 906 of the Sarbanes-Oxley Act of
      200232.2**
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of Pacific
      Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act
      of 2002**Pursuant
      to Item 601(b) (32) of SEC Regulation S-K, these Exhibits are furnished
      rather than filed with this report.







68





SIGNATURES





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








PG&E
      CORPORATIONKENT
      M. HARVEYKent
      M. Harvey
              Senior
      Vice President and Chief Financial Officer
              (duly
      authorized officer and principal financial
  officer)








PACIFIC
      GAS AND ELECTRIC COMPANYBARBARA
      L. BARCONBarbara
      L. Barcon
              Vice
      President, Finance and Chief Financial Officer
              (duly
      authorized officer and principal financial
  officer)











Dated:  October
29, 2009







69





EXHIBIT
INDEX


3.1
            Bylaws
      of PG&E Corporation amended as of September 16,
20093.2
            Bylaws
      of Pacific Gas and Electric Company amended as of September 16,
      200912.1
            Computation
      of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric
      Company12.2
            Computation
      of Ratios of Earnings to Combined Fixed Charges and Preferred Stock
      Dividends for Pacific Gas and Electric Company12.3
            Computation
      of Ratios of Earnings to Fixed Charges for PG&E
      Corporation31.1
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of PG&E
      Corporation required by Section 302 of the Sarbanes-Oxley Act of
      200231.2
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of Pacific
      Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act
      of 200232.1**
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of PG&E
      Corporation required by Section 906 of the Sarbanes-Oxley Act of
      200232.2**
            Certifications
      of the Chief Executive Officer and the Chief Financial Officer of Pacific
      Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act
      of 2002**Pursuant
      to Item 601(b) (32) of SEC Regulation S-K, these Exhibits are furnished
      rather than filed with this report.




70