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****September
                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
      October 21, 2005, (i) the number of shares of Puget Energy, Inc. common stock
      outstanding was 100,467,398 ($.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 Nine Months
                Ended
              September
                30, 2005 and 2004Consolidated
                Statements of Comprehensive Income - Three and
                Nine Months Ended
              September
                30, 2005 and 2004Consolidated
                Balance Sheets - September 30, 2005
                and December 31, 2004Consolidated
                Statements of Cash Flows - Nine Months
                Ended
              September
                30, 2005 and 2004**Puget
                Sound Energy, Inc.**Consolidated
                Statements of Income - Three and Nine Months
                Ended
              September
                30, 2005 and 2004Consolidated
                Statements of Comprehensive Income - Three
                and Nine Months Ended
              September
                30, 2005 and 2004Consolidated
                Balance Sheets - September 30,
                2005 and December 31, 2004Consolidated
                Statements of Cash Flows - Nine Months
                Ended
              September
                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
                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;


·
            air
                quality regulatory requirements at the federal, state and local government
                levels may impact PSE’s generation and costs as climate change has made
                emissions management complex due to efforts being made to further
                reduce
                emissions from all utilities. Proposed legislation and new regulation
                remain unsettled or unresolved, including climate change legislation,
                the
                Clear Skies Initiative and the recently promulgated Clean Air Mercury
                and
                Interstate Rules. As a result, uncertainty with respect to renewable
                energy mandates, potential Green House Gas regulation and new limits
                on
                emissions could impact PSE and
                others;


·
            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 impede PSE’s ability to manage its
                energy portfolio risks and procure energy supply, affect the availability
                and access to capital and credit markets and/or impact delivery of
                energy
                to PSE from its suppliers and;


·
            the
                effect of wholesale market structures (including, but not limited
                to,
                regional market designs or transmission organizations such as Grid
                West or
                the Transmission Improvement Group, 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;


·
            natural
                disasters, such as hurricanes, which can cause temporary supply
                disruptions, and/or price spikes in the cost of fuel and raw
                materials;


·
            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 maintain current
                key customer relationships, 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
              September
                30,
            
            Nine
                Months Ended
              September
                30,2005
            
            2004
            
            2005
            
            2004Operating
                revenues:Electric
            
            $
            375,035
            
            $
            322,669
            
            $
            1,140,545
            
            $
            1,018,256Gas
            
            
            111,042
            
            
            89,433
            
            
            594,737
            
            
            484,603Other
            
            
            4,306
            
            
            2,925
            
            
            6,866
            
            
            4,005Total
                operating revenues
            
            
            490,383
            
            
            415,027
            
            
            1,742,148
            
            
            1,506,864Operating
                expenses:Energy
                costs:Purchased
                electricity
            
            
            200,861
            
            
            147,589
            
            
            587,983
            
            
            517,803Electric
                generation fuel
            
            
            21,058
            
            
            25,130
            
            
            54,400
            
            
            60,132Residential
                exchange
            
            
            (34,525
            )
            
            (34,014
            )
            
            (126,676
            )
            
            (123,799
            )Purchased
                gas
            
            
            59,151
            
            
            44,574
            
            
            359,037
            
            
            270,683Unrealized
                net (gain) loss on derivative instruments
            
            
            477
            
            
            1,894
            
            
            395
            
            
            (1,042
            )Utility
                operations and maintenance
            
            
            81,645
            
            
            67,093
            
            
            240,299
            
            
            214,149Other
                operations and maintenance
            
            
            745
            
            
            529
            
            
            2,045
            
            
            1,513Depreciation
                and amortization
            
            
            60,550
            
            
            57,598
            
            
            178,284
            
            
            170,036Conservation
                amortization
            
            
            5,633
            
            
            4,747
            
            
            16,746
            
            
            17,746Taxes
                other than income taxes
            
            
            44,784
            
            
            42,711
            
            
            165,005
            
            
            149,486Income
                taxes
            
            
            2,476
            
            
            6,958
            
            
            54,649
            
            
            40,621Total
                operating expenses
            
            
            442,855
            
            
            364,809
            
            
            1,532,167
            
            
            1,317,328Operating
                income
            
            
            47,528
            
            
            50,218
            
            
            209,981
            
            
            189,536Other
                income (deductions):Other
                income
            
            
            1,422
            
            
            356
            
            
            4,184
            
            
            1,994Interest
                charges:AFUDC
            
            
            2,680
            
            
            1,650
            
            
            6,183
            
            
            3,807Interest
                expense
            
            
            (45,695
            )
            
            (42,754
            )
            
            (130,307
            )
            
            (128,796
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )
            
            (68
            )
            
            (68
            )Income
                from continuing operations
            
            
            5,912
            
            
            9,447
            
            
            89,973
            
            
            66,473Income
                (loss) from discontinued operations, net of tax
            
            
            (1
            )
            
            1,677
            
            
            908
            
            
            4,237Net
                income
            
            $
            5,911
            
            $
            11,124
            
            $
            90,881
            
            $
            70,710Common
                shares outstanding weighted average (in thousands)
            
            
            100,371
            
            
            99,580
            
            
            100,160
            
            
            99,373Diluted
                common shares outstanding weighted average (in thousands)
            
            
            100,964
            
            
            100,043
            
            
            100,754
            
            
            99,836Basic
                earnings per common share from continuing operations
            
            $
            .06
            
            $
            .09
            
            $
            .90
            
            $
            .67Basic
                earnings per common share from discontinued operations
            
            
            --
            
            
            .02
            
            
            .01
            
            
            .04Basic
                earnings per common share
            
            $
            .06
            
            $
            .11
            
            $
            .91
            
            $
            .71Diluted
                earnings per common share from continuing operations
            
            $
            .06
            
            $
            .09
            
            $
            .89
            
            $
            .67Diluted
                earnings per common share from discontinued operations
            
            
            --
            
            
            .02
            
            
            .01
            
            
            .04Diluted
                earnings per common share
            
            $
            .06
            
            $
            .11
            
            $
            .90
            
            $
            .71





*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
              September
                30,
            
            Nine
                Months Ended
              September
                30,2005
            
            2004
            
            2005
            
            2004Net
                income
            
            $
            5,911
            
            $
            11,124
            
            $
            90,881
            
            $
            70,710Other
                comprehensive income, net of tax at 35%:Foreign
                currency translation adjustment
            
            
            2
            
            
            (5
            )
            
            (10
            )
            
            235Unrealized
                gains on derivative instruments during the period
            
            
            37,896
            
            
            17
            
            
            48,484
            
            
            11,577Reversal
                of unrealized gains on derivative instruments settled during
              the
                period
            
            
            (4,353
            )
            
            (2,829
            )
            
            (3,243
            )
            
            (6,910
            )Loss
                from settlement of cash flow hedge contracts
            
            
            --
            
            
            --
            
            
            (22,960
            )
            
            --Amortization
                of cash flow hedge contracts to earnings
            
            
            191
            
            
            --
            
            
            264
            
            
            --Deferral
                of cash flow hedges related to the power cost adjustment
              mechanism
            
            
            (12,914
            )
            
            (5,501
            )
            
            (4,937
            )
            
            (8,187
            )Other
                comprehensive income (loss)
            
            
            20,822
            
            
            (8,318
            )
            
            17,598
            
            
            (3,285
            )Comprehensive
                income
            
            $
            26,733
            
            $
            2,806
            
            $
            108,479
            
            $
            67,425





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





**PUGET
      ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





September
                30,
              2005
            
            December
                31,
              2004Utility
                plant: (at original cost, including construction work in progress
                of
              $311,783
                and $129,966, respectively)Electric
            
            $
            4,645,289
            
            $
            4,389,882Gas
            
            
            1,966,806
            
            
            1,881,768Common
            
            
            436,822
            
            
            409,677Less:
                Accumulated depreciation and amortization
            
            
            (2,566,492
            )
            
            (2,452,969
            )Net
                utility plant
            
            
            4,482,425
            
            
            4,228,358Other
                property and investments
            
            
            157,249
            
            
            157,670Current
                assets:Cash
            
            
            9,817
            
            
            12,955Restricted
                cash
            
            
            1,045
            
            
            1,633Accounts
                receivable, net of allowance for doubtful accounts
            
            
            112,283
            
            
            137,659Unbilled
                revenue
            
            
            81,265
            
            
            140,391Purchased
                gas adjustment receivable
            
            
            37,508
            
            
            19,088Materials
                and supplies, at average cost
            
            
            33,931
            
            
            31,683Fuel
                and gas inventory, at average cost
            
            
            95,096
            
            
            65,895Unrealized
                gain on derivative instruments
            
            
            203,419
            
            
            14,791Prepayments
                and other
            
            
            34,485
            
            
            6,858Deferred
                income taxes
            
            
            --
            
            
            1,415Current
                assets of discontinued operations
            
            
            122,664
            
            
            110,922Total
                current assets
            
            
            731,513
            
            
            543,290Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            135,194
            
            
            127,252Regulatory
                asset for PURPA contract buyout costs
            
            
            196,188
            
            
            211,241Unrealized
                gain on derivative instruments
            
            
            38,956
            
            
            21,315Power
                cost adjustment mechanism
            
            
            5,583
            
            
            --Other
            
            
            383,662
            
            
            401,795Long-term
                assets of discontinued operations
            
            
            161,753
            
            
            160,298Total
                other long-term assets
            
            
            921,336
            
            
            921,901Total
                assets
            
            $
            6,292,523
            
            $
            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**








September
                30,
              2005
            
            December
                31,
              2004Capitalization:Common
                shareholders’ investment:Common
                stock $0.01 par value, 250,000,000 shares authorized, 100,459,935
                and
              99,868,368
                shares outstanding, respectively
            
            $
            1,005
            
            $
            999Additional
                paid-in capital
            
            
            1,634,600
            
            
            1,621,756Earnings
                reinvested in the business
            
            
            29,679
            
            
            13,853Accumulated
                other comprehensive income (loss), net of tax at 35%
            
            
            3,266
            
            
            (14,332
            )Total
                shareholders’ equity
            
            
            1,668,550
            
            
            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
            
            
            2,068,360
            
            
            2,069,360Total
                redeemable securities and long-term debt
            
            
            2,307,999
            
            
            2,351,499Total
                capitalization
            
            
            3,976,549
            
            
            3,973,775Minority
                interest in discontinued operations
            
            
            6,151
            
            
            4,648Current
                liabilities:Accounts
                payable
            
            
            216,668
            
            
            226,478Short-term
                debt
            
            
            223,871
            
            
            --Current
                maturities of long-term debt
            
            
            46,000
            
            
            31,000Accrued
                expenses:Taxes
            
            
            77,297
            
            
            81,315Salaries
                and wages
            
            
            12,125
            
            
            13,829Interest
            
            
            42,901
            
            
            29,005Unrealized
                loss on derivative instruments
            
            
            14,643
            
            
            26,581Deferred
                income taxes
            
            
            19,593
            
            
            --Tenaska
                disallowance reserve
            
            
            --
            
            
            3,156Other
            
            
            28,994
            
            
            34,918Current
                liabilities of discontinued operations
            
            
            73,783
            
            
            51,892Total
                current liabilities
            
            
            755,875
            
            
            498,174Long-term
                liabilities:Deferred
                income taxes
            
            
            760,382
            
            
            795,291Unrealized
                loss on derivative instruments
            
            
            --
            
            
            385Other
                deferred credits
            
            
            620,525
            
            
            395,236Long-term
                liabilities of discontinued operations
            
            
            173,041
            
            
            183,710Total
                long-term liabilities
            
            
            1,553,948
            
            
            1,374,622Total
                capitalization and liabilities
            
            $
            6,292,523
            
            $
            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)


Nine
                Months Ended
              September
                30,2005
            
            2004Operating
                activities:Net
                income
            
            $
            90,881
            
            $
            70,710Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation
                and amortization
            
            
            178,284
            
            
            183,614Deferred
                income taxes and tax credits, net
            
            
            (32,329
            )
            
            65,294Net
                unrealized (gain) loss on derivative instruments
            
            
            395
            
            
            (1,042
            )Cash
                collateral received from energy suppliers
            
            
            31,050
            
            
            8,520Increase
                in residential exchange program
            
            
            4,984
            
            
            8,452Impairment
                on InfrastruX investment
            
            
            13,204
            
            
            --Other
            
            
            18,733
            
            
            20,588Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            70,084
            
            
            80,563Materials
                and supplies
            
            
            (2,781
            )
            
            (5,281
            )Fuel
                and gas inventory
            
            
            (29,201
            )
            
            (26,671
            )Prepayments
                and other
            
            
            (28,301
            )
            
            (11,159
            )Purchased
                gas adjustment receivable
            
            
            (18,419
            )
            
            (30,157
            )Accounts
                payable
            
            
            (9,269
            )
            
            (49,305
            )Taxes
                payable
            
            
            7,339
            
            
            (50,884
            )Tenaska
                disallowance reserve
            
            
            (3,156
            )
            
            11,212Accrued
                expenses and other
            
            
            9,503
            
            
            7,619Net
                cash provided by operating activities
            
            
            301,001
            
            
            282,073Investing
                activities:Construction
                and capital expenditures - excluding equity AFUDC
            
            
            (406,346
            )
            
            (324,292
            )Energy
                efficiency expenditures
            
            
            (10,763
            )
            
            (13,301
            )Cash
                proceeds from property sales
            
            
            15,830
            
            
            672Refundable
                cash received for customer construction projects
            
            
            10,221
            
            
            9,497Restricted
                cash
            
            
            587
            
            
            (1,240
            )Other
            
            
            2,348
            
            
            521Net
                cash used by investing activities
            
            
            (388,123
            )
            
            (328,143
            )Financing
                activities:Change
                in short-term debt, net
            
            
            230,855
            
            
            10,618Dividends
                paid
            
            
            (65,956
            )
            
            (65,050
            )Issuance
                of common stock
            
            
            3,769
            
            
            3,914Issuance
                of bonds
            
            
            250,000
            
            
            336,000Redemption
                of bonds and notes
            
            
            (250,753
            )
            
