UNITED
        STATES
 SECURITIES
        AND EXCHANGE COMMISSION
 Washington,
        D.C. 20549
 **FORM
        10-Q**
 
 
 [X]
              **QUARTERLY
                  REPORT PURSUANT TO SECTION 13 OR 15(d) OF**
                **THE
                  SECURITIES EXCHANGE ACT OF
                  1934**
  
 **For
                  the quarterly period ended June 30****,
                  2006**
                
                **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.
 Puget
                    Energy, Inc.
                Yes
                /X/
                No
                / /
                
                Puget
                    Sound Energy, Inc.
                Yes
                /X/
                No
                /
                    /
 
 Indicate
          by check mark whether registrant is a large accelerated filer, an accelerated
          filer, or a non-accelerated filer. See definition of “accelerated filer and
          large accelerated filer” in Rule 12b-2 of the Exchange Act.
 Puget
                    Energy, Inc.
                Large
                    accelerated filer
                /X/
                Accelerated
                    filer
                / /
                Non-accelerated
                    filer
                / /Puget
                    Sound Energy, Inc.
                Large
                    accelerated filer
                / /
                Accelerated
                    filer
                / /
                Non-accelerated
                    filer
                /X/
 
 Indicate
          by check mark whether the registrant is a shell company (as defined in
          Exchange
          Act Rule 12b-2)
 Puget
                    Energy, Inc.
                Yes
                /
                    /
                No
                /X/
                
                Puget
                    Sound Energy, Inc.
                Yes
                /
                    /
                No
                /X/


As
      of
      July 27, 2006, (i) the number of shares of Puget Energy, Inc. common stock
      outstanding was 116,241,200 ($.01 par value) and (ii) all of the outstanding
      shares of Puget Sound Energy, Inc. common stock were held by Puget Energy,
      Inc.











**Table
      of Contents**





**Definitions****Filing
                Format****Forward
                Looking Statements****Part
                I.**
            **Financial
                Information****Item
                1.**
            **Financial
                Statements****Puget
                Energy, Inc.**Consolidated
                Statements of Income - Three and Six Months
                Ended June 30, 2006 and 2005Consolidated
                Statements of Comprehensive Income - Three and
                Six Months Ended
              June
                30, 2006 and 2005Consolidated
                Balance Sheets - June 30, 2006 and
                December 31, 2005Consolidated
                Statements of Cash Flows - Six Months
                Ended June 30, 2006 and 2005**Puget
                Sound Energy, Inc.**Consolidated
                Statements of Income - Three and Six Months
                Ended June 30, 2006 and 2005Consolidated
                Statements of Comprehensive Income - Three
                and Six Months Ended
              June
                30, 2006 and 2005Consolidated
                Balance Sheets - June 30, 2006 and
                December 31, 2005Consolidated
                Statements of Cash Flows - Six Months
                Ended June 30, 2006 and 2005**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
                1A.**
            **Risk
                Factors****Item
                4.**
            **Submission
                of Matters to a Vote of Security
                Holders****Item
                6.**
            **Exhibits****Signatures****Exhibit
                Index**








**DEFINITIONS**





AFUDC
            Allowance
                for Funds Used During ConstructionCAISO
            California
                Independent System OperatorFASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy Regulatory CommissionFIN
            Financial
                Accounting Standards Board InterpretationFoundation
            Puget
                Sound Energy FoundationFPA
            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.Tenaska
            Tenaska
                Power Fund, L.P.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 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:





·
            
            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;·
            
            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 (including the Endangered Species Act);·
            
            The
                ability to recover changes in enacted federal state or local tax
                laws
                through revenue in a timely manner;·
            
            Natural
                disasters, such as hurricanes, earthquakes, floods, fires and landslides,
                which can cause temporary supply disruptions and/or price spikes
                in the
                cost of fuel and raw materials;·
            
            Commodity
                price risks associated with procuring natural gas and power in wholesale
                markets that impact customer loads;·
            
            Wholesale
                market disruption, which may result in a deterioration of market
                liquidity, increase the risk of counterparty default, affect the
                regulatory and legislative process in unpredictable ways, negatively
                affect wholesale energy prices and/or impede PSE’s ability to manage its
                energy portfolio risks and procure energy supply, affect the availability
                and access to capital and credit markets and/or impact delivery of
                energy
                to PSE from its suppliers;·
            
            Financial
                difficulties of other energy companies and related events, which
                may
                affect the regulatory and legislative process in unpredictable ways
                and
                also adversely affect the availability of and access to capital and
                credit
                markets and/or impact delivery of energy to PSE from it
                suppliers;·
            
            The
                effect of wholesale market structures (including, but not limited
                to,
                regional market designs or transmission organizations) or other related
                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
                hydro 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
                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;·
            
            The
                loss of significant customers or changes in the business of significant
                customers, which may result in changes in demand for PSE’s services;·
            
            The
                impact of acts of terrorism, flu pandemic or similar significant
                events;·
            
            Capital
                market conditions, including changes in the availability of capital
                or
                interest rate fluctuations;·
            
            Employeeworkforcefactors, including strikes, work stoppages, availability of qualified
                employees or the loss of a key executive;·
            
            The
                ability to obtain adequate insurance coverage and the cost of such
                insurance;·
            
            Adequate
                reserves by Puget Energy for future loss of corporate guarantees
                related
                to InfrastruX sale; and·
            
            The
                ability to maintain effective internal controls over financial reporting.




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. You are also advised to consult
      Item
      1A-“Risk Factors” in our most recent annual report on Form 10-K and this
      quarterly report for updates.








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


Item
      1.  **Financial
      Statements**





**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF INCOME


(Dollars
      in thousands except per share amounts)


(Unaudited)





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2006
            
            2005
            
            2006
            
            2005Operating
                Revenues:Electric
            
            $
            380,980
            
            $
            345,420
            
            $
            848,403
            
            $
            765,511Gas
            
            
            192,457
            
            
            162,567
            
            
            599,044
            
            
            483,695Other
            
            
            787
            
            
            2,127
            
            
            4,510
            
            
            2,561Total
                operating revenues
            
            
            574,224
            
            
            510,114
            
            
            1,451,957
            
            
            1,251,767Operating
                Expenses:Energy
                costs:Purchased
                electricity
            
            
            187,945
            
            
            178,943
            
            
            440,070
            
            
            387,122Electric
                generation fuel
            
            
            14,292
            
            
            12,894
            
            
            35,876
            
            
            33,342Residential
                exchange
            
            
            (38,670
            )
            
            (37,105
            )
            
            (95,303
            )
            
            (92,151
            )Purchased
                gas
            
            
            118,362
            
            
            98,142
            
            
            385,041
            
            
            299,887Net
                unrealized loss (gain) on derivative instruments
            
            
            (150
            )
            
            (591
            )
            
            825
            
            
            (82
            )Utility
                operations and maintenance
            
            
            83,598
            
            
            83,132
            
            
            170,961
            
            
            158,654Other
                operations and maintenance
            
            
            689
            
            
            558
            
            
            1,544
            
            
            1,299Depreciation
                and amortization
            
            
            64,545
            
            
            59,657
            
            
            128,429
            
            
            117,734Conservation
                amortization
            
            
            7,462
            
            
            5,951
            
            
            15,510
            
            
            11,113Taxes
                other than income taxes
            
            
            54,178
            
            
            50,521
            
            
            133,910
            
            
            120,221Income
                taxes
            
            
            15,433
            
            
            6,093
            
            
            55,778
            
            
            52,175Total
                operating expenses
            
            
            507,684
            
            
            458,195
            
            
            1,272,641
            
            
            1,089,314Operating
                income
            
            
            66,540
            
            
            51,919
            
            
            179,316
            
            
            162,453Other
                income (deductions):Charitable
                foundation funding
            
            
            (15,000
            )
            
            --
            
            
            (15,000
            )
            
            --Other
                income
            
            
            5,916
            
            
            1,890
            
            
            8,240
            
            
            3,721Income
                taxes
            
            
            4,532
            
            
            (292
            )
            
            4,547
            
            
            (959
            )Interest
                charges:AFUDC
            
            
            3,027
            
            
            2,041
            
            
            5,049
            
            
            3,503Interest
                expense
            
            
            (44,417
            )
            
            (43,568
            )
            
            (87,959
            )
            
            (84,611
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )
            
            (45
            )
            
            (45
            )Income
                from continuing operations
            
            
            20,575
            
            
            11,967
            
            
            94,148
            
            
            84,062Income
                from discontinued segment (net of tax)
            
            
            32,954
            
            
            1,928
            
            
            51,901
            
            
            909Net
                income before cumulative effect of accounting change
            
            
            53,529
            
            
            13,895
            
            
            146,049
            
            
            84,971Cumulative
                effect of implementation of accounting change (net of tax)
            
            
            --
            
            
            --
            
            
            (89
            )
            
            --Net
                income
            
            $
            53,529
            
            $
            13,895
            
            $
            146,138
            
            $
            84,971Common
                shares outstanding weighted average (in thousands)
            
            
            115,907
            
            
            100,157
            
            
            115,817
            
            
            100,058Diluted
                shares outstanding weighted average (in thousands)
            
            
            116,405
            
            
            100,690
            
            
            116,266
            
            
            100,590Basic
                earnings per common share before cumulative effect of accounting
                change
                from continuing operations
            
            $
            0.18
            
            $
            0.12
            
            $
            0.81
            
            $
            0.84Basic
                earnings per common share from discontinued operations
            
            
            0.28
            
            
            0.02
            
            
            0.45
            
            
            0.01Cumulative
                effect from accounting change
            
            
            --
            
            
            --
            
            
            --
            
            
            --Basic
                earnings per common share
            
            $
            0.46
            
            $
            0.14
            
            $
            1.26
            
            $
            0.85Diluted
                earnings per common share before cumulative effect of accounting
                change
                from continuing operations
            
            $
            0.18
            
            $
            0.12
            
            
            0.81
            
            $
            0.83Diluted
                earnings per common share from discontinued operations
            
            
            0.28
            
            
            0.02
            
            
            0.45
            
            
            0.01Cumulative
                effect from accounting change
            
            
            --
            
            
            --
            
            
            --
            
            
            --Diluted
                earnings per common share
            
            $
            0.46
            
            $
            0.14
            
            $
            1.26
            
            $
            0.84




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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2006
            
            2005
            
            2006
            
            2005Net
                income
            
            $
            53,529
            
            $
            13,895
            
            $
            146,138
            
            $
            84,971Other
                comprehensive income, net of tax at 35%:Foreign
                currency translation adjustment
            
            
            (311
            )
            
            (15
            )
            
            (327
            )
            
            (12
            )Minimum
                pension liability adjustment
            
            
            145
            
            
            --
            
            
            145
            
            
            --Net
                unrealized gains (losses) on derivative instruments during the
                period
            
            
            (4,984
            )
            
            (8,281
            )
            
            (17,914
            )
            
            10,589Reversal
                of net unrealized gains (losses) on derivative instruments settled
                during
                the period
            
            
            (9,926
            )
            
            6,139
            
            
            (9,885
            )
            
            1,110Settlement
                of cash flow hedge contracts
            
            
            13,860
            
            
            (22,960
            )
            
            13,860
            
            
            (22,960
            )Amortization
                of cash flow hedge contracts to earnings
            
            
            190
            
            
            72
            
            
            382
            
            
            72Deferral
                of cash flow hedges related to the power cost adjustment
                mechanism
            
            
            696
            
            
            13,539
            
            
            6,252
            
            
            7,976Other
                comprehensive loss
            
            
            (330
            )
            
            (11,506
            )
            
            (7,487
            )
            
            (3,225
            )Comprehensive
                income
            
            $
            53,199
            
            $
            2,389
            
            $
            138,651
            
            $
            81,746





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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





June
                30,
              2006
            
            December
                31,
              2005Utility
                Plant: (at original cost, including construction work in progress
                of
                $339,754 and $216,513, respectively)Electric
            
            $
            4,992,980
            
            $
            4,802,363Gas
            
            
            2,050,426
            
            
            1,991,456Common
                plant
            
            
            451,220
            
            
            439,599Less:
                Accumulated depreciation and amortization
            
            
            (2,678,710
            )
            
            (2,602,500
            )Net
                utility plant
            
            
            4,815,916
            
            
            4,630,918Other
                property and investments
            
            
            157,545
            
            
            157,321Current
                assets:Cash
            
            
            16,402
            
            
            16,710Restricted
                cash
            
            
            1,049
            
            
            1,047Accounts
                receivable, net of allowance for doubtful accounts
            
            
            217,789
            
            
            294,509Secured
                pledged accounts receivable
            
            
            --
            
            
            41,000Unbilled
                revenues
            
            
            79,501
            
            
            160,207Purchased
                gas adjustment receivable
            
            
            72,973
            
            
            67,335Materials
                and supplies, at average cost
            
            
            39,637
            
            
            36,491Fuel
                and gas inventory, at average cost
            
            
            87,638
            
            
            91,058Unrealized
                gain on derivative instruments
            
            
            19,880
            
            
            75,037Deferred
                income taxes
            
            
            309
            
            
            --Prepayments
                and other
            
            
            9,381
            
            
            7,596Current
                assets of discontinued operations
            
            
            --
            
            
            107,434Total
                current assets
            
            
            544,559
            
            
            898,424Other
                long-term assets:Restricted
                cash
            
            
            3,700
            
            
            --Regulatory
                asset for deferred income taxes
            
            
            121,643
            
            
            129,693Regulatory
                asset for PURPA contract buyout costs
            
            
            179,555
            
            
            191,170Unrealized
                gain on derivative instruments
            
            
            16,685
            
            
            28,464Power
                cost adjustment mechanism
            
            
            6,246
            
            
            18,380Other
            
            
            524,131
            
            
            388,468Long-term
                assets of discontinued operations
            
            
            --
            
            
            167,113Total
                other long-term assets
            
            
            851,960
            
            
            923,288Total
                assets
            
            $
            6,369,980
            
            $
            6,609,951





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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**CAPITALIZATION
      AND LIABILITIES**




June
                30,
              2006
            
            December
                31,
              2005Capitalization:Common
                shareholders’ investment:Common
                stock $0.01 par value, 250,000,000 shares authorized, 116,233,260
                and
                115,695,463 shares outstanding, respectively
            
            $
            1,162
            
            $
            1,157Additional
                paid-in capital
            
            
            1,960,972
            
            
            1,948,975Earnings
                reinvested in the business
            
            
            157,612
            
            
            69,407Accumulated
                other comprehensive income, net of tax at 35%
            
            
            21
            
            
            7,508Total
                shareholders’ equity
            
            
            2,119,767
            
            
            2,027,047Redeemable
                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
            
            
            37,750
            
            
            237,750Long-term
                debt
            
            
            2,333,360
            
            
            2,183,360Total
                redeemable securities and long-term debt
            
            
            2,372,999
            
            
            2,422,999Total
                capitalization
            
            
            4,492,766
            
            
            4,450,046Minority
                interest in discontinued operations
            
            
            --
            
            
            6,816Current
                liabilities:Accounts
                payable
            
            
            180,279
            
            
            346,490Short-term
                debt
            
            
            182,597
            
            
            41,000Current
                maturities of long-term debt
            
            
            135,000
            
            
            81,000Accrued
                expenses:Taxes
            
            
            58,722
            
            
            112,860Salaries
                and wages
            
            
            19,787
            
            
            15,034Interest
            
            
            30,964
            
            
            31,004Unrealized
                loss on derivative instruments
            
            
            45,404
            
            
            9,772Deferred
                income taxes
            
            
            --
            
            
            10,968Other
            
            
            34,955
            
            
            35,694Current
                liabilities of discontinued operations
            
            
            --
            
            
            55,791Total
                current liabilities
            
            
            687,708
            
            
            739,613Long-term
                liabilities:Deferred
                income taxes
            
            
            723,049
            
            
            738,809Unrealized
                loss on derivative instruments
            
            
            487
            
            
            --Other
                deferred credits
            
            
            465,970
            
            
            513,023Long-term
                liabilities of discontinued operations
            
            
            --
            
            
            161,644Total
                long-term liabilities
            
            
            1,189,506
            
            
            1,413,476Total
                capitalization and liabilities
            
            $
            6,369,980
            
            $
            6,609,951





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





**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF CASH FLOWS


(Dollars
      in thousands)


(Unaudited)


Six
                Months Ended
              June
                30,2006
            
            2005Operating
                activities:Net
                income
            
            $
            146,138
            
            $
            84,971Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation
                and amortization
            
            
            128,429
            
            
            117,734Deferred
                income taxes and tax credits, net
            
            
            (25,138
            )
            
            (3,301
            )Net
                unrealized loss (gain) on derivative instruments
            
            
            825
            
            
            (82
            )Amortization
                of gas pipeline capacity assignment
            
            
            (5,267
            )
            
            --Non-cash
                return on regulatory assets
            
            
            4,153
            
            
            --Impairment
                on InfrastruX investment
            
            
            (7,269
            )
            
            5,110Gain
                on sale of InfrastruX
            
            
            (29,764
            )
            
            --Cash
                collateral (paid) received from energy suppliers
            
            
            (19,950
            )
            
            2,950Increase
                (decrease) in residential exchange program
            
            
            (7,529
            )
            
            4,377Chelan
                PUD contract initiation prepayment
            
            
            (89,000
            )
            
            --Other
            
            
            5,595
            
            
            20,081Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            190,636
            
            
            (1,172
            )Materials
                and supplies
            
            
            (2,229
            )
            
            (1,580
            )Fuel
                and gas inventory
            
            
            3,420
            
            
            776Prepayments
                and other
            
            
            (4,470
            )
            
            (15,795
            )Purchased
                gas adjustment receivable
            
            
            (5,638
            )
            
            (13,474
            )Accounts
                payable
            
            
            (163,262
            )
            
            (81,051
            )Taxes
                payable
            
            
            (50,081
            )
            
            20,779Tenaska
                disallowance reserve
            
            
            --
            
            
            (3,156
            )Accrued
                expenses and other
            
            
            2,392
            
            
            (552
            )Net
                cash provided by operating activities
            
            
            71,991
            
            
            136,615Investing
                activities:Construction
                and capital expenditures - excluding equity AFUDC
            
            
            (310,663
            )
            
            (221,369
            )Energy
                efficiency expenditures
            
            
            (13,846
            )
            
            (15,611
            )Refundable
                cash received for customer construction projects
            
            
            7,739
            
            
            6,137Restricted
                cash
            
            
            (3,703
            )
            
            527Gross
                proceeds from sale of InfrastruX, net of cash disposed
            
            
            263,575
            
            
            --Other
            
            
            3,363
            
            
            18,492Net
                cash used by investing activities
            
            
            (53,535
            )
            
            (211,824
            )Financing
                activities:Change
                in short-term debt, net
            
            
            148,656
            
            
            163,749Dividends
                paid
            
            
            (51,984
            )
            
            (43,910
            )Payments
                to minority shareholders of InfrastruX
            
            
            (10,451
            )
            
            --Issuance
                of common stock
            
            
            3,411
            
            
            2,714Issuance
                of bonds and notes
            
            
            250,000
            
            
            250,000Redemption
                of bonds and notes
            
            
            (183,358
            )
            
            (203,456
            )Redemption
                of trust preferred stock
            
            
            (200,000
            )
            
            (42,500
            )Settlement
                of cash flow hedge of interest rate derivative
            
            
            21,323
            
            
            (35,323
            )Issuance
                and redemption costs of bonds and other
            
            
            (2,548
            )
            
            (11,500
            )Net
                cash provided (used) by financing activities
            
            
            (24,951
            )
            
            79,774Net
                increase (decrease) in cash
            
            
            (6,495
            )
            
            4,565Cash
                at beginning of year
            
            
            22,897
            
            
            19,773Cash
                at end of period
            
            $
            16,402
            
            $
            24,338Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            92,358
            
            $
            89,742Income
                taxes
            
            
            77,346
            
            
            32,682




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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2006
            
            2005
            
            2006
            
            2005Operating
                revenues:Electric
            
            $
            380,980
            
            $
            345,420
            
            $
            848,403
            
            $
            765,511Gas
            
            
            192,457
            
            
            162,567
            
            
            599,044
            
            
            483,695Other
            
            
            787
            
            
            2,127
            
            
            4,510
            
            
            2,561Total
                operating revenues
            
            
            574,224
            
            
            510,114
            
            
            1,451,957
            
            
            1,251,767Operating
                expenses:Energy
                costs:Purchased
                electricity
            
