UNITED
      STATES


SECURITIES
      AND EXCHANGE COMMISSION


Washington,
      D.C. 20549





**FORM
      10-Q**








[X]
            **QUARTERLY
                REPORT PURSUANT TO SECTION 13 OR 15(d) OF**
              **THE
                SECURITIES EXCHANGE ACT OF
                1934**







**For
                the quarterly period ended****June
                30, 2005**
              
              **OR**







[
                ]
            **TRANSITION
                REPORT PURSUANT TO SECTION 13 OR 15(d) OF**
              **THE
                SECURITIES EXCHANGE ACT OF 1934**








**For
                the Transition period from ________ to
                _________**








Commission
              File
                Number
            Exact
                name of registrant as specified
              in
                its charter, state of incorporation,
              address
                of principal executive offices,
              telephone
                number
            I.R.S.
              Employer
              Identification
              Number








1-16305
            **PUGET
                ENERGY, INC.**
              A
                Washington Corporation
              10885
                NE 4thStreet, Suite 1200
              Bellevue,
                Washington 98004-5591
              (425)
                454-6363
            91-1969407








1-4393
            **PUGET
                SOUND ENERGY, INC.**
              A
                Washington Corporation
              10885
                NE 4thStreet, Suite 1200
              Bellevue,
                Washington 98004-5591
              (425)
                454-6363
            91-0374630








Indicate
                by check mark whether the registrants: (1) have 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
                registrants were required to file such reports), and (2) have been
                subject
                to such filing requirements for the past 90 days.Yes
            X
            
            No





Indicate
                by check mark whether Puget Energy, Inc. is an accelerated filer
                (as
                defined in Rule 12b-2 of the Exchange Act).Yes
            X
            
            No





Indicate
                by check mark whether Puget Sound Energy, Inc. is an accelerated
                filer (as
                defined in Rule 12b-2 of the Exchange Act).Yes
            
            
            No
            X





As
      of
      July 20, 2005, (i) the number of shares of Puget Energy, Inc. common stock
      outstanding was 100,291,193 ($.01 par value) and (ii) all of the outstanding
      shares of Puget Sound Energy, Inc. common stock were held by Puget Energy,
      Inc.








**Table
        of Contents**





**Definitions****Filing
                Format****Forward
                Looking
                Statements****Part
                I.**
            **Financial
                Information****Item
                1.**
            **Financial
                Statements****Puget
                Energy, Inc.**Consolidated
                Statements of Income - Three and Six Months
                Ended
              June
                30, 2005 and 2004Consolidated
                Statements of Comprehensive Income - Three
                and Six Months Ended
              June
                30, 2005 and 2004Consolidated
                Balance Sheets - June 30,
                2005 and December 31, 2004Consolidated
                Statements of Cash Flows - Six
                Months Ended
              June
                30, 2005 and 2004**Puget
                Sound Energy, Inc.**Consolidated
                Statements of Income - Three and Six
                Months Ended
              June
                30, 2005 and 2004Consolidated
                Statements of Comprehensive Income -
                Three and Six Months Ended
              June
                30, 2005 and 2004Consolidated
                Balance Sheets - June
                30, 2005 and December 31, 2004Consolidated
                Statements of Cash Flows - Six Months
                Ended
              June
                30, 2005 and 2004**Notes**Combined
                Notes to Consolidated Financial
                Statements**Item
                2.**
            **Management’s
                Discussion and Analysis of Financial Condition**
              **and
                Results of Operations****Item
                3.**
            **Quantitative
                and Qualitative Disclosure About Market
                Risk****Item
                4.**
            **Controls
                and Procedures****Part
                II.**
            **Other
                Information****Item
                1.**
            **Legal
                Proceedings****Item
                4.**
            **Submission
                of Matters to a Vote of Security
                Holders****Item
                6.**
            **Exhibits****Signatures****Exhibit
                Index**








**DEFINITIONS**





AFUDC
            Allowance
                for Funds Used During ConstructionAPB
            Accounting
                Principles BoardCAISO
            California
                Independent System OperatorFASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy Regulatory CommissionFIN
            Financial
                Accounting Standards Board InterpretationFPA
            Federal
                Power ActInfrastruX
            InfrastruX
                Group, Inc.kWh
            Kilowatt
                HourLIBOR
            London
                Interbank Offered RateMW
            Megawatt
                (one MW equals one thousand kW)MWh
            Megawatt
                Hour (one MWh equals one thousand kWh)PCA
            Power
                Cost AdjustmentPCORC
            Power
                Cost Only Rate CasePGA
            Purchased
                Gas AdjustmentPSE
            Puget
                Sound Energy, Inc.Puget
                Energy
            Puget
                Energy, Inc.SFAS
            Statement
                of Financial Accounting StandardsWashington
                Commission
            Washington
                Utilities and Transportation
                Commission








**FILING
      FORMAT**


This
      Quarterly Report on Form 10-Q is a combined quarterly report being filed
      separately by two different registrants, Puget Energy, Inc. (Puget Energy)
      and
      Puget Sound Energy, Inc. (PSE). Any references in this report to the “Company”
      are to Puget Energy and PSE collectively. PSE makes no representation as to
      the
      information contained in this report relating to Puget Energy and the
      subsidiaries of Puget Energy other than PSE and its subsidiaries.





**FORWARD-LOOKING
        STATEMENTS**


Puget
        Energy and Puget Sound Energy (PSE) are including the following cautionary
        statements in this Form 10-Q to make applicable and to take advantage of
        the
        safe harbor provisions of the Private Securities Litigation Reform Act of
        1995
        for any forward-looking statements made by or on behalf of Puget Energy or
        PSE.
        This report includes forward-looking statements, which are statements of
        expectations, beliefs, plans, objectives, assumptions of future events or
        performance. Words or phrases such as
“anticipates,”“believes,”“estimates,”“expects,”“future,”“intends,”“plans,”“predicts,”“projects,”“will
        likely result,”“will continue” or similar expressions identify forward-looking
        statements.


Forward-looking
      statements involve risks and uncertainties that could cause actual results
      or
      outcomes to differ materially from those expressed. Puget Energy’s and PSE’s
      expectations, beliefs and projections are expressed in good faith and are
      believed by Puget Energy and PSE, as applicable, to have a reasonable basis,
      including without limitation management’s examination of historical operating
      trends, data contained in records and other data available from third parties;
      but there can be no assurance that Puget Energy’s and PSE’s expectations,
      beliefs or projections will be achieved or accomplished.


In
      addition to other factors and matters discussed elsewhere in this report, some
      important factors that could cause actual results or outcomes for Puget Energy
      and PSE to differ materially from those discussed in forward-looking statements
      include:




**Risks relating to the regulated utility business (PSE)**


·
            governmental
                policies and regulatory actions, including those of the Federal Energy
                Regulatory Commission (FERC) and the Washington Utilities and
                Transportation Commission (Washington Commission), with respect to
                allowed
                rates of return, cost recovery, industry and rate structures, transmission
                and generation business structures within PSE, acquisition and disposal
                of
                assets and facilities, operation, maintenance and construction of
                electric
                generating facilities, operation of distribution and transmission
                facilities (gas and electric), licensing of hydroelectric operations
                and
                gas storage facilities, recovery of other capital investments, recovery
                of
                power and gas costs, recovery of regulatory assets, and present or
                prospective wholesale and retail
                competition;


·
            financial
                difficulties of other energy companies and related events, which
                may
                affect the regulatory and legislative process in unpredictable ways
                and
                also adversely affect the availability of and access to capital and
                credit
                markets and/or impact delivery of energy to PSE from its
                suppliers;


·
            commodity
                price risks associated with procuring natural gas and power in wholesale
                markets to serve customer loads;


·
            wholesale
                market disruption, which may result in a deterioration of market
                liquidity, increase the risk of counterparty default, affect the
                regulatory and legislative process in unpredictable ways, negatively
                affect wholesale energy prices and/or impede PSE’s ability to manage its
                energy portfolio risks and procure energy
                supply;


·
            the
                effect of wholesale market structures (including, but not limited
                to,
                regional market designs such as Grid West, or other federal
                initiatives);


·
            PSE
                electric or gas distribution system failure, which may impact PSE’s
                ability to deliver energy supply to its
                customers;


·
            weather,
                which can have a potentially serious impact on PSE’s revenues and/or
                impact its ability to procure adequate supplies of gas, fuel or purchased
                power to serve its customers and on the cost of procuring such
                supplies;


·
            variable
                hydroelectric conditions, which can impact streamflow and PSE’s ability to
                generate electricity from hydroelectric
                facilities;


·
            plant
                outages, which can have an adverse impact on PSE’s expenses with respect
                to repair costs, added costs to replace energy or higher costs associated
                with dispatching a more expensive resource;


·
            the
                ability of gas or electric plant to operate as
                intended;


·
            the
                ability to renew contracts for electric and gas supply and the price
                of
                renewal;


·
            blackouts
                or large curtailments of transmission systems, whether PSE’s or others’,
                which can affect PSE’s ability to deliver load to its customers;


·
            the
                ability to restart generation following a regional transmission
                disruption;


·
            failure
                of the interstate gas pipeline delivering to PSE’s system, which may
                impact PSE’s ability to adequately deliver gas supply to its
                customers;


·
            the
                ability to relicense FERC hydroelectric projects at a cost-effective
                level;


·
            the
                amount of collection, if any, of PSE’s receivables from the California
                Independent System Operator (CAISO) and other parties, and the amount
                of
                refunds found to be due from PSE to the CAISO or other parties;


·
            industrial,
                commercial and residential growth and demographic patterns in the
                service
                territories of PSE;


·
            general
                economic conditions in the Pacific Northwest, which might impact
                customer
                consumption or affect PSE’s accounts receivable;
                and


·
            the
                loss of significant customers or changes in the business of significant
                customers, which may result in changes in demand for PSE’s
                services.





**Risks relating to the non-regulated utility service business (InfrastruX Group,
      Inc.)**


·
            the
                ability of Puget Energy to complete a sale of its interests in InfrastruX
                to a third party under reasonable
                terms;


·
            the
                failure of InfrastruX to service its obligations under its credit
                agreement, in which case Puget Energy, as guarantor, may be required
                to
                satisfy these obligations, which could have a negative impact on
                Puget
                Energy’s liquidity and access to
                capital;


·
            the
                inability to generate internal growth at InfrastruX, which could
                be
                affected by, among other factors, InfrastruX’s ability to expand the range
                of services offered to customers, attract new customers, increase
                the
                number of projects performed for existing customers, hire and retain
                employees and open additional
                facilities;


·
            the
                effect of competition in the industry in which InfrastruX competes,
                including from competitors that may have greater resources than
                InfrastruX, which may enable them to develop expertise, experience
                and
                resources to provide services that are superior in quality or lower
                in
                price;


·
            the
                extent to which existing electric power and gas companies or prospective
                customers will continue to outsource services in the future, which
                may be
                impacted by, among other things, regional and general economic conditions
                in the markets InfrastruX serves;


·
            delinquencies,
                including those associated with the financial conditions of InfrastruX’s
                customers;


·
            the
                impact of any goodwill impairments on the results of operations of
                InfrastruX arising from its acquisitions, which could have a negative
                effect on the results of operations of Puget
                Energy;


·
            the
                impact of adverse weather conditions that negatively affect operating
                conditions and results;


·
            the
                ability to obtain adequate bonding coverage and the cost of such
                bonding;
                and


·
            the
                perception of risk associated with its business due to a challenging
                business environment.




**Risks relating to both the regulated and non-regulated
      businesses**


·
            the
                impact of acts of terrorism or similar significant
                events;


·
            the
                ability of Puget Energy, PSE and InfrastruX to access the capital
                markets
                to support requirements for working capital, construction costs and
                the
                repayment of maturing debt;


·
            capital
                market conditions, including changes in the availability of capital
                or
                interest rate fluctuations;


·
            changes
                in Puget Energy’s or PSE’s credit ratings, which may have an adverse
                impact on the availability and cost of capital for Puget Energy,
                PSE and
                InfrastruX;


·
            legal
                and regulatory proceedings;


·
            the
                ability to recover changes in enacted federal, state or local tax
                laws
                through revenue in a timely manner;


·
            changes
                in, adoption of and compliance with laws and regulations including
                environmental and endangered species laws, regulations, decisions
                and
                policies concerning the environment, natural resources, and fish
                and
                wildlife;


·
            employee
                workforce factors, including strikes, work stoppages, availability
                of
                qualified employees or the loss of a key executive;


·
            the
                ability to obtain and keep patent or other intellectual property
                rights to
                generate revenue;


·
            the
                ability to obtain adequate insurance coverage and the cost of such
                insurance;


·
            the
                impacts of natural disasters such as earthquakes, hurricanes, floods,
                fires or landslides;


·
            the
                ability to maintain effective internal controls over financial reporting;
                and


·
            the
                ability to maintain customers and
                employees.





Any
      forward-looking statement speaks only as of the date on which such statement
      is
      made, and, except as required by law, Puget Energy and PSE undertake no
      obligation to update any forward-looking statement to reflect events or
      circumstances after the date on which such statement is made or to reflect
      the
      occurrence of unanticipated events. New factors emerge from time to time and
      it
      is not possible for management to predict all such factors, nor can it assess
      the impact of any such factor on the business or the extent to which any factor,
      or combination of factors, may cause results to differ materially from those
      contained in any forward-looking statement.


**PART
        I****FINANCIAL
        INFORMATION**


Item
      1.**Financial
      Statements**





**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF INCOME


(Dollars
      in thousands except per share amounts)


(Unaudited)





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2005
            
            2004
            
            2005
            
            2004Operating
                Revenues:Electric
            $
            345,420
            
            $
            303,091
            
            $
            765,511
            
            $
            695,587Gas
            
            162,567
            
            
            119,479
            
            
            483,695
            
            
            395,170Other
            
            2,127
            
            
            553
            
            
            2,561
            
            
            1,080Total
                operating revenues
            
            510,114
            
            
            423,123
            
            
            1,251,767
            
            
            1,091,837Operating
                Expenses:Energy
                costs:Purchased
                electricity
            
            178,943
            
            
            173,847
            
            
            387,122
            
            
            370,214Electric
                generation fuel
            
            12,894
            
            
            21,014
            
            
            33,342
            
            
            35,002Residential
                exchange
            
            (37,105
            )
            
            (35,362
            )
            
            (92,151
            )
            
            (89,785
            )Purchased
                gas
            
            98,142
            
            
            63,703
            
            
            299,887
            
            
            226,109Unrealized
                net gain on derivative instruments
            
            (591
            )
            
            (2,849
            )
            
            (82
            )
            
            (2,936
            )Utility
                operations and maintenance
            
            83,132
            
            
            73,201
            
            
            158,654
            
            
            147,056Other
                operations and maintenance
            
            558
            
            
            500
            
            
            1,299
            
            
            983Depreciation
                and amortization
            
            59,657
            
            
            56,569
            
            
            117,734
            
            
            112,439Conservation
                amortization
            
            5,951
            
            
            4,809
            
            
            11,113
            
            
            12,999Taxes
                other than income taxes
            
            50,521
            
            
            42,550
            
            
            120,221
            
            
            106,774Income
                taxes
            
            6,093
            
            
            (5,434
            )
            
            52,175
            
            
            33,665Total
                operating expenses
            
            458,195
            
            
            392,548
            
            
            1,089,314
            
            
            952,520Operating
                Income
            
            51,919
            
            
            30,575
            
            
            162,453
            
            
            139,317Other
                income (deductions):Other
                income
            
            1,598
            
            
            1,570
            
            
            2,762
            
            
            1,638Interest
                charges:AFUDC
            
            2,041
            
            
            1,079
            
            
            3,503
            
            
            2,157Interest
                expense
            
            (43,568
            )
            
            (42,921
            )
            
            (84,611
            )
            
            (86,042
            )Mandatorily
                redeemable securities interest expense
            
            (23
            )
            
            (23
            )
            
            (45
            )
            
            (45
            )Income
                (loss) from continuing operations
            
            11,967
            
            
            (9,720
            )
            
            84,062
            
            
            57,025Income
                from discontinued operations, net of tax
            
            1,928
            
            
            2,940
            
            
            909
            
            
            2,560Net
                income (loss)
            $
            13,895
            
            $
            (6,780
            )
            $
            84,971
            
            $
            59,585Common
                shares outstanding weighted average (in thousands)
            
            100,157
            
            
            99,371
            
            
            100,058
            
            
            99,271Diluted
                common shares outstanding weighted average (in thousands)
            
            100,690
            
            
            99,371
            
            
            100,590
            
            
            99,786Basic
                earnings per common share from continuing operations
            $
            0.12
            
            $
            (0.10
            )
            $
            0.84
            
            $
            0.57Basic
                earnings per common share from discontinued operations
            
            0.02
            
            
            0.03
            
            
            0.01
            
            
            0.03Basic
                earnings per common share
            $
            0.14
            
            $
            (0.07
            )
            $
            0.85
            
            $
            0.60Diluted
                earnings per common share from continuing operations
            $
            0.12
            
            $
            (0.10
            )
            $
            0.83
            
            $
            0.57Diluted
                earnings per common share from discontinued operations
            
            0.02
            
            
            0.03
            
            
            0.01
            
            
            0.03Diluted
                earnings per common share
            $
            0.14
            
            $
            (0.07
            )
            $
            0.84
            
            $
            0.60





*The
      accompanying notes are an integral part of the financial
      statements.*





**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2005
            
            2004
            
            2005
            
            2004Net
                income (loss)
            $
            13,895
            
            $
            (6,780
            )
            $
            84,971
            
            $
            59,585Other
                comprehensive income, net of tax at 35%:Foreign
                currency translation adjustment
            
            (15
            )
            
            (25
            )
            
            (12
            )
            
            240Unrealized
                gains (losses) on derivative instruments during the period
            
            (8,281
            )
            
            4,255
            
            
            10,589
            
            
            11,560Reversal
                of unrealized gains (losses) on derivative instruments settled
              during
                the
                period
            
            6,139
            
            
            (1,511
            )
            
            1,110
            
            
            (4,081
            )Loss
                from settlement of cash flow hedge contracts
            
            (22,960
            )
            
            --
            
            
            (22,960
            )
            
            --Amortization
                of cash flow hedge contracts to earnings
            
            72
            
            
            --
            
            
            72
            
            
            --Deferral
                of cash flow hedges related to the power cost adjustment
              mechanism
            
            13,539
            
            
            2,002
            
            
            7,976
            
            
            (2,686
            )Other
                comprehensive income (loss)
            
            (11,506
            )
            
            4,721
            
            
            (3,225
            )
            
            5,033Comprehensive
                income (loss)
            $
            2,389
            
            $
            (2,059
            )
            $
            81,746
            
            $
            64,618





*The
      accompanying notes are an integral part of the financial
      statements.* ****


**PUGET
        ENERGY,
        INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





June
                30,
              2005
            
            December
                31,
              2004Utility
                Plant: (at original cost, including construction work in progress
                of
              $205,541
                and $129,966,
                respectively)Electric
            
            $
            4,495,814
            
            $
            4,389,882Gas
            
            
            1,937,595
            
            
            1,881,768Common
            
            
            416,119
            
            
            409,677Less:
                Accumulated depreciation and amortization
            
            
            (2,522,339
            )
            
            (2,452,969
            )Net
                utility plant
            
            
            4,327,189
            
            
            4,228,358Other
                property and investments
            
            
            159,085
            
            
            157,670Current
                assets:Cash
            
            
            16,616
            
            
            12,955Restricted
                cash
            
            
            1,105
            
            
            1,633Accounts
                receivable, net of allowance for doubtful accounts
            
            
            203,523
            
            
            137,659Unbilled
                revenue
            
            
            73,295
            
            
            140,391Purchased
                gas adjustment receivable
            
            
            32,563
            
            
            19,088Materials
                and supplies, at average cost
            
            
            98,380
            
            
            97,578Unrealized
                gain on derivative instruments
            
            
            37,171
            
            
            14,791Prepayments
                and other
            
            
            18,037
            
            
            6,858Deferred
                income taxes
            
            
            --
            
            
            1,415Current
                assets of discontinued operations
            
            
            116,670
            
            
            110,922Total
                current assets
            
            
            597,360
            
            
            543,290Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            138,347
            
            
            127,252Regulatory
                asset for PURPA contract buyout costs
            
            
            201,205
            
            
            211,241Unrealized
                gain on derivative instruments
            
            
            29,600
            
            
            21,315Power
                cost adjustment mechanism
            
            
            5,518
            
            
            --Other
            
            
            389,856
            
            
            401,795Long-term
                assets of discontinued operations
            
            
            164,990
            
            
            160,298Total
                other long-term assets
            
            
            929,516
            
            
            921,901Total
                assets
            
            $
            6,013,150
            
            $
            5,851,219





*The
      accompanying notes are an integral part of the financial
      statements.*


**PUGET
        ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**CAPITALIZATION
      AND LIABILITIES**





June
                30,
              2005
            
            December
                31,
              2004Capitalization:Common
                shareholders’ investment:Common
                stock $0.01 par value, 250,000,000 shares authorized, 100,285,742
                and
              99,868,368
                shares outstanding, respectively
            