            (243,982
            )Redemption
                of trust preferred stock
            
            
            (42,500
            )
            
            --Settlement
                of cash flow hedge derivative on treasury rate lock
            
            
            (34,776
            )
            
            --Issuance
                and redemption costs of bonds and other
            
            
            (8,356
            )
            
            (1,700
            )Net
                cash provided by financing activities
            
            
            82,283
            
            
            39,800Net
                decrease in cash
            
            
            (3,137
            )
            
            (79
            )Change
                in cash from discontinued operations
            
            
            (1,702
            )
            
            (6,191
            )Cash
                at beginning of year
            
            
            19,771
            
            
            27,481Cash
                at end of period
            
            $
            14,932
            
            $
            21,211Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            123,499
            
            $
            125,262Income
                taxes
            
            
            72,940
            
            
            1,294





*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
              September
                30,
            
            Nine
                Months Ended
              September
                30,2005
            
            2004
            
            2005
            
            2004Operating
                revenues:Electric
            
            $
            375,035
            
            $
            322,669
            
            $
            1,140,545
            
            $
            1,018,256Gas
            
            
            111,042
            
            
            89,432
            
            
            594,737
            
            
            484,603Other
            
            
            4,306
            
            
            2,925
            
            
            6,866
            
            
            4,005Total
                operating revenues
            
            
            490,383
            
            
            415,026
            
            
            1,742,148
            
            
            1,506,864Operating
                expenses:Energy
                costs:Purchased
                electricity
            
            
            200,861
            
            
            147,589
            
            
            587,983
            
            
            517,803Electric
                generation fuel
            
            
            21,058
            
            
            25,130
            
            
            54,400
            
            
            60,132Residential
                exchange
            
            
            (34,525
            )
            
            (34,014
            )
            
            (126,676
            )
            
            (123,799
            )Purchased
                gas
            
            
            59,151
            
            
            44,574
            
            
            359,037
            
            
            270,683Unrealized
                net (gain) loss on derivative instruments
            
            
            477
            
            
            1,894
            
            
            395
            
            
            (1,042
            )Utility
                operations and maintenance
            
            
            81,645
            
            
            67,093
            
            
            240,299
            
            
            214,149Other
                operations and maintenance
            
            
            425
            
            
            277
            
            
            925
            
            
            850Depreciation
                and amortization
            
            
            60,550
            
            
            57,598
            
            
            178,284
            
            
            170,036Conservation
                amortization
            
            
            5,633
            
            
            4,747
            
            
            16,746
            
            
            17,746Taxes
                other than income taxes
            
            
            44,784
            
            
            42,711
            
            
            165,005
            
            
            149,486Income
                taxes
            
            
            2,619
            
            
            7,064
            
            
            55,449
            
            
            40,908Total
                operating expenses
            
            
            442,678
            
            
            364,663
            
            
            1,531,847
            
            
            1,316,952Operating
                income
            
            
            47,705
            
            
            50,363
            
            
            210,301
            
            
            189,912Other
                income (deductions):Other
                income, net of tax
            
            
            1,422
            
            
            356
            
            
            4,184
            
            
            1,994Interest
                charges:AFUDC
            
            
            2,680
            
            
            1,650
            
            
            6,183
            
            
            3,807Interest
                expense
            
            
            (45,614
            )
            
            (42,699
            )
            
            (130,083
            )
            
            (128,639
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )
            
            (68
            )
            
            (68
            )Net
                income
            
            $
            6,170
            
            $
            9,647
            
            $
            90,517
            
            $
            67,006





*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
              September
                30,
            
            Nine
                Months Ended
              September
                30,2005
            
            2004
            
            2005
            
            2004Net
                income
            
            $
            6,170
            
            $
            9,647
            
            $
            90,517
            
            $
            67,006Other
                comprehensive income, net of tax at 35%:Unrealized
                gains on derivative instruments during the period
            
            
            37,896
            
            
            17
            
            
            48,484
            
            
            11,577Reversal
                of unrealized gains on derivative instruments settled during
              the
                period
            
            
            (4,353
            )
            
            (2,829
            )
            
            (3,243
            )
            
            (6,910
            )Loss
                from settlement of cash flow hedge contracts
            
            
            --
            
            
            --
            
            
            (22,960
            )
            
            --Amortization
                of cash flow hedge contracts to earnings
            
            
            191
            
            
            --
            
            
            264
            
            
            --Deferral
                of cash flow hedges related to the power cost adjustment
              mechanism
            
            
            (12,914
            )
            
            (5,501
            )
            
            (4,937
            )
            
            (8,187
            )Other
                comprehensive income (loss)
            
            
            20,820
            
            
            (8,313
            )
            
            17,608
            
            
            (3,520
            )Comprehensive
                income
            
            $
            26,990
            
            $
            1,334
            
            $
            108,125
            
            $
            63,486





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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





September
                30,
              2005
            
            December
                31,
              2004Utility
                plant: (at original cost, including construction work in progress
                of
              $311,783
                and $129,966, respectively)Electric
            
            $
            4,645,289
            
            $
            4,389,882Gas
            
            
            1,966,806
            
            
            1,881,768Common
            
            
            436,822
            
            
            409,677Less:
                Accumulated depreciation and amortization
            
            
            (2,566,492
            )
            
            (2,452,969
            )Net
                utility plant
            
            
            4,482,425
            
            
            4,228,358Other
                property and investments
            
            
            157,249
            
            
            157,670Current
                assets:Cash
            
            
            9,816
            
            
            12,955Restricted
                cash
            
            
            1,045
            
            
            1,633Accounts
                receivable, net of allowance for doubtful accounts
            
            
            112,333
            
            
            138,792Unbilled
                revenue
            
            
            81,265
            
            
            140,391Purchased
                gas adjustment receivable
            
            
            37,508
            
            
            19,088Materials
                and supplies, at average cost
            
            
            33,931
            
            
            31,683Fuel
                and gas inventory, at average cost
            
            
            95,096
            
            
            65,895Unrealized
                gain on derivative instruments
            
            
            203,419
            
            
            14,791Prepayments
                and other
            
            
            33,875
            
            
            6,247Deferred
                income taxes
            
            
            --
            
            
            1,415Total
                current assets
            
            
            608,288
            
            
            432,890Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            135,194
            
            
            127,252Regulatory
                asset for PURPA contract buyout costs
            
            
            196,188
            
            
            211,241Unrealized
                gain on derivative instruments
            
            
            38,956
            
            
            21,315Power
                cost adjustment mechanism
            
            
            5,583
            
            
            --Other
            
            
            383,141
            
            
            401,030Total
                other long-term assets
            
            
            759,062
            
            
            760,838Total
                assets
            
            $
            6,007,024
            
            $
            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**





September
                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
            
            
            612,769
            
            
            609,467Earnings
                reinvested in the business
            
            
            162,110
            
            
            138,678Accumulated
                other comprehensive income (loss), net of tax at 35%
            
            
            2,858
            
            
            (14,750
            )Total
                shareholder’s equity
            
            
            1,636,775
            
            
            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
            
            
            3,944,774
            
            
            3,938,932Current
                liabilities:Accounts
                payable
            
            
            216,668
            
            
            229,747Short-term
                debt
            
            
            223,871
            
            
            --Current
                maturities of long-term debt
            
            
            46,000
            
            
            31,000Accrued
                expenses:Taxes
            
            
            77,709
            
            
            81,634Salaries
                and wages
            
            
            12,125
            
            
            13,829Interest
            
            
            42,901
            
            
            29,005Unrealized
                loss on derivative instruments
            
            
            14,643
            
            
            26,581Deferred
                income taxes
            
            
            19,593
            
            
            --Tenaska
                disallowance reserve
            
            
            --
            
            
            3,156Other
            
            
            27,653
            
            
            34,918Total
                current liabilities
            
            
            681,163
            
            
            449,870Long-term
                liabilities:Deferred
                income taxes
            
            
            760,669
            
            
            795,392Unrealized
                loss on derivative instruments
            
            
            --
            
            
            385Other
                deferred credits
            
            
            620,418
            
            
            395,177Total
                long-term liabilities
            
            
            1,381,087
            
            
            1,190,954Total
                capitalization and liabilities
            
            $
            6,007,024
            
            $
            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)


Nine
                Months Ended
              September
                30,2005
            
            2004Operating
                activities:Net
                income
            
            $
            90,517
            
            $
            67,006Adjustments
                to reconcile net income to net cash
              provided by operating activities:Depreciation
                and amortization
            
            
            178,284
            
            
            170,036Deferred
                income taxes and tax credits, net
            
            
            (31,137
            )
            
            65,498Net
                unrealized (gain) loss on derivative instruments
            
            
            395
            
            
            (1,042
            )Cash
                collateral received from energy suppliers
            
            
            31,050
            
            
            8,520Increase
                in residential exchange program
            
            
            4,984
            
            
            8,452Other
            
            
            12,968
            
            
            21,827Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            85,585
            
            
            105,883Materials
                and supplies
            
            
            (2,249
            )
            
            (3,499
            )Fuel
                and gas inventory
            
            
            (29,201
            )
            
            (26.671
            )Prepayments
                and other
            
            
            (27,628
            )
            
            (7,272
            )Purchased
                gas adjustment receivable
            
            
            (18,419
            )
            
            (30,157
            )Accounts
                payable
            
            
            (13,080
            )
            
            (52,514
            )Taxes
                payable
            
            
            (3,926
            )
            
            (56,123
            )Tenaska
                disallowance reserve
            
            
            (3,156
            )
            
            11,212Accrued
                expenses and other
            
            
            3,786
            
            
            4,491Net
                cash provided by operating activities
            
            
            278,773
            
            
            285,647Investing
                activities:Construction
                expenditures - excluding equity AFUDC
            
            
            (393,619
            )
            
            (311,408
            )Energy
                efficiency expenditures
            
            
            (10,763
            )
            
            (13,301
            )Cash
                proceeds from property sales
            
            
            15,830
            
            
            672Restricted
                cash
            
            
            587
            
            
            (1,240
            )Refundable
                cash received for customer construction projects
            
            
            10,221
            
            
            9,497Other
            
            
            2,359
            
            
            426Net
                cash used by investing activities
            
            
            (375,385
            )
            
            (315,354
            )Financing
                activities:Change
                in short-term debt, net
            
            
            223,871
            
            
            --Dividends
                paid
            
            
            (67,085
            )
            
            (65,876
            )Issuance
                of bonds
            
            
            250,000
            
            
            200,000Settlement
                of cash flow hedge derivative on treasury rate lock
            
            
            (34,776
            )
            
            --Redemption
                of trust preferred stock
            
            
            (42,500
            )
            
            --Redemption
                of bonds and notes
            
            
            (231,000
            )
            
            (106,447
            )Issuance
                and redemption cost of bonds and other
            
            
            (5,037
            )
            
            1,950Net
                cash provided by financing activities
            
            
            93,473
            
            
            29,627Net
                decrease in cash
            
            
            (3,139
            )
            
            (80
            )Cash
                at beginning of year
            
            
            12,955
            
            
            14,778Cash
                at end of period
            
            $
            9,816
            
            $
            14,698Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            116,857
            
            $
            120,615Income
                taxes
            
            
            75,482
            
            
            1,294





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











**COMBINED
      NOTESTO 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 (PUHCA) of 1935. The Energy Policy Act of 2005 repealed
      the
      PUHCA of 1935 effective February 8, 2006. 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 into its regulated utility
      subsidiary, PSE. Management believes the 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 in
      2005. Puget Energy is actively marketing InfrastruX and has held discussions
      with interested financial and strategic parties in 2005. Puget Energy has
      recently retained an investment banker to assist in the disposal of InfrastruX.
      To date, Puget Energy has not entered into a definitive agreement that would
      result in the sale of its investment in InfrastruX.


For
      the
      three and nine months ended September 30, 2005, Puget Energy reported InfrastruX
      related income from discontinued operations (net of taxes and minority interest)
      of $0.0 million and $0.9 million, respectively, compared to income of $1.7
      million and $4.2 million (net of taxes and minority interest) for the three
      and
      nine months ended September 30, 2004, respectively. Included in the income
      for
      discontinued operations is a charge of $8.1 million after-tax for the three
      months ended September 30, 2005 and $14.3 million after-tax for the nine months
      ended September 30, 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. The following chart summarizes Puget
      Energy’s income from discontinued operations for the three and nine months ended
      September 30, 2005:





(Dollars
                in millions)
            
            Three
                Months
              Ended
              September
                30,
              2005
            
            Nine
                Months
              Ended
              September
                30,
              2005Net
                income reported by InfrastruX
            
            $
            5.3
            
            $
            7.8InfrastruX
                depreciation and amortization not recorded
              by
                Puget Energy, net of tax
            
            
            2.9
            
            
            7.3Puget
                Energy tax benefit from goodwill deduction
            
            
            0.7
            
            
            1.4Puget
                Energy carrying value adjustment of InfrastruX,
              including
                cost of sale, net of tax
            
            
            (8.1
            )
            
            (14.3
            )Minority
                interest in income from discontinued operations and other
            
            
            (0.8
            )
            
            (1.3
            )Income
                from discontinued operations
            
            $
            --
            
            $
            0.9





InfrastruX’s
      bank and vendor debt under its credit agreements totaled $151.6 million at
      September 30, 2005 compared to $159.4 million at December 31, 2004 and $181.3
      million at September 30, 2004. In May 2004, InfrastruX signed a three-year
      agreement with a group of banks to provide up to $150 million in financing,
      with
      Puget Energy as guarantor. Certain InfrastruX subsidiaries also have borrowing
      capacities for working capital purposes of which Puget Energy is not the
      guarantor. Of the $150 million bank facility available to InfrastruX, $121
      million was outstanding at September 30, 2005 and $131 million was outstanding
      at December 31, 2004. In determining the fair value of its InfrastruX
      investment, Puget Energy has determined proceeds of a sale will first be used
      to
      extinguish all outstanding InfrastruX debt.