            
            187,945
            
            
            178,943
            
            
            440,070
            
            
            387,122Electric
                generation fuel
            
            
            14,292
            
            
            12,894
            
            
            35,876
            
            
            33,342Residential
                exchange
            
            
            (38,670
            )
            
            (37,105
            )
            
            (95,303
            )
            
            (92,151
            )Purchased
                gas
            
            
            118,362
            
            
            98,142
            
            
            385,041
            
            
            299,887Net
                unrealized loss (gain) on derivative instruments
            
            
            (150
            )
            
            (591
            )
            
            825
            
            
            (82
            )Utility
                operations and maintenance
            
            
            83,598
            
            
            83,132
            
            
            170,961
            
            
            158,654Other
                operations and maintenance
            
            
            242
            
            
            241
            
            
            561
            
            
            500Depreciation
                and amortization
            
            
            64,545
            
            
            59,657
            
            
            128,429
            
            
            117,734Conservation
                amortization
            
            
            7,462
            
            
            5,951
            
            
            15,510
            
            
            11,113Taxes
                other than income taxes
            
            
            54,178
            
            
            50,521
            
            
            133,910
            
            
            120,221Income
                taxes
            
            
            15,633
            
            
            6,285
            
            
            56,337
            
            
            52,830Total
                operating expenses
            
            
            507,437
            
            
            458,070
            
            
            1,272,217
            
            
            1,089,170Operating
                income
            
            
            66,787
            
            
            52,044
            
            
            179,740
            
            
            162,597Other
                income (deductions):Other
                income
            
            
            5,560
            
            
            1,890
            
            
            7,884
            
            
            3,721Income
                taxes
            
            
            (713
            )
            
            (292
            )
            
            (698
            )
            
            (959
            )Interest
                charges:AFUDC
            
            
            3,027
            
            
            2,041
            
            
            5,049
            
            
            3,503Interest
                expense
            
            
            (44,538
            )
            
            (43,494
            )
            
            (88,080
            )
            
            (84,469
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )
            
            (45
            )
            
            (45
            )Net
                income before cumulative effect of accounting change
            
            
            30,100
            
            
            12,166
            
            
            103,850
            
            
            84,348Cumulative
                effect of implementation of accounting change (net of tax)
            
            
            --
            
            
            --
            
            
            (89
            )
            
            --Net
                Income
            
            $
            30,100
            
            $
            12,166
            
            $
            103,939
            
            $
            84,348





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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months ended
              June
                30,
            
            Six
                Months Ended
              June
                30,2006
            
            2005
            
            2006
            
            2005Net
                income
            
            $
            30,100
            
            $
            12,166
            
            $
            103,939
            
            $
            84,348Other
                comprehensive income, net of tax at 35%:Minimum
                pension liability adjustment
            
            
            145
            
            
            --
            
            
            145
            
            
            --Net
                unrealized gains (losses) on derivative instruments during the
                period
            
            
            (4,984
            )
            
            (8,281
            )
            
            (17,914
            )
            
            10,589Reversal
                of net unrealized gains (losses) on derivative instruments settled
                during
                the period
            
            
            (9,926
            )
            
            6,139
            
            
            (9,885
            )
            
            1,110Settlement
                of cash flow hedge contracts
            
            
            13,860
            
            
            (22,960
            )
            
            13,860
            
            
            (22,960
            )Amortization
                of cash flow hedge contracts to earnings
            
            
            190
            
            
            72
            
            
            382
            
            
            72Deferral
                of cash flow hedges related to the power cost adjustment
                mechanism
            
            
            696
            
            
            13,539
            
            
            6,252
            
            
            7,976Other
                comprehensive loss
            
            
            (19
            )
            
            (11,491
            )
            
            (7,160
            )
            
            (3,213
            )Comprehensive
                income
            
            $
            30,081
            
            $
            675
            
            $
            96,779
            
            $
            81,135





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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





June
                30,
              2006
            
            December
                31,
              2005Utility
                plant: (at original cost, including construction work in progress
                of
                $339,754 and $216,513, respectively)Electric
            
            $
            4,992,980
            
            $
            4,802,363Gas
            
            
            2,050,426
            
            
            1,991,456Common
                plant
            
            
            451,220
            
            
            439,599Less:
                Accumulated depreciation and amortization
            
            
            (2,678,710
            )
            
            (2,602,500
            )Net
                utility plant
            
            
            4,815,916
            
            
            4,630,918Other
                property and investments
            
            
            157,545
            
            
            157,321Current
                assets:Cash
            
            
            16,351
            
            
            16,709Restricted
                cash
            
            
            1,049
            
            
            1,047Accounts
                receivable, net of allowance for doubtful accounts
            
            
            214,883
            
            
            299,938Secured
                pledged accounts receivable
            
            
            --
            
            
            41,000Unbilled
                revenues
            
            
            79,501
            
            
            160,207Purchased
                gas adjustment receivable
            
            
            72,973
            
            
            67,335Materials
                and supplies, at average cost
            
            
            39,637
            
            
            36,491Fuel
                and gas inventory, at average cost
            
            
            87,638
            
            
            91,058Unrealized
                gain on derivative instruments
            
            
            19,880
            
            
            75,037Deferred
                income taxes
            
            
            309
            
            
            --Prepayments
                and other
            
            
            8,808
            
            
            7,023Total
                current assets
            
            
            541,029
            
            
            795,845Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            121,643
            
            
            129,693Regulatory
                asset for PURPA contract buyout costs
            
            
            179,555
            
            
            191,170Unrealized
                gain on derivative instruments
            
            
            16,685
            
            
            28,464Power
                cost adjustment mechanism
            
            
            6,246
            
            
            18,380Other
            
            
            523,794
            
            
            388,009Total
                other long-term assets
            
            
            847,923
            
            
            755,716Total
                assets
            
            $
            6,362,413
            
            $
            6,339,800





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








**PUGET
      SOUND ENERGY,
      INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**CAPITALIZATION
      AND LIABILITIES**





June
                30,
              2006
            
            December
                31,
              2005Capitalization: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
            
            
            989,825
            
            
            924,154Earnings
                reinvested in the business
            
            
            242,776
            
            
            196,248Accumulated
                other comprehensive income, net of tax at 35%
            
            
            21
            
            
            7,181Total
                shareholder’s equity
            
            
            2,091,660
            
            
            1,986,621Redeemable
                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
            
            
            37,750
            
            
            237,750Long-term
                debt
            
            
            2,333,360
            
            
            2,183,360Total
                redeemable securities and long-term debt
            
            
            2,372,999
            
            
            2,422,999Total
                capitalization
            
            
            4,464,659
            
            
            4,409,620Current
                liabilities:Accounts
                payable
            
            
            180,604
            
            
            346,490Short-term
                debt
            
            
            209,099
            
            
            41,000Current
                maturities of long-term debt
            
            
            135,000
            
            
            81,000Accrued
                expenses:Taxes
            
            
            58,686
            
            
            111,900Salaries
                and wages
            
            
            18,749
            
            
            15,034Interest
            
            
            31,086
            
            
            31,004Unrealized
                loss on derivative instruments
            
            
            45,404
            
            
            9,772Deferred
                income taxes
            
            
            --
            
            
            10,968Other
            
            
            34,613
            
            
            30,932Total
                current liabilities
            
            
            713,241
            
            
            678,100Long-term
                liabilities:Deferred
                income taxes
            
            
            726,894
            
            
            739,162Unrealized
                loss on derivative instruments
            
            
            487
            
            
            --Other
                deferred credits
            
            
            457,132
            
            
            512,918Total
                long-term liabilities
            
            
            1,184,513
            
            
            1,252,080Total
                capitalization and liabilities
            
            $
            6,362,413
            
            $
            6,339,800





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





**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF CASH FLOWS


(Dollars
      in thousands)


(Unaudited)


Six
                Months Ended
              June
                30,2006
            
            2005Operating
                activities:Net
                income
            
            $
            103,939
            
            $
            84,348Adjustments
                to reconcile net income to net cashprovided
                by operating activities:Depreciation
                and amortization
            
            
            128,429
            
            
            117,734Deferred
                income taxes and tax credits, net
            
            
            (11,562
            )
            
            (2,877
            )Net
                unrealized loss (gain) on derivative instruments
            
            
            825
            
            
            (82
            )Amortization
                of gas pipeline capacity assignment
            
            
            (5,267
            )
            
            --Non-cash
                return on regulatory assets
            
            
            4,153
            
            
            --Cash
                collateral (paid) received from energy suppliers
            
            
            (19,950
            )
            
            2,950Increase
                (decrease) in residential exchange program
            
            
            (7,529
            )
            
            4,377Chelan
                PUD contract initiation prepayment
            
            
            (89,000
            )
            
            --Other
            
            
            20,245
            
            
            13,951Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            206,759
            
            
            1,721Materials
                and supplies
            
            
            (3,146
            )
            
            (1,579
            )Fuel
                and gas inventory
            
            
            3,420
            
            
            776Prepayments
                and other
            
            
            (1,785
            )
            
            (11,177
            )Purchased
                gas adjustment receivable
            
            
            (5,638
            )
            
            (13,474
            )Accounts
                payable
            
            
            (165,884
            )
            
            (79,941
            )Taxes
                payable
            
            
            (53,214
            )
            
            17,269Tenaska
                disallowance reserve
            
            
            --
            
            
            (3,156
            )Accrued
                expenses and other
            
            
            7,479
            
            
            (4,811
            )Net
                cash provided by operating activities
            
            
            112,274
            
            
            126,029Investing
                activities:Construction
                expenditures - excluding equity AFUDC
            
            
            (306,387
            )
            
            (212,054
            )Energy
                efficiency expenditures
            
            
            (13,846
            )
            
            (15,611
            )Restricted
                cash
            
            
            (3
            )
            
            527Refundable
                cash received for customer construction projects
            
            
            7,739
            
            
            6,137Other
            
            
            3,466
            
            
            18,507Net
                cash used by investing activities
            
            
            (309,031
            )
            
            (202,494
            )Financing
                activities:Change
                in short-term debt, net
            
            
            168,099
            
            
            159,623Dividends
                paid
            
            
            (57,411
            )
            
            (45,039
            )Investment
                from Puget Energy
            
            
            62,986
            
            
            2,425Issuance
                of bonds and notes
            
            
            250,000
            
            
            250,000Redemption
                of bonds and notes
            
            
            (46,000
            )
            
            (200,000
            )Redemption
                of trust preferred stock
            
            
            (200,000
            )
            
            (42,500
            )Settlement
                of cash flow hedge interest rate derivative
            
            
            21,323
            
            
            (35,323
            )Issuance
                and redemption cost of bonds and other
            
            
            (2,598
            )
            
            (9,060
            )Net
                cash provided by financing activities
            
            
            196,399
            
            
            80,126Net
                increase (decrease) in cash
            
            
            (358
            )
            
            3,661Cash
                at beginning of year
            
            
            16,709
            
            
            12,955Cash
                at end of period
            
            $
            16,351
            
            $
            16,616Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            88,958
            
            $
            85,581Income
                taxes
            
            
            77,346
            
            
            32,682


*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 a holding company that owns Puget Sound Energy (PSE) and until May
      7,
      2006, InfrastruX. PSE is a public utility incorporated in the State of
      Washington that furnishes electric and gas services in a territory covering
      6,000 square miles, primarily in the Puget Sound region.


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 owned a 90.9% interest in InfrastruX until it was
      sold
      on May 7, 2006. The results of PSE and InfrastruX are presented on a
      consolidated basis. The financial position and results of operations for
      InfrastruX are presented as discontinued operations. InfrastruX is a
      non-regulated utility construction service 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. 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,
      2005. With the treatment of InfrastruX as discontinued operations, Puget Energy
      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 and Corporate Guarantees**(Puget
                Energy Only)





On
      May 7,
      2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P.
      (Tenaska) for $275 million before taking into account cash on hand at May 7,
      2006 of $11.4 million for a net sale price of $263.6 million. After repayment
      of
      debt, adjustments for working capital, transaction costs and distributions
      to
      minority interests, Puget Energy received after-tax cash proceeds of
      approximately $95.9 million for its 90.9% interest in InfrastruX in the second
      quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the
      three months ended June 30, 2006. Puget Energy accounted for InfrastruX as
      a
      discontinued operation under SFAS No. 144, “Accounting for the Impairment or
      Disposal of Long-Lived Assets” in 2005 and 2006.


Under
      the
      terms of the sale agreement, Puget Energy is obligated for certain
      representations and warranties made by InfrastruX concerning its business.
      Puget
      Energy obtained a representation and warranty insurance policy and deposited
      $3.7 million into an escrow account to serve as retention under the policy.
      As
      of June 30, 2006, long-term restricted cash in the amount of $3.7 million is
      included in the accompanying balance sheets; that amount represents management’s
      estimate of the aggregate fair value of the amount potentially payable under
      those representations and warranties and is Puget Energy’s maximum exposure. The
      obligation expires May 7, 2008. Should Tenaska make any claims against Puget
      Energy, payment for the claims will be made from the escrow account, and total
      payments are limited to $3.7 million. Puget Energy also agreed to indemnify
      Tenaska for certain potential future losses related to one of InfrastruX’s
      subsidiary companies. Under the indemnity agreement, Puget Energy is liable
      for
      certain costs with the maximum amount of loss not to exceed $15.0 million.
      As of
      June 30, 2006, a liability in the amount of $5.0 million is included in the
      accompanying balance sheets; that amount represents Puget Energy’s estimate of
      the fair value of the amount potentially payable using a probability-weighted
      approach to a range of future cash flows. The obligation expires May 7, 2011.
      Tenaska and Puget Energy have also negotiated the terms of an environmental
      guaranty as part of the sale agreement. Under the terms of the agreement,
      Tenaska will be responsible for the first $0.1 million of environmental claims,
      Tenaska and Puget Energy will share the next $6.4 million equally and Puget
      Energy will be responsible for the next $3.5 million. Based on a review of
      a
      third-party environmental report, Puget Energy believes it will not have a
      future loss in connection with the environmental guarantee.


For
      the
      three and six months ended June 30, 2006, Puget Energy reported InfrastruX
      related income from discontinued operations (net of taxes and minority
      interest), including gain on sale, of $33.0 million and $51.9 million,
      respectively, compared to $1.9 million and $0.9 million (net of taxes and
      minority interest) for the three and six months ended June 30, 2005. Puget
      Energy’s income from discontinued operations for the six months ended June 30,
      2006 includes $7.3 million related to the reversal of a carrying value
      adjustment recorded in 2005.





Three
                Months Ended
              June
                30,
            
            Six
                Months Ended
              June
                30,(Dollars
                in thousands)
            
            2006
            
            2005
            
            2006
            
            2005Revenues
            
            $
            46,504
            
            $
            97,307
            
            $
            138,573
            
            $
            174,998Operating
                expenses (including interest expense)
            
            
            (40,735
            )
            
            (85,544
            )
            
            (128,634
            )
            
            (163,260
            )Pre-tax
                income
            
            
            5,769
            
            
            11,763
            
            
            9,939
            
            
            11,738Income
                tax expense
            
            
            (2,260
            )
            
            (4,028
            )
            
            (3,516
            )
            
            (3,903
            )Puget
                Energy carrying value adjustment of InfrastruX
            
            
            --
            
            
            (5,110
            )
            
            7,269
            
            
            (5,110
            )Puget
                Energy cost of sale related to InfrastruX, net of tax
            
            
            --
            
            
            --
            
            
            (937
            )
            
            (1,116
            )Puget
                Energy deferred tax basis adjustment of InfrastruX
            
            
            --
            
            
            --
            
            
            9,966
            
            
            --Gain
                on sale, net of tax
            
            
            29,764
            
            
            --
            
            
            29,764
            
            
            --Minority
                interest in income of discontinued operations
            
            
            (319
            )
            
            (697
            )
            
            (584
            )
            
            (700
            )Income
                from discontinued operations
            
            $
            32,954
            
            $
            1,928
            
            $
            51,901
            
            $
            909





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 $1.9 million ($1.3 million after-tax)
      and $4.7 million ($2.9 million after-tax) lower depreciation and amortization
      expense than otherwise would have been recorded as continuing operations for
      the
      three months ended June 30, 2006 and 2005, respectively. Depreciation and
      amortization was $6.7 million ($4.3 million after-tax) and $7.3 million ($4.5
      million after-tax) lower than otherwise would have been recorded as continuing
      operations for the six months ended June 30, 2006 and 2005,
      respectively.


Puget
      Energy’s balance sheet at June 30, 2006 does not include InfrastruX assets and
      liabilities as a result of the disposition in May 2006. InfrastruX’s summarized
      assets and liabilities, including intercompany balances eliminated in
      consolidation, at December 31, 2005 were:


(Dollars
                in thousands)
            
            December
                31,
              2005Assets:Cash
            
            $
            6,187Accounts
                receivable
            
            
            78,842Other
                current assets
            
            
            22,405Total
                current assets
            
            
            107,434Goodwill
            
            
            43,886Intangibles
            
            
            14,443Non-utility
                property and other
            
            
            108,784Total
                long-term assets
            
            
            167,113Total
                assets
            
            $
            274,547


Liabilities:Accounts
                payable
            
            $
            9,178Short-term
                debt
            
            
            3,809Current
                maturities of long-term debt
            
            
            6,477Other
                current liabilities
            
            
            36,327Total
                current liabilities
            
            
            55,791Deferred
                income taxes
            
            
            24,645Long-term
                debt
            
            
            120,013Other
                deferred credits
            
            
            16,986Total
                long-term liabilities
            
            
            161,644Total
                liabilities
            
            $
            217,435








**(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 115,907,000 and 115,817,000 for the three
      and six months ended June 30, 2006, respectively, and 100,157,000 and
      100,058,000 for the three and six months ended June 30, 2005, respectively.


Puget
      Energy’s diluted earnings per common share have been computed based on weighted
      average common shares outstanding of 116,405,000 and 116,266,000 for the three
      and six months ended June 30, 2006, respectively, and 100,690,000 and
      100,590,000 for the three and six months ended June 30, 2005, 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.
      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 these contracts
      qualify for the normal purchase normal sale (NPNS) exception to derivative
      accounting rules if they meet certain criteria. NPNS applies if the counterparty
      is creditworthy and has energy resources within the western region to allow
      for
      physical delivery of the energy, and if the transaction is within PSE’s
      forecasted load requirements. Those contracts that do not meet NPNS 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 Power
      Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA)
      Mechanism.


The
      nature of serving regulated electric customers with its wholesale 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 portfolio management function
      monitors and manages these risks using analytical models and tools. 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
      Company’s energy portfolio management staff develops hedging strategies for the
      Company’s energy supply portfolio. The first priority is to obtain reliable
      supply for delivery to the Company’s retail customers. The second priority is to
      protect against unwanted risk exposure. The third priority is to optimize excess
      capacity or flexibility within the energy portfolio.


At
      June
      30, 2006, the Company was subject to a range of netting provisions, including
      both stand alone agreements and the provisions associated with the Western
      Systems Power Pool agreement, of which many energy suppliers in the western
      United States are a part.


During
      the three months ended June 30, 2006, the Company recorded an increase in
      earnings for the change in the market value of derivative instruments not
      meeting NPNS nor cash flow hedge criteria of approximately $0.2 million compared
      to an increase in earnings of approximately $0.6 million for the three months
      ended June 30, 2005. At June 30, 2006, the Company had a net unrealized gain
      recorded in other comprehensive income of $15.4 million after-tax related to
      energy and financial contracts which meet the criteria for designation as cash
      flow hedges under SFAS No. 133. At June 30, 2006, PSE had a net short-term
      liability of $0.8 million related to non-cash flow hedges; as well as a net
      short-term asset of $7.5 million and a net long-term asset of $16.2 million
      related to energy contracts designated as cash flow hedges that represent
      forward financial purchases of gas supply for electric generation from 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.


During
      the six months ended June 30, 2006, 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 $0.8 million compared to an increase in
      earnings of approximately $0.1 million for the six months ended June 30,
      2005.


At
      June
      30, 2006, the Company also has a net short-term liability of approximately
      $32.3
      million related to the cash flow hedge of gas contracts to serve natural gas
      customers. All mark-to-market adjustments relating to the natural gas business
      have been reclassified to a deferred account in accordance with SFAS No. 71
      due
      to the PGA mechanism. The PGA mechanism passes increases and decreases in the
      cost of natural gas supply to customers. 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.