            $
            1,003
            
            $
            999Additional
                paid-in capital
            
            
            1,630,524
            
            
            1,621,756Earnings
                reinvested in the business
            
            
            48,842
            
            
            13,853Accumulated
                other comprehensive loss, net of tax at 35%
            
            
            (17,557
            )
            
            (14,332
            )Total
                shareholders’ equity
            
            
            1,662,812
            
            
            1,622,276Redeemable
                securities and long-term debt:Preferred
                stock subject to mandatory redemption
            
            
            1,889
            
            
            1,889Junior
                subordinated debentures of the corporation payable to a subsidiary
                trust
              holding
                mandatorily
                redeemable preferred securities
            
            
            237,750
            
            
            280,250Long-term
                debt
            
            
            2,073,360
            
            
            2,069,360Total
                redeemable securities and long-term debt
            
            
            2,312,999
            
            
            2,351,499Total
                capitalization
            
            
            3,975,811
            
            
            3,973,775Minority
                interest in discontinued operations
            
            
            5,346
            
            
            4,648Current
                liabilities:Accounts
                payable
            
            
            146,537
            
            
            226,478Short-term
                debt
            
            
            159,623
            
            
            --Current
                maturities
                of long-term debt
            
            
            77,000
            
            
            31,000Accrued
                expenses:Taxes
            
            
            97,440
            
            
            81,315Salaries
                and wages
            
            
            14,310
            
            
            13,829Interest
            
            
            28,045
            
            
            29,005Unrealized
                loss on
                derivative instruments
            
            
            13,948
            
            
            26,581Deferred
                income
                taxes
            
            
            451
            
            
            --Tenaska
                disallowance reserve
            
            
            --
            
            
            3,156Other
            
            
            32,021
            
            
            34,918Current
                liabilities
                of discontinued operations
            
            
            61,232
            
            
            51,892Total
                current
                liabilities
            
            
            630,607
            
            
            498,174Long-term
                liabilities:Deferred
                income
                taxes
            
            
            799,760
            
            
            795,291Long-term
                portion
                of unrealized loss on derivative instruments
            
            
            83
            
            
            385Other
                deferred
                credits
            
            
            419,319
            
            
            395,236Long-term
                liabilities of discontinued operations
            
            
            182,224
            
            
            183,710Total
                long-term liabilities
            
            
            1,401,386
            
            
            1,374,622Total
                capitalization and liabilities
            
            $
            6,013,150
            
            $
            5,851,219





*The
      accompanying notes are an integral part of the financial
      statements.*


**PUGET
        ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF CASH FLOWS


(Dollars
      in thousands)


(Unaudited)





Six
                Months Ended
              June
                30,2005
            
            2004Operating
                activities:Net
                income
            
            $
            84,971
            
            $
            59,585Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation
                and amortization
            
            
            117,734
            
            
            121,410Deferred
                income taxes and tax credits, net
            
            
            (3,301
            )
            
            27,238Net
                unrealized gain on derivative instruments
            
            
            (82
            )
            
            (2,936
            )Cash
                collateral received from energy suppliers
            
            
            2,950
            
            
            5,020Increase
                (decrease) in residential exchange program
            
            
            4,377
            
            
            (1,651
            )Impairment
                on InfrastruX investment
            
            
            5,110
            
            
            --Other
            
            
            20,081
            
            
            21,144Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            (1,172
            )
            
            154,567Materials
                and supplies
            
            
            (804
            )
            
            (13,918
            )Prepayments
                and other
            
            
            (15,795
            )
            
            (5,331
            )Purchased
                gas adjustment receivable
            
            
            (13,474
            )
            
            (21,731
            )Accounts
                payable
            
            
            (81,051
            )
            
            (62,446
            )Taxes
                payable
            
            
            20,779
            
            
            (13,507
            )Tenaska
                disallowance reserve
            
            
            (3,156
            )
            
            13,642Accrued
                expenses and other
            
            
            (552
            )
            
            5,833Net
                cash provided by operating activities
            
            
            136,615
            
            
            286,919Investing
                activities:Construction
                and capital expenditures - excluding equity AFUDC
            
            
            (221,369
            )
            
            (235,201
            )Energy
                efficiency expenditures
            
            
            (15,611
            )
            
            (8,338
            )Refundable
                cash received for customer construction projects
            
            
            6,137
            
            
            4,810Restricted
                cash
            
            
            527
            
            
            695Other
            
            
            18,492
            
            
            (4,696
            )Net
                cash used by investing activities
            
            
            (211,824
            )
            
            (242,730
            )Financing
                activities:Change
                in short-term debt, net
            
            
            163,749
            
            
            38,521Dividends
                paid
            
            
            (43,910
            )
            
            (43,288
            )Issuance
                of common stock
            
            
            2,714
            
            
            2,848Issuance
                of bonds
            
            
            250,000
            
            
            136,000Redemption
                of bonds and notes
            
            
            (203,456
            )
            
            (187,004
            )Redemption
                of trust preferred stock
            
            
            (42,500
            )
            
            --Settlement
                of cash flow hedge derivative on treasury rate lock
            
            
            (35,323
            )
            
            --Issuance
                and redemption costs of bonds and other
            
            
            (11,500
            )
            
            (1,417
            )Net
                cash provided (used) by financing activities
            
            
            79,774
            
            
            (54,340
            )Net
                increase (decrease) in cash
            
            
            4,565
            
            
            (10,151
            )Change
                in cash from discontinued operations
            
            
            (904
            )
            
            5,386Cash
                at beginning of year
            
            
            12,955
            
            
            14,778Cash
                at end of period
            
            $
            16,616
            
            $
            10,013Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            89,742
            
            $
            88,763Income
                taxes
            
            
            32,682
            
            
            16,651





*The
      accompanying notes are an integral part of the financial
      statements.*





**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2005
            
            2004
            
            2005
            
            2004Operating
                revenues:Electric
            
            $
            345,420
            
            $
            303,091
            
            $
            765,511
            
            $
            695,587Gas
            
            
            162,567
            
            
            119,479
            
            
            483,695
            
            
            395,170Other
            
            
            2,127
            
            
            553
            
            
            2,561
            
            
            1,080Total
                operating revenues
            
            
            510,114
            
            
            423,123
            
            
            1,251,767
            
            
            1,091,837Operating
                expenses:Energy
                costs:Purchased
                electricity
            
            
            178,943
            
            
            173,847
            
            
            387,122
            
            
            370,214Electric
                generation fuel
            
            
            12,894
            
            
            21,014
            
            
            33,342
            
            
            35,002Residential
                exchange
            
            
            (37,105
            )
            
            (35,362
            )
            
            (92,151
            )
            
            (89,785
            )Purchased
                gas
            
            
            98,142
            
            
            63,703
            
            
            299,887
            
            
            226,109Unrealized
                net gain on derivative instruments
            
            
            (591
            )
            
            (2,849
            )
            
            (82
            )
            
            (2,936
            )Utility
                operations and maintenance
            
            
            83,132
            
            
            73,201
            
            
            158,654
            
            
            147,056Other
                operations and maintenance
            
            
            241
            
            
            273
            
            
            500
            
            
            572Depreciation
                and amortization
            
            
            59,657
            
            
            56,569
            
            
            117,734
            
            
            112,439Conservation
                amortization
            
            
            5,951
            
            
            4,809
            
            
            11,113
            
            
            12,999Taxes
                other than income taxes
            
            
            50,521
            
            
            42,550
            
            
            120,221
            
            
            106,774Income
                taxes
            
            
            6,285
            
            
            (5,336
            )
            
            52,830
            
            
            33,844Total
                operating expenses
            
            
            458,070
            
            
            392,419
            
            
            1,089,170
            
            
            952,288Operating
                income
            
            
            52,044
            
            
            30,704
            
            
            162,597
            
            
            139,549Other
                income (deductions):Other
                income, net of tax
            
            
            1,598
            
            
            1,570
            
            
            2,762
            
            
            1,638Interest
                charges:AFUDC
            
            
            2,041
            
            
            1,079
            
            
            3,503
            
            
            2,157Interest
                expense
            
            
            (43,494
            )
            
            (42,870
            )
            
            (84,469
            )
            
            (85,940
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )
            
            (45
            )
            
            (45
            )Net
                income (loss)
            
            $
            12,166
            
            $
            (9,540
            )
            $
            84,348
            
            $
            57,359





*The
      accompanying notes are an integral part of the financial
      statements.*





**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2005
            
            2004
            
            2005
            
            2004Net
                income (loss)
            $
            12,166
            
            $
            (9,540
            )
            $
            84,348
            
            $
            57,359Other
                comprehensive income, net of tax at 35%:Unrealized
                gains (losses) on derivative instruments during the period
            
            (8,281
            )
            
            4,255
            
            
            10,589
            
            
            11,560Reversal
                of unrealized gains (losses) on derivative instruments
              settled
                during the
                period
            
            6,139
            
            
            (1,511
            )
            
            1,110
            
            
            (4,081
            )Loss
                from settlement of cash flow hedge contracts
            
            (22,960
            )
            
            --
            
            
            (22,960
            )
            
            --Amortization
                of cash flow hedge contracts to earnings
            
            72
            
            
            --
            
            
            72
            
            
            --Deferral
                of cash flow hedges related to the power cost adjustment
              mechanism
            
            13,539
            
            
            2,002
            
            
            7,976
            
            
            (2,686
            )Other
                comprehensive income (loss)
            
            (11,491
            )
            
            4,746
            
            
            (3,213
            )
            
            4,793Comprehensive
                income (loss)
            $
            675
            
            $
            (4,794
            )
            $
            81,135
            
            $
            62,152





*The
      accompanying notes are an integral part of the financial
      statements.*





**PUGET
      SOUND ENERGY,
      INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





June
                30,
              2005
            
            December
                31,
              2004Utility
                plant: (at original cost, including construction work in progress
                of
              $205,541
                and $129,966,
                respectively)Electric
            
            $
            4,495,814
            
            $
            4,389,882Gas
            
            
            1,937,595
            
            
            1,881,768Common
            
            
            416,119
            
            
            409,677Less:
                Accumulated depreciation and amortization
            
            
            (2,522,339
            )
            
            (2,452,969
            )Net
                utility plant
            
            
            4,327,189
            
            
            4,228,358Other
                property and investments
            
            
            159,085
            
            
            157,670Current
                assets:Cash
            
            
            16,616
            
            
            12,955Restricted
                cash
            
            
            1,105
            
            
            1,633Accounts
                receivable, net of allowance for doubtful accounts
            
            
            204,168
            
            
            138,792Unbilled
                revenue
            
            
            73,295
            
            
            140,391Purchased
                gas adjustment receivable
            
            
            32,563
            
            
            19,088Materials
                and supplies, at average cost
            
            
            98,380
            
            
            97,578Unrealized
                gain on derivative instruments
            
            
            37,171
            
            
            14,791Prepayments
                and other
            
            
            17,423
            
            
            6,247Deferred
                income taxes
            
            
            --
            
            
            1,415Total
                current assets
            
            
            480,721
            
            
            432,890Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            138,347
            
            
            127,252Regulatory
                asset for PURPA contract buyout costs
            
            
            201,205
            
            
            211,241Unrealized
                gain on derivative instruments
            
            
            29,600
            
            
            21,315Power
                cost adjustment mechanism
            
            
            5,518
            
            
            --Other
            
            
            389,246
            
            
            401,030Total
                other long-term assets
            
            
            763,916
            
            
            760,838Total
                assets
            
            $
            5,730,911
            
            $
            5,579,756





*The
      accompanying notes are an integral part of the financial
      statements.*





**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**CAPITALIZATION
      AND LIABILITIES**





June
                30,
              2005
            
            December
                31,
              2004Capitalization:Common
                shareholder’s investment:Common
                stock ($10 stated value) - 150,000,000 shares authorized,
              85,903,791
                shares
                outstanding
            
            $
            859,038
            
            $
            859,038Additional
                paid-in capital
            
            
            611,892
            
            
            609,467Earnings
                reinvested in the business
            
            
            177,987
            
            
            138,678Accumulated
                other comprehensive loss, net of tax at 35%
            
            
            (17,963
            )
            
            (14,750
            )Total
                shareholder’s equity
            
            
            1,630,954
            
            
            1,592,433Redeemable
                securities and long-term debt:Preferred
                stock
                subject to mandatory redemption
            
            
            1,889
            
            
            1,889Junior
                subordinated debentures of the corporation payable to a subsidiary
              trust
                holding
                mandatorily redeemable preferred securities
            
            
            237,750
            
            
            280,250Long-term
                debt
            
            
            2,068,360
            
            
            2,064,360Total
                redeemable securities and long-term debt
            
            
            2,307,999
            
            
            2,346,499Total
                capitalization
            
            
            3,938,953
            
            
            3,938,932Current
                liabilities:Accounts
                payable
            
            
            149,806
            
            
            229,747Short-term
                debt
            
            
            159,623
            
            
            --Current
                maturities of long-term debt
            
            
            77,000
            
            
            31,000Accrued
                expenses:Taxes
            
            
            98,904
            
            
            81,634Salaries
                and
                wages
            
            
            14,310
            
            
            13,829Interest
            
            
            28,045
            
            
            29,005Unrealized
                loss
                on derivative instruments
            
            
            13,948
            
            
            26,581Deferred
                income
                taxes
            
            
            451
            
            
            --Tenaska
                disallowance reserve
            
            
            --
            
            
            3,156Other
            
            
            30,586
            
            
            34,918Total
                current liabilities
            
            
            572,673
            
            
            449,870Long-term
                liabilities:Deferred
                income
                taxes
            
            
            799,973
            
            
            795,392Unrealized
                loss
                on derivative instruments
            
            
            83
            
            
            385Other
                deferred credits
            
            
            419,229
            
            
            395,177Total
                long-term liabilities
            
            
            1,219,285
            
            
            1,190,954Total
                capitalization and liabilities
            
            $
            5,730,911
            
            $
            5,579,756





*The
      accompanying notes are an integral part of the financial
      statements.*


**PUGET
        SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF CASH FLOWS


(Dollars
      in thousands)


(Unaudited)





Six
                Months Ended
              June
                30,2005
            
            2004Operating
                activities:Net
                income
            
            $
            84,348
            
            $
            57,359Adjustments
                to reconcile net income to net cash
              provided by operating activities:Depreciation
                and amortization
            
            
            117,734
            
            
            112,439Deferred
                income taxes and tax credits, net
            
            
            (2,877
            )
            
            27,426Net
                unrealized gain on derivative instruments
            
            
            (82
            )
            
            (2,936
            )Cash
                collateral received from energy suppliers
            
            
            2,950
            
            
            5,020Increase
                (decrease) in residential exchange program
            
            
            4,377
            
            
            (1,651
            )Other
            
            
            13,951
            
            
            21,957Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            1,721
            
            
            169,604Materials
                and supplies
            
            
            (803
            )
            
            (13,190
            )Prepayments
                and other
            
            
            (11,177
            )
            
            (67
            )Purchased
                gas adjustment receivable
            
            
            (13,474
            )
            
            (21,731
            )Accounts
                payable
            
            
            (79,941
            )
            
            (61,895
            )Taxes
                payable
            
            
            17,269
            
            
            (17,212
            )Tenaska
                disallowance reserve
            
            
            (3,156
            )
            
            13,642Accrued
                expenses and other
            
            
            (4,811
            )
            
            3,724Net
                cash provided by operating activities
            
            
            126,029
            
            
            292,489Investing
                activities:Construction
                expenditures - excluding equity AFUDC
            
            
            (212,054
            )
            
            (224,579
            )Energy
                efficiency expenditures
            
            
            (15,611
            )
            
            (8,338
            )Restricted
                cash
            
            
            527
            
            
            695Refundable
                cash received for customer construction projects
            
            
            6,137
            
            
            4,810Other
            
            
            18,507
            
            
            (4,871
            )Net
                cash used by investing activities
            
            
            (202,494
            )
            
            (232,283
            )Financing
                activities:Change
                in short-term debt, net
            
            
            159,623
            
            
            28,100Dividends
                paid
            
            
            (45,039
            )
            
            (44,114
            )Issuance
                of bonds
            
            
            250,000
            
            
            --Settlement
                of cash flow hedge derivative on treasury rate lock
            
            
            (35,323
            )
            
            --Redemption
                of trust preferred stock
            
            
            (42,500
            )
            
            --Redemption
                of bonds and notes
            
            
            (200,000
            )
            
            (50,197
            )Issuance
                and redemption cost of bonds and other
            
            
            (6,635
            )
            
            1,240Net
                cash provided (used) by financing activities
            
            
            80,126
            
            
            (64,971
            )Net
                increase (decrease) in cash
            
            
            3,661
            
            
            (4,765
            )Cash
                at beginning of year
            
            
            12,955
            
            
            14,778Cash
                at end of period
            
            $
            16,616
            
            $
            10,013Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            85,581
            
            $
            87,249Income
                taxes
            
            
            32,682
            
            
            16,651





*The
      accompanying notes are an integral part of the financial
      statements* *.*







**COMBINED
        NOTES TO CONSOLIDATED FINANCIAL
        STATEMENTS**








**(1)**
            **Summary
                of Consolidation Policy**





Basis
      of
      Presentation


Puget
      Energy is an exempt public utility holding company under the Public Utility
      Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and
      has
      a 90.9% ownership interest in InfrastruX Group, Inc. (InfrastruX). PSE is a
      public utility incorporated in the State of Washington and furnishes electric
      and gas services in a territory covering 6,000 square miles, primarily in the
      Puget Sound region. InfrastruX is a non-regulated utility construction services
      company incorporated in the State of Washington, which provides construction
      services to the electric and gas utility industries primarily in the Midwest,
      Texas, south-central and eastern United States regions.


The
      consolidated financial statements of Puget Energy include the accounts of Puget
      Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the
      common shares of PSE and holds a 90.9% interest in InfrastruX. The results
      of
      PSE and InfrastruX are presented on a consolidated basis. The financial position
      and results of operations for InfrastruX have been presented as a discontinued
      operation (see Note 2). PSE’s consolidated financial statements include the
      accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively
      referred to herein as “the Company.” The consolidated financial statements are
      presented after elimination of all significant intercompany items and
      transactions. Certain amounts previously reported have been reclassified to
      conform with current year presentations with no effect on total equity or net
      income.


The
      consolidated financial statements contained in this Form 10-Q are unaudited.
      In
      the respective opinions of the management of Puget Energy and PSE, all
      adjustments necessary for a fair statement of the results for the interim
      periods have been reflected and were of a normal recurring nature. These
      condensed financial statements should be read in conjunction with the audited
      financial statements (and the Combined Notes thereto) included in the combined
      Puget Energy and PSE annual report on Form 10-K for the year ended December
      31,
      2004. Puget Energy previously had two reportable segments which included
      regulated utility operations (PSE) and utility construction services
      (InfrastruX). With the treatment of InfrastruX as a discontinued operation,
      Puget Energy now only has one reportable segment.


The
      preparation of financial statements in conformity with generally accepted
      accounting principles requires management to make estimates and assumptions
      that
      affect the reported amounts of assets and liabilities, disclosure of contingent
      assets and liabilities at the date of the financial statements, and the reported
      amounts of revenues and expenses during the reporting period. Actual results
      could differ from those estimates.








**(2)**
            **Discontinued
                Operations**(Puget
                Energy Only)





Following
      a strategic review of Puget Energy’s unregulated subsidiary, InfrastruX, on
      February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility
      construction services sector. Puget Energy intends to monetize its interest
      in
      InfrastruX through a sale and to invest the proceeds of such monetization in
      its
      regulated utility subsidiary, PSE. This planned disposal meets the criteria
      established for recognition as a discontinued operation under Statement of
      Financial Accounting Standard (SFAS) No. 144, “Accounting for the Impairment or
      Disposal of Long-Lived Assets.” Puget Energy has initiated discussions with
      interested financial and strategic parties who are in various stages of the
      due
      diligence process.  The disposal is expected to be completed
      during
      2005.


The
      following amounts related to InfrastruX have been segregated from continuing
      operations and reflected as discontinued operations:





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,(Dollars
                in
                thousands)
            2005
            
            2004
            
            2005
            
            2004Revenues
            $
            97,307
            
            $
            92,816
            
            $
            174,998
            
            $
            167,571Operating expenses (including interest expense)
            
            (90,654
            )
            
            (87,083
            )
            
            (170,087
            )
            
            (162,647
            )Pre-tax income
            
            6,653
            
            
            5,733
            
            
            4,911
            
            
            4,924Income
                tax
                expense
            
            (4,028
            )
            
            (2,504
            )
            
            (3,302
            )
            
            (2,118
            )Minority
                interest
                in income of discontinued operations
            
            (697
            )
            
            (289
            )
            
            (700
            )
            
            (246
            )Income
                from
                discontinued operations
            $
            1,928
            
            $
            2,940
            
            $
            909
            
            $
            2,560








Income
      from discontinued operations includes a charge of $1.1 million after-tax
      recorded in the first quarter 2005 related to estimated disposal of InfrastruX
      and a $5.1 million after-tax charge recorded in the second quarter 2005 to
      adjust Puget Energy's carrying value of InfrastruX to the estimated fair value.
      In accordance with SFAS No. 144, InfrastruX discontinued depreciation and
      amortization of its assets effective February 8, 2005. This discontinuation
      of
      depreciation and amoritization resulted in $4.7 million ($2.9 million after-tax)
      and $7.3 million ($4.5 million after-tax) lower depreciation and amortization
      expense than otherwise would have been recorded as continuing operations for
      the
      three and six months ended June 30, 2005, respectively.