In
      accordance with SFAS No. 144, Puget Energy has adjusted the carrying value
      of
      its investment in InfrastruX to the estimate of fair value, less cost to sell,
      at September 30, 2005. This estimate could change based on InfrastruX’s
      financial performance and market conditions in the utility constructions
      services sector. After reflecting an $8.1 million carrying value reduction
      in
      the third quarter 2005 and $14.3 million for the nine months ended September
      30,
      2005, Puget Energy’s equity investment in InfrastruX was $34.3 million at
      September 30, 2005. It is not anticipated that any funding will be needed from
      Puget Energy to maintain operations at InfrastruX or to complete the sale
      transaction.


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




Three
                  Months Ended
                September
                  30,
              
              Nine
                  Months Ended
                September
                  30,(Dollars
                  in thousands)
              
              2005
              
              2004
              
              2005
              
              2004Revenues
              
              $
              111,667
              
              $
              99,925
              
              $
              286,665
              
              $
              267,496Operating
                  expenses (including interest expense)
              
              
              (106,180
              )
              
              (96,519
              )
              
              (276,267
              )
              
              (259,166
              )Pre-tax
                  income
              
              
              5,487
              
              
              3,406
              
              
              10,398
              
              
              8,330Income
                  tax expense
              
              
              (4,684
              )
              
              (1,567
              )
              
              (7,986
              )
              
              (3,685
              )Minority
                  interest in income of discontinued operations
              
              
              (804
              )
              
              (162
              )
              
              (1,504
              )
              
              (408
              )Income
                  (loss) from discontinued operations
              
              $
              (1
              )
              $
              1,677
              
              $
              908
              
              $
              4,237




In
        accordance with SFAS No. 144, InfrastruX discontinued depreciation and
        amortization of its assets effective February 8, 2005. This discontinuation
        of
        depreciation and amortization resulted in $4.7 million ($2.9 million after-tax)
        and $12 million ($7.3 million after-tax) lower depreciation and amortization
        expense than otherwise would have been recorded as continuing operations
        for the
        three and nine months ended September 30, 2005, respectively.
 InfrastruX’s
          summarized balance sheets, excluding intercompany balances eliminated in
          consolidation, are as follows:
 (Dollars
                  in thousands)
              
              September
                  30, 2005
              
              December
                  31, 2004Assets:Cash
              
              $
              5,115
              
              $
              6,817Accounts
                  receivable
              
              
              93,064
              
              
              78,646Other
                  current assets
              
              
              24,485
              
              
              25,459Total
                  current assets
              
              
              122,664
              
              
              110,922Goodwill
              
              
              43,886
              
              
              43,503Intangibles
              
              
              15,167
              
              
              16,680Non-utility
                  property and other
              
              
              102,700
              
              
              100,115Total
                  long-term assets
              
              
              161,753
              
              
              160,298Total
                  assets
              
              $
              284,417
              
              $
              271,220Liabilities:Accounts
                  payable
              
              $
              10,314
              
              $
              9,773Short-term
                  debt
              
              
              15,281
              
              
              8,297Current
                  maturities of long-term debt
              
              
              6,566
              
              
              7,933Other
                  current liabilities
              
              
              41,622
              
              
              25,889Total
                  current liabilities
              
              
              73,783
              
              
              51,892Deferred
                  income taxes
              
              
              22,641
              
              
              25,828Long-term
                  debt
              
              
              129,786
              
              
              143,172Other
                  deferred credits
              
              
              20,614
              
              
              14,710Total
                  long-term liabilities
              
              
              173,041
              
              
              183,710Total
                  liabilities
              
              $
              246,824
              
              $
              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 100,371,000 and 100,160,000 for the
        three
        and nine months ended September 30, 2005, respectively, and 99,580,000 and
        99,373,000 for the three and nine months ended September 30, 2004, respectively.
 Puget
        Energy’s diluted earnings per common share have been computed based on weighted
        average common shares outstanding of 100,964,000 and 100,754,000 for the
        three
        and nine months ended September 30, 2005, respectively, and 100,043,000 and
        99,836,000 for the three and nine months ended September 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 contracts requiring physical
        delivery of electricity and natural gas 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 portfolio of owned
        and
        contracted electric generation 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 price risk
        exposure. The third priority is to optimize the value of excess capacity
        or
        flexibility within the energy portfolio. The Company is not engaged in the
        business of assuming risk for the purpose of realizing 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
        advisable 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 September 30, 2005, the Company recorded a decrease
        in
        earnings for the change in the market value of derivative instruments not
        meeting cash flow hedge criteria of approximately $0.5 million compared to
        a
        decrease in earnings of approximately $1.9 million for the three months ended
        September 30, 2004. At September 30, 2005, the Company had a net unrealized
        gain
        recorded in other comprehensive income of $33.8 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. At September 30, 2005, PSE had a short-term asset of $51.9 million
        related to energy contracts designated as cash flow hedges that represent
        forward financial purchases of gas supply for electric generation of PSE-owned
        electric plants in future periods. If it is determined that it is uneconomical
        to run the plants in the future period, the hedging relationship is ended
        and
        the cash flow hedge is de-designated and any unrealized gains and losses
        are
        recorded in the income statement. Gains and losses, when these de-designated
        cash flow hedges are settled, are recognized in energy costs and are included
        as
        part of the PCA mechanism. Due to high forward market prices at the end of
        September 2005, sizeable unrealized gains have resulted in cash flow hedge
        assets for the period.
 At
        September 30, 2005, the Company also has a short-term asset of approximately
        $133.4 million related to the cash flow hedge of gas contracts to serve natural
        gas customers. The third quarter 2005 saw market gas prices spike in part
        due to
        the impact of hurricane damage in the gulf coast region in the United States
        which affected supply, therefore existing gas financial hedges showed sizeable
        unrealized gains when marked to the higher market prices. 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. As the gains and losses on the cash flow hedges are realized
        in future periods, they will be recorded as gas costs under the PGA mechanism.
 During
        the nine months ended September 30, 2005, the Company recorded a decrease
        in
        earnings for the change in the market value of derivative instruments not
        meeting cash flow hedge criteria of approximately $0.4 million compared to
        an
        increase in earnings of approximately $1.0 million for the nine months ended
        September 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 September 30, 2005, the Company recorded a liability
        associated with these two contracts in the amount of $0.8 million and an
        unrealized loss in the amount of $0.5 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 $250.0
        million that was completed in May 2005. Since treasury interest rates related
        to
        the hedged debt decreased 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 is being 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 pre-tax. The ending balance in other comprehensive income related
        to the treasury lock contracts at September 30, 2005 was a loss of $22.7
        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 additional asset retirement obligations
        related to unprotected bare steel gas pipe and leases to operate wind turbine
        generators. 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; (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;
        and (6) to remove wind turbine generators and related equipment, improvements
        and fixtures at the termination of the related leases. The replacement of
        bare
        steel natural gas pipe and the future removal of the wind generators are
        the
        additional asset retirement obligations liabilities recognized in
        2005.
 The
        following table describes all changes to the Company’s asset retirement
        obligation liability during the nine months ended September 30:
 
 (Dollars
                  in thousands)At
                  September 30
              
              2005
              
              2004Asset
                  retirement obligation at beginning of year
              
              $
              3,516
              
              $
              3,421New
                  ARO liability recognized in the period
              
              
              2,538
              
              
              --Liability
                  settled in the period
              
              
              (321
              )
              
              --Accretion
                  expense
              
              
              141
              
              
              71Asset
                  retirement obligation at September 30
              
              $
              5,874
              
              $
              3,492
 
 In
        March
        2005, FASB issued FIN 47 which provided guidance on when an asset retirement
        obligation, that is conditional on a future event, should be recognized.
        The
        Company will adopt FIN 47 in the fourth quarter 2005. See Note 9 for further
        explanation.
 
 
 **(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
                September
                  30,
              
              Nine
                  Months Ended
                September
                  30,(Dollars
                  in thousands, except per share amounts)
              
              2005
              
              2004
              
              2005
              
              2004Net
                  income, as reported
              
              $
              5,911
              
              $
              11,124
              
              $
              90,881
              
              $
              70,710Add:
                  Total stock-based employee compensation expense
                included
                  in net income, net of tax
              
              
              995
              
              
              904
              
              
              2,800
              
              
              2,474Less:
                  Total stock-based employee compensation expense
                per
                  the fair value method of SFAS No. 123, net of tax
              
              
              (992
              )
              
              (860
              )
              
              (2,891
              )
              
              (2,301
              )Pro
                  forma net income
              
              $
              5,914
              
              $
              11,168
              
              $
              90,790
              
              $
              70,883Earnings
                  per share:Basic
                  per common share as reported
              
              $
              0.06
              
              $
              0.11
              
              $
              0.91
              
              $
              0.71Diluted
                  per common share as reported
              
              $
              0.06
              
              $
              0.11
              
              $
              0.90
              
              $
              0.71Basic
                  per common share pro forma
              
              $
              0.06
              
              $
              0.11
              
              $
              0.91
              
              $
              0.71Diluted
                  per common share pro forma
              
              $
              0.06
              
              $
              0.11
              
              $
              0.90
              
              $
              0.71
 
 In
        December 2004, FASB issued SFAS No. 123R, “Share-Based Payments,” which revises
        SFAS No. 123. The Company will implement SFAS No. 123R for periods commencing
        January 1, 2006. See Note 9 for further explanation.
 
 
 **(7)**
              **Retirement
                  Benefits**
 
 The
        following summarizes the net periodic benefit cost for the three months ended
        September 30:
 
 Pension
                  Benefits
              
              Other
                  Benefits(Dollars
                  in thousands)
              
              2005
              
              2004
              
              2005
              
              2004Service
                  cost
              
              $
              2,915
              
              $
              2,586
              
              $
              49
              
              $
              42Interest
                  cost
              
              
              5,979
              
              
              6,021
              
              
              344
              
              
              376Expected
                  return on plan assets
              
              
              (9,482
              )
              
              (9,777
              )
              
              (220
              )
              
              (200
              )Amortization
                  of prior service cost
              
              
              756
              
              
              797
              
              
              77
              
              
              78Recognized
                  net actuarial (gain) loss
              
              
              814
              
              
              282
              
              
              (115
              )
              
              (179
              )Amortization
                  of transition (asset) obligation
              
              
              (41
              )
              
              (276
              )
              
              105
              
              
              104Net
                  periodic benefit cost (income)
              
              $
              941
              
              $
              (367
              )
              $
              240
              
              $
              221
  The
        following summarizes the net periodic benefit cost for the nine months ended
        September 30:
 
 Pension
                  Benefits
              
              Other
                  Benefits(Dollars
                  in thousands)
              
              2005
              
              2004
              
              2005
              
              2004Service
                  cost
              
              $
              8,745
              
              $
              7,757
              
              $
              139
              
              $
              142Interest
                  cost
              
              
              17,937
              
              
              18,062
              
              
              939
              
              
              1,252Expected
                  return on plan assets
              
              
              (28,446
              )
              
              (29,330
              )
              
              (659
              )
              
              (644
              )Amortization
                  of prior service cost
              
              
              2,268
              
              
              2,392
              
              
              233
              
              
              232Recognized
                  net actuarial (gain) loss
              
              
              2,443
              
              
              846
              
              
              (529
              )
              
              (179
              )Amortization
                  of transition (asset) obligation
              
              
              (122
              )
              
              (828
              )
              
              313
              
              
              314Net
                  periodic benefit cost (income)
              
              $
              2,825
              
              $
              (1,101
              )
              $
              436
              
              $
              1,117
 
 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 nine months
        ended
        September 30, 2005, the actual cash contributions to the pension plans were
        $0.3
        million and $1.2 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 $0.3 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 nine months ended September 30, 2005, actual other post-retirement
        medical benefit plan contributions were $0.1 million and $1.1 million,
        respectively. In the third quarter, the Company’s expected contributions to the
        post-retirement medical benefit plan for 2005 was revised from $1.4 million
        to
        $1.0 million. As the Company has already made payments of $1.0 million for
        the
        nine months ended September 30, 2005, it does not expect to make additional
        contributions during the last three months of 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 nine months ended September 30, 2005 for the 2005
        plan
        year by $0.6 million.
 