In
      the
      second quarter 2006, the Company settled its two forward starting interest
      rate
      swap contracts originating in May 2005. The purpose of the forward starting
      swap
      contracts was to hedge interest rate volatility for a debt offering of $200
      million that was completed on June 30, 2006. Since interest rates increased
      related to the hedged debt from the date of issuance of the forward starting
      swap contracts, PSE received $21.3 million from the counterparties when the
      contracts were settled. The forward starting swap contracts were designated
      and
      documented under SFAS No. 133 criteria as cash flow hedges, with all changes
      in
      market value for each reporting period presented net of tax in other
      comprehensive income. In the second quarter 2006, the settlement of these
      instruments resulted in a gain of $13.9 million after-tax, which was recorded
      in
      other comprehensive income. In accordance with SFAS No. 133, the gain will
      be
      amortized out of other comprehensive income to current earnings as a decrease
      to
      interest expense over the life of the new debt issued at an annual amount of
      approximately $0.7 million pre-tax. The ending balance in other comprehensive
      income related to the forward starting swaps and previously settled treasury
      lock contracts at June 30, 2006 was a loss of $8.3 million after-tax and
      accumulated amortization.








**(5)**
            **Stock
                Compensation**





Prior
      to
      2006, the Company had various stock-based compensation plans which 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 applied SFAS No. 123 accounting to stock
      compensation awards granted subsequent to January 1, 2003, while grants prior
      to
      2003 continued to be accounted for using the intrinsic value method of APB
      No.
      25. Effective January 1, 2006, the Company adopted the fair value recognition
      provisions of SFAS No. 123R, “Share-Based Payment,” using the
      modified-prospective transition method. Under that transition method,
      compensation cost recognized in 2006 includes: (a) compensation cost for all
      share-based payments granted prior to, but not yet vested as of January 1,
      2006,
      based on the grant date fair value estimated in accordance with the original
      provisions of SFAS No. 123, and (b) compensation cost for all share-based
      payments granted subsequent to January 1, 2006, based on the grant-date fair
      value estimated in accordance with the provisions of SFAS No. 123R. Results
      for
      prior periods have not been restated, as provided for under the
      modified-prospective method.


The
      adoption of SFAS No. 123R resulted in a cumulative benefit from an accounting
      change of $0.1 million, net of tax, for the quarter ended March 31, 2006. The
      cumulative effect adjustment is the result of the inclusion of estimated
      forfeitures occurring before award vesting dates in the computation of
      compensation expense for unvested awards.


As
      a
      result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before
      income taxes and net income from continuing operations for the six months ended
      June 30, 2006, is $0.1 million and $0.1 million higher, respectively, than
      if it
      had continued to account for share-based compensation under SFAS No. 123 due
      to
      the inclusion of estimated forfeitures in compensation cost. There is no
      difference between basic and diluted earnings per share for income from
      continuing operations for the three and six months ended June 30, 2006 under
      SFAS No. 123R as compared to earlier methods.


Had
      Puget
      Energy applied 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:





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





The
      Company’s Long-Term Incentive Plan (LTI Plan), established in 1995 after
      approval by shareholders, encompasses many of the awards granted to employees.
      The plan was amended and restated in 2005, and approved by shareholders. The
      LTI
      Plan applies to officers and key employees of the Company and awards granted
      under this plan include stock awards, performance awards or other stock-based
      awards as defined by the plan. Any shares awarded are either purchased on the
      open market or are a new issuance. The 2006 cycle included a grant of restricted
      stock, which was added to reduce the volatility of the plan. Beginning with
      the
      2004 share grants, plan participants meeting the Company’s stock ownership
      guidelines can elect to be paid up to 50% of the share award in cash. The
      maximum number of shares that may be purchased or issued as new shares for
      the
      LTI Plan is 4,200,000.





**Performance
      Share Grants**


The
      Company generally awards performance share grants annually under the LTI Plan.
      These are granted to key employees and vest at the end of three years for grants
      made in 2004, 2005 and 2006. Grants made prior to 2004 vest in four years.
      The
      number of shares awarded and expense recorded depends on Puget Energy’s
      performance as compared to other companies and service quality indices for
      customer service. Compensation expense related to performance share grants
      was
      $(0.6) million and $(1.4) million for the three months ended June 30, 2006
      and
      2005, respectively, and $1.3 million and $2.0 million for the six months ended
      June 30, 2006 and 2005, respectively. The weighted average fair value per share
      of the performance awards granted for the 2006, 2005, 2004 and 2003 cycles
      was
      $21.40, $21.19, $19.70, and $16.93, respectively. There were a total of 151,815
      performance awards granted for the 2006 cycle of which the company estimates
      a
      forfeiture rate of 10.1%, or 15,333 awards based on historical forfeitures.
      There were a total of 251,680 performance awards granted for the 2005 cycle
      of
      which the Company estimated a forfeiture rate of 11.8%, or 29,698, awards based
      on historical forfeitures. As of June 30, 2006, there were four active grant
      cycles for a total of 859,063 grants outstanding. As of December 31, 2005,
      there
      were four active grant cycles for a total of 907,983 share grants outstanding.
      As of June 30, 2006, there was $4.3 million of total unrecognized compensation
      cost, net of forfeitures, related to nonvested performance share grants. That
      cost is expected to be recognized over a weighted-average period of two years.
      During the three and six months ended June 30, 2006, 4,880 and 47,772
      performance shares, respectively, were forfeited. No performance shares vested
      during the three or six months ended June 30, 2006 and 2005. The fair value
      of
      the 2006 performance share grants takes into consideration the historical
      performance of the performance share grants and prospective analysis using
      the
      Capital Asset Pricing Model and expected EPS growth rates. Shares granted prior
      to 2006 were valued using the Black-Scholes option pricing model.





**Measurement
      of Performance Share Grants**


The
      portion of the performance share grants that can be paid in cash is classified
      and accounted for as a liability under SFAS No. 123R. As a result, the expense
      recognized over the performance period for a portion of the performance share
      grants will equal the fair value (i.e. cash value) of the award as of the last
      day of the performance period times the number of awards that are earned.
      Furthermore, SFAS No. 123R requires that the quarterly expense recognized during
      the performance period is based on the fair value of the performance share
      grants as of the end of the most recent quarter. Prior to the end of the
      performance period, compensation costs for the liability portion of performance
      share grants are based on the awards’ most recent quarterly fair values and the
      number of months of service rendered during the performance period. The
      fair
      value of the performance share grants is based on the closing price of the
      Company’s common stock on the date of measurement.





**Stock
      Options**


In
      2002,
      Puget Energy’s Board of Directors granted 40,000 stock options under the LTI
      Plan and an additional 260,000 options outside of the LTI Plan (for a total
      of
      300,000 non-qualified stock options) to the Chairman, President and Chief
      Executive Officer. These options can be exercised at the grant date market
      price
      of $22.51 per share and vest annually over four and five years although the
      options would become fully vested upon a change of control of the Company or
      an
      employment termination without cause. The options expire 10 years from the
      grant
      date and have a remaining contractual term of approximately 6 years. All 300,000
      options remained outstanding at June 30, 2006, with 270,000 options exercisable.
      There is no aggregate intrinsic value of options vested (or expected to vest)
      or
      options currently exercisable at June 30, 2006. At June 30, 2005, 202,500
      options were exercisable. The fair value of the options at the grant date was
      $3.33 per share. Compensation expense related to stock options was immaterial
      to
      the financial statements for the three and six months ended June 30, 2006.
      As of
      June 30, 2006, there was an immaterial amount of total unrecognized compensation
      cost related to nonvested stock options which will be recognized in 2006. The
      total fair value of stock options vested during the six months ended June 30,
      2006 and 2005, was $0.2 million and $0.2 million, respectively. The fair value
      of the stock option award was estimated on the date of grant using the
      Black-Scholes option valuation model.





**Restricted
      Stock**


In
      2006,
      2005, 2004 and 2003, the Company granted 107,181 shares, 50,000 shares, 40,000
      shares and 11,000 shares, respectively, of restricted stock under the LTI Plan
      to be purchased on the open market or as a new issuance. During the six months
      ended June 30, 2006, 107,181 shares of restricted stock were granted as part
      of
      the 2006 LTIP cycle. The shares vest 15% on January 1, 2007, 25% vest on January
      1, 2008, and the remaining 60% vest on January 1, 2009 based upon a performance
      and service condition. Under the 2005 grant, 40,000 shares vest in one
      installment on the date of the 2008 Annual Shareholders’ Meeting based upon
      performance criteria and the remaining 10,000 shares vest equally over three
      years. The 2004 grant vests 8,000 shares in three years and the remaining 32,000
      shares in four years. For the 2003 grant, 1,000 vested in 2003 with the
      remaining shares vesting evenly over the following five years. At June 30,
      2006,
      there were 212,598 total shares of nonvested restricted stock and the weighted
      average grant date fair value of these shares was $22.02. Compensation expense
      related to the restricted shares, including the restricted shares granted as
      part of the 2006 LTIP cycle, was $0.5 million and $0.2 million for the three
      months ended June 30, 2006 and 2005, respectively, and $1.0 million and $0.3
      million for the six months ended June 30, 2006 and 2005, respectively. Dividends
      are paid on all outstanding shares of restricted stock and are accounted for
      as
      a Puget Energy common stock dividend, not as compensation expense. The weighted
      average grant date fair value for all outstanding shares of restricted stock
      granted in 2006 and 2005 was $21.32 and $21.86, respectively. As of June 30,
      2006, there was $2.8 million of total unrecognized compensation cost related
      to
      nonvested restricted stock. That cost is expected to be recognized over a
      weighted-average period of 2.1 years. No restricted stock vested and 583 shares
      were forfeited during the three and six months ended June 30, 2006. No
      restricted stock vested or was forfeited during the three and six months ended
      June 30, 2005. The fair value of the restricted stock is based on the closing
      price of the Company’s common stock on the date of grant.





**Restricted
      Stock Units**


In
      2004,
      the Company granted 10,000 restricted stock units outside of the LTI Plan but
      subject to the terms and conditions of the plan. The units vest 2,000 shares
      in
      three years and the remaining 8,000 shares in four years. At June 30, 2006,
      there were 3,573 total shares of nonvested restricted stock units and the
      weighted average fair value of these units was $21.48. There were no restricted
      stock units granted or forfeited during the three and six months ended June
      30,
      2006 and 2005. There were 643 restricted stock units accrued during the three
      months ended June 30, 2006 and 1,285 restricted stock units accrued during
      the
      six months ended June 30, 2006. The restricted stock units will be settled
      in
      cash when they become vested at the end of each cycle. Dividends are paid on
      the
      outstanding stock units and are accounted for as compensation expense.
      Compensation expense related to the restricted stock units agreement was
      immaterial for the three and six months ended June 30, 2006 and 2005. The
      weighted average grant date fair value for the restricted stock units was
      $23.55. As of June 30, 2006, there was $0.1 million of total unrecognized
      compensation cost related to nonvested restricted stock units. That cost is
      expected to be recognized over a weighted-average period of 1.8 years. The
      fair
      value of the restricted stock units is based on the closing price of the
      Company’s common stock at each reporting period.





**Retirement
      Equivalent Stock**


The
      Company has a retirement equivalent stock agreement under which in lieu of
      participating in the Company’s executive supplemental retirement plan, the
      Chairman, President and Chief Executive Officer is granted performance-based
      stock equivalents in January of each year, which are deferred under the
      Company’s deferred compensation plan. In 2006, 2005, 2004 and 2003, the Company
      awarded 8,218, 6,063, 6,469 and 4,319, shares, respectively, which vest over
      a
      period from January 1, 2002 to May 2008 at 15% per year for the first six years
      and the remaining 10% in the seventh year. At June 30, 2006 there were 6,744
      total shares of nonvested retirement equivalent stock units and the weighted
      average grant date fair value of these units was $22.71. During the six months
      ended June 30, 2006, 8,218 retirement equivalent stock units were granted.
      Dividends are paid on the stock equivalents accumulated in the deferred
      compensation account in the form of Puget Energy common stock, which is added
      to
      the deferred compensation account. Compensation expense related to the
      retirement equivalent stock agreement was immaterial to the financial
      statements. The weighted average grant date fair value for the retirement
      equivalent stock was $20.42, $24.70, $23.77 and $22.05 for 2006, 2005, 2004
      and
      2003, respectively. As of June 30, 2006, there was an immaterial amount of
      unrecognized compensation cost related to nonvested retirement equivalent stock
      units. That cost is expected to be recognized over a weighted-average period
      of
      1.9 years. There were 778 retirement equivalent stock units that vested during
      the three months ended June 30, 2006 and 6,487 retirement equivalent stock
      units
      that vested during the six months ended June 30, 2006. No retirement equivalent
      stock units were forfeited during the quarter ended June 30, 2006. The fair
      value of the restricted stock is based on the closing price of the Company’s
      common stock on the date of grant.





**Employee
      Stock Purchase Plan**


The
      Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open
      to
      all employees. Offerings occur at six-month intervals at the end of which the
      participating employees receive shares for 85% of the lower of the stock’s fair
      market price at the beginning or the end of the six-month period. A maximum
      of
      500,000 shares may be sold to employees under the plan through May 2007. At
      June
      30, 2006, 117,393 shares could still be sold to employees under the plan. Under
      the SFAS No. 123 accounting that the Company adopted in 2003 and under SFAS
      No.
      123R, ESPP is considered to be compensation expense and the amount is immaterial
      to the financial statements. New shares issued for the Employee Stock Purchase
      Plan were 31,421 and 23,048 for the six months ended June 30, 2006 and 2005,
      respectively. Dividends are not paid on ESPP shares until they are purchased
      by
      employees and thus are accounted for as dividends, not compensation expense.





**Non-Employee
      Director Stock Plan**


The
      Company has a director stock plan approved by shareholders in 1997 and effective
      beginning in 1998, for all non-employee directors of Puget Energy and PSE.
      The
      plan was amended and restated in 2005 and approved by shareholders in 2005.
      Under the plan, which has a term through December 31, 2015, non-employee
      directors receive a portion of their quarterly retainer fees in Puget Energy
      stock except that 100% of quarterly retainers are paid in Puget Energy stock
      until the director holds a number of shares equal in value to two years of
      their
      retainer fees. Directors may optionally receive their entire retainer in Puget
      Energy stock. The compensation expense related to the director stock plan was
      $0.1 million and $0.1 million for the three months ended June 30, 2006 and
      2005,
      respectively, and $0.2 million and $0.2 million for the six months ended June
      30, 2006, respectively. The Company issues new shares or purchases stock for
      this plan on the open market up to a maximum of 350,000 shares. As of June
      30,
      2006, 32,086 shares had been issued or purchased for the director stock plan
      and
      83,361 deferred, for a total of 115,447 shares. As of June 30, 2005, the number
      of shares that had been purchased for the director stock plan was 21,033 and
      70,425 deferred, for a total of 91,458 shares.





**Option
      Model Assumptions**


The
      Company used the Black-Scholes option pricing model to determine the fair value
      of certain stock-based awards to employees. The following assumptions were
      used
      for awards outstanding in 2006 and 2005.





**Stock
                issuance cycle**
            
            2006
            
            2005
            
            2004
            
            2003
            
            2002Stock
                optionsRisk-free
                interest rate
            
            
            *
            
            
            *
            
            
            *
            
            
            *
            
            
            4.32
            %Expected
                lives-years
            
            
            *
            
            
            *
            
            
            *
            
            
            *
            
            
            5.0Expected
                stock volatility
            
            
            *
            
            
            *
            
            
            *
            
            
            *
            
            
            22.82
            %Dividend
                yield
            
            
            *
            
            
            *
            
            
            *
            
            
            *
            
            
            5.00
            %Performance
                awardsRisk-free
                interest rate
            
            
            **
            
            
            2.50
            %
            
            2.59
            %
            
            2.35
            %
            
            *Expected
                lives-years
            
            
            3.0
            
            
            3.0
            
            
            3.0
            
            
            4.0
            
            
            *Expected
                stock volatility
            
            
            **
            
            
            15.10
            %
            
            22.24
            %
            
            23.85
            %
            
            *Dividend
                yield
            
            
            *
            
            
            4.18
            %
            
            4.45
            %
            
            4.86
            %
            
            *Employee
                Stock Purchase PlanRisk-free
                interest rate
            
            
            4.07
            %
            
            2.68
            %
            
            1.28
            %
            
            1.07
            %
            
            *Expected
                lives-years
            
            
            0.5
            
            
            0.5
            
            
            0.5
            
            
            0.5
            
            
            *Expected
                stock volatility
            
            
            13.03
            %
            
            13.98
            %
            
            9.89
            %
            
            19.47
            %
            
            *Dividend
                yield
            
            
            4.77
            %
            
            4.17
            %
            
            4.42
            %
            
            4.39
            %
            
            *





***
            
            *Not
                applicable*****
            
            *Fair
                value is determined by end of period market
                value.*





The
      expected lives of the securities represents the estimated period of time until
      exercise and is based on the vesting period of the award and the historical
      exercise experience of similar awards. All participants were assumed to have
      similar exercise behavior. Expected volatility is based on historical volatility
      over the approximate expected term of the option.








**(6)**
            **Retirement
                Benefits**





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





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2006
            
            2005
            
            2006
            
            2005Service
                cost
            
            $
            3,061
            
            $
            2,761
            
            $
            85
            
            $
            69Interest
                cost
            
            
            6,163
            
            
            5,979
            
            
            358
            
            
            279Expected
                return on plan assets
            
            
            (9,434
            )
            
            (9,451
            )
            
            (182
            )
            
            (220
            )Amortization
                of prior service cost
            
            
            586
            
            
            717
            
            
            134
            
            
            117Recognized
                net actuarial (gain) loss
            
            
            1,246
            
            
            910
            
            
            (127
            )
            
            (295
            )Amortization
                of transition (asset) obligation
            
            
            --
            
            
            (41
            )
            
            105
            
            
            104Net
                periodic benefit cost
            
            $
            1,622
            
            $
            875
            
            $
            373
            
            $
            54








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





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2006
            
            2005
            
            2006
            
            2005Service
                cost
            
            $
            6,122
            
            $
            5,775
            
            $
            171
            
            $
            152Interest
                cost
            
            
            12,329
            
            
            11,928
            
            
            716
            
            
            698Expected
                return on plan assets
            
            
            (18,869
            )
            
            (18,964
            )
            
            (363
            )
            
            (439
            )Amortization
                of prior service cost
            
            
            1,171
            
            
            1,433
            
            
            267
            
            
            233Recognized
                net actuarial (gain) loss
            
            
            2,499
            
            
            1,677
            
            
            (254
            )
            
            (320
            )Amortization
                of transition (asset) obligation
            
            
            --
            
            
            (82
            )
            
            209
            
            
            209Net
                periodic benefit cost
            
            $
            3,252
            
            $
            1,767
            
            $
            746
            
            $
            533





The
      Company previously disclosed in its financial statements for the year ended
      December 31, 2005 that it expected contributions by the Company to fund the
      pension and other benefits plans for the year ended December 31, 2006 to be
      $2.1
      million and $1.0 million, respectively. During the three and six months ended
      June 30, 2006, the actual cash contributions to the pension plans were $1.6
      million and $2.1 million, respectively. Based on this activity, the Company
      anticipates contributing an additional $1.0 million to the Company’s pension
      plan in 2006. The full amount of the pension plan funding for 2006 is for the
      Company’s non-qualified supplemental retirement plan.


During
      the three and six months ended June 30, 2006, actual other post-retirement
      medical benefit plan contributions were $0.2 million and $0.6 million,
      respectively, and the Company expects to make additional contributions of $0.1
      million for a total of $0.7 in 2006.


On
      March
      31, 2006, Financial Accounting Standards Board (FASB) issued a Proposed
      Statement of Financial Accounting Standard, “Employers’ Accounting for Defined
      Benefit Pension and Other Postretirement Plans.” The
      proposed statement would require the Company to report the overfunded or
      underfunded status of defined benefit postretirement plans in the Company’s
      consolidated balance sheet. An overfunded status would result in the recognition
      of an asset and an underfunded status would result in the recognition of a
      liability. This amount is to be measured as the difference between the fair
      value of plan assets and the projected benefit obligation. At December 31,
      2005,
      the combined fair value of plan assets and projected benefit obligation for
      the
      Company’s defined benefit pension and the retiree medical and life plans were
      $481 million and $439 million, respectively. Any adjustment required to
      recognize an asset or liability upon adoption of the standard, as currently
      proposed, would result in a charge or benefit to Accumulated Other Comprehensive
      Income. The Company is currently evaluating what impact the application of
      the
      proposed standard will have on its operations. FASB indicated that it expects
      to
      issue a final statement by September 2006 and that the statement would be
      effective for fiscal years ending after December 15, 2006, which will be the
      year ended December 31, 2006, for the Company. On July 12, 2006, FASB affirmed
      the effective date of the proposed standard for fiscal years ending after
      December 15, 2006.