InfrastruX’s
      summarized balance sheets, excluding intercompany balances eliminated in
      consolidation, are as follows:


(Dollars
                in thousands)
            
            June
                30,
              2005
            
            December
                31,
              2004Assets:Cash
            
            $
            7,721
            
            $
            6,817Accounts
                receivable
            
            
            81,051
            
            
            78,646Other
                current assets
            
            
            27,898
            
            
            25,459Total
                current assets
            
            
            116,670
            
            
            110,922Goodwill
            
            
            43,886
            
            
            43,503Intangibles
            
            
            15,693
            
            
            16,680Non-utility
                property and other
            
            
            105,411
            
            
            100,115Total
                long-term assets
            
            
            164,990
            
            
            160,298Total
                assets
            
            $
            281,660
            
            $
            271,220Liabilities:Accounts
                payable
            
            $
            8,663
            
            $
            9,773Short-term
                debt
            
            
            12,423
            
            
            8,297Current
                maturities of long-term debt
            
            
            6,778
            
            
            7,933Other
                current liabilities
            
            
            33,368
            
            
            25,889Total
                current liabilities
            
            
            61,232
            
            
            51,892Deferred
                income taxes
            
            
            23,335
            
            
            25,828Long-term
                debt
            
            
            140,871
            
            
            143,172Other
                deferred credits
            
            
            18,018
            
            
            14,710Total
                long-term liabilities
            
            
            182,224
            
            
            183,710Total
                liabilities
            
            $
            243,456
            
            $
            235,602








**(3)**
            **Earnings
                per Common Share**(Puget
                Energy Only)





Puget
      Energy’s basic earnings per common share have been computed based on weighted
      average common shares outstanding of 100,157,000 and 100,058,000 for the three
      and six months ended June 30, 2005, respectively, and 99,371,000 and 99,271,000
      for the three and six months ended June 30, 2004, respectively.


Puget
      Energy’s diluted earnings per common share have been computed based on weighted
      average common shares outstanding of 100,690,000 and 100,590,000 for the three
      and six months ended June 30, 2005, respectively, and 99,371,000 and 99,786,000
      for the three and six months ended June 30, 2004, respectively. These shares
      include the dilutive effect of securities related to employee and director
      equity plans.








**(4)**
            **Accounting
                for Derivative Instruments and Hedging
                Activities**





SFAS
      No.
      133, “Accounting for Derivative Instruments and Hedging Activities,” as amended
      by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to
      be
      derivative instruments be recorded on the balance sheet at their fair value,
      except for the normal purchase normal sale exception. The Company enters into
      both physical and financial contracts to manage its energy resource portfolio
      and interest rate exposure including forward physical and financial contracts,
      option contracts and swaps. The majority of physical delivered contracts
      qualify for the normal purchase normal sale exception. Those contracts that
      do
      not meet normal purchase normal sale exception or cash flow hedge criteria
      are
      marked-to-market to current earnings in the income statement, subject to
      deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of
      Regulation,” for energy related derivatives due to the $40 million cap of the
      Power Cost Adjustment (PCA) mechanism. Contracts that settle either prior to
      reaching the projected or actual $40 million PCA mechanism cap or after June
      30,
      2006 have 100% of the mark-to-market adjustment recorded in the income
      statement. Contracts that settle after reaching the projected or actual $40
      million PCA mechanism cap up until June 30, 2006 have 99% of the mark-to-market
      adjustment deferred to the balance sheet, with the remaining 1% recorded in
      the
      income statement.


The
      nature of serving regulated electric customers with its wholesale portfolio
      of
      owned and contracted resources exposes the Company and its customers to some
      volumetric and commodity price risks within the sharing mechanism of the PCA.
      The Company’s energy risk management function monitors and manages these risks
      using analytical models and tools. The Company’s energy risk management staff
      develops hedging strategies for the Company’s energy supply portfolio. The first
      priority is to obtain reliable supply for delivery to the Company’s retail
      customers. The second priority is to protect against unwanted risk exposure.
      The
      third priority is to optimize excess capacity or flexibility within the energy
      portfolio. The Company is not engaged in the business of assuming risk for
      the
      purpose of speculative trading revenues. Therefore, mark-to-market adjustments
      associated with wholesale market transactions result as the Company seeks to
      hedge portfolio risks and optimize unused capacity. In order to manage risks
      effectively, the Company enters into physical and financial transactions, which
      are appropriate for the service territory of the Company and are relevant to
      its
      regulated electric and gas portfolios.


The
      Company has entered into master netting agreements with counterparties when
      available to mitigate credit exposure to those counterparties. The Company
      believes that entering into such agreements reduces risk of settlement default
      with the ability to make only one net payment. In addition, the Company believes
      risk is mitigated with an improved position in potential counterparty bankruptcy
      situations due to a consistent netting approach. The Company is subject to
      a
      range of netting provisions, including both stand alone agreements and the
      provisions associated with the Western Systems Power Pool agreement of which
      many energy suppliers in the western United States are a part.


During
      the three months ended June 30, 2005, the Company recorded an increase in
      earnings for the change in the market value of derivative instruments not
      meeting cash flow hedge criteria of approximately $0.6 million compared to
      an
      increase in earnings of approximately $2.8 million for the three months ended
      June 30, 2004. At June 30, 2005, the Company had a net unrealized gain recorded
      in other comprehensive income of $13.1 million after-tax related to energy
      and
      financial contracts which meet the criteria for designation as cash flow hedges
      under SFAS No. 133. In 2005, a portion of the total unrealized gain on cash
      flow
      hedge transactions in other comprehensive income and the marked-to-market gain
      in the income statement were deferred in accordance with SFAS No. 71 due to
      the
      Company exceeding the $40 million cap under the PCA mechanism. When these
      transactions are realized, they will be reflected in the PCA
      calculation.


During
      the six months ended June 30, 2005, the Company recorded an increase in earnings
      for the change in the market value of derivative instruments not meeting cash
      flow hedge criteria of approximately $0.1 million compared to an increase in
      earnings of approximately $2.9 million for the six months ended June 30, 2004.


In
      the
      second quarter 2005, the Company entered into two forward starting interest
      rate
      swap contracts to hedge exposure to rate volatility for a debt offering
      anticipated to be performed in the second half of 2006. A forward starting
      interest rate swap is a financial arrangement between the Company and a
      counterparty whereby one of the parties will be required to make a payment
      to
      the other party on a specific valuation date based upon the change in value
      of a
      designated treasury bond. If interest rates rise related to the hedged debt
      from
      the date of issuance of the swap instruments, the Company would receive a
      payment from the counterparty for the change in the bond value upon settlement.
      Alternatively, if interest rates decrease related to the hedged debt from the
      date of issuance of the swap instruments, the Company would pay the counterparty
      for the change in the bond value upon settlement. The forward starting interest
      rate swap contracts were designated under SFAS No. 133 criteria as cash flow
      hedges, with all changes in market value for each reporting period being
      presented net of tax in other comprehensive income. When the forward starting
      interest rate swap contracts are settled upon issuance of debt, any gain or
      loss
      will be amortized from other comprehensive income to interest expense over
      the
      life of the issued debt. At June 30, 2005, the Company recorded a liability
      associated with these two contracts in the amount of $11.7 million and an
      unrealized loss in the amount of $7.6 million, after-tax, which is included
      in
      other comprehensive income.


In
      the
      second quarter 2005, the Company settled its two treasury lock contracts that
      were entered into in August 2004. The purpose of the treasury lock contracts
      was
      to hedge exposure to interest rate volatility for a debt offering of $250
      million that was completed in May 2005. Since treasury interest rates decreased
      related to the hedged debt from the date of issuance of the treasury lock
      instruments, PSE paid the counterparties $35.3 million for the change in bond
      value when the contracts were settled. In addition, the bonds issued associated
      with the treasury lock instruments had a correspondingly lower interest rate
      since treasury rates decreased from the date of issuance of the treasury lock
      instruments. The treasury lock contracts were designated and documented under
      SFAS No. 133 criteria as cash flow hedges, with all changes in market value
      for
      each reporting period being presented net of tax in other comprehensive income.
      In the second quarter 2005, the settlement loss on these instruments amounted
      to
      $23.0 million, after-tax, and was recorded as a loss in other comprehensive
      income. In accordance with SFAS No. 133, this loss will be amortized out of
      other comprehensive income to current earnings as an increase to interest
      expense over the life of the new debt issued at an annual rate of approximately
      $1.2 million before tax. The ending balance in other comprehensive income
      related to the treasury lock contracts at June 30, 2005 was a loss of $22.9
      million after-tax and accumulated amortization.







**(5)**
            **Asset
                Retirement Obligations**





SFAS
      No.
      143, “Accounting for Asset Retirement Obligations,” requires legal obligations
      associated with the retirement of long-lived assets to be recognized at their
      fair value at the time the obligations are incurred. Upon initial recognition
      of
      a liability, that cost is capitalized as part of the related long-lived asset
      and allocated to expense over the useful life of the asset.


The
      Company identified various asset retirement obligations under SFAS No. 143
      upon
      initial adoption, and in 2005 identified an additional asset retirement
      obligation related to unprotected bare steel gas pipe. The Company has an
      obligation (1) to dismantle two leased electric generation turbine units and
      deliver the turbines to the nearest railhead at the termination of the lease
      in
      2009; (2) to remove certain structures as a result of re-negotiations with
      the
      Department of Natural Resources of a now expired lease; (3) to replace or line
      all cast iron pipes in its service territory by 2007 as a result of a 1992
      Washington Commission order; (4) to restore ash holding ponds at a jointly-owned
      coal-fired electric generating facility in Montana; and (5) to replace all
      unprotected bare steel gas pipe in its service territory by 2015 as a result
      of
      a January 31, 2005 Washington Commission order.


The
      following table describes all changes to the Company’s asset retirement
      obligation liability during the six months ended June 30:





(Dollars
                in thousands)At
                June
                30,
            
            2005
            
            2004Asset
                retirement obligation at beginning of year
            
            $
            3,516
            
            $
            3,421Liability
                recognized in the period
            
            
            2,202
            
            
            --Liability
                settled in the period
            
            
            (273
            )
            
            --Accretion
                expense
            
            
            94
            
            
            49Asset
                retirement obligation at June 30,
            
            $
            5,539
            
            $
            3,470








**(6)**
            **Stock
                Compensation**(Puget
                Energy Only)





The
      Company has various stock-based compensation plans which, prior to 2003, were
      accounted for according to Accounting Principles Board (APB) No. 25, “Accounting
      for Stock Issued to Employees,” and related interpretations as allowed by SFAS
      No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted
      the fair value based accounting of SFAS No. 123 using the prospective method
      under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company is applying SFAS No. 123 accounting
      prospectively to stock compensation awards granted from 2003 on, while grants
      that were made in years prior to 2003 continue to be accounted for using the
      intrinsic value method of APB No. 25. Had the Company used the fair value method
      of accounting specified by SFAS No. 123 for all grants at their grant date
      rather than prospectively implementing SFAS No. 123, net income and earnings
      per
      share would have been as follows:





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,(Dollars
                in thousands, except per share amounts)
            2005
            
            2004
            
            2005
            
            2004Net
                income (loss), as reported
            $
            13,895
            
            $
            (6,780
            )
            $
            84,971
            
            $
            59,585Add:
                Total stock-based employee compensation expense
              included
                in
                net income, net of tax
            
            1,069
            
            
            810
            
            
            1,805
            
            
            1,461Less:
                Total stock-based employee compensation expense
              per
                the fair
                value method of SFAS No. 123, net of tax
            
            (989
            )
            
            (878
            )
            
            (1,899
            )
            
            (1,440
            )Pro
                forma net income (loss)
            $
            13,975
            
            $
            (6,848
            )
            $
            84,877
            
            $
            59,606Earnings
                per share:Basic
                per common share as reported
            $
            0.14
            
            $
            (0.07
            )
            $
            0.85
            
            $
            0.60Diluted
                per common share as reported
            $
            0.14
            
            $
            (0.07
            )
            $
            0.84
            
            $
            0.60Basic
                per common share pro forma
            $
            0.14
            
            $
            (0.07
            )
            $
            0.85
            
            $
            0.60Diluted
                per common share pro forma
            $
            0.14
            
            $
            (0.07
            )
            $
            0.84
            
            $
            0.60








**(7)**
            **Retirement
                Benefits**





The
      following summarizes the net periodic benefit cost for the three months ended
      June 30:





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2005
            
            2004
            
            2005
            
            2004Service
                cost
            
            $
            2,789
            
            $
            2,663
            
            $
            41
            
            $
            50Interest
                cost
            
            
            5,994
            
            
            6,075
            
            
            264
            
            
            438Expected
                return on plan assets
            
            
            (9,451
            )
            
            (9,753
            )
            
            (220
            )
            
            (222
            )Amortization
                of prior service cost
            
            
            756
            
            
            790
            
            
            78
            
            
            77Recognized
                net actuarial (gain) loss
            
            
            886
            
            
            282
            
            
            (271
            )
            
            --Amortization
                of transition (asset) obligation
            
            
            (41
            )
            
            (277
            )
            
            104
            
            
            105Net
                periodic benefit cost (income)
            
            $
            933
            
            $
            (220
            )
            $
            (4
            )
            $
            448





The
      following summarizes the net periodic benefit cost for the six months ended
      June
      30:





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2005
            
            2004
            
            2005
            
            2004Service
                cost
            
            $
            5,830
            
            $
            5,171
            
            $
            97
            
            $
            100Interest
                cost
            
            
            11,958
            
            
            12,041
            
            
            668
            
            
            876Expected
                return on plan assets
            
            
            (18,964
            )
            
            (19,553
            )
            
            (439
            )
            
            (444
            )Amortization
                of prior service cost
            
            
            1,512
            
            
            1,595
            
            
            155
            
            
            154Recognized
                net actuarial (gain) loss
            
            
            1,629
            
            
            564
            
            
            (271
            )
            
            --Amortization
                of transition (asset) obligation
            
            
            (82
            )
            
            (552
            )
            
            209
            
            
            210Net
                periodic benefit cost (income)
            
            $
            1,883
            
            $
            (734
            )
            $
            419
            
            $
            896





The
      Company previously disclosed in its financial statements for the year ended
      December 31, 2004 that it expected contributions by the Company to fund the
      pension and other benefits plans for the year ended December 31, 2005 to be
      $2.0
      million and $1.4 million, respectively. During the three and six months ended
      June 30, 2005, the actual cash contributions to the pension plans were $0.3
      million and $0.9 million, respectively. In addition, some plan participants
      chose lump sum pension payments totaling $0.6 million and deferred them under
      the Company’s deferred compensation plan in the first quarter 2005. Based on
      this activity, the Company anticipates contributing an additional $0.6 million
      to the Company’s pension plan in 2005. The full amount of the pension plan
      funding for 2005 is for the Company’s non-qualified supplemental retirement
      plan.


During
      the three and six months ended June 30, 2005, actual other post-retirement
      medical benefit plan contributions were $0.6 million and $1.0 million,
      respectively, and the Company expects to make additional contributions of $0.4
      million for a total of $1.4 million in 2005.


On
      May
      19, 2004, FASB issued FASB Staff Position No. 106-2 “Accounting and Disclosure
      Requirements Related to the Medicare Prescription Drug, Improvement and
      Modernization Act of 2003” as the result of the new Medicare Prescription Drug
      Improvement and Modernization Act which was signed into law in December 2003.
      The law provides a subsidy for plan sponsors that provide prescription drug
      benefits to Medicare beneficiaries that are equivalent to the Medicare Part
      D
      plan. Based on new Medicare regulations issued in May 2005, the Company
      determined that it provides benefits at a higher level than provided under
      Medicare Part D, and therefore would qualify for federal tax subsidies. As
      a
      result, the Company reduced its accumulated post retirement benefit obligation
      by $4.1 million in the second quarter 2005 and reduced its estimated accrued
      expense recorded for the six months ended June 2005 for the 2005 plan year
      by
      $0.4 million.








**(8)**  **Purchased
      Gas Adjustment Mechanism True-Up**





In
      the
      second quarter 2005, PSE determined from a review of its Purchased Gas
      Adjustment (PGA) mechanism that a gas demand charge created during the
      settlement of the 2001 general rate case for a gas customer rate class had
      not
      been included within the parameters to calculate the costs under the PGA
      mechanism for rate recovery purposes. As a result, the balance of the PGA
      mechanism receivable has been overstated due to the exclusion of this charge
      for
      a 31-month period from September 1, 2002 to March 31, 2005. The PGA mechanism
      balance and gas costs at June 30, 2005 include a one-time true-up of $5.0
      million to reflect the impact of the demand charge. The total impact to
      earnings, net of tax, was $3.3 million, reflected in the quarter ended June
      30,
      2005. The effect of the true-up was not material to any one quarter since
      September 1, 2002.








**(9)**
            **Other**





On
      June
      7, 2005, PSE filed a power cost only rate case (PCORC) with the Washington
      Utilities and Transportation Commission (Washington Commission) to help recover
      the higher cost of power. The PCORC requested a 3.7% increase in electric rates,
      or $55.6 million annually. Included in the request is recovery of capital and
      anticipated operating costs for the newly acquired Hopkins Ridge wind project
      once it goes online, which is expected in late 2005. The PCORC process is an
      accelerated rate proceeding where only power costs and new resources are
      reviewed. The PCORC proceeding can take up to five months to be
      concluded.


On
        May
        18, 2005, PSE tendered an offer to repurchase all of PSE's 8.231% Capital
        Trust
        Preferred Securities (classified as Junior Subordinated Debentures of the
        Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable
        Preferred Securities on the balance sheet). The purpose of the tender offer
        was
        to help reduce interest costs by retiring higher cost debt. As a result of
        the
        tender offer, $42.5 million of the Capital Trust Preferred Securities were
        redeemed on June 2, 2005 at a 4% premium which totaled approximately $4.6
        million.
 In
        May
        2005, PSE completed the issuance of $250 million of senior notes secured
        by
        first mortgage bonds, at a rate of 5.483%. The net proceeds from the issuance
        of
        the senior notes of approximately $247.6 million were used to redeem $200
        million of variable rate senior notes, which were redeemed at par in May
        2005,
        and to repay a portion of PSE’s short-term debt.


In
      January 2003, the Financial Accounting Standards Board (FASB) issued
      Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R).
      FIN 46R requires that if a business entity has a controlling financial interest
      in a variable interest entity, the financial statements of the variable interest
      entity must be included in the consolidated financial statements of the business
      entity. The Company has evaluated its purchase power agreements and determined
      that three counterparties may be considered variable interest entities.
      Consistent with FIN 46R, PSE submitted requests for information to those
      parties; however, the parties have refused to submit to PSE the necessary
      information for PSE to determine whether they meet the requirements of a
      variable interest entity. PSE also determined that it does not have a
      contractual right to such information. PSE will continue to submit requests
      for
      information to the counterparties on a quarterly basis in accordance with FIN
      46R.


For
      the
      three purchase power agreements that may be considered variable interest
      entities under FIN 46R, PSE is required to buy all the generation from these
      plants, subject to displacement by PSE, at rates set forth in the purchase
      power
      agreements. If at any time the counterparties cannot deliver energy to PSE,
      PSE
      would have to buy energy in the wholesale market at prices which could be higher
      or lower than the purchase power agreement prices. PSE’s Purchased Electricity
      expense for the three months ended June 30, 2005 and 2004 for these three
      entities was $41.6 million and $31.1 million, respectively. PSE’s Purchased
      Electricity expense for the six months ended June 30, 2005 and 2004 for these
      three entities was $113.5 million and $110.0 million, respectively.


On
      July
      12, 2005, Puget Energy received a notice of proposed adjustment (NOPA) from
      the
      Internal Revenue Service relating to a deduction in Puget Energy's 2003 tax
      return. The deduction relates to the receivable balance due from the California
      Independent System Operator Corporation (CAISO). The NOPA states that the
      deduction is not valid for the 2003 tax year and requests payment of
      approximately $14.5 million in taxes and approximately $1.0 million in related
      interest. Management of Puget Energy believes the deduction is valid and intends
      to vigorously defend the deduction, however the outcome of this issue cannot
      be
      predicted. Any potential tax related payment (excluding interest) would have
      no
      impact on earnings as it would be recognized as a deferred tax
      asset.