 
 **(8)**
              **Other**
 
 At
        September 30, 2005, PSE had a net receivable totaling $21.3 million in
        connection with wholesale sales in 2000 to the California Independent System
        Operator (CAISO) and counterparties where payment to PSE was conditioned
        on the
        counterparties being paid by the California Power Exchange. In August 2005,
        PSE
        submitted a Fuel Cost Adjustment Claim for $3.4 million related to sales
        in 2000
        to the CAISO, pursuant to FERC’s California refund proceeding.
 Pursuant
        to an order issued by FERC in August 2005, PSE also submitted a Portfolio
        Cost
        Claim in September 2005 for $9.3 million to the CAISO. FERC has not yet
        clarified several important computational issues with these types of claims,
        nor
        has it determined a mechanism for the allocation and payment of Portfolio
        Cost
        Claim and Fuel Cost Adjustment Claim. PSE’s ability to recover all or a portion
        of these claims is uncertain at the present time.
 Based
        upon FERC orders, PSE has determined a range related to its CAISO receivable
        to
        be between $21.3 million (PSE’s net receivable balance) and $34.2 million
        including interest on its past due receivables as of September 30,
        2005.
 On
        October 20, 2005, the Washington Commission approved a 3.7%, or $55.6 million
        annually, power cost only rate case (PCORC) increase to allow PSE to recover
        higher projected costs of power effective November 1, 2005. Included in the
        increase is the recovery of capital and operating costs of the newly acquired
        Hopkins Ridge wind project, which is expected to be completed in late 2005.
        The
        Washington Commission also approved an amendment to the PCA mechanism by
        changing the annual PCA reporting periods to a calendar year period beginning
        January 1, 2007 with provisions made to reduce the sharing bands in half
        for the
        period July 1, 2006 through December 31, 2006. The order also requires PSE
        to
        update the power cost baseline rate in the PCA mechanism by filing a tariff
        change to the power cost rate during May 2006 which would be effective July
        1,
        2006. Finally, the order requires PSE to file a general rate case by
        mid-February 2006 so that a new power cost baseline rate will be effective
        on
        January 1, 2007.
 On
        October 18, 2005, PSE learned of two additional potential royalty claims
        that
        are likely to be asserted by the State of Montana in the near future. The
        potential claims, in total, amount to $0.3 million, plus interest. PSE’s initial
        assessment of these claims is that they would likely have a similar ultimate
        result to the parallel MMS claims that are being appealed. If the State of
        Montana’s claims are asserted, PSE will defend them consistently with the MMS
        claims. PSE reserved $1.1 million for the MMS claim in the second quarter
        of
        2004.
 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 September 30, 2005 and 2004 for these
        three
        entities was $73.2 million and $70.9 million, respectively. PSE’s Purchased
        Electricity expense for the nine months ended September 30, 2005 and 2004
        for
        these three entities was $186.7 million and $180.9 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. The NOPA states that the deduction was not valid
        for the 2003 tax year and would require repayment of approximately $14.5
        million
        in tax. 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. If
        the
        Company is unsuccessful, a charge for interest expense could apply.
 During
        2002, PSE changed its tax accounting method with respect to capitalizable
        internal labor and overheads, which permitted the Company to deduct immediately
        certain costs that it had previously capitalized. On August 2, 2005, the
        Internal Revenue Service and the Treasury Department issued Revenue Ruling
        2005-53 and related Regulations. The Revenue Ruling and the Regulations will
        require utility companies, including PSE, to switch to a less advantageous
        method of accounting and to repay the accumulated tax benefits. Through
        September 30, 2005, the Company claimed $66.3 million in accumulated tax
        benefits. PSE accounted for the accumulated tax benefits as temporary
        differences in determining its deferred income tax balances. Consequently,
        the
        repayment of the tax benefits would not impact earnings but does have a cash
        flow impact of $33.2 million in fourth quarter 2005 and $33.1 million in
        2006.
        There is some uncertainty in the new guidance. PSE believes that the new
        Regulations require the Company to repay the accumulated tax benefits over
        the
        next two years and that the tax deductions claimed on the Company’s tax returns
        were appropriate based on the applicable statutes, regulations, and case
        law in
        effect at the time. However, there is no assurance that PSE’s position will
        prevail. If the Company is unsuccessful, a charge for interest expense could
        apply.
 Due
        to
        the new Regulations, PSE filed on October 19, 2005 an accounting petition
        with
        the Washington Commission to defer cost using PSE’s allowed net of tax rate of
        return of 7.01% associated with increasing capital borrowing necessary to
        repay
        $72 million in income tax that was treated as a reduction to rate base in
        the
        Washington Commission order of February 18, 2005, beginning November 1, 2005.
        This accounting petition was approved by the Washington Commission on October
        26, 2005, for deferral of additional capital costs beginning November 1,
        2005.
        PSE will request recovery of this deferral commencing January 2007 in its
        February 2006 electric general rate case filing.
 On
        May
        18, 2005, PSE made 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%, due June 1, 2035. 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
        October 2005, PSE completed the issuance of $150 million of senior notes
        secured
        by first mortgage bonds, at a rate of 5.197%, due October 1, 2015. The net
        proceeds from the issuance of the senior notes of approximately $149 million
        were used to repay a portion of PSE’s short-term debt.
 On
        October 26, 2005, Puget Energy agreed to sell 15 million shares of common
        stock
        to Lehman Brothers Inc. The net proceeds of approximately $309.8 million
        were
        invested in PSE and used to repay short-term debt incurred to primarily fund
        PSE’s construction program. In addition, Lehman Brothers has a 30 day option
        to
        purchase up to an additional 1.7 million shares of Puget Energy common stock
        if
        the underwriter sells more than 15 million shares in the offering.
 
 
 **(9)**
              ******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, which will be January 1, 2006 for the Company. 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. Puget Energy’s
          ability to complete the sale of InfrastruX to a third party on reasonable
          terms
          is subject to a number of factors beyond our control. 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 energy market. PSE
          is continually exploring new electric-power resource generation and long-term
          purchase power agreements to meet this goal. The completion of its acquisitions
          of the Hopkins Ridge wind project in the first quarter 2005 and the Wild
          Horse
          wind project in the third quarter is one step in reaching this goal. In
          the
          first quarter 2005, PSE issued notice to proceed with construction of the
          Hopkins Ridge wind project which is expected to be completed by the end
          of 2005.
          The Hopkins Ridge wind project will provide approximately 150 MW of capacity
          or
          52 average MW. PSE also issued notice to proceed with construction of the
          Wild
          Horse wind project in the third quarter 2005 which is expected to be completed
          by the end of 2006. The Wild Horse wind project will provide approximately
          230
          MW of capacity or 73 average MW. Combined, these projects will require
          approximately $570 million in capital requirements in 2005 and 2006. Together
          these electric generation resources will serve the needs of approximately
          123,000 of PSE’s electric customers.
 The
          Hopkins Ridge wind project and the Wild Horse wind project were included
          as part
          of PSE’s energy resource portfolio in its 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 was
          followed by issuing an all-source request for proposal (RFP) on November
          1,
          2005. PSE obtained approval of the all-source RFP from the Washington Commission
          on October 28, 2005.
 
 
 **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 September 30, 2005 was
          $5.9
          million on operating revenues of $490.4 million from continuing operations
          compared to net income of $11.1 million on operating revenues of $415.0
          million
          from continuing operations for the same period in 2004. The net income
          for both
          periods includes the results of discontinued operations for InfrastruX.
 Basic
          and
          diluted earnings per share for the three months ended September 30, 2005
          were
          $0.06 compared to basic and diluted earnings per share for the three months
          ended September 30, 2004 of $0.11. Discontinued operations and loss on
          disposal
          of InfrastruX had no effect on the basic and diluted earnings per share
          for the
          three months ended September 30, 2005. Included in the basic and diluted
          earnings per share for the three months ended September 30, 2004 was $0.02
          earnings per share related to discontinued operations of
          InfrastruX.
 Net
          income for the three months ended September 30, 2005 was positively impacted
          by
          increased gas margins of $4.4 million compared to the same period in 2004
          related to the effects of increased gas usage and the gas general rate
          case
          which increased margins by $2.4 million. Higher planned maintenance costs
          at
          PSE-owned energy production facilities, delivery infrastructure and employee
          pension and benefit costs negatively impacted net income. Also negatively
          impacting net income was higher depreciation and amortization expense on
          PSE’s
          transmission and distribution system infrastructure projects.
 For
          the
          nine months ended September 30, 2005, Puget Energy’s net income was $90.9
          million on operating revenues of $1.7 billion compared to net income of
          $70.7
          million on operating revenues of $1.5 billion for the same period in 2004.
          Basic
          and diluted earnings per share for the nine months ended September 30,
          2005 were
          $0.91 and $0.90, respectively, compared to basic and diluted earnings per
          share
          of $0.71 for the same period in 2004. Included in the basic and diluted
          earnings
          per share for the nine months ended September 30, 2005 was $0.01 earnings
          per
          share related to discontinued operations and loss on disposal of InfrastruX
          compared to $0.04 basic and diluted earnings per share related to discontinued
          operations of InfrastruX for the same period in 2004.
 Net
          income for the nine months ended September 30, 2005 was positively impacted
          by
          increased electric and gas margins of $51.6 million and $9.0 million,
          respectively, compared to the same period in 2004, mainly due to the Tenaska
          disallowance in May 2004, increased electric and gas usage and increase
          in gas
          general rates offset by a one-time true-up of previously reported purchased
          gas
          costs.
 The
          Tenaska disallowance in May 2004 relates to an order in May 2004 in which
          the
          Washington Utilities and Transportation Commission (Washington Commission)
          determined that PSE did not prudently manage gas costs for the Tenaska
          electric
          generating plant and ordered PSE to adjust its deferral account by expensing
          a
          one-time charge to purchased electricity. The order also established guidelines
          for future recovery of Tenaska costs. See further discussion under section
          titles “Other” - “Tenaska Disallowance”.
 
 **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, and its lowest
          sales in the third quarter 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 September 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 September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeElectric
                    retail sales revenue
                
                $
                315.3
                
                $
                293.7
                
                $
                21.6
                
                
                7.4
                %Electric
                    transportation revenue
                
                
                1.7
                
                
                2.7
                
                
                (1.0
                )
                
                (37.0
                )%Other
                    electric revenue-gas supply resale
                
                
                9.1
                
                
                1.6
                
                
                7.5
                
                
                468.8
                %Total
                    electric revenue for margin1
                
                
                326.1
                
                
                298.0
                
                
                28.1
                
                
                9.4
                %Adjustments
                    for amounts included in revenue:Pass-through
                    tariff items
                
                
                (6.5
                )
                
                (5.3
                )
                
                (1.2
                )
                
                (22.6
                )%Pass-through
                    revenue-sensitive taxes
                
                
                (23.2
                )
                
                (21.3
                )
                
                (1.9
                )
                
                (8.9
                )%Residential
                    exchange credit
                
                
                34.5
                
                
                34.0
                
                
                0.5
                
                
                1.5
                %Net
                    electric revenue for margin
                
                
                330.9
                
                
                305.4
                
                
                25.5
                
                
                8.3
                %Minus
                    power costs:Electric
                    generation fuel
                
                
                (21.0
                )
                
                (25.1
                )
                
                4.1
                
                
                16.3
                %Purchased
                    electricity, net of sales to other utilities and marketers2
                
                
                (160.2
                )
                
                (133.4
                )
                
                (26.8
                )
                
                (20.1
                )%Total
                    electric power costs3
                
                
                (181.2
                )
                
                (158.5
                )
                
                (22.7
                )
                
                (14.3
                )%Electric
                    margin before PCA
                
                
                149.7
                
                
                146.9
                
                
                2.8
                
                
                1.9
                %Tenaska
                    disallowance reserve
                
                
                --
                
                
                2.4
                
                
                (2.4
                )
                
                *Power
                    cost deferred under the PCA mechanism
                
                
                --
                
                
                --
                
                
                --
                
                
                --Electric
                    margin4
                
                $
                149.7
                
                $
                149.3
                
                $
                0.4
                
                
                0.3
                %
 _________________________________
 *  *Percent
          change not applicable or unmeaningful* *.*
 1***For the three months ended September 30, 2005, total
          electric revenue for margin was $326.1 million, which does not include
          $40.6
          million in sales to other utilities and marketers and $8.3 million in other
          miscellaneous electric revenue included in electric operating revenues
          of $375.0
          million. For the three months ended September 30, 2004, total electric
          revenue
          for margin was $298.0 million, which does not include $16.6 million in
          sales to
          other utilities and marketers and $8.1 million in other miscellaneous electric
          revenues included in electric operating revenues of $322.7
          million.*
 2*For the three months ended September 30, 2005, purchased electricity,
          net of sales to other utilities and marketers, was $160.2 million, excluding
          sales to other utilities and marketers of $40.7 million, purchased electricity
          was $200.9 million. For the three months ended September 30, 2004, purchased
          electricity, net of sales to other utilities and marketers, was $133.4
          million
          ,excluding sales to other utilities and marketers of $16.6 million and
          deducting
          the Tenaska disallowance reserve of $(2.4) million, purchased electricity
          was
          $147.6 million.*
 3 *For
          the three months ended September 30, 2005, total electric power costs were
          $181.2 million, which includes electric generation fuel and purchased
          electricity, net of sales to other utilities and marketers (see note 2
          above),
          but does not include the residential exchange credit of $(34.5) million
          and
          unrealized net loss on derivative instruments of $0.5 million. These amounts,
          excluding sales of electricity to other utilities and marketers, provide
          electric energy costs of $187.9 million. For the three months ended September
          30, 2004, total electric power costs were $158.5 million, which includes
          electric generation fuel and purchased electricity, net of sales to other
          utilities and marketers (see note 2 above), but does not include the residential
          exchange credit of $(34.0) million and unrealized net loss on derivative
          instruments of $1.9 million. These amounts excluding sales of electricity
          to
          other utilities and marketers provide electric energy costs of $140.6
          million.*
 4*Electric margin does not include any allocation for
          amortization/depreciation expense or electric generation operations and
          maintenance expense**.*
 
 
 The
          following table displays the details of electric margin changes for the
          nine
          months ended September 30, 2005 compared to the same period in
          2004.
 