**(7)**
            **Regulatory
                and Other**





On
      June
      28, 2006, the Washington Commission approved a 5.9%, or $45.3 million, power
      cost only rate case (PCORC) increase in electric rates for the period July
      1,
      2006 through December 31, 2006. The increase allows PSE to recover higher
      projected costs of power caused primarily by higher market prices for natural
      gas used as fuel for electric generators. The rate increase will not
      appreciatively impact PSE’s income. The annualized basis of the PCORC rate
      increase when applied to the general rate case test year is $96.1 million.
      Primarily as a result of this order, PSE reduced its pending electric general
      tariff increase from $140.9 million to $42.9 million, or 2.5%, on an annualized
      basis. Additionally,
      PSE has requested approval of a new tariff in its original general rate case
      filing to recover increases in electric transmission and distribution
      depreciation costs incurred between general rate cases of $7.9 million. The
      resolution of the general rate is expected by the end of
      2006.


On
        July
        10, 2006, PSE reduced its gas general rate increase request filed on February
        15, 2006 from $40.4 million to $39.2 million, or 4.2%, on an annual basis
        with
        the Washington Commission. PSE also has requested approval of a new depreciation
        tracker in its original gas general rate case filing to recover increase
        in gas
        distribution depreciation costs incurred between general rate cases of $10.9
        million. In addition, a gas decoupling mechanism was requested and does not
        have
        an impact on the current rate increase; however, it is designed to stabilize
        revenue changes due to load variations between regulatory filings. The
        resolution of the general rate case is expected by the end of
        2006.


PSE
      leases the Whitehorn power generating facility under a noncancelable operating
      lease expiring in February 2009 and received notice of alleged default for
      the
      non-performance of certain covenants from the lessor. PSE immediately
      investigated the matter and provided notice that it disputed the allegations.
      The facility consists of two dual-fuel combustion turbine engines with 147
      MW
      net capacity, which are operated for peak load conditions, emergencies, and
      to
      maintain reliability of service during periods of adverse water or weather
      conditions. The notice of default included the threat of eviction and recovery
      of all damages should PSE fail to cure the alleged default and assign
      governmental permits and licenses associated with the facility to the lessor.
      PSE subsequently agreed to reimburse the lessor for its legal costs and expenses
      incurred in connection with the default and the lessor has four times agreed
      to
      suspend the notice of default for a one-month period to allow the parties to
      further investigate the matter and negotiate possible solutions. The current
      suspension period runs through August 31, 2006. PSE is seeking resolution of
      the
      matter, which may include the modification of the lease or the purchase of
      the
      project. If PSE cannot negotiate reasonable terms to settle the dispute, the
      amount of the ultimate impact upon the Company, if any, cannot be predicted
      at
      this time.


On
      June
      30, 2006, PSE redeemed for $200 million all of its outstanding shares of the
      8.40% 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) at $25 par value per
      share
      plus accrued interest to the redemption date.


On
      June
      30, 2006, PSE completed the issuance of $250 million of senior secured notes
      at
      a rate of 6.724%, which are due on June 15, 2036. The net proceeds from the
      issuance of the senior notes of approximately $247.8 million were used to redeem
      $200 million of 8.40% Capital Trust Preferred Securities, which were redeemed
      at
      par on June 30, 2006, and to repay a portion of PSE’s short-term debt. The
      short-term debt was incurred to repay $46 million of 8.06% senior notes that
      matured June 19, 2006. The yield to maturity of the $250 million senior secured
      notes was 6.17% after the settlement of two forward starting swap interest
      rate
      contracts.


PSE
      has
      contracted to purchase a portion of the output from the Rocky Reach and Rock
      Island hydroelectric generating facilities located on the mid-Columbia River
      owned by Chelan County PUD (Chelan). On February 3, 2006, PSE and Chelan entered
      into a new Power Sales Agreement and a related Transmission Agreement for 25%
      of
      the output of the Rocky Reach and Rock Island facilities in exchange for PSE
      paying 25% of the operating costs of the facilities. PSE’s share of the output
      represents approximately 487 MW of capacity and 243 average MW of energy. The
      agreements terminate in 2031 and provide that PSE will begin to receive power
      upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky
      Reach and Rock Island output (expiring in 2011 and 2012, respectively). FERC
      granted approval of the agreement on March 28, 2006, and PSE made a
      non-refundable capacity reservation payment of $89 million on April 26, 2006
      to
      Chelan under the terms of the agreement. PSE believes that the new agreements
      with Chelan will lower its overall power costs during the 20-year contract
      period compared to other available alternatives, secure critical operational
      flexibility, reduce PSE’s projected long-term energy and capacity deficit and
      continue PSE’s long-term relationship with the public utility district. PSE
      filed for an accounting order from the Washington Commission in April 2006
      for
      approval to recognize such payments as a regulatory asset with accrual of
      carrying costs at the Company’s net of tax rate of return. On April 26, 2006,
      the Washington Commission approved the accounting petition to defer the capacity
      reserve payment plus carrying costs on a temporary basis until resolution of
      PSE’s electric general rate case later this year.


At
      June
      30, 2006, PSE had a net receivable totaling $21.2 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. On January 26, 2006,
      FERC
      issued its order on Cost Filings accepting PSE’s cost filing subject to certain
      modifications, which appear to have the effect of reducing PSE’s Portfolio Claim
      substantially. However, the Company does not believe the claim will be reduced
      below the $21.2 million receivable. PSE does not agree with all of FERC’s
      rulings and sought rehearing. 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 $21.2 million (PSE’s net receivable balance) and $29.3 million,
      including interest, on its past due receivables as of June 30,
      2006.


In
      January 2003, 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 in accordance with FIN
      46R.


For
      the
      three purchase power agreements that may be considered variable interest
      entities under FIN 46R, PSE is required to buy all the generation from these
      plants, subject to displacement by PSE, at rates set forth in the purchase
      power
      agreements. If at any time the counterparties cannot deliver energy to PSE,
      PSE
      would have to buy energy in the wholesale market at prices which could be higher
      or lower than the purchase power agreement prices. PSE’s purchased electricity
      expense for the three months ended June 30, 2006 and 2005 for these three
      entities was $37.1 million and $41.6 million, respectively. PSE’s purchased
      electricity expense for the six months ended June 30, 2006 and 2005 for these
      three entities was $95.9 million and $113.5 million, respectively.








**(8)**
            **Litigation**





There
      are
      several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville
      Power Administration (BPA), in which the petitioners assert or may assert that
      BPA acted contrary to law or without authority in deciding to enter into, or
      in
      entering into or performing or implementing, a number of agreements, including
      the amended settlement agreement (and the May 2004 agreement) between BPA and
      PSE regarding the BPA Residential Purchase and Sale Program. BPA rates used
      in
      such agreements between BPA and PSE for determining the amounts of money to
      be
      paid to PSE by BPA under such agreements during the period October 1, 2001
      through September 30, 2006 have been confirmed, approved and allowed to go
      into
      effect by FERC. There are also several actions in the U.S. Ninth Circuit Court
      of Appeals against BPA, in which petitioners assert that BPA acted contrary
      to
      law in adopting or implementing the rates or rate adjustment clause upon which
      the benefits received or to be received from BPA during the October 1, 2001
      through September 30, 2006 period are based. The parties to these various
      actions presented oral arguments to the U.S. Ninth Circuit Court of Appeals
      in
      November 2005. A decision from the Court is anticipated in 2006. A number of
      parties have claimed that the BPA rates proposed or adopted in the BPA rate
      proceeding to develop BPA rates to be used in the agreements for determining
      the
      amounts of money to be paid to PSE by BPA during the period October 1, 2006
      through September 30, 2009 are contrary to law and that BPA acted contrary
      to
      law or without authority in deciding to enter into, or in entering into or
      performing or implementing such agreements. It is not clear what impact, if
      any,
      development or review of such rates, review of such agreements, and the above
      described U.S. Ninth Circuit Court of Appeals actions may have on
      PSE.








**(9)**
            **Related
                Party Transaction**





During
      the three-month period ended June 30, 2006, Puget Energy established the Puget
      Sound Energy Foundation (Foundation) with a $15.0 million contribution to the
      Foundation from a portion of the proceeds from the sale of InfrastruX. The
      contribution was recorded as other income (deduction) expense. The Foundation
      was established by Puget Energy as a not-for-profit organization whose results
      are not consolidated by Puget Energy.


On
      June
      1, 2006, PSE entered into a revolving credit facility with its parent, Puget
      Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE
      may borrow up to $30 million from Puget Energy, subject to approval. Under
      the
      terms of the Note, PSE pays interest on the outstanding borrowings based on
      the
      lowest of the weighted average interest rate of (a) PSE’s outstanding commercial
      paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or
      (c) PSE Funding receivable securitization facility interest rate which is the
      LIBOR rate plus a marginal rate. At June 30, 2006, the outstanding balance
      of
      Note was $26.5 million.








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





At
      its
      June 15, 2006 meeting, the Financial Accounting Standards Board’s (FASB)
      Emerging Issues Task Force (EITF) approved the issuance of EITF Issue No. 06-3
      “How Taxes Collected from Customers and Remitted to Governmental Authorities
      Should Be Presented in the Income Statement (That Is, Gross versus Net
      Presentation).” EITF No. 06-3 will require disclosure whether or not the taxes
      collected from customers and remitted to government authorities are reported
      on
      a gross (included in revenues and costs) or a net (excluded from revenues)
      basis. In addition, for any such taxes that are reported on a gross basis,
      a
      company should disclose the amounts of those taxes in interim and annual
      financial statements for each period for which an income statement is presented
      if those amounts are significant. The EITF concluded that these requirements
      should be applied to financial reports for interim and annual periods beginning
      after December 15, 2006, which will be the quarter ended March 31, 2007, for
      the
      Company. PSE collected Washington State excise taxes (which are a component
      of
      general retail rates) and municipal taxes of $40.6 million and $105.2 million
      for the three and six months ended June 30, 2006, respectively, and $37.3
      million and $90.9 million for the three and six months ended June 30, 2005,
      respectively. The Company’s policy is to report such taxes on a gross basis in
      operating revenues and taxes other than income taxes in the accompanying
      consolidated statements of income.


In
      July
      2006, FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in
      Income Taxes, an Interpretation of FASB Statement No. 109”, which clarifies the
      accounting for uncertainty in income taxes recognized in the financial
      statements in accordance with FASB Statement No. 109, “Accounting for Income
      Taxes.” FIN 48 provides guidance on recognition threshold and measurement
      attributed to a tax position taken or expected to be taken in a tax return.
      The
      tax positions should only be recognized when it is more likely than not, based
      on technical merits, that the position will be sustained upon examination by
      the
      taxing authority. FIN 48 is effective for fiscal years beginning after December
      15, 2006, which will be the quarter ended March 31, 2007. The Company is
      currently evaluating the provisions of FIN 48 to determine the potential impact,
      if any, the adoption will have on the Company’s financial statements.










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 subsidiary Puget Sound Energy (PSE), a regulated electric
      and gas utility company, and until May 7, 2006, InfrastruX. Puget Energy owned
      a
      90.9% interest in InfrastruX, a utility construction and services company,
      until
      it was sold to an affiliate of Tenaska Power Fund, L.P. on May 7, 2006 for
      $275
      million before taking into account cash on hand at may 7, 2006 of $11.4 million
      for a net sale price of $263.6 million. After repayment of debt, adjustments
      for
      working capital, transaction costs and distributions to minority interests,
      Puget Energy received $95.9 million for its 90.9% interest in InfrastruX in
      the
      second quarter 2006. The sale resulted in an after-tax gain of $29.8 million
      for
      the three months ended June 30, 2006. Puget Energy accounted for InfrastruX
      as a
      discontinued operation under SFAS No. 144, “Accounting for the Impairment or
      Disposal of Long-Lived Assets” in 2005 and 2006. See section titled “InfrastruX”
      for further discussion. The $95.9 million net proceeds Puget Energy received
      from the sale of InfrastruX was used to support PSE through an equity
      contribution of $60.0 million and a loan of $26.5 million. In addition, Puget
      Energy established a charitable foundation, Puget Sound Energy Foundation,
      with
      a contribution of $15.0 million from the net proceeds from the sale of
      InfrastruX along with investment income of $0.4 million on the cash proceeds
      and
      a federal income tax benefit of $5.3 million from funding the Puget Sound Energy
      Foundation.





**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 gas and
      electric distribution and transmission lines; 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 intends 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 the Hopkins
      Ridge
      wind project in the fourth quarter 2005 and progress on construction of the
      Wild
      Horse wind project are two steps in reaching this goal. The Hopkins Ridge wind
      project provides approximately 150 MW of capacity or 52 average MW. The Company
      expects to complete construction of the Wild Horse wind project by the end
      of
      2006. The Wild Horse wind project is designed to provide approximately 230
      MW of
      capacity or 73 average MW. 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. Proposals were received January 13, 2006 and are currently under
      evaluation and assessment.








**Results
      of Operations**





**Puget
      Energy**


All
      the
      operations of Puget Energy are conducted through PSE and until May 7, 2006,
      InfrastruX. Net income for the three months ended June 30, 2006 was $53.5
      million on operating revenues from continuing operations of $574.2 million
      compared to net income of $13.9 million on operating revenues from continuing
      operations of $510.1 million for the same period in 2005. 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 June 30, 2006 were $0.46
      compared to basic and diluted earnings per share for the three months ended
      June
      30, 2005 of $0.14. Included in the basic and diluted earnings per share for
      the
      three months ended June 30, 2006 and 2005 was earnings per share related to
      discontinued operations of InfrastruX of $0.28 and $0.02,
      respectively.


Net
      income for the three months ended June 30, 2006 was positively impacted by
      income from discontinued operations from InfrastruX of $33.0 million (after-tax)
      compared to $1.9 million (after-tax) for the three months ended June 30, 2005.
      The income from discontinued operations for the three months ended June 30,
      2006
      includes a gain on disposal of $29.8 million (after-tax) resulting from the
      sale
      of InfrastruX. Net income for the three months ended June 30, 2006 was also
      positively impacted by increased electric margins of $25.8 million compared
      to
      the same period in 2005 primarily from overrecovery of excess power cost under
      the Power Cost Adjustment (PCA) mechanism and increased sales volumes. In
      addition, gas margin increased $7.2 million as compared to 2005, largely due
      to
      a $5.0 million true-up of previously reported gas costs in 2005. Increased
      electric and natural gas sales volumes favorably impacted energy margins for
      the
      three and six months ended June 30, 2006. The increase was partially offset
      by a
      charitable contribution of $15.0 million ($9.75 million after-tax) to the Puget
      Sound Energy Foundation (Foundation) formed on May 12, 2006. The terms of the
      contribution require the Foundation to establish an endowment and permit
      contributions to qualified nonprofit organizations. The increase was also
      partially offset by higher depreciation expense, which negatively impacted
      net
      income. Income from continuing operations was $30.4 million and $103.9 million,
      for the three and six months ended June 30, 2006, respectively, excluding the
      impact of the charitable contribution to the Foundation. Management of the
      Company believes it is useful to present income from continuing operations
      and
      diluted earnings excluding the impact of the charitable contribution because
      it
      represents a more accurate measure of our operating performance and facilitates
      period-to-period comparisons. Diluted earnings per share from continuing
      operations was $0.26 and $0.89 for the three and six months ended June 30,
      2006,
      respectively, excluding the impact of the charitable contribution to the
      Foundation. A reconciliation to amounts under generally accepted accounting
      principles is as follows:





(Dollars
                in millions, except per share amounts)
            
            Three
                Months Ended
              June
                30,2006
            
            Six
                Months
              Ended
              June
                30,2006Income
                from continuing operations, as reported
            
            $
            20.6
            
            $
            94.1Add:
                Impact of charitable contribution to Foundation, net of
                tax
            
            
            9.8
            
            
            9.8Income
                from continuing operations, excluding charitable
                contribution
            
            $
            30.4
            
            $
            103.9Earnings
                per share:Basic
                and diluted earnings per share before cumulative effect of accounting
                change from continuing operations, as reported
            
            $
            0.18
            
            $
            0.81Add:
                Impact of charitable contribution to Foundation
            
            
            0.08
            
            
            0.08Basic
                and diluted earnings per share before cumulative effect of accounting
                change from continuing operations,
                excludingcharitable
                contribution
            
            $
            0.26
            
            $
            0.89





For
      the
      six months ended June 30, 2006, Puget Energy’s net income was $146.1 million on
      operating revenues from continuing operations of $1.5 billion compared to net
      income of $85.0 million on operating revenues from continuing operations of
      $1.3
      billion for the same period in 2005. Basic and diluted earnings per share for
      the six months ended June 30, 2006 were $1.26 compared to basic and diluted
      earnings per share of $0.85 and $0.84, respectively, for the same period in
      2005. Included in the basic and diluted earnings per share for the six months
      ended June 30, 2006 and 2005 was $0.45 and $0.01, respectively, earnings per
      share related to discontinued operations of InfrastruX.


Net
      income for the six months ended June 30, 2006 was positively impacted by income
      from discontinued operations of InfrastruX of $51.9 million (after-tax) compared
      to $0.9 million (after-tax) for the six months ended June 30, 2005. The income
      from discontinued operations for the six months ended June 30, 2006 includes
      a
      gain on disposal of $29.8 million (after-tax) resulting from the sale of
      InfrastruX. The reversal of an InfrastruX carrying value charge recognized
      in
      2005 of $7.3 million contributed to the gain on disposal. Natural gas and
      electric margins increased by $20.0 million and $30.1 million, respectively,
      for
      the six months ended June 30, 2006 compared to the same period in 2005, which
      positively impacted net income. The increase in natural gas margins resulted
      from increased natural gas general rates, increased sales volumes and the
      true-up of previously reported gas costs in 2005. The increase in electric
      margins was the result of favorable hydro conditions, increased sales volumes
      and an increase in electric tariff rates. The increase was partially offset
      by a
      charitable contribution of $15.0 million ($9.75 million after-tax), higher
      storm
      damage repair costs of $7.2 million due to severe wind storms in the first
      quarter 2006, an increase in non-storm related operations and maintenance
      expense and depreciation expense which negatively impacted net income.





**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
      whether PSE is collecting the appropriate amount of energy costs from its
      customers to allow recovery of its operating costs.


The
      following table displays the details of electric margin changes for the three
      months ended June 30, 2006 compared to the same period in 2005. Electric margin
      is electric sales to retail and transportation customers less pass-through
      tariff items and revenue-sensitive taxes, and the cost of generating and
      purchasing electric energy sold to customers, including transmission costs
      to
      bring electric energy to PSE’s service territory.