**(10)**
            ******New
                Accounting Pronouncements**




In
      December 2004, FASB issued SFAS No. 123R, “Share-Based Payment”, which revises
      SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No. 123R requires
      companies that issue share-based payment awards to employees for goods or
      services to recognize as compensation expense, the fair value of the expected
      vested portion of the award as of the grant date over the vesting period of
      the
      award. Forfeitures that occur before the award vesting date will be adjusted
      from the total compensation expense, but once the award vests, no adjustment
      to
      compensation expense will be allowed for forfeitures or unexercised awards.
      In
      addition, SFAS No. 123R would require recognition of compensation expense of
      all
      existing outstanding awards that are not fully vested for their remaining
      vesting period as of the effective date that were not accounted for under a
      fair
      value method of accounting at the time of their award. SFAS No. 123R was
      originally effective for interim reporting periods beginning after June 15,
      2005. However, on April 14, 2005, the Securities and Exchange Commission delayed
      implementation of SFAS No. 123R to annual reporting periods beginning after
      June
      15, 2005. The Company is currently evaluating what impact the application of
      SFAS No. 123R will have on its operations. The Company had adopted the fair
      value provisions of SFAS No. 123 “Accounting for Stock-Based Compensation” in
      January 2003.


In
      March
      2005, FASB issued FIN 47, which finalized a proposed interpretation of SFAS
      No.
      143 titled “Accounting for Conditional Asset Retirement Obligations.” The
      interpretation addresses the issue of whether SFAS No. 143 requires an entity
      to
      recognize a liability for a legal obligation to perform asset retirement when
      the asset retirement activities are conditional on a future event, and if so,
      the timing and valuation of the recognition. The decision reached by FASB was
      that there are no instances where a law or regulation obligates an entity to
      perform retirement activities but then allows the entity to permanently avoid
      settling the obligation. The Company is currently evaluating what impact FIN
      47
      will have on potential asset retirement obligations. The adoption of FIN 47
      is
      effective for fiscal years ending after December 15, 2005, and is required
      to be
      accounted for as a cumulative effect of an accounting change.








Item
      2. **Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations**





*The
      following discussion of the Company’s financial condition and results of
      operations contains forward-looking statements that involve risks and
      uncertainties, such as statements of the Company’s plans, objectives,
      expectations and intentions. Words such as
“anticipates,”“believes,”“estimates,”“expects,”“future,”“intends,”“plans,”“projects,”“predicts,”“will
      likely result,” and “will continue” and similar expressions are used to identify
      forward-looking statements. However, these words are not the exclusive means
      of
      identifying such statements. In addition, any statements that refer to
      expectations, projections or other characterizations of future events or
      circumstances are forward-looking statements. The Company’s actual results could
      differ materially from those anticipated in these forward-looking statements
      for
      many reasons, including the factors described below and under the caption
“Forward-Looking Statements” at the beginning of this report. You should not
      place undue reliance on these forward-looking statements, which apply only
      as of
      the date of this Form 10-Q.*








**Overview**





Puget
      Energy is an energy services holding company and all of its operations are
      conducted through its two subsidiaries. These subsidiaries are PSE, a regulated
      electric and gas utility company, and InfrastruX, a utility construction and
      services company. Following a strategic review of Puget Energy’s unregulated
      subsidiary, InfrastruX, on February 8, 2005, Puget Energy’s Board of Directors
      decided to exit the utility construction services sector. Puget Energy intends
      to monetize its interest in InfrastruX through a sale and to invest the proceeds
      of such monetization in its regulated utility subsidiary, PSE. See section
      titled “InfrastruX” for further discussion.





**Puget
        Sound Energy**


PSE
      generates revenues from the sale of electric and gas services, mainly to
      residential and commercial customers within Washington State. A majority of
      PSE’s revenues are generated in the first and fourth quarters during the winter
      heating season in Washington State.


As
      a
      regulated utility company, PSE is subject to Federal Energy Regulatory
      Commission (FERC) and Washington Utilities and Transportation Commission
      (Washington Commission) regulation which may impact a large array of business
      activities, including limitation of future rate increases; directed accounting
      requirements that may negatively impact earnings; licensing of PSE-owned
      generation facilities; and other FERC and Washington Commission directives
      that
      may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent
      to the utility industry as a whole, including weather changes affecting
      purchases and sales of energy; outages at owned and non-owned generation plants
      where energy is obtained; storms or other events which can damage electric
      distribution and transmission lines; and energy trading and wholesale market
      stability over time.


PSE’s
      main operational objective is to provide reliable, safe and cost-effective
      energy to its customers. To help accomplish this objective, PSE is attempting
      to
      be more self-sufficient in energy generation resources. Owning more generation
      resources will reduce the Company’s reliance on the wholesale market. PSE is
      continually exploring new electric-power resource generation and long-term
      purchase power agreements to meet this goal. The completion of its acquisition
      of the Hopkins Ridge wind project in the first quarter 2005 and the issued
      notice to proceed with construction of the project was one step in reaching
      this
      goal. The Hopkins Ridge wind project is expected to provide up to 150 MW of
      capacity or 52 average MW, and is expected to be completed by the end of 2005.
      In addition, PSE continues negotiations from its September 2004 non-binding
      letter of intent to acquire the Wild Horse wind project, which is anticipated
      to
      provide approximately 230 MW of capacity or 77 average MW.


The
      Hopkins Ridge wind project and proposed Wild Horse wind project are part of
      PSE’s long-term electric Least Cost Plan that was filed May 2, 2005 with the
      Washington Commission. The plan supports a strategy of diverse resource
      acquisitions including resources fueled by natural gas and coal, renewable
      resources and shared resources. The Least Cost Plan will be followed by issuing
      an all-source request for proposal (RFP) in late 2005. On July 29, 2005, PSE
      filed a draft version of this all-source RFP with the Washington Commission.








**Results
      of Operations**




**Puget
      Energy**


All
      the
      operations of Puget Energy are conducted through its subsidiaries, PSE and
      InfrastruX. Net income for the three months ended June 30, 2005 was $13.9
      million on operating revenues of $510.1 million compared to a loss of $6.8
      million on operating revenues of $423.1 million for the same period in 2004.
      The
      net income and loss for both periods includes the results of discontinued
      operations for InfrastruX.


Basic
      and
      diluted earnings per share for the three months ended June 30, 2005 were $0.14
      compared to a basic and diluted loss per share for the three months ended June
      30, 2004 of $0.07. Included in the basic and diluted earnings per share for
      the
      three months ended June 30, 2005 was $0.02 earnings per share related to
      discontinued operations and estimated loss on disposal of InfrastruX. Included
      in the basic and diluted loss per share for the three months ended June 30,
      2004
      was $0.03 earnings per share related to discontinued operations of
      InfrastruX.


Net
      income for the three months ended June 30, 2005 was positively impacted by
      increased electric and gas margins of $42.7 million and $4.0 million,
      respectively, compared to the same period in 2004 mainly due to the Tenaska
      disallowance in May 2004 and increased electric and gas usage compared to the
      same period in 2004 offset by a one-time true-up of previously reported
      purchased gas costs. Net income was negatively impacted by higher utility
      operations and maintenance expenses as a result of higher production and higher
      depreciation and amortization expense from the acquisition of Frederickson
      1 in
      April 2004 and other PSE transmission and distribution system infrastructure
      projects.


For
      the
      six months ended June 30, 2005, Puget Energy's net income was $85.0 million
      on
      operating revenues of $1.3 billion compared to net income of $59.6 million
      on
      operating revenues of $1.1 billion for the same period in 2004. Basic and
      diluted earnings per share for the six months ended June 30, 2005 was $0.85
      and
      $0.84, respectively, compared to basic and diluted earnings per share of $0.60
      for the same period in 2004. Included in the basic and diluted earnings per
      share for the six months ended June 30, 2005 was $0.01 earnings per share
      related to discontinued operations of InfrastruX.


Net
      income for the six months ended June 30, 2005 was positively impacted by
      increased electric and gas margins of $50.1 million and $4.5 million,
      respectively, compared to the same period in 2004, mainly due to the Tenaska
      disallowance in May 2004 and increased electric and gas usage offset by a
      one-time true-up of previously reported purchased gas costs.





**Puget
      Sound Energy**


PSE’s
      operating revenues and associated expenses are not generated evenly during
      the
      year. Variations in energy usage by consumers occur from season to season and
      from month to month within a season, primarily as a result of weather
      conditions. PSE normally experiences its highest retail energy sales during
      the
      heating season in the first and fourth quarters of the year. Varying wholesale
      electric prices and the amount of hydroelectric energy supplies available to
      PSE
      also make quarter-to-quarter comparisons difficult.





**Energy
      Margins**


PSE
      uses
      the following margin information in reviewing its operations to determine if
      PSE
      is collecting the appropriate amount of energy costs from its customers to
      allow
      recovery of its operating costs.


The
      following table displays the details of electric margin changes for the three
      months ended June 30, 2005 compared to the same period in 2004. Electric margin
      is electric sales to retail and transportation customers less pass-through
      tariff items and revenue-sensitive taxes, and the cost of generating and
      purchasing electric energy sold to customers, including transmission costs
      to
      bring electric energy to PSE’s service territory.





Electric
                Margin(Dollars
                in Millions)
              Three
                Months Ended June 30
            2005
            
            2004
            
            Change
            
            Percent
              ChangeElectric
                retail sales revenue
            $
            316.5
            
            $
            280.9
            
            $
            35.6
            
            
            12.7
            %Electric
                transportation revenue
            
            2.4
            
            
            2.4
            
            
            --
            
            
            --
            %Other
                electric revenue-gas supply resale
            
            1.0
            
            
            0.6
            
            
            0.4
            
            
            66.7
            %Total
                electric revenue for margin
            
            319.9
            
            
            283.9
            
            
            36.0
            
            
            12.7
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            (7.2
            )
            
            (5.6
            )
            
            (1.6
            )
            
            (28.6
            )%Pass-through
                revenue-sensitive taxes
            
            (23.6
            )
            
            (20.9
            )
            
            (2.7
            )
            
            (12.9
            )%Residential
                exchange credit
            
            37.1
            
            
            35.4
            
            
            1.7
            
            
            4.8
            %Net
                electric revenue for margin
            
            326.2
            
            
            292.8
            
            
            33.4
            
            
            11.4
            %Minus
                power costs:Fuel
            
            (12.9
            )
            
            (21.0
            )
            
            8.1
            
            
            38.6
            %Purchased
                electricity, net of sales to other utilities and marketers
            
            (152.4
            )
            
            (132.0
            )
            
            (20.4
            )
            
            (15.5
            )%Total
                electric power costs
            
            (165.3
            )
            
            (153.0
            )
            
            (12.3
            )
            
            (8.0
            )%Electric
                margin before PCA
            
            160.9
            
            
            139.8
            
            
            21.1
            
            
            15.1
            %Tenaska
                disallowance reserve
            
            --
            
            
            (36.5
            )
            
            36.5
            
            
            *Power
                cost deferred under the PCA mechanism
            
            (9.6
            )
            
            5.3
            
            
            (14.9
            )
            
            *Electric
                margin1
            $
            151.3
            
            $
            108.6
            
            $
            42.7
            
            
            39.3
            %


_________________________________


* *Percent
      change not applicable or unmeaningful**.*


*1Electric
      margin does not include any allocation for depreciation
      expense.*





The
      following table displays the details of electric margin changes for the six
      months ended June 30, 2005 compared to the same period in 2004.





Electric
                Margin(Dollars
                in Millions)
              Six
                Months Ended June 30
            2005
            
            2004
            
            Change
            
            Percent
              ChangeElectric
                retail sales revenue
            $
            703.6
            
            $
            648.4
            
            $
            55.2
            
            
            8.5
            %Electric
                transportation revenue
            
            5.1
            
            
            4.6
            
            
            0.5
            
            
            10.9
            %Other
                electric revenue-gas supply resale
            
            5.1
            
            
            4.0
            
            
            1.1
            
            
            27.5
            %Total
                electric revenue for margin
            
            713.8
            
            
            657.0
            
            
            56.8
            
            
            8.6
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            (13.7
            )
            
            (14.1
            )
            
            0.4
            
            
            2.8
            %Pass-through
                revenue-sensitive taxes
            
            (52.2
            )
            
            (47.0
            )
            
            (5.2
            )
            
            (11.1
            )%Residential
                exchange credit
            
            92.2
            
            
            89.8
            
            
            2.4
            
            
            2.7
            %Net
                electric revenue for margin
            
            740.1
            
            
            685.7
            
            
            54.4
            
            
            7.9
            %Minus
                power costs:Fuel
            
            (33.4
            )
            
            (35.0
            )
            
            1.6
            
            
            4.6
            %Purchased
                electricity, net of sales to other utilities and marketers
            
            (362.2
            )
            
            (330.8
            )
            
            (31.4
            )
            
            (9.5
            )%Total
                electric power costs
            
            (395.6
            )
            
            (365.8
            )
            
            (29.8
            )
            
            (8.1
            )%Electric
                margin before PCA
            
            344.5
            
            
            319.9
            
            
            24.6
            
            
            7.7
            %Tenaska
                disallowance reserve
            
            --
            
            
            (36.5
            )
            
            36.5
            
            
            *Tenaska
                reserve turnaround
            
            5.3
            
            
            --
            
            
            5.3
            
            
            *Power
                cost deferred under the PCA mechanism
            
            3.0
            
            
            19.3
            
            
            (16.3
            )
            
            (84.5
            )%Electric
                margin1
            $
            352.8
            
            $
            302.7
            
            $
            50.1
            
            
            16.6
            %


_________________________________
 * *Percent
        change not applicable or unmeaningful**.*
 *1Electric
        margin does not include any allocation for depreciation
        expense.*


Electric
      margin increased $42.7 million for the three months ended June 30, 2005 compared
      to the same period in 2004, primarily due to the Tenaska disallowance recorded
      in May 2004 and the disallowance set in rates, which reduced margin by $37.8
      million for the three months ended June 30, 2004. In addition, electric margin
      increased as a result of the effects of the Power Cost Only Rate Case (PCORC)
      for the Frederickson 1 generating facility and other power costs that became
      effective May 24, 2004, and the effects of the electric general tariff increase
      effective March 4, 2005. The PCORC and the electric general rate case
      contributed $6.2 million to electric margin for the three months ended June
      30,
      2005 compared to the same period in 2004, offset by a $2.7 million Tenaska
      disallowance for the three months ended June 30, 2005. In addition, retail
      customer kWh sales (residential, commercial and industrial customers) increased
      4.9% for the three months ended June 30, 2005 compared to 2004, which provided
      $6.9 million to electric margin, and changes in customer class usage
      (residential, commercial and industrial), increased margin by $8.2 million
      compared to the same period in 2004. These increases were partially offset
      by a
      reduction in customer deferral of excess power costs under the PCA mechanism,
      which decreased margin by $9.7 million for the three months ended June 2005
      compared to the same period in 2004 due to overall lower power costs in 2005.


Electric
      margin increased $50.1 million for the six months ended June 30, 2005 compared
      to the same period in 2004 primarily as a result of the aforementioned Tenaska
      disallowance recorded in May 2004 and the disallowance set in rates, which
      reduced margin by $37.8 million for the six months ended June 30, 2004. Also
      contributing to the increase were the effects of the PCORC and the electric
      general tariff increases, which provided a combined $9.4 million to margin.
      In
      February 2005, a final resolution and recovery of $6.0 million return on the
      Tenaska Regulatory asset for the PCA 2 period was received which increased
      margin by the same amount. Other items that increased margin include a 2.4%
      increase in retail customer usage, which contributed $7.8 million to margin,
      and
      a change in customer class usage, which increased margin by $7.2 million. These
      increases were partially offset by a reduction in customer deferral of excess
      power costs under the PCA mechanism which decreased margin by $16.2 million
      for
      the six months ended June 2005 compared to the same period in 2004 due to
      overall lower power costs in 2005.


The
      following table displays the details of gas margin changes for the three months
      ended June 30, 2005 compared to the same period in 2004. Gas margin is gas
      sales
      to retail and transportation customers less pass-through tariff items and
      revenue-sensitive taxes and the cost of gas purchased, including gas
      transportation costs to bring gas to PSE’s service territory.





Gas
                Margin(Dollars
                in Millions)
              Three
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangeGas
                retail revenue
            
            $
            155.2
            
            $
            112.6
            
            $
            42.6
            
            
            37.8
            %Gas
                transportation revenue
            
            
            3.2
            
            
            3.1
            
            
            0.1
            
            
            3.2
            %Total
                gas revenue for margin
            
            
            158.4
            
            
            115.7
            
            
            42.7
            
            
            36.9
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            
            (1.0
            )
            
            (0.5
            )
            
            (0.5
            )
            
            (100.0
            )%Pass-through
                revenue-sensitive taxes
            
            
            (13.7
            )
            
            (9.9
            )
            
            (3.8
            )
            
            (38.4
            )%Net
                gas revenue for margin
            
            
            143.7
            
            
            105.3
            
            
            38.4
            
            
            36.5
            %Minus
                purchased gas costs1
            
            
            (98.1
            )
            
            (63.7
            )
            
            (34.4
            )
            
            (54.0
            )%Gas
                margin2
            
            $
            45.6
            
            $
            41.6
            
            $
            4.0
            
            
            9.6
            %


_________________________________


*1* *Included
      in 2005 purchased gas costs is a one-time true-up of previously reported gas
      cost of $5.0 million.  See discussion under Operating Expenses-Purchased
      Gas.*


*2****Gas
      margin does not include any allocation for depreciation
      expense.*





The
      following table displays the details of gas margin changes for the six months
      ended June 30, 2005 compared to the same period in 2004.





Gas
                Margin(Dollars
                in Millions)
              Six
                Months Ended June 30
            2005
            
            2004
            
            Change
            
            Percent
              ChangeGas
                retail revenue
            $
            468.1
            
            $
            382.0
            
            $
            86.1
            
            
            22.5
            %Gas
                transportation revenue
            
            6.6
            
            
            6.5
            
            
            0.1
            
            
            1.5
            %Total
                gas revenue for margin
            
            474.7
            
            
            388.5
            
            
            86.2
            
            
            22.2
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            (2.9
            )
            
            (1.6
            )
            
            (1.3
            )
            
            (81.3
            )%Pass-through
                revenue-sensitive taxes
            
            (38.7
            )
            
            (32.1
            )
            
            (6.6
            )
            
            (20.6
            )%Net
                gas revenue for margin
            
            433.1
            
            
            354.8
            
            
            78.3
            
            
            22.1
            %Minus
                purchased gas costs1
            
            (299.9
            )
            
            (226.1
            )
            
            (73.8
            )
            
            (32.6
            )%Gas
                margin2
            $
            133.2
            
            $
            128.7
            
            $
            4.5
            
            
            3.5
            %


_________________________________


*1**See Footnote 1 for three months ended June 30 Gas Margin
      table.*


*2****Gas margin does not include any allocation for
      depreciation expense.*





Gas
      margin increased $4.0 million for the three months ended June 30, 2005 compared
      to the same period in 2004 primarily due to increased gas usage and the gas
      general tariff rate case. Gas margin increased $4.0 million as a result of
      the
      gas general tariff increase effective March 4, 2005. Retail customer therm
      sales
      increased 12.8% for the three months ended June 30, 2005 compared to the same
      period in 2004, which provided $5.3 million to gas margin. The increased usage
      was primarily due to overall cooler weather for the three months ended June
      30,
      2005 compared to the same period in 2004, with 15.2% more heating degree days
      for the three months ended June 30, 2005 compared to the same period in 2004.
      Negatively impacting gas margin for the three months ended June 30, 2005 was
      a
      $5.0 million one-time true-up of previously reported gas costs under the PGA
      mechanism. See further discussion under the section titled “Operating
      Expenses-Purchased Gas.”


Gas
      margin increased $4.5 million for the six months ended June 30, 2005 compared
      to
      the same period in 2004. Gas margin increased $6.2 million as a result of the
      gas general tariff rate case. In addition, retail customer therm sales increased
      1.4% for the six months ended June 30, 2005 compared to the same period in
      2004,
      which provided $1.7 million to gas margin, and changes in customer class usage
      provided $2.1 million to gas margin. Negatively impacting gas margin for the
      six
      months ended June 30, 2005, was the $5.0 million one-time true-up of previously
      reported gas costs as noted above.





**Electric
      Operating Revenues**


The
      table
      below sets forth changes in electric operating revenues for PSE for the three
      months ended June 30, 2005 compared to the same period in 2004.





(Dollars
                in Millions)
              Three
                Months Ended June 30
            2005
            
            2004
            
            Change
            
            Percent
              ChangeElectric
                operating revenues:Residential
                sales
            $
            152.9
            
            $
            132.3
            
            $
            20.6
            
            
            15.6
            %Commercial
                sales
            
            150.0
            
            
            131.5
            
            
            18.5
            
            
            14.1
            %Industrial
                sales
            
            23.2
            
            
            20.8
            
            
            2.4
            
            
            11.5
            %Other
                retail sales, including unbilled revenue
            
            (9.6
            )
            
            (3.7
            )
            
            (5.9
            )
            
            (159.5
            )%Total
                retail sales
            
            316.5
            
            
            280.9
            
            
            35.6
            
            
            12.7
            %Transportation
                sales
            
            2.4
            
            
            2.4
            
            
            --
            
            
            --
            %Sales
                to other utilities and marketers
            
            16.9
            
            
            10.7
            
            
            6.2
            
            
            57.9
            %Other
            
            9.6
            
            
            9.1
            
            
            0.5
            
            
            5.5
            %Total
                electric operating revenues
            $
            345.4
            
            $
            303.1
            
            $
            42.3
            
            
            14.0
            %





Electric
      retail sales increased $35.6 million for the three months ended June 30, 2005
      compared to the same period in 2004 due primarily to rate increases related
      to
      the PCORC and the electric general rate case, and increased retail customer
      usage. The PCORC and electric general rate case provided a combined additional
      $13.6 million to electric operating revenues for the three months ended June
      30,
      2005 compared to the same period in 2004. Retail electricity usage increased
      215,174 MWh or 4.9% for the three months ended June 30, 2005 compared to the
      same period in 2004. The increase in electricity usage was primarily the result
      of cooler temperatures for the three months ended June 30, 2005 compared to
      the
      same period in 2004, and due to a 1.9% increase in the average number of
      customers served.