 Electric
                    Margin(Dollars
                    in Millions)
                  Nine
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeElectric
                    retail sales revenue
                
                $
                1,018.9
                
                $
                942.1
                
                $
                76.8
                
                
                8.2
                %Electric
                    transportation revenue
                
                
                6.7
                
                
                7.3
                
                
                (0.6
                )
                
                (8.2
                )%Other
                    electric revenue-gas supply resale
                
                
                14.3
                
                
                5.6
                
                
                8.7
                
                
                155.4
                %Total
                    electric revenue for margin1
                
                
                1,039.9
                
                
                955.0
                
                
                84.9
                
                
                8.9
                %Adjustments
                    for amounts included in revenue:Pass-through
                    tariff items
                
                
                (19.0
                )
                
                (19.4
                )
                
                0.4
                
                
                2.1
                %Pass-through
                    revenue-sensitive taxes
                
                
                (75.4
                )
                
                (68.3
                )
                
                (7.1
                )
                
                (10.4
                )%Residential
                    exchange credit
                
                
                126.7
                
                
                123.8
                
                
                2.9
                
                
                2.3
                %Net
                    electric revenue for margin
                
                
                1,072.2
                
                
                991.1
                
                
                81.1
                
                
                8.2
                %Minus
                    power costs:Electric
                    generation fuel
                
                
                (54.4
                )
                
                (60.1
                )
                
                5.7
                
                
                9.5
                %Purchased
                    electricity, net of sales to other utilities and marketers2
                
                
                (522.5
                )
                
                (464.2
                )
                
                (58.3
                )
                
                (12.6
                )%Total
                    electric power costs3
                
                
                (576.9
                )
                
                (524.3
                )
                
                (52.6
                )
                
                (10.0
                )%Electric
                    margin before PCA
                
                
                495.3
                
                
                466.8
                
                
                28.5
                
                
                6.1
                %Tenaska
                    disallowance reserve
                
                
                5.3
                
                
                (34.1
                )
                
                39.4
                
                
                *
                %Power
                    cost deferred under the PCA mechanism
                
                
                3.0
                
                
                19.3
                
                
                (16.3
                )
                
                (84.5
                )%Electric
                    margin4
                
                $
                503.6
                
                $
                452.0
                
                $
                51.6
                
                
                11.4
                %
 _________________________________
 *  *Percent
          change not applicable or unmeaningful* *.*
 1
                *For
                    the nine months ended September 30, 2005, total electric revenue
                    for
                    margin was $1,039.9 million, which does not include $73.8 million
                    in sales
                    to other utilities and marketers and $26.8 million in other miscellaneous
                    electric revenue included in electric operating revenues of $1,140.5
                    million. For the nine months ended September 30, 2004, total
                    electric
                    revenue for margin was $955.0 million, which does not include
                    $38.8
                    million in sales to other utilities and marketers and $24.5 million
                    in
                    other miscellaneous electric revenues included in electric operating
                    revenues of $1,018.3 million.*
 2*For the nine months ended September 30, 2005, purchased electricity,
          net of sales to other utilities and marketers, was $522.5 million excluding
          sales to other utilities and marketers of $73.8 million and including the
          Tenaska disallowance of $(5.3) million and power cost deferral under the
          PCA
          mechanism of $(3.0) million, purchased electricity was $588.0 million.
          For the
          nine months ended September 30, 2004, purchased electricity, net of sales
          to
          other utilities and marketers, was $464.2 million, excluding sales to other
          utilities and marketers of $38.8 million and including the Tenaska disallowance
          of $34.1 million and the power cost deferral under the PCA mechanism of
          $(19.3)
          million, purchased electricity was $517.8 million.*
 3*For the nine months ended September 30, 2005, total electric
          power
          costs were $576.9 million, which includes electric generation fuel and
          purchased
          electricity, net of sales to other utilities and marketers (see note 2
          above),
          but does not include the residential exchange credit of $(126.7) million
          and
          unrealized net loss on derivative instruments of $0.4 million. These amounts
          excluding sales of electricity to other utilities and marketers provide
          electric
          energy costs of $516.1 million. For the nine months ended September 30,
          2004,
          total electric power costs were $524.3 million, which includes electric
          generation fuel and purchased electricity, net of sales to other utilities
          and
          marketers (see note 2 above), but does not include the residential exchange
          credit of $(123.8) million and unrealized net gain on derivative instruments
          of
          $(1.0) million. These amounts excluding sales of electricity to other utilities
          and marketers provide electric energy costs of $453.1 million.*
 *4* *Electric
          margin does not include any allocation for amortization/depreciation expense
          or
          electric generation operations and maintenance
          expense.*
  Electric
          margin increased $0.4 million for the three months ended September 30,
          2005
          compared to the same period in 2004. The electric general rate case for
          the
          three months ended September 30, 2005 increased electric revenues but were
          offset by additional recovery of power costs through the Power Cost Adjustment
          (PCA) mechanism which does not increase margin. Retail customer kWh sales
          (residential, commercial and industrial customers) increased 1.5% for the
          three
          months ended September 30, 2005 compared to 2004.
 Electric
          margin increased $51.6 million for the nine months ended September 30,
          2005
          compared to the same period in 2004 primarily as a result of the one-time
          Tenaska disallowance recorded in May 2004, and ongoing Tenaska disallowance,
          which reduced margin by $34.1 million for the nine months ended September
          30,
          2004. In February 2005, a final resolution and recovery of a $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
          2.2% increase in retail customer usage, and change in customer class usage,
          which contributed $33.3 million to margin. These increases were partially
          offset
          by a reduction in customer deferral of excess power costs in 2005 under
          the PCA
          mechanism which provided recovery of power costs for the nine months ended
          September 30, 2005 compared to the same period in 2004. Electric margin
          for the
          nine months ended September 30, 2005 was also affected by the ongoing Tenaska
          disallowance applicable to periods after May 24, 2004 which increased $3.7
          million as compared to the same period in 2004.
 The
          following table displays the details of gas margin changes for the three
          months
          ended September 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 September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeGas
                    retail revenue
                
                $
                103.7
                
                $
                83.0
                
                $
                20.7
                
                
                24.9
                %Gas
                    transportation revenue
                
                
                3.3
                
                
                3.1
                
                
                0.2
                
                
                6.5
                %Total
                    gas revenue for margin1
                
                
                107.0
                
                
                86.1
                
                
                20.9
                
                
                24.3
                %Adjustments
                    for amounts included in revenue:Pass-through
                    tariff items
                
                
                (0.6
                )
                
                (0.4
                )
                
                (0.2
                )
                
                (50.0
                )%Pass-through
                    revenue-sensitive taxes
                
                
                (8.5
                )
                
                (6.8
                )
                
                (1.7
                )
                
                (25.0
                )%Net
                    gas revenue for margin
                
                
                97.9
                
                
                78.9
                
                
                19.0
                
                
                24.1
                %Minus
                    purchased gas costs
                
                
                (59.2
                )
                
                (44.6
                )
                
                (14.6
                )
                
                (32.7
                )%Gas
                    margin2
                
                $
                38.7
                
                $
                34.3
                
                $
                4.4
                
                
                12.8
                %
 _________________________________
 *1For the three months ended September 30, 2005, total gas revenue
          for
          margin was $107.0 million, which does not include $4.0 million related
          to other
          gas operating revenues that is included in gas operating revenues of $111.0
          million. For the three months ended September 30, 2004, total gas revenue
          for
          margin was $86.1 million, which does not include $3.3 million related to
          other
          gas operating revenues that is included in gas operating revenues of $89.4
          million.*
 *2Gas
          margin does not include any allocation for amortization/depreciation expense
          or
          electric generation operations and maintenance expense.*
 
 The
          following table displays the details of gas margin changes for the nine
          months
          ended September 30, 2005 compared to the same period in 2004.
 
 Gas
                    Margin(Dollars
                    in Millions)
                  Nine
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeGas
                    retail revenue
                
                $
                571.8
                
                $
                465.0
                
                $
                106.8
                
                
                23.0
                %Gas
                    transportation revenue
                
                
                9.9
                
                
                9.7
                
                
                0.2
                
                
                2.1
                %Total
                    gas revenue for margin1
                
                
                581.7
                
                
                474.7
                
                
                107.0
                
                
                22.5
                %Adjustments
                    for amounts included in revenue:Pass-through
                    tariff items
                
                
                (3.5
                )
                
                (2.0
                )
                
                (1.5
                )
                
                (75.0
                )%Pass-through
                    revenue-sensitive taxes
                
                
                (47.2
                )
                
                (39.0
                )
                
                (8.2
                )
                
                (21.0
                )%Net
                    gas revenue for margin
                
                
                531.0
                
                
                433.7
                
                
                97.3
                
                
                22.4
                %Minus
                    purchased gas costs2
                
                
                (359.0
                )
                
                (270.7
                )
                
                (88.3
                )
                
                (32.6
                )%Gas
                    margin3
                
                $
                172.0
                
                $
                163.0
                
                $
                9.0
                
                
                5.5
                %
 _________________________________
 *1**For the nine months ended September 30, 2005, total gas
          revenue
          for margin was $581.7 million, which does not include $13.0 million related
          to
          other gas operating revenues that is included in gas operating revenues
          of
          $594.7 million. For the nine months ended September 30, 2004, total gas
          revenue
          for margin was $474.7 million, which does not include $9.9 million related
          to
          other gas operating revenues that is included gas operating revenues of
          $484.6
          million.*
 *2* *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.*
 *3****Gas margin does not include any allocation for
          amortization/depreciation expense or electric generation operations and
          maintenance expense.*
 
 Gas
          margin increased $4.4 million for the three months ended September 30,
          2005
          compared to the same period in 2004 primarily due to increased gas general
          tariff rates and increased usage by customers. Gas margin increased $2.4
          million
          as a result of the gas general tariff increase effective March 4, 2005.
          Therm
          sales increased 1.3% for the three months ended September 30, 2005 compared
          to
          the same period in 2004, which provided $2.0 million to gas margin.
 Gas
          margin increased $9.0 million for the nine months ended September 30, 2005
          compared to the same period in 2004. Gas margin increased $8.6 million
          as a
          result of the gas general tariff rate case. In addition, therm sales increased
          0.8% for the nine months ended September 30, 2005 compared to the same
          period in
          2004, which provided $1.3 million to gas margin, and changes in customer
          class
          usage provided $4.0 million to gas margin. Negatively impacting gas margin
          for
          the nine months ended September 30, 2005, was a $5.0 million one-time true-up
          of
          previously reported gas costs under the PGA mechanism in the second quarter.
          See
          further discussion under the section titled “Operating Expenses-Purchased Gas.”
          In addition, warmer than normal temperatures in PSE’s service territory in the
          first and second quarters have adversely impacted sales volumes for natural
          gas.
  **Electric
          Operating Revenues**
 The
          table
          below sets forth changes in electric operating revenues for PSE for the
          three
          months ended September 30, 2005 compared to the same period in
          2004.
 
 (Dollars
                    in Millions)
                  Three
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeElectric
                    operating revenues:Residential
                    sales
                
                $
                131.7
                
                $
                122.4
                
                $
                9.3
                
                
                7.6
                %Commercial
                    sales
                
                
                153.1
                
                
                143.7
                
                
                9.4
                
                
                6.5
                %Industrial
                    sales
                
                
                23.7
                
                
                22.2
                
                
                1.5
                
                
                6.8
                %Other
                    retail sales, including unbilled revenue
                
                
                6.8
                
                
                5.4
                
                
                1.4
                
                
                25.9
                %Total
                    retail sales
                
                
                315.3
                
                
                293.7
                
                
                21.6
                
                
                7.4
                %Transportation
                    sales
                
                
                1.7
                
                
                2.7
                
                
                (1.0
                )
                
                (37.0
                )%Sales
                    to other utilities and marketers
                
                
                40.6
                
                
                16.6
                
                
                24.0
                
                
                144.6
                %Other
                
                
                17.4
                
                
                9.7
                
                
                7.7
                
                
                79.4
                %Total
                    electric operating revenues
                
                $
                375.0
                
                $
                322.7
                
                $
                52.3
                
                
                16.2
                %
 
 Electric
          retail sales increased $21.6 million for the three months ended September
          30,
          2005 compared to the same period in 2004 due primarily to the electric
          general
          rate case and increased retail customer usage. The electric general rate
          case
          provided $12.8 million to electric operating revenues for the three months
          ended
          September 30, 2005 compared to the same period in 2004. Retail electricity
          usage
          increased 68,279 MWh or 1.5% for the three months ended September 30, 2005
          compared to the same period in 2004, which resulted in an approximate $4.5
          million increase in electric operating revenue. The increase in electricity
          usage was primarily the result of a 1.8% increase in the average number
          of
          customers served.
 During
          the three month period ended September 30, 2005, the benefits of the Residential
          and Farm Energy Exchange Benefit credited to customers reduced electric
          operating revenues by $36.2 million compared to $35.3 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 $24.0 million compared to the three
          month period ended September 30, 2004 primarily due to an increase of 326,313
          MWh sold related to excess energy available for sale on the wholesale market.
          This resulted primarily from normal streamflows for hydro electric generation
          in
          the quarter instead of below normal streamflows that were expected. 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
          are
          included in the PCA mechanism as a reduction in determining net power
          costs.
 Other
          electric revenues increased $7.7 million for the three months ended September
          30, 2005 compared to the same period in 2004, primarily from the sale of
          excess
          non-core gas purchased for intended electric generation. Non-core gas sales
          are
          included in the PCA mechanism calculation as a reduction in determining
          net
          power costs.
 The
            table
            below sets forth changes in electric operating revenues for PSE for the
            nine
            months ended September 30, 2005 compared to the same period in
            2004.
 
 (Dollars
                    in Millions)
                  Nine
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeElectric
                    operating revenues:Residential
                    sales
                
                $
                496.5
                
                $
                459.1
                
                $
                37.4
                
                
                8.1
                %Commercial
                    sales
                
                
                461.1
                
                
                428.9
                
                
                32.2
                
                
                7.5
                %Industrial
                    sales
                
                
                68.9
                
                
                65.3
                
                
                3.6
                
                
                5.5
                %Other
                    retail sales, including unbilled revenue
                
                
                (7.6
                )
                
                (11.2
                )
                
                3.6
                
                
                32.1
                %Total
                    retail sales
                
                
                1,018.9
                
                
                942.1
                
                
                76.8
                
                
                8.2
                %Transportation
                    sales
                
                
                6.7
                
                
                7.3
                
                
                (0.6
                )
                
                (8.2
                )%Sales
                    to other utilities and marketers
                
                
                73.8
                
                
                38.8
                
                
                35.0
                
                
                90.2
                %Other
                
                
                41.1
                
                
                30.1
                
                
                11.0
                
                
                36.5
                %Total
                    electric operating revenues
                
                $
                1,140.5
                
                $
                1,018.3
                
                $
                122.2
                
                
                12.0
                %
 
 Electric
          retail sales increased $76.8 million for the nine months ended September
          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
          $28.6 million to electric operating revenues for the nine months ended
          September
          30, 2005 compared to the same period in 2004, which provided approximately
          $20.3
          million in electric operating revenues. Retail electricity usage increased
          311,785 MWh or 2.2% for the nine months ended September 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 nine month period
          ended
          September 30, 2005 compared to the same period in 2004.
 During
          the nine months ended September 30, 2005, the benefits of the Residential
          and
          Farm Energy Exchange Benefit credited to customers reduced electric operating
          revenues by $132.6 million compared to $129.2 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 $35.0 million compared to the nine
          months ended September 30, 2004 primarily due to an increase of 567,957
          MWh sold
          related to excess generation and energy available for sale on the wholesale
          market. This resulted primarily from normal streamflows for hydro electric
          generation in the third quarter as compared to below normal streamflows
          that
          were expected. 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 $11.0 million for the nine months ended September
          30, 2005 compared to the same period in 2004, primarily from the sale of
          excess
          non-core gas purchased for intended electric generation. 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
                Average
                  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
                %
                57.7Power
                    Cost Only Rate Case
                November
                    1, 2005
                3.7
                %
                55.6
 
 **Gas
          Operating Revenues**
 The
          table
          below sets forth changes in gas operating revenues for PSE for the three
          months
          ended September 30, 2005 compared to the same period in 2004.
 