Electric
                Margin(Dollars
                in Millions)
              Three
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeElectric
                retail sales revenue
            
            $
            345.2
            
            $
            316.5
            
            $
            28.7
            
            
            9.1
            %Electric
                transportation revenue
            
            
            2.7
            
            
            2.4
            
            
            0.3
            
            
            12.5
            %Other
                electric revenue-gas supply resale
            
            
            6.1
            
            
            1.0
            
            
            5.1
            
            
            *Total
                electric revenue for margin1
            
            
            354.0
            
            
            319.9
            
            
            34.1
            
            
            10.7
            %Adjustments
                for amounts included in revenue:Pass-through
                production tax credits (PTCs)
            
            
            3.1
            
            
            --
            
            
            3.1
            
            
            *Pass-through
                tariff items
            
            
            (8.4
            )
            
            (7.2
            )
            
            (1.2
            )
            
            (16.7
            )%Pass-through
                revenue-sensitive taxes
            
            
            (24.8
            )
            
            (23.6
            )
            
            (1.2
            )
            
            (5.1
            )%Residential
                exchange credit
            
            
            38.7
            
            
            37.1
            
            
            1.6
            
            
            4.3
            %Net
                electric revenue for margin
            
            
            362.6
            
            
            326.2
            
            
            36.4
            
            
            11.2
            %Minus
                power costs:Electric
                generation fuel
            
            
            (14.3
            )
            
            (12.9
            )
            
            (1.4
            )
            
            (10.9
            )%Purchased
                electricity, net of sales to other utilities and marketers2
            
            
            (151.3
            )
            
            (152.4
            )
            
            1.1
            
            
            0.7
            %Total
                electric power costs3
            
            
            (165.6
            )
            
            (165.3
            )
            
            (0.3
            )
            
            (0.2
            )%Electric
                margin before PCA
            
            
            197.0
            
            
            160.9
            
            
            36.1
            
            
            22.4
            %Power
                cost deferred under the PCA mechanism
            
            
            (19.9
            )
            
            (9.6
            )
            
            (10.3
            )
            
            *Electric
                margin4
            
            $
            177.1
            
            $
            151.3
            
            $
            25.8
            
            
            17.1
            %


_________________________________




*
            
            *Percent
                change not applicable or unmeaningful**.*1
            
            *For
                the three months ended June 30, 2006, total electric revenue for
                margin
                was $354.0 million, which does not include $16.8 million in sales
                to other
                utilities and marketers and $10.2 million in other miscellaneous
                electric
                revenue included in electric operating revenues of $381.0 million.
                For the
                three months ended June 30, 2005, total electric revenue for margin
                was
                $319.9 million, which does not include $16.9 million in sales to
                other
                utilities and marketers and $8.6 million in other miscellaneous electric
                revenues included in electric operating revenues of $345.4
                million.*2
            
            *For
                the three months ended June 30, 2006, purchased electricity, net
                of sales
                to other utilities and marketers, was $151.3 million, excluding sales
                to
                other utilities and marketers of $16.8 million and including power
                cost
                deferral under the PCA mechanism of $19.9 million, purchased electricity
                was $188.0 million. For the three months ended June 30, 2005, purchased
                electricity, net of sales to other utilities and marketers, was $152.4
                million, excluding sales to other utilities and marketers of $16.9
                million
                and including power cost deferral under the PCA mechanism of $9.6
                million,
                purchased electricity was $178.9 million.*3
            
            *For
                the three months ended June 30, 2006, total electric power costs
                were
                $165.6 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 $(38.7)
                million and unrealized net gain on derivative instruments of $(0.2)
                million. These amounts, excluding sales of electricity to other utilities
                and marketers, provide electric energy costs of $163.4 million. For
                the
                three months ended June 30, 2005, total electric power costs were
                $165.3
                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 $(37.1)
                million and unrealized net gain on derivative instruments of $(0.6)
                million. These amounts, excluding sales of electricity to other utilities
                and marketers, provide electric energy costs of $154.1
                million.*4
            
            *Electric
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense**.*





Electric
      margin increased $25.8 million for the three months ended June 30, 2006 compared
      to the same period in 2005, primarily due to favorable hydro conditions
      resulting in lower power costs than the amount reflected in PSE’s rates,
      increase in retail customer usage and varied usage among customer classes as
      compared to 2005. Lower power costs under the PCA mechanism contributed $11.3
      million to margin for the three months ended June 30, 2006 as compared to 2005.
      Retail customer kWh sales (residential, commercial and industrial customers)
      increased 3.4% for the three months ended June 30, 2006 compared to 2005, which
      contributed $5.9 million to electric margin, and changes in customer class
      usage
      increased margin by $8.9 million compared to the same period in
      2005.


The
      following table displays the details of electric margin changes for the six
      months ended June 30, 2006 compared to the same period in 2005.




Electric
                Margin(Dollars
                in Millions)
              Six
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeElectric
                retail sales revenue
            
            $
            780.4
            
            $
            703.6
            
            $
            76.8
            
            
            10.9
            %Electric
                transportation revenue
            
            
            5.4
            
            
            5.1
            
            
            0.3
            
            
            5.9
            %Other
                electric revenue-gas supply resale
            
            
            11.9
            
            
            5.1
            
            
            6.8
            
            
            *Total
                electric revenue for margin1
            
            
            797.7
            
            
            713.8
            
            
            83.9
            
            
            11.8
            %Adjustments
                for amounts included in revenue:Pass-through
                production tax credits (PTCs)
            
            
            7.0
            
            
            --
            
            
            7.0
            
            
            *Pass-through
                tariff items
            
            
            (17.0
            )
            
            (13.7
            )
            
            (3.3
            )
            
            (24.1
            )%Pass-through
                revenue-sensitive taxes
            
            
            (56.7
            )
            
            (52.2
            )
            
            (4.5
            )
            
            (8.6
            )%Residential
                exchange credit
            
            
            95.3
            
            
            92.2
            
            
            3.1
            
            
            3.4
            %Net
                electric revenue for margin
            
            
            826.3
            
            
            740.1
            
            
            86.2
            
            
            11.6
            %Minus
                power costs:Electric
                generation fuel
            
            
            (35.9
            )
            
            (33.4
            )
            
            (2.5
            )
            
            (7.5
            )%Purchased
                electricity, net of sales to other utilities and marketers2
            
            
            (394.8
            )
            
            (362.2
            )
            
            (32.6
            )
            
            (9.0
            )%Total
                electric power costs3
            
            
            (430.7
            )
            
            (395.6
            )
            
            (35.1
            )
            
            (8.9
            )%Electric
                margin before PCA
            
            
            395.6
            
            
            344.5
            
            
            51.1
            
            
            14.8
            %Tenaska
                disallowance reserve
            
            
            --
            
            
            5.3
            
            
            (5.3
            )
            
            *Power
                cost deferred under the PCA mechanism
            
            
            (12.7
            )
            
            3.0
            
            
            (15.7
            )
            
            *Electric
                margin4
            
            $
            382.9
            
            $
            352.8
            
            $
            30.1
            
            
            8.5
            %


_________________________________




*
            *Percent
                change not applicable or unmeaningful**.*1
            *For
                the six months ended June 30, 2006, total electric revenue for margin
                was
                $797.7 million, which does not include $32.6 million in sales to
                other
                utilities and marketers and $18.1 million in other miscellaneous
                electric
                revenue included in electric operating revenues of $848.4 million.
                For the
                six months ended June 30, 2005, total electric revenue for margin
                was
                $713.8 million, which does not include $33.2 million in sales to
                other
                utilities and marketers and $18.6 million in other miscellaneous
                electric
                revenues included in electric operating revenues of $765.5
                million.*2
            *For
                the six months ended June 30, 2006, purchased electricity, net of
                sales to
                other utilities and marketers, was $394.8 million. Excluding sales
                to
                other utilities and marketers of $32.6 million and including power
                cost
                deferral under the PCA mechanism of $12.7 million, purchased electricity
                was $440.1 million. For the six months ended June 30, 2005, purchased
                electricity, net of sales to other utilities and marketers, was $362.2
                million, excluding sales to other utilities and marketers of $33.2
                million
                and including the Tenaska disallowance reserve turnaround of $(5.3)
                million and power cost deferral under the PCA mechanism of $(3.0)
                million,
                purchased electricity was $387.1 million.*3
            *For
                the six months ended June 30, 2006, total electric power costs were
                $430.7
                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 $(95.3)
                million and unrealized net loss on derivative instruments of $0.8
                million.
                These amounts, excluding sales of electricity to other utilities
                and
                marketers, provide electric energy costs of $381.5 million. For the
                six
                months ended June 30, 2005, total electric power costs were $395.6
                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 $(92.2)
                million and unrealized net gain on derivative instruments of $(0.1)
                million. These amounts, excluding sales of electricity to other utilities
                and marketers, provide electric energy costs of $328.2
                million.*4
            *Electric
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense**.*





Electric
      margin increased $30.1 million for the six months ended June 30, 2006 compared
      to the same period in 2005 primarily due to favorable hydro conditions resulting
      in lower power costs than the amount in PSE’s rates which increased margin $11.0
      million, a change in customer class usage, which increased margin by $8.3
      million and an increase in retail customer usage, which contributed $13.4
      million to margin. Retail customer kWh sales (residential, commercial and
      industrial customers) increased 3.9% for the six months ended June 30, 2006
      compared to 2005. In addition, electric margin increased as a result of the
      effects of the power cost only rate case (PCORC) effective November 1, 2005,
      which increased margin by $8.2 million. These increases were partially offset
      by
      the non-recurring benefit of a February 23, 2005 Washington Commission order
      allowing recovery of power costs that lowered electric margin by $6.0 million
      and a reduction in the rate of return due to the general rate case which
      decreased margin by $7.1 million for the six months ended June 30,
      2006.


The
      following table displays the details of gas margin changes for the three months
      ended June 30, 2006 compared to the same period in 2005. Gas margin is gas
      sales
      to retail and transportation customers less pass-through tariff items and
      revenue-sensitive taxes, and the cost of gas purchased, including gas
      transportation costs to bring gas to PSE’s service territory.





Gas
                Margin(Dollars
                in Millions)
              Three
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeGas
                retail revenue
            
            $
            185.1
            
            $
            155.2
            
            $
            29.9
            
            
            19.3
            %Gas
                transportation revenue
            
            
            3.1
            
            
            3.2
            
            
            (0.1
            )
            
            (3.1
            )%Total
                gas revenue for margin1
            
            
            188.2
            
            
            158.4
            
            
            29.8
            
            
            18.8
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            
            (1.2
            )
            
            (1.0
            )
            
            (0.2
            )
            
            (20.0
            )%Pass-through
                revenue-sensitive taxes
            
            
            (15.8
            )
            
            (13.7
            )
            
            (2.1
            )
            
            (15.3
            )%Net
                gas revenue for margin
            
            
            171.2
            
            
            143.7
            
            
            27.5
            
            
            19.1
            %Minus
                purchased gas costs
            
            
            (118.4
            )
            
            (98.1
            )
            
            (20.3
            )
            
            (20.7
            )%Gas
                margin2
            
            $
            52.8
            
            $
            45.6
            
            $
            7.2
            
            
            15.8
            %


_________________________________




1
            
            *For
                the three months ended June 30, 2006, total gas revenue for margin
                was
                $188.2 million, which does not include $4.3 million related to other
                gas
                operating revenues that is included in gas operating revenues of
                $192.5
                million. For the three months ended June 30, 2005, total gas revenue
                for
                margin was $158.4 million, which does not include $4.2 million related
                to
                other gas operating revenues that is included in gas operating revenues
                of
                $162.6 million.*2
            
            *Gas
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Gas
      margin increased $7.2 million for the three months ended June 30, 2006 compared
      to the same period in 2005 primarily due to a one-time true-up of previously
      reported gas costs under the Purchased Gas Adjustment (PGA) mechanism during
      the
      three months ended June 30, 2005 which increased margin $5.0 million. In
      addition, retail customer therm sales increased 5.1% for the three months ended
      June 30, 2006, compared to the same period in 2005, which provided $2.6 million
      to margin. Gas margin decreased $0.4 million for the three months ended June
      30,
      2006 compared to the same period in 2005 as a result of changes in customer
      class usage.


The
      following table displays the details of gas margin changes for the six months
      ended June 30, 2006 compared to the same period in 2005.





Gas
                Margin(Dollars
                in Millions)
              Six
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeGas
                retail revenue
            
            $
            583.7
            
            $
            468.0
            
            $
            115.7
            
            
            24.7
            %Gas
                transportation revenue
            
            
            6.7
            
            
            6.6
            
            
            0.1
            
            
            1.5
            %Total
                gas revenue for margin1
            
            
            590.4
            
            
            474.6
            
            
            115.8
            
            
            24.4
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            
            (3.8
            )
            
            (2.9
            )
            
            (0.9
            )
            
            (31.0
            )%Pass-through
                revenue-sensitive taxes
            
            
            (48.5
            )
            
            (38.7
            )
            
            (9.8
            )
            
            (25.3
            )%Net
                gas revenue for margin
            
            
            538.1
            
            
            433.0
            
            
            105.1
            
            
            24.3
            %Minus
                purchased gas costs
            
            
            (385.0
            )
            
            (299.9
            )
            
            (85.1
            )
            
            (28.4
            )%Gas
                margin2
            
            $
            153.1
            
            $
            133.1
            
            $
            20.0
            
            
            15.0
            %


_________________________________




1
            
            *For
                the six months ended June 30, 2006, total gas revenue for margin
                was
                $590.4 million, which does not include $8.6 million related to other
                gas
                operating revenues that is included in gas operating revenues of
                $599.0
                million. For the six months ended June 30, 2005, total gas revenue
                for
                margin was $474.6 million, which does not include $9.1 million related
                to
                other gas operating revenues that is included in gas operating revenues
                of
                $483.7 million.*2
            
            *Gas
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Gas
      margin increased $20.0 million for the six months ended June 30, 2006 compared
      to the same period in 2005. Gas margin increased $7.0 million as a result of
      the
      gas general tariff rate case and the effect of the one-time true-up of
      previously reported gas costs as noted above increased margin by $4.5 million.
      In addition, retail customer therm sales increased 7.3% for the six months
      ended
      June 30, 2006 compared to the same period in 2005, which provided $10.1 million
      to gas margin, and changes in customer class usage reduced margin by $1.6
      million.





**Electric
      Operating Revenues**


The
      table
      below sets forth changes in electric operating revenues for PSE for the three
      months ended June 30, 2006 compared to the same period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeElectric
                operating revenues:Residential
                sales
            
            $
            167.1
            
            $
            152.9
            
            $
            14.2
            
            
            9.3
            %Commercial
                sales
            
            
            159.5
            
            
            150.0
            
            
            9.5
            
            
            6.3
            %Industrial
                sales
            
            
            24.2
            
            
            23.2
            
            
            1.0
            
            
            4.3
            %Other
                retail sales, including unbilled revenue
            
            
            (5.6
            )
            
            (9.6
            )
            
            4.0
            
            
            41.7
            %Total
                retail sales
            
            
            345.2
            
            
            316.5
            
            
            28.7
            
            
            9.1
            %Transportation
                sales
            
            
            2.7
            
            
            2.4
            
            
            0.3
            
            
            12.5
            %Sales
                to other utilities and marketers
            
            
            16.8
            
            
            16.9
            
            
            (0.1
            )
            
            (0.6
            )%Other
            
            
            16.3
            
            
            9.6
            
            
            6.7
            
            
            69.8
            %Total
                electric operating revenues
            
            $
            381.0
            
            $
            345.4
            
            $
            35.6
            
            
            10.3
            %





Electric
      retail sales increased $28.7 million for the three months ended June 30, 2006
      compared to the same period in 2005 due primarily to rate increases related
      to
      the PCORC and increased retail customer usage. The PCORC rate case provided
      $16.6 million to electric operating revenues for the three months ended June
      30,
      2006 compared to the same period in 2005. Retail electricity usage increased
      155,538 MWh or 3.4% for the three months ended June 30, 2006 compared to the
      same period in 2005, which resulted in an approximate $10.9 million increase
      in
      electric operating revenue. During the three month period ended June 30, 2006,
      the benefits of the Residential and Farm Energy Exchange Benefit credited to
      customers reduced electric operating revenues by $40.5 million compared to
      $38.8
      million for the same period in 2005. This credit also reduced power costs by
      a
      corresponding amount with no impact on earnings.


During
      the three month period ended June 30, 2006, the benefits of production tax
      credits (PTCs) (federal income tax credits received for wind generation) were
      passed through to electric customers by crediting customers’ bills, which
      reduced electric operating revenues by $3.1 million. The PTCs also reduced
      income taxes. The PTCs began November 2005 when the Hopkins Ridge wind
      generation facility was placed in service.


Other
      electric revenues increased $6.7 million for the three months ended June 30,
      2006 compared to the same period in 2005, primarily from the increase in the
      sale of non-core gas purchased for intended electric generation of $5.1 million.
      Non-core gas sales are included in the PCA mechanism calculation as a reduction
      in determining net power costs. Miscellaneous customer revenue and transmission
      revenue increased other electric revenues by $1.6 million compared to the same
      period in 2005.


The
      table
      below sets forth changes in electric operating revenues for PSE for the six
      months ended June 30, 2006 compared to the same period in 2005.





(Dollars
                in Millions)
              Six
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeElectric
                operating revenues:Residential
                sales
            
            $
            409.1
            
            $
            364.8
            
            $
            44.3
            
            
            12.1
            %Commercial
                sales
            
            
            342.2
            
            
            307.9
            
            
            34.3
            
            
            11.1
            %Industrial
                sales
            
            
            50.5
            
            
            45.2
            
            
            5.3
            
            
            11.7
            %Other
                retail sales, including unbilled revenue
            
            
            (21.4
            )
            
            (14.4
            )
            
            (7.0
            )
            
            (48.6
            )%Total
                retail sales
            
            
            780.4
            
            
            703.5
            
            
            76.9
            
            
            10.9
            %Transportation
                sales
            
            
            5.4
            
            
            5.1
            
            
            0.3
            
            
            5.9
            %Sales
                to other utilities and marketers
            
            
            32.6
            
            
            33.2
            
            
            (0.6
            )
            
            (1.8
            )%Other
            
            
            30.0
            
            
            23.7
            
            
            6.3
            
            
            26.6
            %Total
                electric operating revenues
            
            $
            848.4
            
            $
            765.5
            
            $
            82.9
            
            
            10.8
            %





Electric
      retail sales increased $76.9 million for the six months ended June 30, 2006
      compared to the same period in 2005 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
      $30.6 million to electric operating revenues for the six months ended June
      30,
      2006 compared to the same period in 2005. Retail electricity usage increased
      402,173 MWh or 3.9% for the six months ended June 30, 2006 compared to the
      same
      period in 2005. The increase in electricity usage was mainly the result of
      a
      1.3% higher average number of customers served in the six month period ended
      June 30, 2006 compared to the same period in 2005.


During
      the six month period ended June 30, 2006, the benefits of the Residential and
      Farm Energy Exchange Benefit credited to customers reduced electric operating
      revenues by $99.8 million compared to $96.4 million for the same period in
      2005.
      This credit also reduced power costs by a corresponding amount with no impact
      on
      earnings.


Other
      electric revenues increased $6.3 million for the six month period ended June
      30,
      2006 compared to the same period in 2005, primarily from the sale of excess
      non-core gas. 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
      2006 and 2005:





Type
                of Rate
              Adjustment
            Effective
                Date
            Average
              Percentage
                Increase
              in
                Rates
            Annual
                Increase
              in
                Revenues
              (Dollars
                in Millions)Electric
                General Rate Case
            March
                4, 2005
            4.1
            %
            $
                57.7Power
                Cost Only Rate Case
            November
                1, 2005
            3.7
            %
            55.6Power
                Cost Only Rate Case
            July
                1, 2006
            5.9
            %
            45.3





**Gas
      Operating Revenues**


The
      table
      below sets forth changes in gas operating revenues for PSE for the three months
      ended June 30, 2006 compared to the same period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            110.1
            
            $
            94.8
            
            $
            15.3
            
            
            16.1
            %Commercial
                sales
            
            
            62.4
            
            
            50.4
            
            
            12.0
            
            
            23.8
            %Industrial
                sales
            
            
            12.6
            
            
            10.0
            
            
            2.6
            
            
            26.0
            %Total
                retail sales
            
            
            185.1
            
            
            155.2
            
            
            29.9
            
            
            19.3
            %Transportation
                sales
            
            
            3.1
            
            
            3.2
            
            
            (0.1
            )
            
            (3.1
            )%Other
            
            
            4.3
            
            
            4.2
            
            
            0.1
            
            
            2.4
            %Total
                gas operating revenues
            
            $
            192.5
            
            $
            162.6
            
            $
            29.9
            
            
            18.4
            %





Gas
      retail sales increased $29.9 million for the three months ended June 30, 2006
      compared to the same period in 2005 due to higher PGA mechanism rates in 2006
      and higher customer gas usage. The Washington Commission approved a PGA
      mechanism rate increase effective October 1, 2005 that increased rates 14.7%
      annually. The PGA mechanism passes through to customers increases or decreases
      in the gas supply portion of the natural gas service rates based upon changes
      in
      the price of natural gas purchased from producers and wholesale marketers or
      changes in gas pipeline transportation costs. PSE’s gas margin and net income
      are not affected by changes under the PGA mechanism. For the three months ended
      June 30, 2006, the effects of the PGA mechanism rate increases provided an
      increase of $21.2 million in gas operating revenues. An increase of 3.0% in
      the
      average number of customers increased customer usage by 7.6 million therms
      or
      approximately $8.3 million in gas operating revenues.


The
      table
      below sets forth changes in gas operating revenues for PSE for the six months
      ended June 30, 2006 compared to the same period in 2005.