During
      the three month period ended June 30, 2005, the benefits of the Residential
      and
      Farm Energy Exchange Benefit credited to customers reduced electric operating
      revenues by $38.8 million compared to $37.0 million for the same period in
      2004.
      This credit also reduced power costs by a corresponding amount with no impact
      on
      earnings.


Sales
      to
      other utilities and marketers increased $6.2 million compared to the three
      month
      period ended June 30, 2004 primarily due to an increase of 165,470 MWh sold
      related to excess generation available for sale on the wholesale market. The
      increase in MWh sold was due to differences in timing of the need for power
      to
      serve base load and actual weather conditions. Sales to other utilities and
      marketers is included in the PCA mechanism as a reduction in determining net
      power costs.


The
      table
      below sets forth changes in electric operating revenues for PSE for the six
      months ended June 30, 2005 compared to the same period in 2004.





(Dollars
                in Millions)
              Six
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangeElectric
                operating revenues:Residential
                sales
            
            $
            364.8
            
            $
            336.7
            
            $
            28.1
            
            
            8.3
            %Commercial
                sales
            
            
            307.9
            
            
            285.2
            
            
            22.7
            
            
            8.0
            %Industrial
                sales
            
            
            45.2
            
            
            43.2
            
            
            2.0
            
            
            4.6
            %Other
                retail sales, including unbilled revenue
            
            
            (14.4
            )
            
            (16.6
            )
            
            2.2
            
            
            13.3
            %Total
                retail sales
            
            
            703.5
            
            
            648.5
            
            
            55.0
            
            
            8.5
            %Transportation
                sales
            
            
            5.1
            
            
            4.6
            
            
            0.5
            
            
            10.9
            %Sales
                to other utilities and marketers
            
            
            33.2
            
            
            22.2
            
            
            11.0
            
            
            49.5
            %Other
            
            
            23.7
            
            
            20.3
            
            
            3.4
            
            
            16.7
            %Total
                electric operating revenues
            
            $
            765.5
            
            $
            695.6
            
            $
            69.9
            
            
            10.0
            %





Electric
        retail sales increased $55.0 million for the six months ended June 30, 2005
        compared to the same period in 2004 due primarily to rate increases related
        to
        the PCORC and the electric general rate case, and increased retail customer
        usage. The PCORC and electric general rate case provided a combined additional
        $28.4 million to electric operating revenues for the six months ended June
        30,
        2005 compared to the same period in 2004. Retail electricity usage increased
        243,506 MWh or 2.4% for the six months ended June 30, 2005 compared to the
        same
        period in 2004. The increase in electricity usage was mainly the result of
        a
        1.9% higher average number of customers served in the six month period ended
        June 30, 2005 compared to the same period in 2004.


During
      the six month period ended June 30, 2005, the benefits of the Residential and
      Farm Energy Exchange Benefit credited to customers reduced electric operating
      revenues by $96.4 million compared to $94.0 million for the same period in
      2004.
      This credit also reduced power costs by a corresponding amount with no impact
      on
      earnings.


Sales
      to
      other utilities and marketers increased $11.0 million compared to the six month
      period ended June 30, 2004 primarily due to an increase of 165,470 MWh sold
      related to excess generation available for sale on the wholesale market. The
      increase in MWh sold was due to differences in timing of the need for power
      to
      serve base load and actual weather conditions.


Other
      electric revenues increased $3.4 million for the six month period ended June
      30,
      2005 compared to the same period in 2004, primarily from the sale of excess
      non-core gas and electric transmission. Non-core gas sales are included in
      the
      PCA mechanism calculation as a reduction in determining net power
      costs.


The
      following electric rate changes were approved by the Washington Commission
      in
      2005 and 2004:





Type
                of Rate
              Adjustment
            Effective
                Date
            Percentage
                Increase
              in
                Rates
            Annual
                Increase
              in
                Revenues
              (Dollars
                in Millions)Power
                Cost Only Rate Case
            May
                24, 2004
            3.2
            %
            $
                44.1Electric
                General Rate Case
            March
                4, 2005
            4.1
            %
            57.7








**Gas
      Operating Revenues**


The
      table
      below sets forth changes in gas operating revenues for PSE for the three months
      ended June 30, 2005 compared to the same period in 2004.





(Dollars
                in Millions)
              Three
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            94.8
            
            $
            67.5
            
            $
            27.3
            
            
            40.4
            %Commercial
                sales
            
            
            50.4
            
            
            37.7
            
            
            12.7
            
            
            33.7
            %Industrial
                sales
            
            
            10.0
            
            
            7.4
            
            
            2.6
            
            
            35.1
            %Total
                retail sales
            
            
            155.2
            
            
            112.6
            
            
            42.6
            
            
            37.8
            %Transportation
                sales
            
            
            3.2
            
            
            3.1
            
            
            0.1
            
            
            3.2
            %Other
            
            
            4.2
            
            
            3.8
            
            
            0.4
            
            
            10.5
            %Total
                gas operating revenues
            
            $
            162.6
            
            $
            119.5
            
            $
            43.1
            
            
            36.1
            %





Gas
      retail sales increased $42.6 million for the three months ended June 30, 2005
      compared to the same period in 2004 due to higher Purchased Gas Adjustment
      (PGA)
      mechanism rates in 2005, approval of a 3.5% general gas rate increase in the
      gas
      general rate case effective March 4, 2005, and higher retail customer gas usage.
      The Washington Commission approved a PGA mechanism rate increase effective
      October 1, 2004 that increased rates 17.6% annually. The PGA mechanism passes
      through to customers increases or decreases in the gas supply portion of the
      natural gas service rates based upon changes in the price of natural gas
      purchased from producers and wholesale marketers or changes in gas pipeline
      transportation costs. PSE’s gas margin and net income are not affected by
      changes under the PGA mechanism. For the three months ended June 30, 2005,
      the
      effects of the PGA mechanism rate increases provided an increase of $21.6
      million in gas operating revenues. In addition, the gas general rate case
      increased gas rates by 3.5%, which provided an additional $4.0 million in gas
      operating revenue for the three months ended June 30, 2005 compared to the
      same
      period in 2004. Cooler weather in the three months ended June 30, 2005 compared
      to the same period in 2004 and a 3.2% increase in the average number of
      customers increased customer usage by 16.1 million therms and provided the
      remaining increase in retail gas revenues.


The
      table
      below sets forth changes in gas operating revenues for PSE for the six months
      ended June 30, 2005 compared to the same period in 2004.





(Dollars
                in Millions)
              Six
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            303.4
            
            $
            248.3
            
            $
            55.1
            
            
            22.2
            %Commercial
                sales
            
            
            141.6
            
            
            115.1
            
            
            26.5
            
            
            23.0
            %Industrial
                sales
            
            
            23.0
            
            
            18.6
            
            
            4.4
            
            
            23.7
            %Total
                retail sales
            
            
            468.0
            
            
            382.0
            
            
            86.0
            
            
            22.5
            %Transportation
                sales
            
            
            6.6
            
            
            6.5
            
            
            0.1
            
            
            1.5
            %Other
            
            
            9.1
            
            
            6.7
            
            
            2.4
            
            
            35.8
            %Total
                gas operating revenues
            
            $
            483.7
            
            $
            395.2
            
            $
            88.5
            
            
            22.4
            %





Gas
      retail sales increased $86.0 million for the six months ended June 30, 2005
      compared to the same period in 2004 due to higher Purchased Gas Adjustment
      (PGA)
      mechanism rates in 2005, approval of a 3.5% general gas rate increase in the
      gas
      general rate case and higher retail customer gas usage. The Washington
      Commission approved a PGA mechanism rate increase effective October 1, 2004
      that
      provided $68.0 million in gas revenues for the six months ended June 30, 2005
      compared to the same period in 2004. In addition, the gas general rate case
      increase provided an additional $6.2 million in gas operating revenues for
      the
      six months ended June 30, 2005 compared to the same period in 2004. The
      remaining increase in gas retail revenues was primarily due to a higher average
      number of customers, which increased 3.2% for the six months ended June 30,
      2005
      compared to the same period in 2004.


The
      following gas rate adjustments were approved by the Washington Commission in
      2005 and 2004:





Type
                of Rate
              Adjustment
            Effective
                Date
            Percentage
                Increase
              in
                Rates
            Annual
                Increase
              in
                Revenues
              (Dollars
                in Millions)PGA
            October
                1, 2004
            17.6
            %
            $
                121.7Gas
                General Rate Case
            March
                4, 2005
            3.5
            %
            26.3




**Operating
      Expenses**


The
      table
      below sets forth significant changes in operating expenses for PSE and its
      subsidiaries for the three months ended June 30, 2005 compared to the same
      period in 2004.




(Dollars
                in Millions)
              Three
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangePurchased
                electricity
            
            $
            178.9
            
            $
            173.8
            
            $
            5.1
            
            
            2.9
            %Electric
                generation fuel
            
            
            12.9
            
            
            21.0
            
            
            (8.1
            )
            
            (38.6
            )%Residential
                exchange credit
            
            
            (37.1
            )
            
            (35.4
            )
            
            1.7
            
            
            4.8
            %Purchased
                gas
            
            
            98.1
            
            
            63.7
            
            
            34.4
            
            
            54.0
            %Unrealized
                gain on derivative instruments
            
            
            (0.6
            )
            
            (2.8
            )
            
            (2.2
            )
            
            (78.6
            )%Utility
                operations and maintenance
            
            
            83.1
            
            
            73.2
            
            
            9.9
            
            
            13.5
            %Depreciation
                and amortization
            
            
            59.7
            
            
            56.6
            
            
            3.1
            
            
            5.5
            %Taxes
                other than income taxes
            
            
            50.5
            
            
            42.6
            
            
            7.9
            
            
            18.5
            %Income
                taxes
            
            
            6.3
            
            
            (5.3
            )
            
            11.6
            
            
            *
            %


_________________________________


*
      *Percent change not applicable or unmeaningful**.*





The
        table
        below sets forth significant changes in operating expenses for PSE and its
        subsidiaries for the six months ended June 30, 2005 compared to the same
        period
        in 2004.





(Dollars
                in Millions)
              Six
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangePurchased
                electricity
            
            $
            387.1
            
            $
            370.2
            
            $
            16.9
            
            
            4.6
            %Electric
                generation fuel
            
            
            33.3
            
            
            35.0
            
            
            (1.7
            )
            
            (4.9
            )%Residential
                exchange credit
            
            
            (92.2
            )
            
            (89.8
            )
            
            2.4
            
            
            2.7
            %Purchased
                gas
            
            
            299.9
            
            
            226.1
            
            
            73.8
            
            
            32.6
            %Unrealized
                gain on derivative instruments
            
            
            (0.1
            )
            
            (2.9
            )
            
            (2.8
            )
            
            (96.6
            )%Utility
                operations and maintenance
            
            
            158.7
            
            
            147.1
            
            
            11.6
            
            
            7.9
            %Depreciation
                and amortization
            
            
            117.7
            
            
            112.4
            
            
            5.3
            
            
            4.7
            %Taxes
                other than income taxes
            
            
            120.2
            
            
            106.8
            
            
            13.4
            
            
            12.5
            %Income
                taxes
            
            
            52.8
            
            
            33.8
            
            
            19.0
            
            
            56.2
            %





**Purchased
      electricity** expenses
      increased $5.1 million and $16.9 million for the three and six months ended
      June
      30, 2005, respectively, compared to the same periods in 2004. The increase
      for
      the three months ended June 30, 2005 was primarily the result of higher customer
      usage, which increased both the amount of power purchased as well as generated
      power at PSE-controlled facilities. Total purchased power for the three months
      ended June 30, 2005 increased 264,281 MWh, or an increase of 7.4% compared
      to
      the same period in 2004. The increase for the six months ended June 30, 2005
      was
      the result of higher purchases and higher wholesale market prices. Total
      purchased power for the six months ended June 30, 2005 increased 453,918 MWh,
      or
      a 5.7% increase over the same period in 2004. These increases were partially
      offset by a February 23, 2005 Washington Commission order concerning PSE’s
      compliance filing related to the PCA 2 period of July 1, 2003 through June
      30,
      2004. In its order, the Washington Commission determined that PSE was allowed
      to
      reflect additional power costs totaling $6.0 million during the PCA 2 period
      of
      July 1, 2003 through December 31, 2003. These costs were deferred under the
      PCA
      mechanism, which resulted in a reduction in purchased electricity expense for
      the three and six months ended June 30, 2005.


PSE’s
      hydroelectric production and related power costs in 2005 and 2004 have continued
      to be negatively impacted by below-normal winter precipitation and reduced
      snow
      pack in the Pacific Northwest region. The June 17, 2005 Columbia Basin Runoff
      Forecast published by the National Weather Service Northwest River Forecast
      Center indicated that the total forecasted runoff above Grand Coulee Reservoir
      for the period January through July 2005 would be 86% of normal, which compares
      to 80% of normal observed runoff for the same period in 2004. PSE cannot
      determine if this trend of lower than normal runoff will continue in future
      years nor what impact such a trend may have on the amount of electricity that
      will need to be purchased.


To
      meet
      customer demand, PSE economically dispatches resources in its power supply
      portfolio such as fossil-fuel generation, owned and contracted hydroelectric
      capacity and energy, and long-term contracted power. However, depending
      principally upon availability of hydroelectric energy, plant availability,
      fuel
      prices and/or changing load as a result of weather, PSE may sell surplus power
      or purchase deficit power in the wholesale market. PSE manages its core energy
      portfolio through short-term and intermediate-term off-system physical purchases
      and sales, and through other risk management techniques.


**Electric
      generation fuel** expense
      decreased $8.1 million and $1.7 million for the three and six months ended
      June
      30, 2005, respectively, compared to the same periods in 2004. The decrease
      for
      the three months ended June 30, 2005 is primarily related to a $6.9 million
      charge recorded in June 2004 related to a binding arbitration settlement between
      Western Energy Company and PSE. Excluding this settlement, the net decrease
      was
      $1.2 million related to the overall lower cost of gas for combustion turbine
      units due to lower generation. The change for the six months ended June 30,
      2005
      excluding the $6.9 million Western Energy Company settlement in June 2004 was
      an
      increase in electric generation fuel of $5.2 million. This increase is primarily
      related to increased costs for higher generation at combustion turbine
      units.


**Purchased
      gas** expenses
      increased $34.4 million and $73.8 million for the three and six months ended
      June 30, 2005, respectively, compared to the same periods in 2004 primarily
      due
      to an increase in PGA rates as approved by the Washington Commission. The PGA
      mechanism allows PSE to recover expected gas costs, and defer, as a receivable
      or liability, any gas costs that exceed or fall short of this expected gas
      cost
      amount in PGA mechanism rates, including accrued interest. The PGA mechanism
      receivable balance at June 30, 2005 and December 31, 2004 was $32.6 million
      and
      $19.1 million, respectively. A receivable balance in the PGA mechanism reflects
      a current underrecovery of market gas cost through rates.


In the second quarter 2005, PSE determined from a review of its PGA mechanism
      that a gas demand charge created during the settlement of the 2001 general
      rate
      case for a gas customer rate class had not been included within the parameters
      to calculate the costs under the PGA mechanism for rate recovery purposes.
      As a
      result, the balance of the PGA mechanism receivable has been overstated due
      to
      the exclusion of this charge over a 31-month period from September 1, 2002
      to
      March 31, 2005. The PGA mechanism balance and gas costs at June 30, 2005 include
      a one-time true-up of $5.0 million to reflect the impact of the demand charge.
      The total impact to earnings, net of tax, was $3.3 million for the three and
      six
      months ended June 30, 2005. This adjustment impacts the comparability of gas
      margin information and purchased gas expense for both the three and six months
      ended June 30, 2005 compared with the same periods in 2004.


**Unrealized gain on derivative instruments** decreased
        $2.2 million and $2.8 million for the three and six months ended June 30,
        2005,
        respectively, compared to the same periods in 2004. The primary reason for
        the
        decrease is the timing of when the Company will be at or over the $40 million
        cap for the PCA mechanism in 2005 versus 2004, which affects the timing and
        extent of mark-to-market activity that is recorded in the income statement
        rather than being deferred on the balance sheet.


**Utility
      operations and maintenance** expense
      increased $9.9 million and $11.6 million for the three and six months ended
      June
      30, 2005, respectively, compared to the same periods in 2004. Included in the
      increases for the three and six months ended June 30, 2005 is a $1.3 million
      and
      $3.2 million increase, respectively, related to low-income program costs that
      are passed-through in retail rates with no impact on earnings. As a result,
      the
      impact on net income from utility operations and maintenance for the three
      and
      six months ended June 30, 2005 was an increase of $8.6 million and $8.4 million,
      respectively. The increases for both periods were mainly due to a $3.6 million
      and $4.3 million increase in production operations and maintenance costs for
      the
      three and six months ended June 30, 2005, respectively, associated with the
      Frederickson 1 generating facility which went into service in May 2004, and
      planned maintenance costs at the Encogen generating facility. Also included
      in
      the increase for the three and six months ended June 30, 2005 is a $1.4 million
      loss reserve associated with an arbitration panel's ruling in favor of the
      Muckleshoot Indian Tribe relating to the operation of a fish hatchery on the
      White River - see further discussion under the section titled “Other.” The
      remaining increase for both the three and six months ended June 30, 2005 relates
      to increased overhead line maintenance expenses and gas operation and
      distribution expenses. These increases were partially offset by lower storm
      damage costs of $2.0 million and $7.1 million for the three and six months
      ended
      June 30, 2005, respectively, due to less severe weather and outages in 2005.
      PSE
      anticipates operation and maintenance expense to increase in future years as
      investments in new generating resources and energy delivery infrastructure
      are
      completed. The timing and amounts of increases will vary depending on when
      new
      generating resources come into service.


**Depreciation
      and amortization** expense
      increased $3.1 million and $5.3 million for the three and six months ended
      June
      30, 2005, respectively, compared to the same periods in 2004. The increase
      was
      due to the effects of new plant placed in service during 2004, including $80.8
      million in costs for the Frederickson 1 generating facility in April 2004 and
      $32.8 million for the Everett Delta gas transmission line late in 2004. PSE
      anticipates depreciation expense will increase in future years as investments
      in
      new generating resources and energy delivery infrastructure are
      completed.


**Taxes
      other than income taxes** increased $7.9 million and $13.4 million for the three and six months ended
      June
      30, 2005, respectively, compared to the same periods in 2004 due primarily
      to
      increases in revenue-based Washington State excise tax and municipal tax due
      to
      increased operating revenues. Revenue sensitive Washington State excise and
      municipal taxes have no impact on earnings.


**Income
      taxes** increased $11.6 million and $19.0 million for the three and six months ended
      June 30, 2005, respectively, compared to the same periods in 2004 as a result
      of
      higher taxable income and a higher effective federal income tax rate.




**Other
      Income And Interest Charges**


The
      table
      below sets forth significant changes in other income and interest charges for
      PSE and its subsidiaries for the six months ended June 30, 2005 compared to
      the
      same period in 2004.





(Dollars
                in Millions)
              Six
                Months Ended June 30
            
            2005
            
            2004
            
            Change
            
            Percent
              ChangeOther
                income (net of tax)
            
            $
            2.8
            
            $
            1.6
            
            $
            1.2
            
            
            75.0
            %Interest
                charges
            
            
            81.0
            
            
            83.8
            
            
            (2.8
            )
            
            (3.3
            )%




**Other
      income** increased
      $1.2 million (after-tax) for the six months ended June 30, 2005 compared to
      the
      same period in 2004 primarily due to increases in the surrender value of
      corporate-owned life insurance policies and a higher level of equity portion
      of
      allowance for funds used during construction.


**Interest
      charges** decreased
      $2.8 million for the six months ended June 30, 2005 compared to the same period
      in 2004 due to the redemption of $137.5 million of long-term debt with rates
      ranging from 6.45% to 7.80% in 2004. Also, in May 2005, PSE redeemed $42.5
      million of PSE's
      8.231% Capital Trust Preferred Securities (classified as Junior Subordinated
      Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily
      Redeemable Preferred Securities on the balance sheet). These
      redemptions and resulting decreases in interest expense were partially offset
      by
      the issuance of $250 million of long-term senior notes in June
      2005.