 (Dollars
                    in Millions)
                  Three
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeGas
                    operating revenues:Residential
                    sales
                
                $
                57.3
                
                $
                47.1
                
                $
                10.2
                
                
                21.7
                %Commercial
                    sales
                
                
                37.2
                
                
                29.0
                
                
                8.2
                
                
                28.3
                %Industrial
                    sales
                
                
                9.2
                
                
                6.9
                
                
                2.3
                
                
                33.3
                %Total
                    retail sales
                
                
                103.7
                
                
                83.0
                
                
                20.7
                
                
                24.9
                %Transportation
                    sales
                
                
                3.3
                
                
                3.1
                
                
                0.2
                
                
                6.5
                %Other
                
                
                4.0
                
                
                3.3
                
                
                0.7
                
                
                21.2
                %Total
                    gas operating revenues
                
                $
                111.0
                
                $
                89.4
                
                $
                21.6
                
                
                24.2
                %
 
 Gas
          retail sales increased $20.7 million for the three months ended September
          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 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 September 30,
          2005,
          the effects of the PGA mechanism rate increases provided an increase of
          $13.8
          million in gas operating revenues. In addition, the gas general rate case
          increased gas rates by 3.5%, which provided an additional $2.4 million
          in gas
          operating revenue for the three months ended September 30, 2005 compared
          to the
          same period in 2004. An increase of 2.9% in the average number of customers
          increased customer usage by 2.7 million therms or approximately $2.5 million
          in
          gas operating revenues.
 The
          table
          below sets forth changes in gas operating revenues for PSE for the nine
          months
          ended September 30, 2005 compared to the same period in 2004.
 
 (Dollars
                    in Millions)
                  Nine
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeGas
                    operating revenues:Residential
                    sales
                
                $
                360.7
                
                $
                295.4
                
                $
                65.3
                
                
                22.1
                %Commercial
                    sales
                
                
                178.9
                
                
                144.2
                
                
                34.7
                
                
                24.1
                %Industrial
                    sales
                
                
                32.2
                
                
                25.4
                
                
                6.8
                
                
                26.8
                %Total
                    retail sales
                
                
                571.8
                
                
                465.0
                
                
                106.8
                
                
                23.0
                %Transportation
                    sales
                
                
                9.9
                
                
                9.7
                
                
                0.2
                
                
                2.1
                %Other
                
                
                13.0
                
                
                9.9
                
                
                3.1
                
                
                31.3
                %Total
                    gas operating revenues
                
                $
                594.7
                
                $
                484.6
                
                $
                110.1
                
                
                22.7
                %
 
 Gas
          retail sales increased $106.8 million for the nine months ended September
          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 $81.8 million in gas revenues for the nine months ended September
          30,
          2005 compared to the same period in 2004. In addition, the gas general
          rate case
          increase provided an additional $8.6 million in gas operating revenues
          for the
          nine months ended September 30, 2005 compared to the same period in 2004.
          An
          increase of 3.1% in the average number of customers for the nine months
          ended
          September 30, 2005 provided the remaining increase in retail gas revenues
          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
                Average
                  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
                %
                26.3PGA
                October
                    1, 2005
                14.7
                %
                121.6
 
 **Operating
          Expenses**
 The
          table
          below sets forth significant changes in operating expenses for PSE and
          its
          subsidiaries for the three months ended September 30, 2005 compared to
          the same
          period in 2004.
 
 (Dollars
                    in Millions)
                  Three
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangePurchased
                    electricity
                
                $
                200.9
                
                $
                147.6
                
                $
                53.3
                
                
                36.1
                %Electric
                    generation fuel
                
                
                21.1
                
                
                25.1
                
                
                (4.0
                )
                
                (15.9
                )%Purchased
                    gas
                
                
                59.2
                
                
                44.6
                
                
                14.6
                
                
                32.7
                %Unrealized
                    (gain) loss on derivative instruments
                
                
                0.5
                
                
                1.9
                
                
                (1.4
                )
                
                (73.7
                )%Utility
                    operations and maintenance
                
                
                81.6
                
                
                67.1
                
                
                14.5
                
                
                21.6
                %Depreciation
                    and amortization
                
                
                60.6
                
                
                57.6
                
                
                3.0
                
                
                5.2
                %Taxes
                    other than income taxes
                
                
                44.8
                
                
                42.7
                
                
                2.1
                
                
                4.9
                %Income
                    taxes
                
                
                2.6
                
                
                7.1
                
                
                (4.5
                )
                
                (63.4
                )%
 
 The
          table
          below sets forth significant changes in operating expenses for PSE and
          its
          subsidiaries for the nine months ended September 30, 2005 compared to the
          same
          period in 2004.
 
 (Dollars
                    in Millions)
                  Nine
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangePurchased
                    electricity
                
                $
                588.0
                
                $
                517.8
                
                $
                70.2
                
                
                13.6
                %Electric
                    generation fuel
                
                
                54.4
                
                
                60.1
                
                
                (5.7
                )
                
                (9.5
                )%Residential
                    exchange credit
                
                
                (126.7
                )
                
                (123.8
                )
                
                2.9
                
                
                2.3
                %Purchased
                    gas
                
                
                359.0
                
                
                270.7
                
                
                88.3
                
                
                32.6
                %Unrealized
                    (gain) loss on derivative instruments
                
                
                0.4
                
                
                (1.0
                )
                
                1.4
                
                
                140.0
                %Utility
                    operations and maintenance
                
                
                240.3
                
                
                214.1
                
                
                26.2
                
                
                12.2
                %Depreciation
                    and amortization
                
                
                178.3
                
                
                170.0
                
                
                8.3
                
                
                4.9
                %Taxes
                    other than income taxes
                
                
                165.0
                
                
                149.5
                
                
                15.5
                
                
                10.4
                %Income
                    taxes
                
                
                55.4
                
                
                40.9
                
                
                14.5
                
                
                35.5
                %
 
 **Purchased
          electricity** expenses
          increased $53.3 million and $70.2 million for the three and nines months
          ended
          September 30, 2005, respectively, compared to the same periods in 2004.
          The
          increase for the three months ended September 30, 2005 was primarily the
          result
          of lower generation of power at PSE-controlled facilities, higher wholesale
          market prices and higher customer usage, which increased the amount of
          power
          purchased. Total purchased power for the three months ended September 30,
          2005
          increased 532,685 MWh or 14.7% compared to the same period in 2004. Generation
          at PSE-controlled facilities decreased 148,463 MWh or 7.7% compared to
          the same
          period in 2004. The increase for the nine months ended September 30, 2005
          was
          the result of increased power purchases and higher wholesale market prices
          offset by a one-time $37.8 million disallowance charge related to the return
          on
          the Tenaska gas supply regulatory asset in 2004. Total purchased power
          for the
          nine months ended September 30, 2005 increased 1,086,551 MWh, or a 9.5%
          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
          nine
          months ended September 30, 2005.
 PSE’s
          hydroelectric production and related power costs in 2005 and 2004 have
          continued
          to be negatively impacted by below-normal precipitation and reduced snow
          pack in
          the Pacific Northwest region. The July 8, 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 September 2005 would be 86% of normal, which compares
          to
          84% 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 regulated
          power portfolio through short-term and intermediate-term off-system physical
          purchases and sales, and through other risk management techniques.
 **Electric
          generation fuel** expense
          decreased $4.0 million and $5.7 million for the three and nine months ended
          September 30, 2005, respectively, compared to the same periods in 2004.
          The
          decrease for the three months ended September 30, 2005 is primarily related
          to
          lower generation at PSE-controlled combustion turbine generating facilities
          of
          82,087 MWhs and overall lower cost of gas for those facilities due to hedging
          of
          gas supply costs for a decrease of $5.5 million. Offsetting the decrease
          is an
          increase of $1.4 million in the cost of coal due to higher generation at
          Colstrip generating facilities of 49,225 MWhs and an increase in the price
          of
          the fuel. The decrease for the nine months ended September 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, electric generation fuel costs increased $1.2 million related
          to
          higher generation at Colstrip generating facilities of 82,741 MWhs and
          the price
          paid for fuel at the facility totaling $4.2 million offset by overall lower
          cost
          of gas for combustion turbine units due to lower generation and cost of
          gas at
          those facilities totaling $3.0 million.
 **Residential
          exchange credits** associated with the Residential Purchase and Sale Agreement with BPA increased
          $2.9 million for the nine months ended September 30, 2005 compared to the
          same
          periods in 2004. The overall increase for the nine months ended September
          30,
          2004 was a result of increased residential and small farm customer electric
          load. The residential exchange credit is a pass-through tariff item with
          a
          corresponding credit in electric operating revenue, thus it has no impact
          on
          electric margin or net income.
 **Purchased
          gas** expenses
          increased $14.6 million and $88.3 million for the three and nine months
          ended
          September 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 September 30, 2005 and December 31,
          2004 was
          $37.5 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 for the nine months
          ended September 30, 2005 include a one-time true-up of $3.3 million to
          reflect
          the impact of the demand charge. This adjustment impacts the comparability
          of
          gas margin information and purchased gas expense for the nine months ended
          September 30, 2005 compared with the same periods in 2004.
 **Unrealized
          gain on derivative instruments** increased
          $1.4 million and decreased $1.4 million for the three and nine months ended
          September 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 $14.5 million and $26.2 million for the three and nine months
          ended
          September 30, 2005, respectively, compared to the same periods in 2004.
          Included
          in the increases for the three and nine months ended September 30, 2005
          are a
          $1.3 million and a $4.5 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 nine months ended September 30, 2005 was
          an
          increase of $13.2 million and $21.7 million, respectively. The increase
          for the
          three months ended September 30, 2005 includes increases related to higher
          planned maintenance costs at PSE-owned energy production facilities, delivery
          infrastructure, and employee pension and benefit costs.
 The
          increase for the nine months ended September 30, 2005 includes increases
          related
          to higher planned maintenance costs for PSE-owned energy production facilities,
          delivery facilities, employee pension and benefit costs. Production operation
          and maintenance increase for the nine months ended September 30, 2005 also
          includes 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 recorded in the second quarter 2005 -
          see
          further discussion under the section titled “Other.” These increases were
          partially offset by lower storm damage repair costs of $7.2 million for
          nine
          months ended September 30, 2005 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 $3.0 million and $8.3 million for the three and nine months ended
          September 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
          and
          2005, including $32.8 million for the Everett Delta gas transmission line
          late
          in 2004. The nine months ended September 30, 2005 includes the effects
          of the
          $80.8 million Frederickson 1 generating facility in April 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 $2.1 million and $15.5 million for the three and nine months
          ended
          September 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. The increase
          for
          the three months ended September 30, 2005 was offset by a decrease of $1.5
          million related to the 2005 property tax assessment issued by the Washington
          State Department of Revenue in the third quarter 2005.
 **Income
          taxes** decreased $4.5 million and increased $14.5 million for the three and nine
          months
          ended September 30, 2005, respectively, compared to the same periods in
          2004.
          The decrease for the three months ended September 30, 2005 was the result
          of
          lower taxable income as compared to the same period in 2004. The increase
          for
          the nine months ended September 30, 2005 is a result of higher taxable
          income
          and a higher effective federal income tax rate as compared to the same
          period in
          2004.
 
 **Other
          Income And Interest Charges**
 The
          table
          below sets forth significant changes in interest charges for PSE and its
          subsidiaries for the three months ended September 30, 2005 compared to
          the same
          period in 2004.
 
 (Dollars
                    in Millions)
                  Three
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeInterest
                    charges
                
                $
                43.0
                
                $
                41.1
                
                $
                1.9
                
                
                4.6
                %
 
 **Interest
          charges** increased
          $1.9 million for the three months ended September 30, 2005 compared to
          the same
          period in 2004. The three months ended September 30, 2005 increase is due
          primarily to higher amounts of short-term borrowings and the issuance of
          $250
          million long-term senior notes in June 2005 at 5.483% which was used in
          part to
          repay a $200 million variable rate note with a lower interest rate offset
          by
          redemptions of $50.2 million of long-term debt with rates ranging from
          6.45% to
          7.70% in 2004. In addition, the increase was offset by a May 2005 redemption
          of
          $42.5 million of 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
          table
          below sets forth significant changes in other income for PSE and its
          subsidiaries for the nine months ended September 30, 2005 compared to the
          same
          period in 2004.
 
 (Dollars
                    in Millions)
                  Nine
                    Months Ended September 30
                
                2005
                
                2004
                
                Change
                
                Percent
                  ChangeOther
                    income (net of tax)
                
                $
                4.2
                
                $
                2.0
                
                $
                2.2
                
                
                110.0
                %
 
 **Other
          income** increased
          $2.2 million (after-tax) for the nine months ended September 30, 2005 compared
          to the same period in 2004 primarily due to increases in the equity portion
          of
          allowance for funds used during construction and in the surrender value
          of
          corporate-owned life insurance policies.
 