(Dollars
                in Millions)
              Six
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            375.1
            
            $
            303.4
            
            $
            71.7
            
            
            23.6
            %Commercial
                sales
            
            
            179.2
            
            
            141.6
            
            
            37.6
            
            
            26.6
            %Industrial
                sales
            
            
            29.4
            
            
            23.0
            
            
            6.4
            
            
            27.8
            %Total
                retail sales
            
            
            583.7
            
            
            468.0
            
            
            115.7
            
            
            24.7
            %Transportation
                sales
            
            
            6.7
            
            
            6.6
            
            
            0.1
            
            
            1.5
            %Other
            
            
            8.6
            
            
            9.1
            
            
            (0.5
            )
            
            (5.5
            )%Total
                gas operating revenues
            
            $
            599.0
            
            $
            483.7
            
            $
            115.3
            
            
            23.8
            %





Gas
      retail sales increased $115.7 million for the six months ended June 30, 2006
      compared to the same period in 2005 due to higher PGA mechanism rates in 2006,
      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, 2005 that provided $69.1 million
      in
      gas revenues for the six months ended June 30, 2006 compared to the same period
      in 2005. In addition, the gas general rate case increase provided an additional
      $7.0 million in gas operating revenues for the six months ended June 30, 2006
      compared to the same period in 2005. The remaining increase in gas retail
      revenues was primarily due to a higher average number of customers, which
      increased 3.0%, and higher gas sales of 40.3 million therms or $34.7 million
      for
      the six months ended June 30, 2006 compared to the same period in
      2005.


The
      following gas rate adjustments were approved by the Washington Commission in
      2006 and 2005:





Type
                of Rate
              Adjustment
            Effective
                Date
            Average
              Percentage
                Increase
              in
                Rates
            Annual
                Increase
              in
                Revenues
              (Dollars
                in Millions)Gas
                General Rate Case
            March
                4, 2005
            3.5
            %
            $  26.3Purchased
                Gas Adjustment
            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 June 30, 2006 compared to the same
      period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangePurchased
                electricity
            
            $
            187.9
            
            $
            178.9
            
            $
            9.0
            
            
            5.0
            %Electric
                generation fuel
            
            
            14.3
            
            
            12.9
            
            
            1.4
            
            
            10.9
            %Residential
                exchange credit
            
            
            (38.7
            )
            
            (37.1
            )
            
            1.6
            
            
            4.3
            %Purchased
                gas
            
            
            118.4
            
            
            98.1
            
            
            20.3
            
            
            20.7
            %Depreciation
                and amortization
            
            
            64.5
            
            
            59.7
            
            
            4.8
            
            
            8.0
            %Conservation
                amortization
            
            
            7.5
            
            
            6.0
            
            
            1.5
            
            
            25.0
            %Taxes
                other than income taxes
            
            
            54.2
            
            
            50.5
            
            
            3.7
            
            
            7.3
            %Income
                taxes
            
            
            15.6
            
            
            6.3
            
            
            9.3
            
            
            *


___________________


*
            
            *Percent
                change not applicable or
                meaningful*





The
      table
      below sets forth significant changes in operating expenses for PSE and its
      subsidiaries for the six months ended June 30, 2006 compared to the same period
      in 2005.





(Dollars
                in Millions)
              Six
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangePurchased
                electricity
            
            $
            440.1
            
            $
            387.1
            
            $
            53.0
            
            
            13.7
            %Electric
                generation fuel
            
            
            35.9
            
            
            33.3
            
            
            2.6
            
            
            7.8
            %Residential
                exchange credit
            
            
            (95.3
            )
            
            (92.2
            )
            
            3.1
            
            
            3.4
            %Purchased
                gas
            
            
            385.0
            
            
            299.9
            
            
            85.1
            
            
            28.4
            %Utility
                operations and maintenance
            
            
            171.0
            
            
            158.7
            
            
            12.3
            
            
            7.8
            %Depreciation
                and amortization
            
            
            128.4
            
            
            117.7
            
            
            10.7
            
            
            9.1
            %Conservation
                amortization
            
            
            15.5
            
            
            11.1
            
            
            4.4
            
            
            39.6
            %Taxes
                other than income taxes
            
            
            133.9
            
            
            120.2
            
            
            13.7
            
            
            11.4
            %Income
                taxes
            
            
            56.3
            
            
            52.8
            
            
            3.5
            
            
            6.6
            %





**Purchased
      electricity** expenses
      increased $9.0 million and $53.0 million for the three and six months ended
      June
      30, 2006, respectively, compared to the same periods in 2005. The increase
      for
      the three months ended June 30, 2006 was primarily the result of the reversal
      of
      previously deferred excess power costs of $10.2 million offset by lower
      wholesale market prices. Total purchased power for the three months ended June
      30, 2006 increased 743,352 MWh or 19.6% compared to the same period in 2005.
      The
      increase for the six months ended June 30, 2006 was primarily the result of
      the
      reversal of deferred excess power costs and from higher customer kWh sales.
      Total purchased power for the six months ended June 30, 2006 increased 838,534
      MWh or 9.9% compared to the same period in 2005. Increases in the purchases
      offset by slightly lower wholesale prices of power contributed $27.3 million
      to
      the increase for the six months ended June 30, 2006. The increase also reflected
      the reversal of previously deferred excess power costs of $12.7 million. Also
      contributing to the increase was 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 during the three
      months ended March 31, 2005. These costs were deferred under the PCA mechanism,
      which resulted in a reduction in purchased electricity expense for the three
      months ended March 31, 2005. Increase in transmission and other expenses
      contributed $4.8 million.


PSE’s
      hydroelectric production and related power costs in 2005 were negatively
      impacted by below-normal precipitation and reduced snow pack in the Pacific
      Northwest region. PSE cannot determine if lower than normal runoff will continue
      in future years nor what impact lower runoff may have on the amount of
      electricity that will need to be purchased. The July 10, 2006 Columbia Basin
      Runoff Forecast published by the National Weather Service Northwest River
      Forecast Center indicated that the total forecasted runoff above Grand Coulee
      Reservoir for the period January through July 2006 would be 106% of normal,
      which compares to 86% of normal observed runoff for the same period in
      2005.


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
      increased $1.4 million and $2.6 million for the three and six months ended
      June
      30, 2006, respectively, compared to the same periods in 2005. The increase
      for
      the three months ended June 30, 2006 is primarily related to an increase in
      the
      cost of gas of PSE-controlled combustion turbine generating facilities. The
      increase for the six months ended June 30, 2006 was primarily the result of
      an
      increase in the cost of coal at Colstrip generating facilities of $2.3 million
      compared to the same period in 2005.


**Residential
      exchange credits** associated with the Residential Purchase and Sale Agreement with BPA increased
      $1.6 million and $3.1 million for the three and six months ended June 30, 2006,
      respectively, compared to the same periods in 2005, as 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 $20.3 million and $85.1 million for the three and six months ended
      June 30, 2006, respectively, compared to the same periods in 2005 primarily
      due
      to an increase in PGA rates as approved by the Washington Commission and higher
      customer therm sales. The PGA mechanism allows PSE to recover expected gas
      costs, and defer, as a receivable or liability, any gas costs that exceed or
      fall short of this expected gas cost amount in PGA mechanism rates, including
      accrued interest. The PGA mechanism receivable balance at June 30, 2006 and
      December 31, 2005 was $73.0 million and $67.3 million, respectively. PSE is
      authorized by the Washington Commission to accrue carrying costs on PGA
      receivable balances. A receivable balance in the PGA mechanism reflects a
      current underrecovery of market gas cost through rates.


**Utility
      operations and maintenance** expense
      increased $12.3 million for the six months ended June 30, 2006, compared to
      the
      same period in 2005. The increase for the six months ended June 30, 2006 was
      primarily due to higher electric distribution system restoration costs as a
      result of a series of strong winter storms with high winds in Western Washington
      during the first quarter of 2006. Storm damage related costs increased $7.2
      million compared to the same period in 2005. In addition, maintenance of
      electric and gas distribution system increased $2.9 million, and customer
      service and call center costs increased $2.9 million for the six months ended
      June 30, 2006 compared to the same period 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 $4.8 million and $10.7 million for the three and six months ended
      June
      30, 2006, respectively, compared to the same periods in 2005 due to additional
      utility plant placed in service. Included in the increase for the three and
      six
      months ended June 30, 2006 is a $2.2 million and $4.1 million increase,
      respectively, related to PSE’s Hopkins Ridge wind project that became
      operational on November 26, 2005. PSE anticipates depreciation expense will
      increase in future years as investments in new generating resources and energy
      delivery infrastructure are completed.


**Conservation
      amortization** increased $1.5 million and $4.4 million for the three and six months ended
      June
      30, 2006, respectively, compared to the same periods in 2005 due to higher
      authorized recovery of electric conservation expenditures. Conservation
      amortization is a pass-through tariff item with no impact on
      earnings.


**Taxes
      other than income taxes** increased $3.7 million and $13.7 million for the three and six months ended
      June
      30, 2006, respectively, compared to the same periods in 2005 due primarily
      to
      increases in revenue-based Washington State excise tax and municipal tax due
      to
      increased operating revenues. Revenue sensitive Washington State excise and
      municipal taxes have no impact on earnings.


**Income
      taxes** increased $9.3 million and $3.5 million for the three and six months ended
      June
      30, 2006, respectively, compared to the same periods in 2005. The increase
      was
      the result of higher taxable income offset by a lower effective tax rate as
      compared to the same periods in 2005 due to higher production tax credits of
      $3.8 million and $0.8 million for the three and six months ended June 30, 2006,
      respectively, as compared to the same periods in 2005.





**Other
      Income (Deductions) And Interest Charges**


The
      table
      below sets forth significant changes in other income for PSE and its
      subsidiaries for the three months ended June 30, 2006 compared to the same
      period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeOther
                income
            
            $
            5.6
            
            $
            1.9
            
            $
            3.7
            
            
            *


___________________


*
            
            *Percent
                change not applicable or
                meaningful*





**Other
      income** increased
      $3.7 million for the three months ended June 30, 2006 compared to the same
      period in 2005 primarily due to increases in the equity portion of allowance
      for
      funds used during construction, a decrease in long-term incentive plan costs
      and
      an increase in the return on regulatory assets.


The
      table
      below sets forth significant changes in other income and interest charges for
      PSE and its subsidiaries for the six months ended June 30, 2006 compared to
      the
      same period in 2005.





(Dollars
                in Millions)
              Six
                Months Ended June 30,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeOther
                income
            
            $
            7.9
            
            $
            3.7
            
            $
            4.2
            
            
            *Interest
                charges
            
            
            83.1
            
            
            81.0
            
            
            2.1
            
            
            2.6
            %


___________________


*
            
            *Percent
                change not applicable or
                meaningful*





**Other
      income** increased
      $4.2 million for the six months ended June 30, 2006 compared to the same period
      in 2005 primarily due
      to
      increases in the equity portion of allowance for funds used during construction,
      a decrease in long-term incentive plan costs and an increase in the return
      on
      regulatory assets .


**Interest
      charges** increased
      $2.1 million for the six months ended June 30, 2006 compared to the same period
      in 2005. The increase is due primarily to higher average interest rates and
      higher amounts of borrowings outstanding during the six months ended June 30,
      2006 compared to the same period in 2005.





**InfrastruX**


On
      May 7,
      2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P.
      (Tenaska) for $275 million before taking into account cash on hand at May 7,
      2006 of $11.4 million for a net sale price of $263.6 million. After
      repayment of debt, adjustments for working capital, transaction costs and
      distributions to minority interests, Puget Energy received after-tax cash
      proceeds of approximately $95.9 million for its 90.9% interest in InfrastruX
      in
      the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million
      for the three months ended June 30, 2006. The repayment of InfrastruX’s debt by
      Puget Energy released Puget Energy’s corporate guarantee relating to the debt.
      Puget Energy accounted for InfrastruX as a discontinued operation under SFAS
      No.
      144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005
      and 2006.


Under
      the
      terms of the sale agreement, Puget Energy is obligated for certain
      representations and warranties made by InfrastruX concerning its business.
      Puget
      Energy obtained a representation and warranty insurance policy and deposited
      $3.7 million into an escrow account to serve as retention under the policy.
      As
      of June 30, 2006, long-term restricted cash in the amount of $3.7 million is
      included in the accompanying balance sheets; that amount represents management’s
      estimate of the aggregate fair value of the amount potentially payable under
      those representations and warranties and is Puget Energy’s maximum exposure. The
      obligation expires May 7, 2008. Should Tenaska make any claims against Puget
      Energy, payment for the claims will be made from the escrow account, and total
      payments are limited to $3.7 million. Puget Energy also agreed to indemnify
      the
      purchaser for certain potential future losses related to one of InfrastruX’s
      subsidiary companies. Under the indemnity agreement, Puget Energy is liable
      for
      certain costs with the maximum amount of loss not to exceed $15.0 million.
      As of
      June 30, 2006, a liability in the amount of $5.0 million is included in the
      accompanying balance sheets; that amount represents Puget Energy’s estimate of
      the fair value of the amount potentially payable using a probability-weighted
      approach to a range of future cash flows. The obligation expires May 7, 2011.
      Tenaska and Puget Energy have also negotiated the terms of an environmental
      guaranty as part of the sale agreement. Under the terms of the agreement,
      Tenaska will be responsible for the first $0.1 million of environmental claims,
      Tenaska and Puget Energy will share the next $6.4 million equally and Puget
      Energy will be responsible for the next $3.5 million. Based on a review of
      a
      third-party environmental report, Puget Energy believes it will not have a
      future loss in connection with the environmental guarantee.


For
      the
      three and six months ended June 30, 2006, Puget Energy reported InfrastruX
      related income from discontinued operations (net of taxes and minority
      interest), including gain on sale, of $33.0 million and $51.9 million,
      respectively, compared to $1.9 million and $0.9 million (net of taxes and
      minority interest) for the three and six months ended June 30, 2005,
      respectively. Puget Energy’s income from discontinued operations for the six
      months ended June 30, 2006 includes $7.3 million related to the reversal of
      a
      carrying value adjustment recorded in 2005.


InfrastruX's
      operating revenue for the three and six months ended June 30, 2006 was $46.5
      million and $138.6 million, respectively, compared to $97.3 million and $175.0
      million, respectively, for the same periods in 2005. Pre-tax income for the
      three and six months ended June 30, 2006 was $5.8 million and $9.9 million,
      respectively, compared to $11.8 million and $11.7 million, respectively for
      the
      same periods in 2005.





**Capital
      Requirements**


**Contractual
      Obligations and Commercial Commitments**


**Puget
      Energy.** The
      following are Puget Energy’s aggregate consolidated (including PSE) contractual
      obligations and commercial commitments as of June 30, 2006:


Puget
                Energy
            
            
            
            
            Payments
                Due Per PeriodContractual
                Obligations
              (Dollars
                in Millions)
            Total
            
            2006
            
            2007-
              2008
            
            2009-
              2010
            
            2011
                & ThereafterLong-term
                debt including interest
            
            $
            4,692.5
            
            $
            116.2
            
            $
            601.2
            
            $
            640.4
            
            $
            3,334.7Short-term
                debt including interest
            
            
            182.6
            
            
            182.6
            
            
            --
            
            
            --
            
            
            --Junior
                subordinated debentures payable to a subsidiary trust including
                interest1
            
            
            102.8
            
            
            1.6
            
            
            6.2
            
            
            6.2
            
            
            88.8Mandatorily
                redeemable preferred stock
            
            
            1.9
            
            
            --
            
            
            --
            
            
            --
            
            
            1.9Service
                contract obligations
            
            
            152.4
            
            
            12.6
            
            
            55.5
            
            
            54.4
            
            
            29.9Non-cancelable
                operating leases
            
            
            95.2
            
            
            6.7
            
            
            29.1
            
            
            21.8
            
            
            37.6Fredonia
                combustion turbines lease2
            
            
            58.6
            
            
            2.2
            
            
            8.5
            
            
            8.2
            
            
            39.7Energy
                purchase obligations
            
            
            6,235.5
            
            
            525.6
            
            
            1,932.9
            
            
            1,283.5
            
            
            2,493.5Contract
                initiation payment/collateral requirement
            
            
            18.5
            
            
            --
            
            
            --
            
            
            --
            
            
            18.5Financial
                hedge obligations
            
            
            24.2
            
            
            0.6
            
            
            23.6
            
            
            --
            
            
            --Purchase
                obligations
            
            
            179.9
            
            
            179.9
            
            
            --
            
            
            --
            
            
            --Non-qualified
                pension and other benefits funding
            
            
            50.0
            
            
            2.7
            
            
            11.1
            
            
            10.2
            
            
            26.0Total
                contractual cash obligations
            
            $
            11,794.1
            
            $
            1,030.7
            
            $
            2,668.1
            
            $
            2,024.7
            
            $
            6,070.6






Puget
                Energy
            
            
            
            
            Amount
                of Commitment
              Expiration Per
                PeriodCommercial
                Commitments
              (Dollars
                in Millions)
            Total
            
            2006
            
            2007-
              2008
            
            2009-
              2010
            
            2011
                & Thereafter


Indemnity
                agreements3
            
            $
            8.7
            
            $
            --
            
            $
            3.7
            
            $
            --
            
            $
            5.0Credit
                agreement - available4
            
            
            316.9
            
            
            --
            
            
            --
            
            
            --
            
            
            316.9Unsecured
                credit agreement
            
            
            20.0
            
            
            --
            
            
            --
            
            
            --
            
            
            20.0Receivable
                securitization facility5
            
            
            177.4
            
            
            --
            
            
            --
            
            
            177.4
            
            
            --Energy
                operations letter of credit
            
            
            0.5
            
            
            0.5
            
            
            --
            
            
            --
            
            
            --Total
                commercial commitments
            
            $
            523.5
            
            $
            0.5
            
            $
            3.7
            
            $
            177.4
            
            $
            341.9


_______________________




1
            *In
                2001, PSE formed Puget Sound Energy Capital Trust II 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 Trust 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
            *Under
                the InfrastruX sale agreement, Puget Energy is obligated for certain
                representations and warranties concerning InfrastruX’s business and
                anti-trust inquiries. The fair value of the business warranty is
                $3.7
                million at June 30, 2006 and the obligation expires on May 7, 2008.
                Puget
                Energy also agreed to indemnify the buyer relating to an anti-trust
                inquiry of an InfrastruX subsidiary that had a fair value of $5.0
                million
                at June 30, 2006. See “InfrastruX” above for further
                discussion.*4
            *At
                June 30, 2006, PSE had available a $500 million unsecured credit
                agreement
                expiring in April 2011. The credit agreement provides credit support
                for
                letters of credit and commercial paper. At June 30, 2006, PSE had
                $0.5
                million for an outstanding letter of credit and $182.6 million commercial
                paper outstanding, effectively reducing the available borrowing capacity
                to $316.9 million.*5
            *At
                June 30, 2006, PSE had available a $200 million receivables securitization
                facility that expires in December 2010. There were no amounts outstanding
                under the receivables securitization facility at June 30, 2006. The
                facility allows receivables to be used as collateral to secure short-term
                loans, not exceeding the lesser of $200 million or the borrowing
                base of
                eligible receivables, which fluctuate with the seasonality of energy
                sales
                to customers. The borrowing base of eligible receivables at June
                30, 2006
                was $177.4 million. See “Receivables Securitization Facility" below for
                further discussion.*


**Puget
      Sound Energy.** The
      following are PSE’s aggregate contractual obligations and commercial commitments
      as of June 30, 2006:


Puget
                Sound Energy
            
            
            
            
            Payments
                Due Per PeriodContractual
                Obligations
              (Dollars
                in Millions)
            Total
            
            2006
            
            2007-
              2008
            
            2009-
              2010
            
            2011
                & Thereafter


Long-term
                debt including interest
            
            $
            4,692.5
            
            $
            116.2
            
            $
            601.2
            
            $
            640.4
            
            $
            3,334.7Short-term
                debt including interest1
            
            
            209.2
            
            
            209.2
            
            
            --
            
            
            --
            
            
            --Junior
                subordinated debentures payable to a subsidiary trust including
                interest2
            
            
            102.8
            
            
            1.6
            
            
            6.2
            
            
            6.2
            
            
            88.8Mandatorily
                redeemable preferred stock
            
            
            1.9
            
            
            --
            
            
            --
            
            
            --
            
            
            1.9Service
                contract obligations
            
            
            152.4
            
            
            12.6
            
            
            55.5
            
            
            54.4
            
            
            29.9Non-cancelable
                operating leases
            
            
            95.2
            
            
            6.7
            
            
            29.1
            
            
            21.8
            
            
            37.6Fredonia
                combustion turbines lease3
            
            
            58.6
            
            
            2.2
            
            
            8.5
            
            
            8.2
            
            
            39.7Energy
                purchase obligations
            
            
            6,235.5
            
            
            525.6
            
            
            1,932.9
            
            
            1,283.5
            
            
            2,493.5Contract
                initiation payment/collateral requirement
            
            
            18.5
            
            
            --
            
            
            --
            
            
            --
            
            
            18.5Financial
                hedge obligations
            
            
            24.2
            
            
            0.6
            
            
            23.6
            
            
            --
            
            
            --Purchase
                obligations
            
            
            179.9
            
            
            179.9
            
            
            --
            
            
            --
            
            
            --Non-qualified
                pension and other benefits funding
            
            
            50.0
            
            
            2.7
            
            
            11.1
            
            
            10.2
            
            
            26.0Total
                contractual cash obligations
            
            $
            11,820.7
            
            $
            1,057.3
            
            $
            2,668.1
            
            $
            2,024.7
            
            $
            6,070.6




Puget
                Sound Energy
            
            
            