**InfrastruX**
 Following
        a strategic review of Puget Energy's unregulated subsidiary, InfrastruX,
        on
        February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility
        construction services sector. Puget Energy intends to monetize its interest
        in
        InfrastruX through a sale and to invest the proceeds of such monetization
        into
        its regulated utility subsidiary, PSE. This planned disposal meets the criteria
        established for recognition as a discontinued operation under SFAS No. 144,
        “Accounting for the Impairment or Disposal of Long-Lived Assets,” and is
        accounted for as such in Puget Energy’s consolidated financial statements. Puget
        Energy has initiated discussions with interested financial and strategic
        parties
        who are in various stages of the due diligence process.  The disposal
        of
        InfrastruX is expected to be completed during 2005.
 For
        the
        three and six months ended June 30, 2005, Puget Energy reported InfrastruX
        related income from discontinued operations (net of taxes and minority interest)
        of $1.9 million and $0.9 million, respectively, compared to income of $2.9
        million and $2.6 million (net of taxes and minority interest) for the three
        and
        six months ended June 30, 2004, respectively. Included in the income for
        discontinued operations is a charge of $1.1 million after-tax recorded in
        the
        first quarter 2005 related to estimated disposal of InfrastruX and a $5.1
        million after-tax charge recorded in the second quarter 2005 to adjust Puget
        Energy's carrying value of InfrastruX to the estimated fair value. In accordance
        with SFAS No. 144, Puget Energy discontinued depreciation and amortization
        of
        InfrastruX's assets effective February 8, 2005. Following is a summary of
        Puget
        Energy’s income from discontinued operations for the three and six months ended
        June 30, 2005:
 
 (Dollars
                  in Millions)
              Three
                  Months Ended
                June
                  30, 2005
              
              Six
                  Months Ended
                June
                  30, 2005Net
                  income reported by InfrastruX
              $
              4.1
              
              $
              2.5Estimated
                  selling costs of InfrastruX, after-tax
              
              --
              
              
              (1.1
              )InfrastruX
                  depreciation/amortization not recorded by Puget Energy,
                  after-tax
              
              2.9
              
              
              4.5Puget
                  Energy tax benefit from goodwill deduction
              
              0.7
              
              
              0.7Puget
                  Energy carrying value adjustment of InfrastruX, after-tax
              
              (5.1
              )
              
              (5.1
              )Minority
                  interest in income from discontinued operations and other
              
              (0.7
              )
              
              (0.6
              )Income
                  from discontinued operations
              $
              1.9
              
              $
              0.9




InfrastruX's
          operating revenue for the three and six months ended June 30, 2005 was
          $97.3
          million and $175.0 million, respectively, compared to $92.8 million and
          $167.6
          million, respectively, for the same periods in 2004. Operating income for
          the
          three and six months ended June 30, 2005 was $6.2 million and $6.6 million,
          respectively, compared to $4.6 million and $5.6 million, respectively for
          the
          same periods in 2004.
 InfrastruX's
          debt totaled $160.1 million at June 30, 2005 compared to $159.4 million
          at
          December 31, 2004.
 InfrastruX’s
          operations are dependent on a number of factors, including weather conditions
          and availability of projects and capital to be spent on utility construction
          projects. As such, Puget Energy cannot determine what income or loss InfrastruX
          will generate during the period of time that Puget Energy continues to
          hold its
          interest in InfrastruX, nor any ultimate gain or loss upon completion of
          the
          sale of the entity. It is not anticipated that any funding will be needed
          from
          Puget Energy to maintain operations at InfrastruX or to complete the sale
          transaction.


**Capital
      Requirements**


**Contractual
      Obligations and Commercial Commitments**


**Puget
      Energy.** The
      following are Puget Energy’s aggregate consolidated (including PSE) contractual
      and commercial commitments from continuing operations as of June 30,
      2005:




**Puget
                Energy**
            
            
            
            Payments
                Due Per PeriodContractual
                Obligations
              (Dollars
                in Millions)
            Total
            2005
            2006-
              2007
            2008-
              2009
            2010
                &
              ThereafterLong-term
                debt including interest
            $
            3,939.8
            $
            102.4
            $
            476.0
            $
            568.0
            $
            2,793.4Short-term
                debt
            
            159.6
            
            159.6
            
            --
            
            --
            
            --Junior
                subordinated debentures payable to a subsidiary trust1
            
            910.7
            
            10.0
            
            39.8
            
            39.8
            
            821.1Mandatorily
                redeemable preferred stock
            
            1.9
            
            --
            
            --
            
            --
            
            1.9Service
                contract obligations
            
            172.0
            
            11.3
            
            54.1
            
            53.2
            
            53.4Non-cancelable
                operating leases
            
            128.9
            
            6.7
            
            33.0
            
            27.5
            
            61.7Fredonia
                combustion turbines lease2
            
            62.9
            
            2.2
            
            8.6
            
            8.3
            
            43.8Energy
                purchase obligations
            
            6,676.3
            
            630.4
            
            1,759.2
            
            1,225.5
            
            3,061.2Financial
                hedge obligations
            
            307.4
            
            161.2
            
            141.4
            
            4.8
            
            --Pension
                funding3
            
            44.8
            
            3.4
            
            8.2
            
            9.8
            
            23.4Total
                contractual cash obligations
            $
            12,404.3
            $$
            1,087.2
            $
            2,520.3
            $$
            1,936.9
            $$
            6,859.9








Amount
                of Commitment
              Expiration
                Per PeriodCommercial
                Commitments
              (Dollars
                in Millions)
            Total
            2005
            2006-
              2007
            2008-
              2009
            2010
                &
              ThereafterGuarantees4
            $
            131.0
            $$
            --
            $
            131.0
            $$
            --
            $$
            --Liquidity
                facilities - available5
            
            489.9
            
            150.0
            
            --
            
            --
            
            339.9Lines
                of credit - available6
            
            --
            
            --
            
            --
            
            --
            
            --Energy
                operations letter of credit
            
            0.5
            
            --
            
            0.5
            
            --
            
            --Total
                commercial commitments
            $
            621.4
            $$
            150.0
            $
            131.5
            $$
            --
            $$
            339.9


_______________________


*1*
            *In
                1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and
                Puget
                Sound Energy Capital Trust II, respectively, for the sole purpose
                of
                issuing and selling preferred securities (Trust Securities) to investors
                and issuing common securities to PSE. The proceeds from the sale
                of Trust
                Securities were used by the Trusts to purchase Junior Subordinated
                Debentures (Debentures) from PSE. The Debentures are the sole assets
                of
                the Trusts and PSE owns all common securities of the Trusts.*


2 **
            *See
                “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
                below.*


*3*
            *Pension
                funding is based on an actuarial
                estimate.*


*4*
            *In
                May 2004, InfrastruX signed a three-year credit agreement with a
                group of
                banks to provide up to $150 million in financing. Under the credit
                agreement, Puget Energy is the guarantor of the line of credit. Certain
                InfrastruX subsidiaries also have certain borrowing capacities for
                working
                capital purposes of which Puget Energy is not a guarantor. Of the
                $150
                million available to InfrastruX, $131.0 was outstanding at June 30,
                2005.*


*5*
            *At
                June 30, 2005, PSE had available a $500 million unsecured credit
                agreement
                expiring in April 2010 and a $150 million receivables securitization
                facility that expires in December 2005. At June 30, 2005, PSE had
                no
                amounts sold under its receivables securitization facility. See “Accounts
                Receivable Securitization Program” under “Off-Balance Sheet Arrangements”
                below for further discussion. The credit agreement and securitization
                facility provide credit support for outstanding commercial paper
                of $159.6
                million and a letter of credit totaling $0.5 million, thereby effectively
                reducing the available borrowing capacity under these liquidity facilities
                to $489.9 million.*


6
            *Puget
                Energy has a $5 million line of credit with a bank. At June 30, 2005,
                $5.0
                million was outstanding, leaving no amounts available to borrow under
                the
                agreement.*




**Puget
      Sound
      Energy** .
      The
      following are PSE’s aggregate contractual and commercial commitments as of June
      30, 2005:





**Puget
                Sound Energy**
            
            
            
            Payments
                Due Per PeriodContractual
                Obligations
              (Dollars
                in Millions)
            Total
            2005
            2006-
              2007
            2008-
              2009
            2010
                & ThereafterLong-term
                debt including interest
            $
            3,934.6
            $
            102.3
            $
            470.9
            $
            568.0
            $
            2,793.4Short-term
                debt
            
            159.6
            
            159.6
            
            --
            
            --
            
            --Junior
                subordinated debentures payable to a subsidiary trust1
            
            910.7
            
            10.0
            
            39.8
            
            39.8
            
            821.1Mandatorily
                redeemable preferred stock
            
            1.9
            
            --
            
            --
            
            --
            
            1.9Service
                contract obligations
            
            172.0
            
            11.3
            
            54.1
            
            53.2
            
            53.4Non-cancelable
                operating leases
            
            128.9
            
            6.7
            
            33.0
            
            27.5
            
            61.7Fredonia
                combustion turbines lease2
            
            62.9
            
            2.2
            
            8.6
            
            8.3
            
            43.8Energy
                purchase obligations
            
            6,676.3
            
            630.4
            
            1,759.2
            
            1,225.5
            
            3,061.2Financial
                hedge obligations
            
            307.4
            
            161.2
            
            141.4
            
            4.8
            
            --Pension
                funding3
            
            44.8
            
            3.4
            
            8.2
            
            9.8
            
            23.4Total
                contractual cash obligations
            $
            12,399.1
            $
            1,087.1
            $
            2,515.2
            $
            1,936.9
            $
            6,859.9





Amount
                of Commitment
              Expiration
                Per PeriodCommercial
                Commitments
              (Dollars
                in Millions)
            Total
            2005
            2006-
              2007
            2008-
              2009
            2010
                & ThereafterLiquidity
                facilities - available4
            $
            489.9
            $
            150.0
            $
            --
            $
            --
            $
            339.9Energy
                operations letter of credit
            
            0.5
            
            --
            
            0.5
            
            --
            
            --Total
                commercial commitments
            $
            490.4
            $
            150.0
            $
            0.5
            $
            --
            $
            339.9


_______________________


*1*
            *See
                note 1 above.*


*2*
            *See
                note 2 above.*


*3*
            *See
                note 3 above.*


*4*
            *See
                note 5 above.*





**Off-Balance
      Sheet Arrangements**





**Accounts
      Receivable Securitization Program**


In
      order
      to provide a source of liquidity to PSE at an attractive cost, PSE entered
      into
      a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned
      subsidiary of PSE in December 2002. Pursuant to the Receivables Sales Agreement,
      PSE sold all its utility customers’ accounts receivable and unbilled utility
      revenues to Rainier Receivables. Concurrently with entering into the Receivables
      Sales Agreement, Rainier Receivables entered into a Receivables Purchase
      Agreement with PSE and a third party. The Receivables Purchase Agreement allows
      Rainier Receivables to sell the receivables purchased from PSE to the third
      party. The amount of receivables sold by Rainier Receivables is not permitted
      to
      exceed $150 million at any time. However, the maximum amount may be
      less
      than $150 million depending on the outstanding eligible amount of PSE’s
      receivables, which fluctuate with the seasonality of energy sales to
      customers.


The
      receivables securitization facility is the functional equivalent of a revolving
      line of credit secured by receivables. In the event Rainier Receivables elects
      to sell receivables under the Receivables Purchase Agreement, Rainier
      Receivables is required to pay fees to the purchasers that are comparable to
      interest rates on a revolving line of credit. As receivables are collected
      by
      PSE as agent for the receivables purchasers, the outstanding amount of
      receivables held by the purchasers declines until Rainier Receivables elects
      to
      sell additional receivables to the purchasers.


The
      receivables securitization facility expires in December 2005, but is terminable
      by PSE and Rainier Receivables upon notice to the receivables purchasers. At
      June 30, 2005, Rainier Receivables had no amounts sold under the receivables
      securitization facility, leaving a maximum amount of receivables available
      to be
      sold under the program of $150.0 million. During the three months ended June
      30,
      2005 and 2004, Rainier Receivables sold a cumulative $60.0 million and $145.0
      million of receivables, respectively. During the six months ended June 30,
      2005,
      and 2004, Rainier Receivables sold a cumulative $60.0 million and $267.0 million
      of receivables, respectively.





**Fredonia
      3 and 4 Operating Lease**


PSE
      leases two combustion turbines for its Fredonia 3 and 4 electric generating
      facility pursuant to a master operating lease that was amended in April 2001.
      The lease has a term expiring in 2011, but can be canceled by PSE at any time.
      Payments under the lease vary with changes in the London Interbank Offered
      Rate
      (LIBOR). At June 30, 2005, PSE’s outstanding balance under the lease was $55.4
      million. The expected residual value under the lease is the lesser of $37.4
      million or 60% of the cost of the equipment. In the event the equipment is
      sold
      to a third party upon termination of the lease and the aggregate sales proceeds
      are less than the unamortized value of the equipment, PSE would be required
      to
      pay the lessor contingent rent in an amount equal to the deficiency up to a
      maximum of 87% of the unamortized value of the equipment.





**Utility
      Construction Program**


Utility
      construction expenditures for generation, transmission and distribution are
      designed to meet continuing customer growth and to improve efficiencies of
      PSE’s
      energy delivery systems. Construction expenditures, excluding equity Allowance
      for Funds Used During Construction (AFUDC) and customer refundable
      contributions, were $237.0 million for the six months ended June 30, 2005.
      Utility construction expenditures in 2005, 2006 and 2007 are anticipated to
      be
      approximately $580 million, $400 million and $384 million, respectively,
      including the new Hopkins Ridge wind project, but excluding amounts for new
      generation resources currently under evaluation. New generation resources under
      evaluation consist of the Wild Horse wind project, which if completed, is
      anticipated to have a total cost of approximately $350 million. The proposed
      utility construction expenditures and new generation resource expenditures,
      if
      acquired, are anticipated to be funded with a combination of short-term debt,
      long-term debt and equity. Construction expenditure estimates, including the
      new
      generation resources, are subject to periodic review and adjustment in light
      of
      changing economic, regulatory, environmental and efficiency
      factors.





**New
      Generation Resources**


On
      March
      11, 2005, PSE completed the acquisition of the Hopkins Ridge wind project from
      Blue Sky Wind, LLC and issued its key contractor, RES America Construction,
      Inc., a notice to proceed with construction of the project. Hopkins Ridge is
      situated on 11,000 acres of remote, open wheat fields in southeastern Washington
      State. The Hopkins Ridge wind project will feature 83 Vestas 1.8-MW wind
      turbines providing up to 150 MW of capacity, or 52 average MW. Upon completion
      of construction, the energy will be delivered to PSE’s service territory by
      BPA’s transmission system via an interconnection. PSE anticipates spending
      approximately $200 million on the project, which it solely owns. Included in
      the
      $200 million estimate is $180 million to acquire and construct the wind plant,
      $10 million to fund upgrades to the transmission systems of the Bonneville
      Power
      Administration and other regional transmission providers, and the balance for
      development, transaction and financing costs.


In
      September 2004, PSE signed a non-binding letter of intent to obtain a 100%
      ownership interest in the proposed Wild Horse wind project. The project is
      located in central Washington State. The Wild Horse project is expected to
      have
      as many as 130 wind turbines which are anticipated to provide approximately
      230
      MW of capacity, or 77 average MW.  The final agreement to purchase the
      Wild
      Horse wind project is anticipated to be executed in 2005.





**Capital
      Resources**


**Cash
      From Operations**


Cash
      generated from operations for the six months ended June 30, 2005 was $136.6
      million. During that period, $47.4 million in cash was used for AFUDC and
      payment of dividends. Consequently, cash flows available for utility
      construction expenditures and other capital expenditures were $89.2 million
      or
      39% of the $227.3 million in construction expenditures (net of AFUDC and
      customer refundable contributions) and other capital expenditure requirements
      for the six months ended June 30, 2005. For the six months ended June 30, 2004,
      cash generated from operations was $286.9 million, $45.4 million of which was
      used for AFUDC and payment of dividends. Therefore, cash flows available for
      utility **** construction
      expenditures and other capital **** expenditures
      were $241.5 million, or 102% of the $236.6 million in construction expenditures
      (net of AFUDC and customer refundable contributions) and other capital
      expenditure requirements for the six month period ended June 30, 2004.


The
      overall cash generated from operating activities for the six month period ended
      June 30, 2005 decreased $150.3 million compared to the same period in 2004.
      The
      decrease was primarily the result of changes in the utilization of sales of
      accounts receivables to Rainier Receivables under the accounts receivable
      securitization program which contributed $179.0 million to the decrease in
      cash
      generated from operations. Also contributing to the decrease was a decrease
      in
      the amounts outstanding in accounts payable of $18.6 million, changes in the
      residential exchange program which contributed $6.0 million to the decrease,
      and
      a decrease in the previously accrued Tenaska disallowance of $16.8 million.
      These decreases were partially offset by an increase in net income of $25.4
      million, an increase in cash flows from accounts receivables of $23.2 million
      and an increase in cash flow from the purchased gas receivable of $8.3
      million.





**Financing
      Program**


Financing
      utility construction requirements and operational needs are dependent upon
      the
      cost and availability of external funds through capital markets and from
      financial institutions. Access to funds is dependent upon factors such as
      general economic conditions, regulatory authorizations and policies, and Puget
      Energy’s and PSE’s credit ratings.





**Restrictive
      Covenants**


In
      determining the type and amount of future financing, PSE may be limited by
      restrictions contained in its electric and gas mortgage indentures, articles
      of
      incorporation and certain loan agreements. Under the most restrictive tests,
      at
      June 30, 2005, PSE could issue:


·
            approximately
                $400 million of additional first mortgage bonds under PSE’s electric
                mortgage indenture based on approximately $667 million of electric
                bondable property available for issuance, subject to an interest
                coverage
                ratio limitation of 2.0 times net earnings available for interest,
                which
                PSE exceeded at June 30, 2005;


·
            approximately
                $192 million of additional first mortgage bonds under PSE’s gas mortgage
                indenture based on approximately $320 million of gas bondable property
                available for issuance, subject to an interest coverage ratio limitation
                of 1.75 times net earnings available for interest, which PSE exceeded
                at
                June 30, 2005;


·
            approximately
                $663 million of additional preferred stock at an assumed dividend
                rate of
                6.375%; and


·
            approximately
                $193 million of unsecured long-term
                debt.





At
      June
      30, 2005, PSE had approximately $3.6 billion in electric and gas ratebase to
      support the interest coverage ratio limitation test for net earnings available
      for interest.





**Credit
      Ratings**


Neither
      Puget Energy nor PSE has had any rating downgrades that would accelerate the
      maturity dates of outstanding debt. However, a downgrade in the companies’
      credit ratings could adversely affect their ability to renew existing, or obtain
      access to new, credit facilities and could increase the cost of such facilities.
      For example, under PSE’s revolving credit facility, the spreads over the index
      and commitment fee increase as PSE’s secured long-term debt ratings decline. A
      downgrade in commercial paper ratings could preclude PSE’s ability to issue
      commercial paper under its current programs. The marketability of PSE commercial
      paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and
      Moody’s Investors Service. In addition, downgrades in any or a combination of
      PSE’s debt ratings may prompt counterparties on a contract by contract basis in
      the wholesale electric, wholesale gas and financial derivative markets to
      require PSE to post a letter of credit or other collateral, make cash
      prepayments, obtain a guarantee agreement or provide other mutually agreeable
      security.




The
      ratings of Puget Energy and PSE, as of July 20, 2005, were as
      follows:





RatingsStandard
                & Poor’s
            Moody’s**Puget
                Sound Energy**Corporate
                credit/issuer rating
            BBB-
            Baa3Senior
                secured debt
            BBB
            Baa2Shelf
                debt senior secured
            BBB
            (P)Baa2Trust
                preferred securities
            BB
            Ba1Preferred
                stock
            BB
            Ba2Commercial
                paper
            A-3
            P-2Revolving
                credit facility
            *
            Baa3Ratings
                outlook
            Stable
            Stable**Puget
                Energy**Corporate
                credit/issuer rating
            BBB-
            Ba1


_______________________


*
      *Standard & Poor’s does not rate credit facilities*.





**Shelf
      Registrations, Long-Term Debt and Common Stock Activity**


On
      April
      19, 2005, Puget Energy and PSE filed a shelf registration statement with the
      Securities and Exchange Commission for the offering, on a delayed or continuous
      basis, of up to $850 million of:


·
            common
                stock of Puget Energy, and


·
            senior
                notes of PSE, secured by a pledge of PSE’s first mortgage
                bonds.


The
      shelf
      registration statement, effective as of May 4, 2005, replaces Puget Energy
      and
      PSE’s previous $500 million shelf registration statement. The new shelf
      registration statement provides the Company with additional capacity and
      flexibility when funding anticipated capital projects and meeting maturing
      debt
      obligations.