 **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 into its regulated
          utility
          subsidiary, PSE. Management believes the 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 in
          2005. Puget Energy is actively marketing InfrastruX and has held discussions
          with interested financial and strategic parties in 2005. Puget Energy has
          recently retained an investment banker to assist in the disposal of InfrastruX.
          To date, Puget Energy has not entered into a definitive agreement that
          would
          result in the sale of its investment in InfrastruX.
 For
          the
          three and nine months ended September 30, 2005, Puget Energy reported InfrastruX
          related income from discontinued operations (net of taxes and minority
          interest)
          of $0.0 million and $0.9 million, respectively, compared to income of $1.7
          million and $4.2 million (net of taxes and minority interest) for the three
          and
          nine months ended September 30, 2004, respectively. Included in the income
          for
          discontinued operations is a charge of $8.1 million after-tax for the three
          months ended September 30, 2005 and $14.3 million after-tax for the nine
          months
          ended September 30, 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. The following chart summarizes Puget Energy’s income from
          discontinued operations for the three and nine months ended September 30,
          2005:
 
 (Dollars
                    in Millions)
                
                Three
                    Months
                  Ended
                  September
                    30,
                  2005
                
                Nine
                    Months
                  Ended
                  September
                    30,
                  2005Net
                    income reported by InfrastruX
                
                $
                5.3
                
                $
                7.8InfrastruX
                    depreciation and amortization not recorded
                  by
                    Puget Energy, net of tax
                
                
                2.9
                
                
                7.3Puget
                    Energy tax benefit from goodwill deduction
                
                
                0.7
                
                
                1.4Puget
                    Energy carrying value adjustment of InfrastruX,
                  including
                    cost of sale, net of tax
                
                
                (8.1
                )
                
                (14.3
                )Minority
                    interest in income from discontinued operations and other
                
                
                (0.8
                )
                
                (1.3
                )Income
                    from discontinued operations
                
                $
                --
                
                $
                0.9
 
 InfrastruX
          reported strong financial results and cash flow in the third quarter 2005.
          InfrastruX’s operating revenue for the three and nine months ended September 30,
          2005 was $111.7 million and $286.7 million, respectively, compared to $99.9
          million and $267.5 million, respectively, for the same periods in 2004.
          Operating income for the three and nine months ended September 30, 2005
          was $7.8
          million and $14.3 million, respectively, compared to $3.6 million and $9.2
          million, respectively, for the same periods in 2004. InfrastruX’s bank and
          vendor debt under its credit agreements totaled $151.6 million at September
          30,
          2005 compared to $159.4 million at December 31, 2004 and $181.3 million
          at
          September 30, 2004. In May 2004, InfrastruX signed a three-year 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 borrowing capacities for working capital
          purposes of which Puget Energy is not the guarantor. Of the $150 million
          bank
          facility available to InfrastruX, $121 million was outstanding at September
          30,
          2005 and $131 million was outstanding at December 31, 2004. In determining
          the
          fair value of its InfrastruX investment, Puget Energy has determined proceeds
          on
          a sale will first be used to extinguish all InfrastruX debt
          outstanding.
 In
          accordance with SFAS No. 144, Puget Energy has adjusted the carrying value
          of
          its investment in InfrastruX to the estimate of fair value, less cost to
          sell,
          at September 30, 2005. This estimate could change based on InfrastruX financial
          performance and market conditions in the utility constructions services
          sector.
          After reflecting an $8.1 million carrying value reduction in the third
          quarter
          2005 and $14.3 million for the nine months ended September 30, 2005, Puget
          Energy’s equity investment in InfrastruX was $34.3 million at September 30,
          2005.
 InfrastruX’s
          operations are dependent on a number of factors, including weather conditions,
          the availability of projects and capital to be spent on utility construction
          projects and key InfrastruX customer contractual relationships. As such,
          Puget
          Energy cannot determine the income or loss from InfrastruX’s operations, 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**
 The
          following are Puget Energy’s and Puget Sound Energy’s aggregate consolidated
          contractual obligations from continuing operations as of September 30,
          2005:
 
 **Puget
                    Energy and Puget Sound Energy**
                
                
                
                Payments
                    Due Per PeriodContractual
                    Obligations
                  (Dollars
                    in Millions)
                Total
                2005
                2006-
                  2007
                2008-
                  2009
                2010
                    & ThereafterLong-term
                    debt including interest
                $
                3,867.7
                $$
                35.4
                $
                470.8
                $
                568.0
                $
                2,793.5Short-term
                    debt
                
                223.9
                
                223.9
                
                --
                
                --
                
                --Junior
                    subordinated debentures payable to a subsidiary trust1
                
                910.7
                
                10.1
                
                39.8
                
                39.8
                
                821.0Mandatorily
                    redeemable preferred stock
                
                1.9
                
                --
                
                --
                
                --
                
                1.9Service
                    contract obligations
                
                176.6
                
                16.0
                
                49.3
                
                57.0
                
                54.3Non-cancelable
                    operating leases
                
                125.8
                
                3.5
                
                33.1
                
                27.6
                
                61.6Fredonia
                    combustion turbines lease2
                
                61.9
                
                1.1
                
                8.6
                
                8.4
                
                43.8Energy
                    purchase obligations
                
                5,476.4
                
                500.9
                
                2,165.7
                
                1,442.1
                
                1,367.7Financial
                    hedge obligations
                
                327.8
                
                106.3
                
                216.7
                
                4.8
                
                --Pension
                    funding3
                
                44.5
                
                3.1
                
                8.2
                
                9.8
                
                23.4Total
                    contractual cash obligations
                $
                11,217.2
                $$
                900.3
                $
                2,992.2
                $$
                2,157.5
                $$
                5,167.2
   **Puget
          Energy.** The
          following are Puget Energy’s aggregate consolidated (including PSE) commercial
          commitments as of September 30, 2005:
 **Puget
                      Energy**
                  
                  
                  
                  Amount
                      of Commitment
                    Expiration
                      Per PeriodCommercial
                      Commitments
                    (Dollars
                      in Millions)
                  Total
                  2005
                  2006-
                    2007
                  2008-
                    2009
                  2010
                      & ThereafterGuarantees4
                  $$
                  121.0
                  $$
                  --
                  $$
                  121.0
                  $$
                  --
                  $$
                  --Liquidity
                      facilities - available5
                  
                  355.6
                  
                  80.0
                  
                  --
                  
                  --
                  
                  275.6Energy
                      operations letter of credit
                  
                  0.5
                  
                  --
                  
                  0.5
                  
                  --
                  
                  --Total
                      commercial commitments
                  $$
                  477.1
                  $$
                  80.0
                  $$
                  121.5
                  $$
                  --
                  $$
                  275.6
 
 *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, $121.0 was outstanding at June
                    30,
                    2005.*
 *5*
                *At
                    September 30, 2005, PSE had available a $500 million unsecured
                    credit
                    agreement expiring in April 2010 and a $132 million receivables
                    securitization facility expiring December 2005. At September
                    30, 2005, PSE
                    had $70.0 million 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 $223.9 million and a letter of credit totaling $0.5
                    million,
                    thereby effectively reducing the available borrowing capacity
                    under these
                    liquidity facilities to $337.6 million.*
 
 **Puget
          Sound Energy** .
          The
          following are PSE’s aggregate commercial commitments as of September 30,
          2005:
  **Puget
                    Sound Energy**
                
                
                
                Amount
                    of Commitment
                  Expiration
                    Per PeriodCommercial
                    Commitments
                  (Dollars
                    in Millions)
                Total
                2005
                2006-
                  2007
                2008-
                  2009
                2010
                    &
                  ThereafterLiquidity
                    facilities - available1
                $$
                355.6
                $
                80.0
                $
                --
                $
                --
                $$
                275.6Energy
                    operations letter of credit
                
                0.5
                
                --
                
                0.5
                
                --
                
                --Total
                    commercial commitments
                $$
                356.1
                $
                80.0
                $
                0.5
                $
                --
                $$
                275.6
 _______________________
 *1*
                *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
          September 30, 2005, Rainier Receivables had $70.0 million sold under the
          receivables securitization facility, leaving $62.0 million of receivables
          available to be sold under the program. During the three months ended September
          30, 2005 and 2004, Rainier Receivables sold a cumulative $130.0 million
          and
          $81.0 million of receivables, respectively. During the nine months ended
          September 30, 2005, and 2004, Rainier Receivables sold a cumulative $190.0
          million and $348.0 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 September 30, 2005, PSE’s outstanding balance under the lease was
          $54.7 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 $400.7 million for the nine months ended September
          30, 2005.
          Utility construction expenditures in 2005, 2006 and 2007 are anticipated
          to be
          the following:
  Capital
                      Expenditure Projections
                    (Dollars
                      in Millions)
                  2005
                  2006
                  2007Energy
                      delivery, technology and facilities
                  $
                  400
                  $
                  445
                  $
                  475Hopkins
                      Ridge wind project
                  
                  190
                  
                  --
                  
                  --Wild
                      Horse wind project
                  
                  80
                  
                  300
                  
                  --Other
                      new energy resources1
                  
                  --
                  
                  --
                  
                  --Total
                      capital expenditures
                  $
                  670
                  $
                  745
                  $
                  475
 _______________________
 1*Construction expenditures for other new energy resources 2006 and 2007
          have not
          been determined.*
 
 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 a notice to proceed with construction on
          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 in late 2005, the energy will be delivered
          to PSE’s service territory by BPA’s transmission system via an interconnection.
          PSE anticipates spending approximately $190 million on the project. Included
          in
          the $190 million estimate is the cost to acquire and construct the wind
          plant,
          to fund upgrades to the transmission systems of the Bonneville Power
          Administration and other regional transmission providers, and for development,
          transaction and financing costs.
 On
          September 30, 2005, PSE completed the acquisition of the Wild Horse wind
          project
          in central Washington State from Horizon Wind Energy LLC and issued a notice
          to
          proceed with construction on the project. Simultaneously, PSE entered into
          an
          agreement with Vestas-American Wind Technology, Inc. (Vestas) to purchase
          and
          construct a total of 127 Vestas 1.8 MW wind turbines providing up to
          approximately 230 MW of capacity, or 73 average MW. The Wild Horse wind
          project
          is within PSE’s service territory and upon completion in late 2006, the energy
          will connect to an existing PSE transmission line. PSE anticipates spending
          up
          to approximately $380 million on the project. Included in the $380 million
          estimate is the cost to acquire land, wind turbines and other necessary
          assets,
          construction costs, and transaction, financing and contingency costs. Through
          September 30, 2005, PSE had spent $27.5 million on the Wild Horse
          project.
 
 
 **Capital
          Resources**
 **Cash
          From Operations**
 Cash
          generated from operations for the nine months ended September 30, 2005
          was
          $301.0 million. During that period, $6.2 million was used for AFUDC, which
          reduced interest expense, and $65.9 million for payment of dividends.
          Consequently, cash flows available for utility construction expenditures
          and
          other capital expenditures were $228.9 million or 57% of the $400.7 million
          in
          construction expenditures (net of AFUDC and customer refundable contributions)
          and other capital expenditure requirements for the nine months ended September
          30, 2005. For the nine months ended September 30, 2004, cash generated
          from
          operations was $282.1 million, $3.8 million was used for AFUDC, which reduced
          interest expense, and $65.1 million was used for payment of dividends.
          Therefore, cash flows available for utility **** construction
          expenditures and other capital **** expenditures
          were $213.2 million, or 66% of the $324.3 million in construction expenditures
          (net of AFUDC and customer refundable contributions) and other capital
          expenditure requirements for the nine month period ended September 30,
          2004. The
          following table provides a summary of cash available and construction
          expenditures:
 
 (Dollars
                    in millions)
                  (Unaudited)
                  For
                    the nine months ended September 30
                
                2005
                
                2004Cash
                    from operations
                
                $
                301.0
                
                $
                282.1Less:
                    Dividends paid
                
                
                (65.9
                )
                
                (65.1
                )AFUDC
                
                
                (6.2
                )
                
                (3.8
                )Cash
                    available for construction expenditures
                
                $
                228.9
                
                $
                213.2Construction
                    and energy efficiency expenditures
                
                $
                417.1
                
                $
                337.6Less:
                    AFUDC
                
                
                (6.2
                )
                
                (3.8
                )Cash
                    received from refundable customer contributions
                
                
                (10.2
                )
                
                (9.5
                )Net
                    construction and energy efficiency expenditures
                
                $
                400.7
                
                $
                324.3
 
 The
          overall cash generated from operating activities for the nine month period
          ended
          September 30, 2005 increased $18.9 million compared to the same period
          in 2004.
          The increase in cash was primarily the result of an increase in the accounts
          payable balance of $40.1 million, as compared to 2004, an increase in cash
          collateral received from energy suppliers of $23.5 million, and a $11.7
          million
          positive cash flow change in the Purchased Gas Adjustment Receivable. These
          increases were partially offset by a $39.2 million decrease in deferred
          income
          taxes, income tax credits, and taxes payable. The increase in cash was
          also
          offset by an increase of $17.2 million in prepayments.
 
 **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
          September 30, 2005, PSE could issue:
 ·
                approximately
                    $250 million of additional first mortgage bonds under PSE’s electric
                    mortgage indenture based on approximately $417 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 September 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
                    September 30, 2005;
 ·
                approximately
                    $635 million of additional preferred stock at an assumed dividend
                    rate of
                    6.625%; and
 ·
                approximately
                    $325 million of unsecured long-term
                    debt.
 At
          September 30, 2005, PSE had approximately $3.7 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 borrowing costs 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 October 21, 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.
 This
          shelf registration statement, effective May 4, 2005, replaces Puget Energy
          and
          PSE’s previous $500 million shelf registration statement and provides the
          Company with additional capacity and flexibility when funding anticipated
          capital projects and meeting maturing debt obligations.
 On
          May
          18, 2005, PSE made 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 was
          redeemed on June 2, 2005 at a 4% premium which totaling 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%, due June 1, 2035. 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
          October 2005, PSE completed the issuance of $150 million of senior notes
          secured
          by first mortgage bonds, at a rate of 5.197%, due October 1, 2015. The
          net
          proceeds from the issuance of the senior notes of approximately $149.0
          million
          were used to repay a portion of PSE’s short-term debt.
 On
          October 26, 2005, Puget Energy agreed to sell 15 million shares of common
          stock
          to Lehman Brothers Inc. The net proceeds of approximately $309.8 million
          were
          invested in PSE and used to repay short-term debt incurred to primarily
          fund
          PSE’s construction program. In addition, Lehman Brothers has a 30 day option
          to
          purchase up to an additional 1.7 million shares of Puget Energy common
          stock if
          the underwriter sells more than 15 million shares in the offering.
 Based
          on
          PSE's goal to become a more vertically integrated utility, it is expected
          that
          further issuances of debt 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
          extended 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 had available $132 million
          of
          its $150 million receivables securitization program with Rainier Receivables,
          which expires in December 2005. At September 30, 2005, PSE had available
          $500
          million in the unsecured credit agreement and $62 million under its receivables
          securitization facility, both of which provide credit support for outstanding
          commercial paper and letters of credit. At September 30, 2005, there was
          $70
          million in receivables securitization facility outstanding, $223.9 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 $337.6 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 September 30, 2005, there were no amounts
          outstanding under this credit agreement.
 On
          September 29, 2005, Puget Energy paid off a $5 million outstanding balance
          on a
          bank credit agreement and closed the credit agreement.
 