            
            Amount
                  of Commitment
                Expiration Per
                  PeriodCommercial
                Commitments
              (Dollars
                in Millions)
            Total
            
            2006
            
            2007-
              2008
            
            2009-
              2010
            
            2011
                & Thereafter


Credit
                agreement - available4
            
            $
            316.9
            
            $
            --
            
            $
            --
            
            $
            --
            
            $
            316.9Unsecured
                credit agreement
            
            
            20.0
            
            
            --
            
            
            --
            
            
            --
            
            
            20.0Receivable
                securitization facility5
            
            
            177.4
            
            
            --
            
            
            --
            
            
            177.4
            
            
            --Energy
                operations letter of credit
            
            
            0.5
            
            
            0.5
            
            
            --
            
            
            --
            
            
            --Total
                commercial commitments
            
            $
            514.8
            
            $
            0.5
            
            $
            --
            
            $
            177.4
            
            $
            336.9


_______________________


1
            *Short-term
                borrowing include $26.5 million outstanding debt under a Demand Promissory
                Note owed to Puget Energy. The outstanding balance under the Demand
                Promissory Note is eliminated by Puget Energy upon consolidation
                of PSE’s
                financial statements.*2
            *See
                note 1 under Puget Energy above.*3
            *See
                note 2 under Puget Energy above.*4
            *See
                note 4 under Puget Energy above.*5
            *See
                note 5 under Puget Energy
                above.*





**Off-Balance
      Sheet Arrangements**


**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 for this lease
      in
      April 2001. The lease has a term expiring in 2011, but can be canceled by PSE
      at
      any time. Payments under the lease vary with changes in the London Interbank
      Offered Rate (LIBOR). At June 30, 2006, PSE’s outstanding balance under the
      lease was $52.6 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 $306.4 million for the six months ended June 30, 2006.
      Utility construction expenditures, excluding AFUDC and excluding new generation
      resources other than the Wild Horse project (which will be determined as the
      Company proceeds through the least cost planning process) are anticipated to
      be
      the following in 2006 and 2007:


Capital
                  Expenditure Projections
                (Dollars
                  in Millions)
              2006
              2007Energy
                  delivery, technology and facilities
              $
              444
              $
              500Wild
                  Horse wind project
              
              317
              
              --Total
                  capital expenditures
              
              761
              
              500Chelan
                  contract payment1
              
              89
              
              --Total
                  expenditures
              $
              850
              $
              500


_______________________


1
            *The
                Chelan contract payment represents a capacity reservation charge
                in
                conjunction with a new contract for hydroelectric power beginning
                2011.
                PSE obtained an accounting order from the Washington Commission that
                treated the payment made on April 26, 2006 as a regulatory
                asset.*





The
      proposed utility construction expenditures and any new generation resource
      expenditures that may be incurred are anticipated to be funded with a
      combination of cash from operations, short-term debt, long-term debt and equity.
      Construction expenditure estimates, including any new generation resources,
      are
      subject to periodic review and adjustment in light of changing economic,
      regulatory, environmental and efficiency factors.





**Capital
      Resources**


**Cash
      From Operations**


Cash
      generated from operations for the six months ended June 30, 2006 was $72.0
      million. During that period, $5.0 million was used for AFUDC, which reduced
      interest expense and $52.0 million for payment of dividends. Consequently,
      cash
      flows available for utility construction expenditures and other capital
      expenditures were $15.0 million or 4.8% of the $311.8 million in construction
      expenditures (net of AFUDC and customer refundable contributions) and other
      capital expenditure requirements for the six months ended June 30, 2006. For
      the
      six months ended June 30, 2005, cash generated from operations was $136.6
      million, $3.5 million was used for AFUDC, which reduced interest expense, and
      $43.9 million for payment of dividends. Therefore, cash flows available for
      utility **** construction
      expenditures and other capital **** expenditures
      were $89.2 million, or 39.2% of the $227.4 million in construction expenditures
      (net of AFUDC and customer refundable contributions) and other capital
      expenditure requirements for the six months ended June 30, 2005. The following
      table provides a summary of cash available and construction
      expenditures:





(Dollars
                in millions)
              (Unaudited)
              Six
                Months Ended June 30,
            
            2006
            
            2005Cash
                from operations
            
            $
            72.0
            
            $
            136.6Less:
                Dividends paid
            
            
            (52.0
            )
            
            (43.9
            )AFUDC
            
            
            (5.0
            )
            
            (3.5
            )Cash
                available for construction expenditures
            
            $
            15.0
            
            $
            89.2Construction
                and energy efficiency expenditures
            
            $
            324.5
            
            $
            237.0Less:
                AFUDC
            
            
            (5.0
            )
            
            (3.5
            )Cash
                received from refundable customer contributions
            
            
            (7.7
            )
            
            (6.1
            )Net
                construction and energy efficiency expenditures
            
            $
            311.8
            
            $
            227.4





The
      overall cash generated from operating activities for the six month period ended
      June 30, 2006 decreased $63.7 million compared to the same period in 2005.
      This
      decrease in cash from operations is primarily attributable to a non-refundable
      capacity reservation prepayment of $89.0 million in April 2006 for the Chelan
      PUD power sales agreement. This agreement will begin providing power to PSE
      at
      the end of 2011. In addition, cash from operations decreased $44.7 million
      due
      to an increase in the amount of taxes paid in 2006 as compared to 2005. Cash
      from operations was also negatively impacted by a $20.0 million refund of
      collateral deposits related to energy counterparties compared to $3.0 million
      receipt in 2005; a $15.0 million payment to fund Puget Sound Energy charitable
      foundation; and an increase of $82.2 million in payments made for accounts
      payable related to energy purchases. Offsetting the decrease in cash from
      operations is an increase in accounts receivable of $191.8 million. The increase
      in accounts receivable is primarily attributable to Rainier Receivables accounts
      receivable securitization sale of $150 million in December 2004 that was not
      collected from customers in the first quarter 2005. This compares to no activity
      under the Rainier Receivables accounts receivable securitization at December
      31,
      2005 due to termination of the Rainier Receivable accounts receivable
      securitization program in December 2005. As a result, cash from operations
      increased due to collection of accounts receivable in 2006.  Collections of
      accounts receivable will increase in the second and third quarters of the year
      due to the highest accounts receivable balances in thre first and fourth
      quarters of the year.





**Financing
      Program**


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





**Restrictive
      Covenants**


In
      determining the type and amount of future financing, PSE may be limited by
      restrictions contained in its electric and gas mortgage indentures, articles
      of
      incorporation and certain loan agreements. Under the most restrictive tests,
      at
      June 30, 2006, PSE could issue:


·
            approximately
                $321 million of additional first mortgage bonds under PSE’s electric
                mortgage indenture based on approximately $535 million of electric
                bondable property available for issuance, subject to an interest
                coverage
                ratio limitation of 2.0 times net earnings available for interest,
                which
                PSE exceeded at June 30, 2006;


·
            approximately
                $250 million of additional first mortgage bonds under PSE’s gas mortgage
                indenture based on approximately $417 million of gas bondable property
                available for issuance, subject to an interest coverage ratio limitation
                of 1.75 times net earnings available for interest, which PSE exceeded
                at
                June 30, 2006;


·
            approximately
                $772 million of additional preferred stock at an assumed dividend
                rate of
                7.0%; and


·
            approximately
                $647 million of unsecured long-term
                debt.


At
      June
      30, 2006, PSE had approximately $3.8 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 any debt outstanding that would accelerate debt
      maturity upon a credit rating downgrade. A ratings downgrade could adversely
      affect the 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 July 27, 2006, 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
      March
      16, 2006, Puget Energy and PSE filed a shelf registration statement with the
      Securities and Exchange Commission for the offering of:


·
            common
                stock of Puget Energy;


·
            senior
                notes of PSE, secured by first mortgage
                bonds;


·
            preferred
                stock of PSE; and


·
            trust
                preferred securities of Puget Sound Energy Capital Trust
                III.


The
      registration statement is valid for three years and does not specify the amount
      of securities that the Company may offer. The Company is subject to restrictions
      under PSE’s indentures and restated articles of incorporation on the amount of
      first mortgage bonds, unsecured debt and preferred stock that the Company may
      issue.


On
      June
      30, 2006, PSE redeemed for $200 million all of its outstanding shares of the
      8.40% 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) at $25 par value per
      share
      plus accrued interest to the redemption date.


On
      June
      30, 2006, PSE completed the issuance of $250 million of senior secured note
      at a
      rate of 6.724% which are due on June 15, 2036. The net proceeds from the
      issuance of the senior notes of approximately $247.8 million were used to redeem
      $200 million of 8.40% Capital Trust Preferred Securities, which were redeemed
      at
      par on June 30, 2006, and to repay a portion of PSE’s short-term debt. The
      short-term debt was incurred to repay $46 million of 8.06% senior notes that
      matured June 19, 2006. The yield to maturity of the $250 million senior secured
      notes was 6.17% after the settlement of two interest rate forward starting
      swap
      contracts.


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.





**Forward
      Starting Interest Rate Swap Settlement**


In
      the
      second quarter 2006, the Company settled its two forward starting interest
      rate
      swap contracts originating in May 2005. The purpose of the forward starting
      swap
      contracts was to hedge interest rate volatility for a debt offering of $200
      million that was completed on June 30, 2006. Since interest rates increased
      related to the hedged debt from the date of issuance of the forward starting
      swap contracts, PSE received $21.3 million from the counterparties when the
      contracts were settled. The forward starting swap contracts were designated
      and
      documented under SFAS No. 133 criteria as cash flow hedges, with all changes
      in
      market value for each reporting period presented net of tax in other
      comprehensive income. In the second quarter 2006, the settlement gain on these
      instruments amounted to $13.9 million after-tax, and was recorded as a gain
      in
      other comprehensive income. In accordance with SFAS No. 133, the gain will
      be
      amortized out of other comprehensive income to current earnings as a decrease
      to
      interest expense over the life of the new debt issued at an annual rate of
      approximately $0.7 million before tax.





**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.





**PSE
      Credit Facilities** ****


The
      Company has two committed credit facilities that provide, in aggregate, $700
      million in short-term borrowing capability. These include a $500 million credit
      agreement and a $200 million accounts receivable securitization facility. In
      addition, PSE has an uncommitted $20 million unsecured credit agreement with
      a
      bank with no expiration date. The unsecured credit agreement can be terminated
      by either party upon written notice. PSE pays a varying interest rate on
      outstanding borrowings based on terms entered into at the time of the
      borrowings. There were no amounts outstanding under the unsecured credit
      agreement at June 30, 2006.





**Demand
      Promissory Note** **.** On
      June
      1, 2006, PSE entered into a revolving credit facility with its parent, Puget
      Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE
      may borrow up to $30 million from Puget Energy, subject to approval. Under
      the
      terms of the Note, PSE pays interest on the outstanding borrowings based on
      the
      lowest of the weighted average interest rate of (a) PSE’s outstanding commercial
      paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or
      (c) PSE Funding receivable securitization facility interest rate which is LIBOR
      rate plus a marginal rate. At June 30, 2006, the outstanding balance of Note
      was
      $26.5 million.





**Credit
      Agreement.** In March
      2005, PSE entered into a five-year, $500 million unsecured credit agreement
      with
      a group of banks. In April 2006, PSE amended this credit agreement to extend
      the
      expiration date from April 2010 to April 2011. The agreement is primarily used
      to provide credit support for commercial paper and letters of credit. 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. At June 30, 2006, there was $0.5
      million outstanding under a letter of credit and $182.6 million commercial
      paper
      outstanding, effectively reducing the available borrowing capacity under the
      credit facility to $316.9 million.





**Receivables
      Securitization Facility.** PSE
      entered into a five-year Receivable Sales Agreement with PSE Funding, Inc.
      (PSE
      Funding), a wholly owned subsidiary, on December 20, 2005. Pursuant to the
      Receivables Sales Agreement, PSE sells all of its utility customer accounts
      receivable and unbilled utility revenues to PSE Funding. In addition, PSE
      Funding entered into a Loan and Servicing Agreement with PSE and two banks.
      The
      Loan and Servicing Agreement allows PSE Funding to use the receivables as
      collateral to secure short-term loans, not exceeding the lesser of $200 million
      or the borrowing base of eligible receivables which fluctuate with the
      seasonality of energy sales to customers. All loans from this facility will
      be
      reported as short-term debt in the financial statements.


The
      PSE
      Funding facility expires in December 2010, and is terminable by PSE and PSE
      Funding upon notice to the banks. During the six months ended June 30, 2006,
      PSE
      Funding borrowed a cumulative amount of $97.0 million secured by accounts
      receivable. There were no loans secured by accounts receivable pledged as
      collateral at June 30, 2006. The borrowing base of eligible receivables at
      June
      30, 2006 was $177.4 million.





**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 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 under the Stock Purchase
      and Dividend Reinvestment Plan of $3.4 million (164,784 shares) and $6.9 million
      (331,635 shares) for the three and six months ended June 30, 2006, respectively,
      compared to $3.7 million (168,213 shares) and $7.3 million (320,020 shares)
      for
      the three and six months ended June 30, 2005, 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**


**Baker
      River project.** The
      Baker
      River project consists of the Lower Baker Development (constructed in 1925)
      and
      the Upper Baker Development (constructed in 1959). The Baker River project’s
      current license expires on April 30, 2007, and PSE submitted an application
      for
      a new license to FERC on April 30, 2004. On November 30, 2004, PSE and 23
      parties comprised of federal, state and local governmental organizations, Native
      American Indian tribes, environmental and other non-governmental entities filed
      a proposed comprehensive settlement agreement on all issues relating to the
      relicensing of the Baker River project. The proposed settlement includes a
      set
      of proposed license articles and, if approved by FERC without material
      modification, would allow for a new license of 45 years or more. The proposed
      settlement would require an investment of approximately $360 million over the
      next 30 years (capital expenditures and operations and maintenance cost) in
      order to implement the conditions of the new license. The proposed settlement
      is
      subject to contingencies that have yet to be resolved and is subject to
      additional regulatory approvals yet to be attained from various agencies. On
      April 7, 2006, FERC issued a Draft Environmental Impact Statement discussing
      the
      proposed settlement. A Final Environmental Impact Statement is due in the third
      quarter of 2006. However, FERC has not yet ruled on the proposed settlement
      and
      its ultimate outcome remains uncertain.





**White
      River project.** The
      White
      River project was built in 1911 and was operated as a hydropower facility until
      January 15, 2004. PSE submitted a license application to FERC in 1983, and
      in
      December 1997, FERC issued a proposed license for the project. PSE appealed
      the
      1997 license because it contained terms and conditions that would render ongoing
      operations of the project uneconomic relative to alternative resources. In
      November 2003, PSE determined that it could no longer continue to operate the
      project economically due to additional conditions primarily related to two
      listings under the Endangered Species Act. On December 23, 2003, PSE notified
      FERC that it rejected the 1997 license for the White River project and on
      January 15, 2004, generation of electricity ceased at the White River project.
      PSE is actively seeking to sell the project to one or more entities interested
      in maintaining the reservoir for commercial purposes. On February 16, 2006,
      PSE
      entered into a Letter of Intent with the Cascade Land Conservancy to facilitate
      efforts to sell certain former project properties to one or more third parties
      that may have an interest in acquiring these properties for potential open
      space, habitat and recreational interests.


In
      the
      PCORC Order issued on April 7, 2004, the Washington Commission approved PSE’s
      recovery on the unamortized White River plant investment. At June 30, 2006,
      the
      White River project net book value totaled $67.2 million, which included $44.2
      million of net utility plant, $15.9 million of capitalized FERC licensing costs,
      $4.6 million of costs related to construction work in progress and $1.7 million
      related to dam operations and safety On February 18, 2005, the Washington
      Commission approved the recovery of the White River net utility plant costs
      but
      did not allow current recovery of FERC licensing costs and other related costs
      until all costs associated with selling the White River plant and any sales
      proceeds are known.


In
      January 2001, certain environmental groups gave notice of their intent to sue
      for alleged violations of the Endangered Species Act, but no such lawsuit has
      been filed.  In May 2004, the Puyallup Indian Tribe gave PSE notice of
      intent to sue for an alleged violation of water quality laws associated with
      the
      release of water from the White River project reservoir. No such lawsuit has
      been filed and PSE is in discussion with the Puyallup Indian Tribe regarding
      their concerns. Additionally, PSE sought further direction from the Washington
      State Department of Ecology (Ecology) as to whether any additional actions
      are
      necessary to maintain compliance with applicable water quality laws, and Ecology
      has not recommended any such further actions.


Homeowners
      and others interested in preserving the project reservoir (Lake Tapps) have
      expressed concern over the possible loss of the reservoir and there has been
      a
      solicitation of interest in a potential lawsuit against PSE to preserve the
      reservoir, but no such lawsuit has been filed to date.


In
      September 2005, the Company renewed its contract with the United States Army
      Corps of Engineers (COE) to maintain operation of the White River diversion
      dam
      to support the COE’s ongoing operation of its Mud Mountain Dam fish passage
      facilities. The agreement provides for reimbursement of a portion of PSE’s
      operating costs and directs PSE to operate the diversion dam in accordance
      with
      measures determined by federal agencies to be necessary to protect listed
      species and habitat. This contract expires in September 2010, unless terminated
      prior to that date.


In
      June
      2003, Ecology approved an application for new municipal water rights related
      to
      the White River project reservoir. This approval was sought in connection with
      PSE’s ongoing efforts to sell the White River project to be used for commercial
      purposes. An appeal of Ecology’s decision approving the new municipal water
      rights was subsequently filed with the Washington State Pollution Control
      Hearings Board. In July 2004, this decision was remanded back to Ecology for
      further analysis of non-hydropower operations. The Company has been advised
      by
      Ecology that Ecology anticipates issuing a revised decision in 2006; however,
      no
      firm date has been set for any such revised decision. Any proceeds from the
      sale
      of the White River water rights will reduce the balance of the deferred
      regulatory asset. Neither the outcome of this matter nor any potential
      associated costs can be predicted at this time.





**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 after 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 Washington State Department of Ecology’s authority to regulate water
      quality and that FERC arbitrarily and capriciously rebalance the public interest
      without support of substantive evidence in the record. The Snoqualmie Tribe
      appealed FERC’s operating license 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, 2005, PSE asked for further
      review by the Ninth Circuit. The two petitions have been consolidated and
      briefing is anticipated to be completed in the third quarter of
      2006.





**Electron
      project.** The Electron project was built in 1904.  The project’s capacity is
      currently 22 MW.  In 1977, the project was determined to be a “pre-1935”
      project under the
      Federal Power Act (FPA) and therefore not
      subject to FERC jurisdiction.  In this status, the project can continue to
      operate without a FERC license absent “post-1935” construction of a nature
      sufficient to invoke FERC’s jurisdiction. PSE does not anticipate undertaking
      any betterments or improvements to the project that would entail “post-1935”
      construction.


The
      project also operates in compliance with the terms and conditions of a “Resource
      Enhancement Agreement” with the Puyallup Indian Tribe. This agreement resolved
      the Tribe’s long-standing claims for resource and other damages allegedly
      associated with the construction and operation of the project. The agreement
      also provides that in 2018 PSE must decide to either retire the project by
      2026
      or, in lieu of retirement, undertake significant upgrades that would likely
      invoke FERC jurisdiction. The outcome of these deliberations is not expected
      to
      have a material impact upon the financial condition, results of operations
      or
      liquidity of the Company. In July of 2005, the National Marine Fisheries Service
      and the U.S. Fish and Wildlife Service advised the Company of concerns with
      potential effects of project facilities and operations on listed species (salmon
      and bull trout). In response, the Company has initiated efforts to secure
      additional authorizations from the Services with respect to project facilities
      and operations. These efforts are ongoing.