On
      May
      18, 2005, PSE tendered an offer to repurchase all of PSE's 8.231% Capital Trust
      Preferred Securities (classified as Junior Subordinated Debentures of the
      Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable
      Preferred Securities on the balance sheet). The purpose of the tender offer
      was
      to help reduce interest costs by retiring higher cost debt. As a result of
      the
      tender offer, $42.5 million of the Capital Trust Preferred Securities were
      redeemed on June 2, 2005 at a 4% premium which totaled approximately $4.6
      million. PSE may undertake future tender offers to reduce higher cost debt
      depending on future market opportunities.


In
      May
      2005, PSE completed the issuance of $250 million of senior notes secured by
      first mortgage bonds, at a rate of 5.483%. The net proceeds from the issuance
      of
      the senior notes of approximately $247.6 million were used to redeem $200
      million of variable rate senior notes, which were redeemed at par in May 2005,
      and to repay a portion of PSE’s short-term debt.


Based
      on
      PSE's goal to become a more vertically integrated utility, it is expected that
      further issuances of debt, equity or both will be utilized within one to two
      years to fund acquisitions of new generating resources. The structure, timing
      and amount of such financings are dependent on market conditions, projects
      available to be developed, and financing needed at the time of any such
      acquisitions.





**Liquidity
      Facilities and Commercial Paper**


PSE’s
      short-term borrowings and sales of commercial paper are used to provide working
      capital and funding of utility construction programs.


In
      May
      2004, PSE entered into a three-year, $350 million unsecured credit agreement
      with a group of banks. In March 2005, PSE amended this credit agreement,
      increasing the total borrowing capacity from $350 million to $500 million,
      and
      extending the expiration date from June 2007 to April 2010. Under the terms
      of
      the credit agreement, PSE pays a floating interest rate on outstanding
      borrowings based either on the agent bank’s prime rate or on LIBOR plus a
      marginal rate based on PSE’s long-term credit rating at the time of borrowing.
      PSE pays a commitment fee on any unused portion of the credit agreement also
      based on long-term credit ratings of PSE. PSE also has available its $150
      million receivables securitization program with Rainier Receivables, which
      expires in December 2005. At June 30, 2005, PSE had available $500 million
      in
      the unsecured credit agreement and $150 million under its receivables
      securitization facility, both of which provide credit support for outstanding
      commercial paper and letters of credit. At June 30, 2005, there was $159.6
      million in commercial paper outstanding and $0.5 million outstanding under
      a
      letter of credit, effectively reducing the available borrowing capacity under
      these liquidity facilities to $489.9 million.


In
      February 2005, PSE entered into an uncommitted $20 million unsecured credit
      agreement with a bank. Under the terms of the credit agreement, PSE pays a
      varying interest rate on outstanding borrowings based on the terms entered
      into
      at the time of borrowing. At June 30, 2005, there were no amounts outstanding
      under this credit agreement.


Puget
      Energy has a $5 million credit agreement expiring in May 2006 with a bank.
      Under
      the terms of the agreement, Puget Energy pays a floating interest rate on
      borrowings based on LIBOR. The interest rate is set for one, two, or three-month
      periods at the option of Puget Energy with interest due at the end of each
      period. Puget Energy also pays a commitment fee on any unused portion of the
      credit facility. Puget Energy had $5 million outstanding under the credit
      agreement at June 30, 2005.




**Stock
      Purchase and Dividend Reinvestment Plan**


Puget
      Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which
      shareholders and other interested investors may invest cash and cash dividends
      in shares of Puget Energy’s common stock. Since new shares of common stock may
      be purchased directly from Puget Energy, funds received may be used for general
      corporate purposes. Puget Energy issued common stock from the Stock Purchase
      and
      Dividend Reinvestment Plan of $3.7 million (168,213 shares) and $7.3 million
      (320,020 shares) for the three and six months ended June 30, 2005, respectively,
      compared to $3.8 million (178,551 shares) and $7.7 million (354,176 shares)
      for
      the three and six months ended June 30, 2004, respectively.





**Common
      Stock Offering Programs**


To
      provide additional financing options, Puget Energy entered into agreements
      in
      July 2003 with two financial institutions under which Puget Energy may offer
      and
      sell shares of its common stock from time to time through these institutions
      as
      sales agents, or as principals. Sales of the common stock, if any, may be made
      by means of negotiated transactions or in transactions that may be deemed to
      be
“at-the-market” offerings as defined in Rule 415 promulgated under the
      Securities Act of 1933, including in ordinary brokers’ transactions on the New
      York Stock Exchange at market prices.








**Other**





**FERC
      Hydroelectric Projects And Licenses**


**Snoqualmie
      Falls project.** The
      Snoqualmie Falls project, built in 1898, had its original license issued May
      13,
      1975, which was made effective retroactive to March 1, 1956, and expired on
      December 31, 1993. PSE filed its application to relicense the project on
      November 25, 1991, and operated the project pursuant to annual licenses issued
      by FERC since the original license expired. On June 29, 2004, FERC granted
      PSE a
      new 40-year operating license for the Snoqualmie Falls project. PSE estimates
      that the investment required to implement the conditions of the new license
      agreement will cost approximately $44 million. These conditions include modified
      operating procedures and various project upgrades that include better protection
      of fish, development of riparian habitat to promote fish propagation, increased
      minimum flows in the Snoqualmie River during low-water periods and the
      development of recreational amenities near the down-river power house. On July
      29, 2004, the Snoqualmie Tribe and certain other parties filed a request for
      rehearing of the new license and a request to stay the FERC license. On March
      1,
      2005, FERC issued an Order on Rehearing and Dismissing Stay Request. The order
      requires additional flows at Snoqualmie Falls during certain times of the year.
      PSE requested rehearing of the order on the grounds that the order interferes
      with the State Department of Ecology’s authority to regulate water quality and
      that FERC arbitrarily and capriciously rebalanced the public interest without
      support of substantive evidence in the record. The Snoqualmie Tribe subsequently
      appealed FERC’s decision to the United States Court of Appeals for the Ninth
      Circuit and PSE intervened in that proceeding. PSE’s request for rehearing was
      denied on June 1, 2005 and on July 8, PSE asked for further review of this
      order
      by the Ninth Circuit. PSE will seek to consolidate the two petitions into one
      review proceeding.




**Baker
      River project.** The
      Baker River hydroelectric project’s current license expires on April 30, 2006,
      and PSE submitted an application for a new license to FERC on April 30, 2004.
      PSE reached a comprehensive settlement agreement with 23 parties on all issues
      relating to the relicensing of the project that must be approved by FERC in
      order to become effective. The proposed settlement includes a set of proposed
      license articles and, if approved by FERC without material modification, would
      allow a new license for 45 years or more. The proposed settlement would require
      an investment of approximately $360 million (capital expenditures and operations
      and maintenance cost) in order to implement the conditions of the new license
      over the next 30 years. FERC has not yet ruled on the proposed settlement and
      its ultimate outcome remains uncertain. In connection with the relicensing
      of
      the Baker River project, PSE is subject to additional regulatory approvals
      yet
      to be attained from various agencies. As required by the Coastal Zone Management
      Act (CZMA), PSE included a certification of consistency with Washington’s
      Coastal Zone Management Program (CZMP). The CZMP requires the submission of
      applications for any required shoreline exemptions, permits or variances under
      the Washington Shoreline Management Act (SMA) in order to provide the State
      of
      Washington Department of Ecology with the necessary data and information to
      make
      its CZMA Consistency Determination. In March 2005, PSE made appropriate filings
      pursuant to the local shoreline regulations adopted by Whatcom County, Skagit
      County and the Town of Concrete. PSE filed requests for exemption in Whatcom
      County and Skagit County and a shoreline substantial development permit with
      the
      Town of Concrete. In May 2005, Skagit County entered a decision denying PSE’s
      shoreline exemption application. On May 20, 2005, PSE appealed Skagit County’s
      decision and challenged the denial of the shoreline exemption application.
      Hearings before the Skagit County Hearing Examiner on the exemption application
      determination are scheduled to take place later in 2005 and its outcome remains
      uncertain. On May 15, 2005, PSE received notice that FERC would issue a Draft
      Environmental Impact Statement (DEIS) in lieu of an Environmental Assessment
      (EA) for the Baker River project. FERC anticipates issuing the DEIS in the
      third
      quarter 2005, as opposed to May 2005 for the EA. The contents of the DEIS and
      potential impacts on the proposed settlement for the new license are as yet
      unknown. Further actions at FERC could have an impact on the schedule for
      issuing a new license.





**Electric
      Regulation and Rates**


**FERC
      matter.** **** PSE’s
      market-based rate tariff was accepted by FERC in an order dated January 29,
      1999. Pursuant to this order, PSE is required to file an updated market power
      analysis every three years. On August 11, 2004, PSE filed an updated market
      power analysis with FERC as required by a FERC order dated May 13, 2004. The
      August 11, 2004 filing was supplemented by additional filings on September
      24,
      2004 and November 19, 2004. On December 20, 2004, FERC issued an order (December
      20 order) finding that PSE had not provided sufficient information for FERC
      to
      determine if PSE had passed the generation market power screens with respect
      to
      wholesale sales within PSE’s control area. The order instituted an investigation
      under Section 206 of the Federal Power Act (FPA) and established a prospective
      refund date of February 27, 2005. Both the proceeding and the refund effective
      date affected only wholesale sales at market-based rates by PSE inside its
      own
      control area. On February 1, 2005, PSE submitted to FERC additional information
      in accordance with the December 20 order. On April 13, 2005, FERC issued an
      order terminating the Section 206 investigation and accepting PSE’s updated
      market power analysis.





**Power
      Cost Only Rate Case.** On
      June
      7, 2005, PSE filed a power cost only rate case (PCORC) with the Washington
      Utilities and Transportation Commission (Washington Commission) to help recover
      the higher cost of power. The PCORC requested a 3.7% increase in electric rates,
      or $55.6 million annually. Included in the request is recovery of capital and
      anticipated operating costs for the newly acquired Hopkins Ridge wind project
      once it goes online, which is expected in late 2005. The PCORC process is an
      accelerated rate proceeding where only power costs are reviewed. The PCORC
      proceeding can take up to five months to be concluded.





**Least
      Cost Plan.** PSE
      filed
      its electric Least Cost Plan on May 2, 2005 with the Washington Commission.
      The
      plan supports a strategy of diverse electric power and demand resource
      acquisitions including resources fueled by natural gas and coal, renewable
      resources (e.g. wind and biomass), and the implementation of energy efficiency
      strategies. The Least Cost Plan will be followed by issuing an all-source
      request for proposal (RFP) in late 2005. A draft version of the all-source
      RFP
      was filed with the Washington Commission on July 29, 2005.


Based
      on
      PSE's projected customer usage for electricity and its current electric
      generation resources, PSE projects that future energy needs will exceed current
      purchased and Company-controlled power resources. The projected MW shortfall
      for
      the period 2006 through 2010 is as follows:





2006
            2007
            2008
            2009
            2010Projected
                MW shortfall1
            208
            263
            305
            360
            457


_______________________


*1*
              *Estimated
                using all resources under long-term contracts and Company-controlled
                resources. Also includes projected completion of the Hopkins Ridge
                wind
                project and anticipated acquisition of the Wild Horse wind
                project.*


PSE
      expects to address this shortfall position with the use of a combination of
      new
      long-term power contracts and the purchase or construction of new generating
      resources as outlined in the Least Cost Plan and draft all-source RFP.





**PCA
      Mechanism.**  PSE
      has a
      PCA mechanism that triggers if PSE’s costs to provide customers’ electricity
      falls outside certain bands from a normalized level of power costs established
      in the electric general rate case. The cumulative maximum pre-tax earnings
      exposure due to power cost variations over the four-year period ending June
      30,
      2006 is limited to $40 million plus 1% of the excess. Upon expiration of the
      $40
      million cumulative cap, the annual power cost variability is subject to the
      bands in the table below. All significant variable power supply cost drivers
      are
      included in the PCA mechanism (hydroelectric generation variability, market
      price variability for purchased power and surplus power sales, natural gas
      and
      coal fuel price variability, generation unit forced outage risk and wheeling
      cost variability).


Upon
      expiration of the cumulative cap, the most significant risks are hydroelectric
      generation variability and wholesale market prices of natural gas and power.
      On
      an annual July through June basis, the PCA mechanism apportions increases or
      decreases in power costs, on a graduated scale, between PSE and its customers
      in
      the following manner:





Annual
                Power
              Cost
                Variability
            
            Customers’
                Share
            
            Company’s
                Share1+/-
                $20 million
            
            0%
            
            100%+/-
                $20 - $40 million
            
            50%
            
            50%+/-
                $40 - $120 million
            
            90%
            
            10%+/-
                $120 million
            
            95%
            
            5%


__________________________


*1*
            *Over
                the four-year period July 1, 2002 through June 30, 2006, the Company’s
                share of pre-tax power cost variations is capped at a cumulative
                $40
                million plus 1% of the excess. Power cost variation after June 30,
                2006
                will be apportioned on an annual basis, based on the graduated
                scale.*





Based
      on
      past activity under the PCA mechanism and volatility of power costs, it is
      possible that PSE could experience higher expenses associated with excess power
      based on the sharing arrangement once the cumulative $40 million cap expires
      on
      June 30, 2006. As such, the risk dynamics change for PSE and its customers.
      PSE
      is required by the Washington Commission to make a PCORC filing or general
      tariff filing by February 28, 2006 to reset the PCA power cost baseline rates
      effective July 1, 2006.





**Tenaska
      Disallowance.** **** The
      Washington Commission issued an order on May 13, 2004 determining that PSE
      did
      not prudently manage gas costs for the Tenaska electric generating plant and
      ordered PSE to adjust its PCA deferral account to reflect a one-time
      disallowance of accumulated costs under the PCA mechanism for these excess
      costs. The order also established guidelines and a benchmark to determine PSE’s
      recovery on the Tenaska regulatory asset starting with the PCA 3 period (July
      1,
      2004) through the expiration of the Tenaska contract in the year 2011. The
      benchmark is defined as the original cost of the Tenaska contract adjusted
      to
      reflect the 1.2% disallowance from a 1994 Prudence Order.




The
      Washington Commission guidelines for determining future recovery of the Tenaska
      costs (gas costs, recovery of the Tenaska regulatory asset and return on the
      Tenaska regulatory asset) are as follows:


1.
            The
                Washington Commission will determine if PSE’s gas purchasing plan and gas
                purchases for Tenaska are prudent through the PCA compliance filings.


2.
            If
                PSE’s gas purchasing plan and gas purchases for Tenaska are prudent,
                and
                if PSE’s actual Tenaska costs fall at or below the benchmark, it will
                fully recover its Tenaska costs.


3.
            If
                PSE’s gas purchasing plan and gas purchases for Tenaska are prudent,
                but
                its actual Tenaska costs exceed the benchmark, PSE will only recover
                50%
                of the lesser of:


a)
            actual
                Tenaska costs that exceed the benchmark;
                or


b)
            the
                return on the Tenaska regulatory asset.


4.
            If
                PSE’s gas purchasing plan or gas purchases are found to be imprudent
                in a
                future proceeding, PSE risks disallowance of any and all Tenaska
                costs.





The
      Washington Commission confirmed that if the Tenaska gas costs are deemed
      prudent, PSE will recover the full amount of actual gas costs and the recovery
      of the Tenaska regulatory asset even if the benchmark is exceeded. Due to
      fluctuations in forward market prices of gas, the amount and timing of any
      potential disallowance related to Tenaska can change significantly day to day.
      The projected costs and projected benchmark costs for Tenaska as of June 30,
      2005, based on current forward market gas prices are as follows:





(Dollars
                in Millions)
            
            Remaining
              2005
            
            2006
            
            2007
            
            2008
            
            2009
            
            2010
            
            2011Projected
                Tenaska costs *
            
            $
            107.2
            
            $
            219.2
            
            $
            222.9
            
            $
            218.4
            
            $
            212.2
            
            $
            204.9
            
            $
            204.4Projected
                Tenaska benchmark costs
            
            
            82.0
            
            
            167.8
            
            
            175.3
            
            
            182.2
            
            
            189.5
            
            
            197.2
            
            
            213.8Over
                (under) benchmark costs
            
            $
            25.2
            
            $
            51.4
            
            $
            47.6
            
            $
            36.2
            
            $
            22.7
            
            $
            7.7
            
            $
            (9.4
            )Projected
                50% disallowance based
              on
                Washington Commission
              methodology
            
            $
            4.7
            
            $
            8.8
            
            $
            7.7
            
            $
            6.3
            
            $
            4.7
            
            $
            2.0
            
            $
            --


_______________________


*
      *Projection will change based on market conditions of gas and replacement
      power costs.*




**FERC
        Standard Market Design.** On July 19, 2005, FERC announced that it had
        officially abandoned efforts commenced in 2002 to create a Standard Market
        Design, stating that voluntary progress in the market had overtaken the need
        for
        a mandatory national approach. The decision to abandon the Standard Market
        Design initiative has no impact on PSE beyond the potential implications
        that
        completion of such an initiative would have had on PSE.
  Other **Muckleshoot
          Indian Tribe vs. PSE Arbitration.** On June 30, 2005 PSE received
          an adverse ruling by an arbitration panel awarding approximately $2.2 million
          in
          costs and interest for operations and maintenance of a fish hatchery on
          the
          White River owned and operated by the Muckleshoot Indian Tribe. The arbitration
          arose out of a disputed interpretation of a 1986 settlement agreement that
          resolved litigation brought by the tribe in the 1980’s regarding the White River
          project. The arbitration related to when the Company’s obligations to pay for
          the hatchery’s O&M costs ceased. Of the $2.2 million awarded, $1.4 million
          was charged to operation and maintenance expense and $0.8 million to interest
          expense in the second quarter 2005.


**Colstrip
      Taxes and Royalties.** The
      Minerals Management Service of the United States Department of the Interior
      issued an order on March 30, 2005 that approved in part and rejected in part
      the
      appeal filed by Western Energy Company (WECO) on the coal transportation
      revenues. On June 17, 2005 WECO filed a further appeal of that order to the
      US
      Department of the Interior Board of Land Appeals. No decision in that process
      is
      expected for over a year.


**Notice
      of Proposed Adjustment by the Internal Revenue Service.** On July
      12, 2005, Puget Energy received a notice of proposed adjustment (NOPA) from
      the
      Internal Revenue Service relating to a deduction in Puget Energy's 2003 tax
      return. The deduction relates to the receivable balance due from the California
      Independent System Operator Corporation. The NOPA states that the deduction
      is
      not valid for the 2003 tax year, and requests payment of approximately $14.5
      million in taxes and approximately $1.0 million in related interest. Management
      of Puget Energy believes the deduction is valid and intends to vigorously defend
      the deduction, however the outcome of this issue cannot be predicted. Any
      potential tax related payment (excluding interest) would have no impact on
      earnings as it would be recognized as a deferred tax asset.





**Proceedings
      Relating to the Western Power Market**


Puget
      Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31,
      2004 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2005
      include a summary and subsequent developments relating to the western power
      market proceedings described below. The following discussion provides a summary
      of material developments in these proceedings that occurred during the period
      covered by this report and of any new material proceedings instituted during
      the
      period covered by this report. PSE intends to vigorously defend against each
      of
      these cases and does not expect the ultimate resolution of these proceedings
      in
      the aggregate to have a material adverse impact on the financial condition,
      results of operations or liquidity of the Company. However, there can be no
      assurances in that regard because litigation is subject to numerous
      uncertainties and PSE is unable to predict the ultimate outcome of these
      matters. Accordingly, there can be no guarantee that these proceedings, either
      individually or in the aggregate, will not materially and adversely affect
      PSE’s
      financial condition, results of operations or liquidity.





**1.**
            **California
                Refund Proceeding.**On
                July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95)
                to
                determine the amount of refunds due to California energy buyers for
                purchases made in the spot markets operated by the CAISO and the
                California PX during the period October 2, 2000 through
                June 20, 2001 (refund period). The CAISO continues
                its efforts
                to prepare revised settlement statements based on newly recalculated
                costs
                and charges for spot market sales to California during the refund
                period
                and currently estimates that it will preliminarily determine “who owes
                what to whom” sometime in 2005 or 2006. A review of that claim is pending,
                especially in light of a June 27, 2005 FERC order clarifying the
                methodology for submitting fuel cost claims. Within the last several
                months, global settlements have been announced and/or approved, including
                settlements between the California Parties and Williams, Duke, El
                Paso,
                Mirant, Dynegy, and Enron. These settlements, supported by a recent
                statement from the new FERC chairman Joseph Kelliher may suggest
                that the
                process momentum toward settlement in the California Refund Proceedings
                is
                increasing.





**2.**
            **Pacific
                Northwest Refund Proceeding.**On
                June 25, 2003, FERC issued an order terminating the proceeding, largely
                on
                procedural, jurisdictional and equitable grounds. Various parties
                filed
                rehearing requests, which were denied by FERC in an order affirming
                the
                termination of the Pacific Northwest Refund Proceeding, (Docket No.
                EL01-10). Seven petitions for review, including PSE’s, are now pending
                before the United States Court of Appeals for the Ninth Circuit.
                Briefing
                is complete and the Ninth Circuit is expected to schedule oral argument
                during the fall of 2005. An order that assigned the case to the same
                panel
                that decided the Lockyer case, which is described in the Company’s Annual
                Report on Form 10-K for the year ended December 31, 2004, was issued
                on
                July 13, 2005.