 **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 $3.6 million (159,985 shares) and $10.9 million
          (480,005 shares) for the three and nine months ended September 30, 2005,
          respectively, compared to $3.8 million (176,227 shares) and $11.6 million
          (530,430 shares) for the three and nine months ended September 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. The two petitions have been consolidated and briefing
          is
          expected to be completed in the first quarter 2006.
 
 **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 denied PSE’s shoreline exemption
          application. 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 were held in September 2005 and,
          on
          October 5, 2005, PSE’s appeal was granted. Skagit County sought reconsideration
          of the decision, which was denied. On October 21, 2005, an appeal to the
          Skagit
          County Board of Commissioners was filed by Skagit County Dike District
          Nos. 1,
          12 and 17, City of Mount Vernon and City of Bellingham. 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 fourth quarter 2005. 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**
 **Power
          Cost Only Rate Case.** On
          October 20, 2005, the Washington Commission approved a 3.7%, or $55.6 million
          annually, power cost only rate case (PCORC) increase to allow PSE to recover
          higher projected costs of power effective November 1, 2005. Included in
          the
          increase is the recovery of capital and operating costs of the newly acquired
          Hopkins Ridge wind project, which is expected to be completed in late 2005.
          The
          Washington Commission also approved an amendment to the PCA mechanism by
          changing the annual PCA reporting periods to a calendar year period beginning
          January 1, 2007 with provisions made to reduce the sharing bands in half
          for the
          period July 1, 2006 through December 31, 2006. The order also requires
          PSE to
          update the power cost baseline rate in the PCA mechanism by filing a tariff
          change to the power cost rate during May 2006 which would be effective
          July 1,
          2006. Finally, the order requires PSE to file a general rate case by
          mid-February 2006 so that a new power cost baseline rate will be effective
          on
          January 1, 2007.
 
 **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
                233
                283
                305
                362
                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
                    Variability1
                Customers’
                    Share
                Company’s
                    Share2+/-
                    $20 million
                0%
                
                100%+/-
                    $20 - $40 million
                50%
                
                500%+/-
                    $40 - $120 million
                90%
                
                10%+/-
                    $120 million
                95%
                
                5%
 __________________________
 *1*
                *In
                    October 2005, the Washington Commission in its Power Cost Only
                    Rate Case
                    order made a provision to reduce the power cost variability amounts
                    to
                    half the annual power cost variability for the period July 1,
                    2006 through
                    December 31, 2006.*
 *2*
                *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, on the graduated scale
                    without a
                    cumulative cap.*
 
 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.
          On
          October 20, 2005, the Washington Commission approved an amendment to the
          PCA
          mechanism changing the PCA period to a calendar year beginning January
          1, 2007,
          keeping the graduated scale but not capping the excess power costs. The
          Washington Commission also made provision to reduce the graduated scale
          to half
          the annual excess power costs for the period July 1, 2006 through December
          31,
          2006 without a cap on excess power costs.
 
 **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 September
          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 *
                
                $
                65.5
                
                $
                264.3
                
                $
                252.0
                
                $
                245.5
                
                $
                231.3
                
                $
                216.6
                
                $
                205.2Projected
                    Tenaska benchmark costs
                
                
                44.0
                
                
                175.3
                
                
                174.8
                
                
                182.9
                
                
                189.9
                
                
                197.4
                
                
                205.6Over
                    (under) benchmark costs
                
                $
                21.5
                
                $
                89.0
                
                $
                77.2
                
                $
                62.6
                
                $
                41.4
                
                $
                19.2
                
                $
                (0.4
                )Projected
                    50% disallowance based on
                  Washington
                    Commission methodology
                
                $
                2.3
                
                $
                8.8
                
                $
                7.7
                
                $
                6.3
                
                $
                4.7
                
                $
                3.0
                
                $
                --
 _______________________
 * *Projection
          will change based on market conditions of gas and replacement power
          costs.*
 
 **Gas
          Regulation and Rates**
 On
          September 28, 2005, the Washington Commission approved PSE’s request for a
          Purchased Gas Adjustment (PGA) filed on August 29, 2005. The approved request
          will increase rates and revenues by approximately 14.7% or $121.6 million
          annually. The increase in PGA rates was to recover higher market prices
          of
          natural gas sold to customers. 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 gas prices. PSE’s gas margin and net income are not
          affected by the change in PGA rates.
 
 
 **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.
 On
          October 18, 2005, PSE learned of two additional potential royalty claims
          that
          are likely to be asserted by the State of Montana in the near future. The
          potential claims, in total, amount to $0.3 million plus interest. PSE’s initial
          assessment of these claims is that they would likely have a similar ultimate
          result to the parallel MMS claims that are being appealed. If the State
          of
          Montana’s claims are asserted, PSE will defend them consistently with the MMS
          claims. PSE reserved $1.1 million for the MMS claim in the second quarter
          2004.
 
 **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. The NOPA states that the deduction is not
          valid for
          the 2003 tax year, and requests payment of approximately $14.5 million
          in tax. .
          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. If
          the
          Company is unsuccessful, a charge for interest expense could apply.
 
 **Internal
          Revenue Service Revenue Ruling on Capitalized Overheads.** During
          2002, PSE changed its tax accounting method with respect to capitalizable
          internal labor and overheads, which permitted the Company to deduct immediately
          costs that it had previously capitalized. On August 2, 2005, the Internal
          Revenue Service and the Treasury Department issued Revenue Ruling 2005-53
          and
          related Regulations. The Revenue Ruling and the Regulations will require
          utility
          companies, including PSE, to switch to a less advantageous method of accounting
          and to repay the accumulated tax benefits. Through September 30, 2005,
          the
          Company claimed $66.3 million in accumulated tax benefits. PSE accounted
          for the
          accumulated tax benefits as temporary differences in determining its deferred
          income tax balances. Consequently, the repayment of the tax benefits would
          not
          impact earnings, but does have a cash flow impact of $33.2 million in the
          fourth
          quarter 2005 and $33.1 million in 2006. There is some uncertainty in the
          new
          guidance. PSE believes that the new Regulations require the Company to
          repay the
          accumulated tax benefits over the next two years and that the tax deductions
          claimed on the Company’s tax returns were appropriate based on the applicable
          statutes, regulations, and case law in effect at the time. However, there
          is no
          assurance that PSE’s position will prevail. If the Company is unsuccessful, a
          charge for interest expense could apply.
 Due
          to
          new Regulations, PSE has filed on October 19, 2005 an accounting order
          with the
          Washington Commission to defer cost using PSE’s allowed net of tax rate of
          return of 7.01% associated with increasing capital borrowing necessary
          to repay
          $72 million in income taxes that was treated as a reduction to rate base
          in the
          Washington Commission order of February 18, 2005, beginning November 1,
          2005.
          This accounting petition was approved by the Washington Commission on October
          26, 2005, for deferral of additional capital costs beginning November 1,
          2005.
          PSE will request recovery of this deferral commencing January 2007 in its
          February 2006 electric general rate case filing.
 
 **Energy
          Policy Act of 2005.** The
          recent adoption of the Energy Policy Act of 2005 includes a number of features
          that will directly or indirectly impact the Company. The Energy Policy
          Act of
          2005 promotes infrastructure reliability and investment, including diverse
          energy supplies through cost recovery mechanisms for reliable investments,
          acceleration of depreciation and production tax credits for certain types
          of
          generating facilities. As a result, PSE will receive production tax credits
          related to its wind generating facilities currently under construction,
          which
          will be passed onto customers through lower rates. The Energy Policy Act
          also
          promotes energy efficiency and conservation through tax incentives, which
          will
          benefit PSE’s energy efficiency programs. In addition, the Energy Policy Act
          repealed the Public Utility Holding Company Act of 1935 and made enhancements
          of
          consumer and market protections, including reform of Public Utility Regulatory
          Policy Act (PURPA) and a prohibition on conversion of Northwest firm
          transmission rights. All the effects of the Energy Policy Act on the Company
          are
          not known at this time.
 
 **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 quarters ended March 31,
          2005 and
          June 30, 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 and an August 8,
                    2005 order
                    for submitting cost recovery 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, Enron, Reliant and Public Service Company of
                    Colorado.
                    These settlements, supported by a statement from FERC chairman
                    Joseph
                    Kelliher, may suggest that the process momentum toward settlement
                    in the
                    California Refund Proceedings is
                    increasing.
 
 **2.**
                **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. On March 10, 2005, Wah
                    Chang filed a notice of appeal to the United States Court of
                    Appeals for
                    the Ninth Circuit. Wah Chang filed its opening brief on September
                    21,
                    2005. Response briefs are due November 30, 2005 and the appeal
                    has been
                    consolidated with Wah Chang’s complaint against energy
                    marketers.
 
 **3.**
                **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 sought, 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 sought indemnification, declaratory
                    relief and conditional relief as buyers in transactions involving
                    cross-defendants should the plaintiffs prevail. On June 3, 2005,
                    the
                    cross-defendants, including PSE, filed a demurrer seeking to
                    dismiss the
                    cross-complaints, the hearing on which is set for December 23,
                    2005.
 On
          July
          22, 2005, the court considered a proposed settlement that would resolve
          all
          claims against the Duke parties and indicated a “preliminary approval” setting a
          hearing date for final approval of December 9, 2005. In August, Reliant
          also
          announced it had reached a settlement that would result in the dismissal
          of the
          Master Complaint. No date has yet been set for approval of the Reliant
          Settlement.
 The
          defendants, including Duke and Reliant, also filed demurrers on the Master
          Complaint, which were preliminarily sustained by the court in an order
          dated
          October 4, 2005, based on federal preemption principles and the filed rate
          doctrine. The order sustaining the demurrers acknowledges that the demurrers
          were removed from the calendar pending approval of the proposed settlements.
          The
          Court set a status conference for November 10, 2005 to discuss the remaining
          issues in the cross-complaints.
 
 **4.**
                **California
                    Receivable.**At
                    September 30, 2005, PSE had a net receivable totaling $21.3 million
                    in
                    connection with wholesale sales in 2000 to the California Independent
                    System Operator (CAISO) and counterparties where payment to PSE
                    was
                    conditioned on the counterparties being paid by the California
                    Power
                    Exchange. In August 2005, PSE submitted a Fuel Cost Adjustment
                    Claim for
                    $3.4 million related to sales in 2000 to the CAISO, pursuant
                    to FERC’s
                    California refund proceeding.
 Pursuant
          to an order issued by FERC in August 2005, PSE also submitted a Portfolio
          Cost
          Claim in September 2005 for $9.3 million to the CAISO. FERC has not yet
          clarified several important computational issues with these types of claims,
          nor
          has it determined a mechanism for the allocation and payment of Portfolio
          Cost
          Claim and Fuel Cost Adjustment Claim. PSE’s ability to recover all or a portion
          of these claims is uncertain at the present time.
 Based
          upon FERC orders, PSE has determined a range related to its CAISO receivable
          to
          be between $21.3 million (PSE’s net receivable balance) and $34.2 million
          including interest on its past due receivables as of September 30,
          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.
          For the period July 1, 2006 through December 31, 2006 the sharing bands
          will be
          half of the annual bands without a cap for excess power costs and beginning
          January 1, 2007 the PCA mechanism will provide sharing of costs and benefits
          that are graduated over four levels for each calendar year without a maximum
          cap
          for excess power costs.
 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 Energy 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 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
          realizing 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 energy portfolios. 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 Energy 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
          advisable 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 September 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 independent third
          parties. 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
          September 30, 2005, the Company had a net asset of approximately $89.8
          million
          of energy contracts designated as qualifying cash flow hedges and a
          corresponding unrealized gain of $58.4 million after-tax recorded in other
          comprehensive income. These cash flow hedges represent forward financial
          purchases of gas intended to run PSE-owned electric plants in future periods.
          If
          it is determined that it is uneconomical to run the plants in the future
          period,
          the hedging relationship is ended and the cash flow hedge is de-designated
          and
          any unrealized gains and losses are recorded in the income statement. Gains
          and
          losses, when these de-designated cash flow hedges are settled, are recognized
          in
          energy costs and are included as part of the PCA mechanism. Of the amount
          in
          other comprehensive income, 99% of the mark-to-market gain beginning October
          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
          loss of $0.3 million through current earnings for the three months ended
          September 30, 2005 and at a loss of $0.3 million for the nine months ended
          September 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
          October 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 September 30, 2005, the Company also has a net asset of
          approximately $125.9 million related to the fair value of gas contracts
          to serve
          gas customers. The third quarter 2005 saw market gas prices spike in part
          due to
          hurricanes affecting supply, therefore existing gas financial hedges showed
          sizeable gains when marked to the higher market prices. 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. As the gains and losses on the cash flow hedges are
          realized
          in future periods, they will be recorded as gas costs under the PGA mechanism.
          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 $11.1 million after-tax and would increase current
          earnings for those contracts marked-to-market in earnings by $1.4 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 September
          30,
          2005, the unrealized loss associated with the two swap contracts was $0.5
          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 $9.5 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 September 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 September 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 September 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 September 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 September
          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
          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:
                    November 1, 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 September 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 September 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.