**3.**
            **Wah
                Chang v. Avista Corp., PSE and others.**In
                June 2004, Puget Energy and PSE were served a federal summons and
                complaint by Wah Chang, an Oregon company. Wah Chang claims that
                during
                1998 through 2001 the Company and other energy companies (and in
                a
                separate complaint, energy marketers) engaged in various fraudulent
                and
                illegal activities including the transmittal of electronic wire
                communications to transmit false or misleading information to manipulate
                the California energy market. The claims include submitting false
                information such as energy schedules and bids to the California PX,
                CAISO,
                electronic trading platforms and publishers of energy indexes, alleges
                damages of not less than $30 million and seeks treble and punitive
                damages, attorneys’ fees and costs. The complaint is similar to the
                allegations made by the Port of Seattle currently on appeal in the
                Ninth
                Circuit. Both cases were dismissed on the grounds that FERC has the
                exclusive jurisdiction over plaintiff’s claims and the filed rate doctrine
                and Federal preemption barred the court from hearing the plaintiff’s
                claims. On March 10, 2005, Wah Chang filed a notice of appeal to
                the
                United States Court of Appeals for the Ninth Circuit. On May 17,
                2005, Wah
                Chang filed a motion to stay or, in the alternative, dismiss its
                appeal
                without prejudice to reinstatement. The defendants responded on May
                25,
                2005, opposing the motion and filed a cross-motion for summary affirmance
                of the judgment. The motions were denied on July 8, 2005 although
                defendants may renew the motion for summary affirmance after Wah
                Chang
                files its opening brief, which is due sometime in the third quarter
                2005.





**4.**
            **California
                Litigation.***California
                Class Actions.*In
                May 2002, PSE was served with two cross-complaints, by Reliant Energy
                Services and Duke Energy Trading & Marketing, respectively, in six
                consolidated class actions filed in Superior Court in San Diego,
                California. Plaintiffs in the lawsuits seek, among other things,
                restitution of all funds acquired by means that violate the law and
                payment of treble damages, interest and penalties. The cross-complaints
                asserted essentially that the cross-defendants, including PSE, were
                also
                participants in the California energy market at relevant times, and
                that
                any remedies ordered against some market participants should be ordered
                against all. Reliant and Duke also seek indemnification and conditional
                relief as buyers in transactions involving cross-defendants should
                the
                plaintiffs prevail. The case was removed to federal court and in
                December
                2002, the federal district court remanded the proceeding to state
                court,
                an action which Duke and Reliant later appealed to the Ninth Circuit.
                The
                Ninth Circuit remanded the case to state court. On June 3, 2005,
                the
                cross-defendants, including PSE, filed a demurrer seeking to dismiss
                the
                action. Further briefing and hearing on the demurrer is currently
                stayed
                pending the outcome of demurrers filed by Duke and Reliant on the
                main
                complaint, which currently is set to be heard on September 9, 2005.
                In
                addition, on July 22, 2005 the court considered a proposed settlement
                that
                would resolve all claims against the Duke parties and indicated
                “preliminary approval,” setting a hearing date for final approval of
                December 9, 2005.






Item
      3. **Quantitative
      and Qualitative Disclosure About Market Risk**





**Energy
      Portfolio Management**


The
      regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity
      price volatility on the Company. The PGA mechanism passes through increases
      and
      decreases in the cost of natural gas supply to customers. The PCA mechanism
      provides for a sharing of costs and benefits that are graduated over four levels
      of power cost variances with an overall cap of $40 million (+/-) plus 1% of
      the
      excess over the $40 million cap over the four-year period ending June 30, 2006.


The
      Company is focused on commodity price exposure and risks associated with
      volumetric variability in the gas portfolio and electric portfolio for its
      customers. Gas and electric portfolio exposure is managed in accordance with
      Company polices and procedures. The Risk Management Committee, which is composed
      of Company officers, provides policy-level and strategic direction for
      management of the energy portfolio. The Audit Committee of the Company’s Board
      of Directors periodically assesses risk management policies.


The
      nature of serving regulated electric customers with its wholesale portfolio
      of
      owned and contracted resources exposes the Company and its customers to some
      volumetric and commodity price risks within the sharing mechanism of the PCA.
      The Company’s energy risk management function monitors and manages these risks
      using analytical models and tools. The Company manages its energy supply
      portfolio to achieve three primary objectives:


·
            ensure
                that physical energy supplies are available to serve retail customer
                requirements;


·
            manage
                portfolio risks to limit undesired impacts on the Company’s costs;
                and


·
            maximize
                the value of the Company’s energy supply
                assets.


The
      Company is not engaged in the business of assuming risk for the purpose of
      speculative trading revenues. Therefore wholesale market transactions are
      focused on balancing the Company’s energy portfolio, reducing costs and risks
      where feasible, and reducing volatility in wholesale costs and margin in the
      portfolio. In order to manage risks effectively, the Company enters into
      physical and financial transactions, which are appropriate for the service
      territory of the Company and are relevant to its regulated electric and gas
      portfolios. The risk metrics the Company employs are aimed at assessing exposure
      in the regulated energy portfolios, and for purposes of developing strategies
      to
      reduce the potential exposure. Specifically, the amount of risk exposure is
      defined by time period and by portfolio. It is determined through statistical
      methods aimed at forecasting risk.


The
      energy risk management staff models forecasted load requirements and expected
      resource availability, and projects the net deficit or surplus position
      resulting from any imbalance between load requirements and existing resources.
      The portfolios are subject to major sources of variability (e.g., hydroelectric
      generation, outage risk, regional economic factors, temperature-sensitive retail
      sales and market prices for gas and power supplies). At certain times, these
      sources of variability can mitigate portfolio imbalances and at other times
      they
      can exacerbate portfolio imbalances. Because of the volumetric and cost
      variability within the electric and gas portfolios, the Company runs market
      simulations to model potential risk scenarios. In this way, strategies can
      be
      developed to address the expected case as well as other potential scenarios.
      Resources in the gas portfolio include gas supply arrangements, gas storage
      and
      gas transportation contracts. Resources in the electric portfolio include power
      purchase agreements, generating resources and transmission
      contracts.


The
      Company’s energy risk management staff develops hedging strategies to manage
      deficit or surplus positions in the portfolios. The Company’s energy risk policy
      states that hedging and optimization strategies will be consistent with the
      stated objectives. The Company relies on risk analysis, operational factors,
      professional judgment of its employees and fundamental analysis. The Company
      will engage in transactions that reduce risks in its electric and gas
      portfolios, and optimize unused capacity where possible. The Company’s hedging
      activities are aimed at removing risks from the Company’s electric and gas
      portfolios, giving important consideration to cost of hedges and lost
      opportunity in order to find a balance between price stability and least cost.
      The hedge strategies for the gas and electric portfolios incorporate risk
      analysis, operational factors and professional judgment of its employees as
      well
      as fundamental analysis. Hedging protocols are developed to ensure disciplined
      hedging, and discretion is used in hedging within specific guidelines of the
      programmatic hedge plans approved by the Risk Management Committee. Most hedges
      can be implemented in ways that retain the Company’s ability to use its energy
      supply optimization opportunities. Some hedges are structured similarly to
      insurance instruments, where the Company pays an insurance premium to protect
      against certain extreme conditions.


Without
      jeopardizing the security of supply within its portfolio, the Company also
      engages in optimizing the portfolio. Optimization may take the form of utilizing
      excess capacity, shaping flexible resources to capture their highest value
      and
      utilizing transmission capacity through third party transactions. As a result,
      portions of the Company’s energy portfolio are monetized through the use of
      forward price instruments which help reduce overall costs.


The
      Company has entered into master netting agreements with counterparties when
      available to mitigate credit exposure to those counterparties. The Company
      believes that entering into such agreements reduces risk of settlement default
      with the ability to make only one net payment. In addition, the Company believes
      risk is mitigated with an improved position in potential counterparty bankruptcy
      situations due to a consistent netting approach. At June 30, 2005, the Company
      is subject to a range of netting provisions, including both stand alone
      agreements and the provisions associated with the Western Systems Power Pool
      agreement of which many energy suppliers in the western United States are a
      part.


Transactions
      that qualify as hedge transactions under SFAS No. 133 are recorded on the
      balance sheet at fair value. Changes in fair value of the Company’s derivatives
      are recorded each period in current earnings or other comprehensive income.
      Short-term derivative contracts for the purchase and sale of electricity are
      valued based on daily quoted prices from an independent energy brokerage
      service. Valuations for short-term and medium-term natural gas financial
      derivatives are derived from a combination of quotes from several independent
      energy brokers and are updated daily. Long-term gas financial derivatives are
      valued based on published pricing from a combination of independent brokerage
      services and are updated monthly. Option contracts are valued using market
      quotes and a Monte Carlo simulation based model approach.


At
      June
      30, 2005, the Company had a net asset of approximately $49.2 million of energy
      contracts designated as qualifying cash flow hedges and a corresponding
      unrealized gain of $31.9 million after-tax recorded in other comprehensive
      income. Of the amount in other comprehensive income, 99% of the mark-to-market
      gain beginning September 1, 2005 though June 30, 2006 has been reclassified
      out
      of other comprehensive income to a deferred account in accordance with SFAS
      No.
      71 due to the Company reaching the $40 million cap under the PCA mechanism.
      Amounts settling after June 30, 2006 have not been deferred under the PCA
      mechanism as the $40 million cap expires at June 30, 2006, and the sharing
      band
      under the PCA mechanism reset. The Company also had energy contracts that were
      marked-to-market at a gain of $0.6 million through current earnings for the
      three months ended June 30, 2005 and at a gain of $0.1 million for the six
      months ended June 30, 2005. These mark-to-market adjustments were primarily
      the
      result of excluding certain contracts from the normal purchase normal sale
      exception under SFAS No. 133. A portion of the mark-to-market adjustments
      beginning September 1, 2005, has been reclassified to a deferred account in
      accordance with SFAS No. 71 due to the Company reaching the $40 million cap
      under the PCA mechanism. At June 30, 2005, the Company also has an asset of
      approximately $14.2 million related to the fair value of gas contracts to serve
      gas customers. All mark-to-market adjustments relating to the natural gas
      business have been reclassified to a deferred account in accordance with SFAS
      No. 71 due to the PGA mechanism. The PGA mechanism passes on to customers
      increases and decreases in the cost of natural gas supply. A hypothetical 10%
      increase in the market prices of natural gas and electricity would increase
      the
      fair value of qualifying cash flow hedges and comprehensive income by
      approximately $9.9 million after-tax and would increase current earnings for
      those contracts marked-to-market in earnings by $1.7 million pre-tax. All items
      affecting comprehensive income are presented after-tax as items recorded in
      comprehensive income are net of tax.





**Interest
      Rate Risk**


The
      Company believes its interest rate risk primarily relates to the use of
      short-term debt instruments, variable-rate notes and leases and long-term debt
      financing needed to fund capital requirements. The Company manages its interest
      rate risk through the issuance of mostly fixed-rate debt of various maturities.
      The Company utilizes bank borrowings, commercial paper, line of credit
      facilities and accounts receivable securitization to meet short-term cash
      requirements. These short-term obligations are commonly refinanced with
      fixed-rate bonds or notes when needed and when interest rates are considered
      favorable. The Company may at times enter into variable rate long-term bonds
      to
      take advantage of lower interest rates. The Company may enter into swap
      instruments or other financial hedge instruments to manage the interest rate
      risk associated with these debts.


In
      the
      second quarter 2005, the Company entered into two forward starting swap
      contracts to hedge against interest rate volatility for a debt offering
      anticipated to be performed in the second half of 2006. A forward starting
      swap
      is a financial arrangement between the Company and a counterparty whereby one
      of
      the parties will be required to make a payment to the other party on a specific
      valuation date based upon the change in value of a designated treasury bond.
      If
      interest rates rise related to the hedged debt from the date of issuance of
      the
      swap instruments, the Company would receive a payment from the counterparty
      for
      the change in the bond value. Alternatively, if interest rates decreased related
      to the hedged debt from the date of issuance of the swap instruments, the
      Company would pay the counterparty for the change in bond value. These swap
      contracts were designated under SFAS No. 133 criteria as cash flow hedges,
      with
      all changes in market value for each reporting period being presented net of
      tax
      in other comprehensive income. All financial hedge contracts of this type are
      reviewed by senior management and presented to the Securities Pricing
      Committee of the Board of Directors, and are approved prior to execution.
      At June 30, 2005, the unrealized loss associated with the two swap contracts
      was
      $7.6 million after-tax and is included in other comprehensive income. A
      hypothetical 10% decrease in the interest rate of a 30-year treasury note would
      result in an additional loss of $9.4 million after-tax in other comprehensive
      income. The swap contracts will settle completely in 2006.








Item
      4.**** **Controls
      and Procedures**





**Puget**  **Energy**


**Evaluation
      of Disclosure Controls and Procedures**


Under
      the
      supervision and with the participation of Puget Energy’s management, including
      the President and Chief Executive Officer and Senior Vice President Finance
      and
      Chief Financial Officer, Puget Energy has evaluated the effectiveness of its
      disclosure controls and procedures (as defined in Rule 13a-15(e) under the
      Securities Exchange Act of 1934) as of June 30, 2005, the end of the period
      covered by this report. Based upon that evaluation, the President and Chief
      Executive Officer and Senior Vice President Finance and Chief Financial Officer
      of Puget Energy concluded that these disclosure controls and procedures are
      effective.





**Changes
      in Internal Control Over Financial Reporting**


There
      have been no changes in Puget Energy’s internal control over financial reporting
      during the quarter ended June 30, 2005 that have materially affected, or are
      reasonably likely to materially affect, Puget Energy’s internal control over
      financial reporting.




**Puget
      Sound Energy**


**Evaluation
      of Disclosure Controls and Procedures**


Under
      the
      supervision and with the participation of PSE’s management, including the
      President and Chief Executive Officer and Senior Vice President Finance and
      Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure
      controls and procedures (as defined in Rule 13a-15(e) under the Securities
      Exchange Act of 1934) as of June 30, 2005, the end of the period covered by
      this
      report. Based upon that evaluation, the President and Chief Executive Officer
      and Senior Vice President Finance and Chief Financial Officer of PSE concluded
      that these disclosure controls and procedures are effective.





**Changes
      in Internal Control Over Financial Reporting**


There
      have been no changes in PSE’s internal control over financial reporting during
      the quarter ended June 30, 2005, that have materially affected, or are
      reasonably likely to materially affect, PSE’s internal control over financial
      reporting.








**PART
      II****OTHER
      INFORMATION**








Item
      1. **Legal
      Proceedings**





See
      the
      section titled “Proceedings Relating to the Western Power Market” under Item 2
“Management’s Discussion and Analysis of Financial Conditions and Results of
      Operations” of this Quarterly Report on Form 10-Q.


Contingencies
      arising out of the normal course of the Company’s business exist at June 30,
      2005. The ultimate resolution of these issues in part or in the aggregate is
      not
      expected to have a material adverse impact on the financial condition, results
      of operations or liquidity of the Company.








Item
      4. **Submission
      of Matters to a Vote of Security Holders**





Puget
      Energy’s annual meeting of shareholders was held on May 10, 2005. At the annual
      meeting, the shareholders elected three directors to hold office until the
      annual meeting of shareholders in 2008 or until their successors are elected
      and
      qualified. In addition, the shareholders elected one director to hold office
      until 2006. The vote was as follows:




Number
                of SharesFor
            WithheldTERMEXPIRING2008William
                S. Ayer
            83,172,755
            1,669,494Robert
                L. Dryden
            78,082,461
            1,917,850Sally
                G. Narodick
            82,731,077
            2,111,172TERMEXPIRING2006Charles
                W. Bingham
            82,924,399
            1,917,850




There
      were no abstentions and no broker non-votes.




The
      terms
      of the following directors continued after the annual meeting:





Craig
      W.
      Cole


Tomio
      Moriguchi


Phyllis
      J. Campbell


Stephen
      E. Frank


Dr.
      Kenneth P. Mortimer


Stephen
      P. Reynolds





Douglas
      P. Beighle, Chairman of the Boards of Directors of Puget Energy and Puget Sound
      Energy since March 2002, retired from the Board on May 10, 2005 after the Annual
      Meeting of Shareholders. On May 10, 2005, the Board appointed Stephen P.
      Reynolds to serve as Chair of the Boards of Puget Energy and Puget Sound Energy,
      and appointed Phyllis J. Campbell to serve as Lead Director.


In
      addition to the election of the Directors at the Annual Meeting of Shareholders,
      the shareholders of Puget Energy approved the Puget Energy, Inc. Amended and
      Restated Nonemployee Director Plan (NED Plan) and the Puget Energy, Inc. 2005
      Long-Term Incentive Plan (2005 LTIP), which amended in its entirety and restated
      the Puget Energy, Inc. 1995 Long-Term Incentive Compensation Plan as previously
      approved by shareholders (1995 LTIP). Shareholders also ratified
      PricewaterhouseCoopers LLP as the Company's independent registered accounting
      firm.


The
      Board
      of Directors originally adopted the NED Plan on October 7, 1997, at
      a time
      when shareholder approval of the plan was not required. As amended and restated,
      the NED Plan includes the following material revisions from the plan as
      originally adopted by the Board:







·
            an
                increase of 250,000 shares in the number of shares authorized for
                issuance,
                from 100,000 to 350,000; and


·
            an
                extension of the term of the plan from December 31, 2007 to December
                31,
                2015.




The
      2005
      LTIP includes the following material revisions from the 1995 LTIP:





·
            an
                increase of 3,000,000 shares in the number of shares authorized for
                issuance, from 1,200,000 to
                4,200,000;


·
            the
                addition of share replenishment
                features;


·
            the
                expansion of the persons eligible to participate in the plan to include
                all employees, other service providers and nonemployee
                directors;


·
            the
                expansion of the types of awards available for grant to also include
                cash-based awards that can qualify as performance-based for purposes
                of
                Section 162(m) of the Internal Revenue Code of 1986 (Section
                162(m));


·
            the
                expansion of the list of performance criteria for purposes of
                performance-based awards under Section
                162(m);


·
            an
                increase in the number of shares subject to awards intended to qualify
                as
                performance-based under Section 162(m) that may be granted to any
                individual during any calendar year, from 40,000 shares to (a) 600,000
                shares, with respect to stock options and stock appreciation rights
                and
                (b) 400,000 shares, with respect to awards other than stock options,
                stock
                appreciation rights or performance
                units;


·
            an
                increase in the maximum dollar value payable with respect to performance
                units intended to qualify as performance-based under Section 162(m)
                to any
                individual during any calendar year, from $400,000 to $3,000,000;
                and


·
            the
                addition of a ten-year term to the plan, which previously had no
                expiration date.




The
      vote
      for these matters was as follows:





Number
                of SharesFor
            Against
            AbstainLong-term
                Incentive Plan
            56,425,063
            8,355,168
            1,454,614Nonemployee
                Director Stock Plan
            57,139,518
            7,516,861
            1,578,466Ratify
                PricewaterhouseCoopers LLP
            82,678,961
            1,414,353
            748,935





The
      Long-term Incentive Plan and Nonemployee Director Stock Plan both received
      18,607,404 broker non-votes.






Item
      6.  **Exhibits**




See
      Exhibit Index for list of exhibits.











**SIGNATURES**





Pursuant
      to the requirements of the Securities Exchange Act of 1934, each registrant
      has
      duly caused this report to be signed on their behalf by the undersigned
      thereunto duly authorized.





**PUGET
                ENERGY, INC.****PUGET
                SOUND ENERGY, INC.**/s/
                James W. Eldredge**James
                W. Eldredge**Vice
                President, Corporate Secretary and Chief Accounting
                OfficerDate:
                August 2, 2005Chief
                accounting officer and officer duly authorized to sign this report
                on
                behalf of each registrant








**EXHIBIT
      INDEX**





The
      following exhibits are filed herewith:








12.1
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2000
                through 2004 and 12 months ended June 30, 2005) for Puget Energy.





12.2
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2000
                through 2004 and 12 months ended June 30, 2005) for
                PSE.





31.1
            Chief
                Executive Officer certification of Puget Energy pursuant to 18 U.S.C.
                Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley
                Act
                of 2002.





31.2
            Chief
                Financial Officer certification of Puget Energy pursuant to 18 U.S.C.
                Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley
                Act
                of 2002.





31.3
            Chief
                Executive Officer certification of Puget Sound Energy pursuant to
                18
                U.S.C. Section 1350, as adopted pursuant to Section 302 of the
                Sarbanes-Oxley Act of 2002.





31.4
            Chief
                Financial Officer certification of Puget Sound Energy pursuant to
                18
                U.S.C. Section 1350, as adopted pursuant to Section 302 of the
                Sarbanes-Oxley Act of 2002.





32.1
            Chief
                Executive Officer certification pursuant to 18 U.S.C. Section 1350,
                as
                adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
                2002.





32.2
            Chief
                Financial Officer certification pursuant to 18 U.S.C. Section 1350,
                as
                adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
                2002.