**Electric
      Regulation and Rates**


**Power
      Cost Only Rate Case **and
      Electric General Rate Case**.** On
      June 28, 2006, the Washington Commission approved a 5.9%, or $45.3 million,
      power cost only rate case (PCORC) increase in electric rates for the period
      July
      1, 2006 through December 31, 2006. The increase allows PSE to recover higher
      projected costs of power caused by higher market prices for natural gas used
      as
      fuel for electric generators. The rate increase granted will not appreciatively
      impact PSE’s income. The annualized basis of the PCORC rate increase when
      applied to the general rate case test year is $96.1 million. Primarily as a
      result of this order, PSE reduced its pending electric general tariff increase
      on July 10, 2006 from $140.9 million to $42.9 million, or 2.5%, on an annualized
      basis. Additionally,
      PSE has requested approval of a new tariff in its original general rate case
      filing to recover increases in electric transmission and distribution
      depreciation costs incurred between general rate cases of $7.9 million. The
      resolution of the general rate case is expected by the end of
      2006.





**PCA
      Mechanism.**  On
      June
      20, 2002, the Washington Commission approved 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 an electric rate case. During
      the
      four-year period ended June 30, 2006, PSE’s cumulative maximum pre-tax earnings
      exposure due to power cost variations was limited to $40 million plus 1% of
      the
      excess. 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 transmission cost
      variability.


Beginning
      July 1, 2006, the most significant risks are hydroelectric generation
      variability and wholesale market prices of natural gas and power. On a July
      through December 2006 basis, the current PCA mechanism apportions increases
      or
      decreases in power costs, on a graduated scale, between PSE and its customers
      in
      the following manner:





Prior
                to July 2006
              Annual
                PowerCost
                Variability
            July-December
                2006
              Power
                Cost Variability1
            
            Customers’
                Share
            
            Company’s
                Share2+/-
                $20 million
            
            +/-
                $10 million
            
            0%
            
            
            100%+/-
                $20 - $40 million
            
            +/-
                $10 - $20 million
            
            50%
            
            
            50%+/-
                $40 - $120 million
            
            +/-
                $20 - $60 million
            
            90%
            
            
            10%+/-
                $120 million
            
            +/-
                $60 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.*





PSE
      proposed the following change to the annual PCA sharing bands effective January
      1, 2007 in its general rate case filing on February 15, 2006:





Power
                Cost Variability
            Customers’
              Share
            Company’s
              Share+/-
                $0 - $25 million
            50%
            50%+/-
                $25 - $120 million
            90%
            10%+/-
                $120 million
            95%
            5%


**Gas
      Regulation and Rates**


**Gas
        General Rate Case.** On
        July 10, 2006, PSE reduced its gas general rate increase request filed on
        February 15, 2006 from $40.4 million to $39.2 million, or 4.2%, on an annual
        basis with the Washington Commission. PSE also has requested approval of
        a new
        depreciation tracker in its original gas general rate case filing to recover
        increase in gas distribution depreciation costs incurred between general
        rate
        cases of $10.9 million. In addition, a gas decoupling mechanism was requested
        and does not have an impact on the current rate increase; however, it is
        designed to stabilize revenue changes due to load variations between regulatory
        filings. The resolution of the general rate case is expected by the end of
        2006.




**Other**


**Whitehorn
      Power Generating Facility Lease** .
      PSE
      leases the Whitehorn power generating facility under a noncancelable operating
      lease expiring in February 2009 and received notice of alleged default for
      the
      non-performance of certain covenants from the lessor. PSE immediately
      investigated the matter and provided notice it disputed the allegations. The
      facility consists of two dual-fuel combustion turbine engines with 147 MW net
      capacity, which are operated for peak load conditions, emergencies, and to
      maintain reliability of service during periods of adverse water or weather
      conditions. The notice of default included the threat of eviction and recovery
      of all damages should PSE fail to cure the alleged default and assign
      governmental permits and licenses associated with the facility to the lessor.
      PSE subsequently agreed to reimburse the lessor for its legal costs and expenses
      incurred in connection with the default and the lessor has four times agreed
      to
      suspend the notice of default for a one-month period to allow the parties to
      further investigate the matter and negotiate possible solutions. The current
      suspension period runs through August 31, 2006. PSE is seeking resolution of
      the
      matter, which may include the modification of the lease or the purchase of
      the
      project. If PSE cannot negotiate reasonable terms to settle the dispute, the
      amount of the ultimate impact upon the Company, if any, cannot be predicted
      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,
        2005 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2006
        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 and
        subsequent to 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
                Receivable and California Refund Proceeding.**In
                2001, PG&E and Southern California Edison failed to pay the California
                Independent System Operator Corporation (CAISO) and the California
                PX for
                energy purchases. The CAISO in turn failed to pay various energy
                suppliers, including PSE, for energy sales made by PSE into the California
                energy market during the fourth quarter 2000. Both PG&E and the
                California PX filed for bankruptcy in 2001, further constraining
                PSE’s
                ability to receive payments due to bankruptcy court controls placed
                on the
                distribution of funds by the California PX and the escrow of funds
                owed by
                PG&E for purchases during the fourth quarter 2000 that are owed by the
                California PX.




**a.**
            ***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.
                If the refunds required by the formula would cause a seller to recover
                less than its actual costs for the refund period, FERC has held that
                the
                seller would be allowed to document these costs and limit its refund
                liability commensurately. In August 2005, PSE submitted its audited
                Fuel
                Cost Allowance Claim with the CAISO. That claim is currently pending.
                In
                September 2005, PSE submitted an additional cost filing claim pursuant
                to
                FERC’s August 2005 order, demonstrating an overall revenue shortfall for
                sales into the California spot markets during the refund period after
                the
                mitigated market clearing price methodology was applied to its
                transactions. In January 2006, FERC issued its order on cost filings
                accepting PSE’s cost filing claim subject to certain modifications and the
                utilization of final CAISO data. PSE does not agree with all of FERC’s
                rulings and sought rehearing of some of FERC’s determinations. Once the
                CAISO receives updated cost offset filings from sellers, including
                PSE, it
                will continue efforts to prepare revised settlement statements for
                spot
                market sales to California during the refund period. Thus, PSE’s ability
                to recover all or a part of its costs remains uncertain at this time.
                Global settlements have been announced and/or approved, including
                settlements between the California Parties and Williams, Duke, El
                Paso,
                Mirant, Dynegy, Enron, Reliant, Public Service Company of Colorado
                and
                Idacorp. 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.
              Many
                of
                the numerous orders that FERC issued in Docket No. EL00-95 are on
                appeal
                before the United States Court of Appeals for the Ninth Circuit.
                Some of
                those issues have been consolidated as a result of a case management
                conference conducted on September 21, 2004. The Ninth Circuit ordered
                on
                October 22, 2004 that briefing proceed in two rounds. The first round
                was
                limited to three issues: (1) which parties are subject to FERC’s refund
                jurisdiction in light of the exemption for government-owned utilities
                in
                section 201(f) of the FPA; (2) the temporal scope of refunds under
                section
                206 of the FPA; and (3) which categories of transactions are subject
                to
                refunds.
              On
                September 6, 2005, the court ruled that, as to the first issue, FERC
                does
                not have refund authority over wholesale electric sales made by
                governmental utilities. On
                August 2, 2006, the court decided the remaining issues of the first
                round,
                ruling that FERC erred in excluding potential relief for tariff violations
                for periods that pre-dated October 2, 2000, and ruling that FERC
                should
                consider remedies for certain CAISO and California PX transactions
                outside
                the 24-hour period previously used to define the scope of the proceedings.
                The
                  August 2, 2006 decision may adversely impact PSE’s ability to recover the
                  full amount of its CAISO Receivable described below, and the decision
                  may
                  expose PSE to claims or liabilities for transactions outside the
                  previously defined “refund period,” but at this time the ultimate
                  financial outcome for PSE is unclear. It is likely that some parties
                  will
                  seek rehearing of the court’s decision and/or that settlement talks will
                  ensue. If the proceedings are not resolved through such a process,
                  the
                  matters would be remanded to FERC for further proceedings. PSE
                  is studying
                  the court’s decision, but is unable to predict either the outcome of the
                  proceedings or the ultimate financial effect on PSE at this time.




**b.**
            ***CAISO
                Receivable****.*At
                June 30, 2006, PSE had a net receivable totaling $21.2 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. On January
                26,
                2006, FERC issued its order on Cost Filings accepting PSE’s cost filing
                subject to certain modifications, which appear to have the effect
                of
                reducing PSE’s Portfolio Claim substantially. PSE filed a revised
                Portfolio Claim in the amount of $2.3 million on March 3, 2006. PSE
                does
                not agree with all of FERC’s rulings and sought rehearing. As a result of
                the Ninth Circuit decision of August 2, 2006 discussed above, PSE
                cannot
                assess the ultimate resolution of its California Receivable. However,
                the
                Company does not believe the claim will be reduced below the $21.2
                million
                receivable. PSE does not agree with all of FERC’s rulings and sought
                rehearing. PSE’s ability to recover all or a portion of these claims is
                uncertain at the present time.
                PSE
                  has determined a range related to its CAISO receivable to be between
                  $21.2
                  million (PSE’s net receivable balance) and $29.3 million, including
                  interest, on its past due receivables as of June 30, 2006. At this
                  time
                  there is no reasonable basis to adjust PSE’s net receivable balance of
                  $21.2 million because the procedural outcome of a rehearing or
                  remand to
                  FERC is uncertain, and any financial impact cannot be
                  quantified.




**Critical
      Accounting Policies And Estimates**


Effective
      January 1, 2006, the Company adopted the fair value recognition provisions
      of
      SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition
      method. Results for prior periods have not been restated, as provided for under
      the modified-prospective method. Prior to 2006, stock-based compensation plans
      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 applied SFAS No. 123 accounting to stock
      compensation awards granted subsequent to January 1, 2003, while grants prior
      to
      2003 continued to be accounted for using the intrinsic value method of APB
      No.
      25.


The
      adoption of SFAS 123R resulted in a cumulative benefit from an accounting change
      of $0.1 million, net of tax, for the quarter ended March 31, 2006. The
      cumulative effect adjustment is primarily the result of the inclusion of
      estimated forfeitures occurring before award vesting dates in the computation
      of
      compensation expense for unvested awards. As a result of adopting SFAS No.
      123R
      on January 1, 2006, the Company’s income before income taxes and net income from
      continuing operations for the six months ended June 30, 2006, is $0.1 million
      and $0.1 million higher, respectively, than if it had continued to account
      for
      share-based compensation under SFAS No. 123 due to the inclusion of estimated
      forfeitures in compensation cost. There is no difference between basic and
      diluted earnings per share for income from continuing operations for the three
      and six months ended June 30, 2006, under SFAS No. 123R as compared to earlier
      methods.


The
      fair
      value of the stock-based grants is based on the closing price of the Company’s
      common stock on the date of measurement and historical performance of the
      certain share grants and prospective analysis using the Capital Asset Pricing
      Model and expected EPS growth rates. Based on this analysis, the Company’s total
      shareholder returns would need to significantly increase as compared to other
      companies to have a material impact on the Company’s financial statements.
      Shares granted prior to 2006 were valued using the Black-Scholes option pricing
      model.








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


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


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


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


The
      Company is not engaged in the business of assuming risk for the purpose of
      speculative trading revenues. 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 for the purpose
      of
      developing strategies to reduce the potential exposure on a cost-effective
      basis
      in regulated utility gas and electric portfolios. Specifically, the amount
      of
      risk exposure is defined by time period and by portfolio, and is determined
      through statistical methods aimed at forecasting risk.


The
      energy portfolio 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.
      However, 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 portfolio management staff develops hedging strategies to
      manage deficit or surplus positions in the portfolios. The Company’s energy risk
      policy states that hedging and optimization strategies will be consistent with
      Company objectives. The Company will engage in transactions that reduce risks
      in
      its electric and gas portfolios, and optimize unused capacity where possible.
      Cost and reliability factors are considered in its hedging strategies. 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. Programmatic hedge plans are developed to ensure
      disciplined hedging and discretion are used in hedging within specific
      guidelines of the programmatic hedge plans approved by the Energy Management
      Committee. The Company’s programmatic hedging strategies may be modified, as
      approved by the Energy Management Committee, in response to market fundamental
      information and trends. Most hedges can be implemented in ways that retain
      the
      Company’s ability to use its energy supply optimization opportunities. Some
      hedges are structured similarly to insurance instruments, where the Company
      pays
      an insurance premium to protect against certain extreme conditions.


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


The
      Company has entered into master netting agreements with counterparties when
      available to mitigate credit exposure to those counterparties. The Company
      believes that entering into such agreements reduces risk of settlement default
      for the ability to make only one net payment. In addition, the Company believes
      risk is mitigated with an improved position in potential counterparty bankruptcy
      situations due to a consistent netting approach.


At
      June
      30, 2006, the Company was subject to a range of netting provisions, including
      both stand alone agreements and the provisions associated with the Western
      Systems Power Pool agreement of which many energy suppliers in the western
      United States are a part.


Transactions
      that qualify as hedge transactions under SFAS No. 133 are recorded on the
      balance sheet at fair value. Changes in fair value of the Company’s derivatives
      are recorded each period in current earnings or other comprehensive income.
      Short-term derivative contracts for the purchase and sale of electricity are
      valued based on daily quoted prices from an independent energy brokerage
      service. Valuations for short-term and medium-term natural gas financial
      derivatives are derived from a combination of quotes from several independent
      energy brokers and are updated daily. Long-term gas financial derivatives are
      valued based on published pricing from a combination of independent brokerage
      services and are updated monthly. Option contracts are valued using market
      quotes and a Monte Carlo simulation process employing stochastic differential
      equations using market volatilities and prices as inputs to create various
      commodity forward curves. These simulated forward curves are then used to value
      various option contracts across a spectrum of commodities.


At
      June
      30, 2006, the Company had a net asset of approximately $23.7 million of energy
      contracts designated as qualifying cash flow hedges and a corresponding
      unrealized gain of $15.4 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. Amounts settling
      after June 30, 2006 have not been deferred as the $40 million cap under the
      PCA
      mechanism has expired and the sharing band under the PCA mechanism reset. The
      Company also had energy contracts that were marked-to-market at a gain of $0.2
      million and a loss of $0.8 million through current earnings for the three and
      six months ended June 30, 2006, respectively. These mark-to-market adjustments
      were the result of excluding certain contracts from the normal purchase normal
      sale exception under SFAS No. 133 and de-designated cash flow hedges where
      the
      hedging relationship was ended. At June 30, 2006, the Company also has a net
      liability of approximately $32.3 million related to the fair value of gas
      contracts to serve gas customers. All mark-to-market adjustments relating to
      the
      natural gas business have been reclassified to a deferred account in accordance
      with SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes on to
      customers increases and decreases in the cost of natural gas supply. 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%
      decrease in the market prices of natural gas and electricity would decrease
      the
      fair value of qualifying cash flow hedges and comprehensive income by
      approximately $5.9 million after-tax and would decrease current earnings for
      those contracts marked-to-market in earnings by $0.2 million pre-tax. All items
      affecting comprehensive income are presented after-tax as items recorded in
      comprehensive income are net of tax.





**Credit
      Risk**


The
      Company is exposed to credit risk primarily through buying and selling
      electricity and gas to serve its customers. Credit risk is the potential loss
      resulting from a counterparty’s non-performance under an agreement. The Company
      manages credit risk with policies and procedures for, among other things,
      counterparty analysis, exposure measurement, exposure monitoring and exposure
      mitigation.


It
      is
      possible that extreme volatility in energy commodity prices could cause the
      Company to have sub-optimal credit risk exposures with one or more
      counterparties. If such counterparties fail to perform their obligations under
      one or more agreements, the Company could suffer a material financial loss.
      However, as of June 30, 2006, approximately 95% of the Company’s energy
      portfolio was rated investment grade or higher by Standard & Poor's Ratings
      Services and/or Moody's Investor Services, Inc.





**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 enter into swap instruments or other financial hedge
      instruments to manage the interest rate risk associated with these debts.


In
      the
      second quarter 2006, the Company settled its two forward starting interest
      rate
      swap contracts originating in May 2005. The purpose of the forward starting
      swap
      contracts was to hedge interest rate volatility for a debt offering of $200
      million that was completed on June 30, 2006. Since interest rates increased
      related to the hedged debt from the date of issuance of the forward starting
      swap contracts, PSE received $21.3 million from the counterparties when the
      contracts were settled. The forward starting swap 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 2006, the settlement gain on these
      instruments amounted to $13.9 million, after-tax, and was recorded as a gain
      in
      other comprehensive income. In accordance with SFAS No. 133, the gain will
      be
      amortized out of other comprehensive income to current earnings as a decrease
      to
      interest expense over the life of the new debt issued at an annual rate of
      approximately $0.7 million before tax. The ending balance in other comprehensive
      income related to the forward starting swaps and previously settled treasury
      lock contracts at June 30, 2006 was a net loss of $8.3 million after-tax and
      accumulated amortization. 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.








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 Chairman, President and Chief Executive Officer and the Senior Vice
      President Finance and Chief Financial Officer, Puget Energy has evaluated the
      effectiveness of its disclosure controls and procedures (as defined in Rule
      13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2006, the
      end of the period covered by this report. Based upon that evaluation, the
      Chairman, President and Chief Executive Officer and the Senior Vice President
      Finance and Chief Financial Officer of Puget Energy concluded that these
      disclosure controls and procedures are effective.





**Changes
      in Internal Control Over Financial Reporting**


There
      have been no changes in Puget Energy’s internal control over financial reporting
      during the quarter ended June 30, 2006 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
      Chairman, President and Chief Executive Officer and the Senior Vice President
      Finance and Chief Financial Officer, PSE has evaluated the effectiveness of
      its
      disclosure controls and procedures (as defined in Rule 13a-15(e) under the
      Securities Exchange Act of 1934) as of June 30, 2006, the end of the period
      covered by this report. Based upon that evaluation, the Chairman, President
      and
      Chief Executive Officer and the Senior Vice President Finance and Chief
      Financial Officer of PSE concluded that these disclosure controls and procedures
      are effective.





**Changes
      in Internal Control Over Financial Reporting**


There
      have been no changes in PSE’s internal control over financial reporting during
      the quarter ended June 30, 2006, that have materially affected, or are
      reasonably likely to materially affect, PSE’s internal control over financial
      reporting.








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








Item
      1. **Legal
      Proceedings**





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


Contingencies
      arising out of the normal course of the Company’s business exist at June 30,
      2006. 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
      1A.  **Risk
      Factors**





Risk
      factors previously disclosed by Puget Energy and Puget Sound Energy under “Risks
      Relating to Disposition of Discontinued Operations” in their Form 10-K, Item 1A
      for the period ending December 31, 2005, are no longer relevant after May 7,
      2006 as InfrastruX was sold on that date. In addition, the following risk factor
      is an update to the previously disclosed risk factors by Puget Energy and PSE
      in
      the Form 10-K, Item 1A.





**The
      mechanism by which variations in PSE’s power costs are apportioned between it
      and its customers will change in 2006, at which time PSE could experience a
      significant increase in expenses.**


PSE
      has a
      PCA mechanism that provides for recovery of power costs from customers or
      refunding of power cost savings to customers, as those costs vary from the
      “power cost baseline” level of power costs which are set in part based on
      normalized assumptions about weather and hydro conditions. PSE’s exposure due to
      power cost variations over the four-year period ending June 30, 2006 was
      limited to $40 million plus 1% of the excess costs. The $40 million cap expired
      June 30, 2006, after which excess power costs or power cost savings will be
      apportioned between PSE and its customers pursuant to the graduated scale set
      forth in the PCA mechanism without operation of any cap. Although PSE received
      approval to reset its power cost baseline rates effective July 1, 2006, it
      is
      possible that PSE could experience higher expenses associated with excess power
      costs under the apportionment arrangement. PSE was also required by the
      settlement terms of its 2005 power cost only rate case to make a general rate
      case filing in February 2006 to again reset the power cost baseline rate
      effective January 1, 2007, and PSE has complied with that requirement. PSE’s
      pending general rate case filing, has requested modifications to the PCA
      mechanism but the outcome of that case cannot be known at this time and PSE
      may
      continue to experience substantial exposure to excess power costs beyond January
      1, 2007.








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





Puget
      Energy’s annual meeting of shareholders was held on May 9, 2006. At the annual
      meeting, the shareholders elected three directors to hold office until the
      annual meeting of shareholders in 2009. The vote was as follows:





Number
                of SharesFor
            WithheldTERMEXPIRING2009Craig
                W. Cole
            97,934,526
            1,324,773Tomio
                Moriguchi
            97,936,836
            1,322,463Herbert
                B. Simon
            97,943,607
            1,315,692





There
      were no broker non-votes.





In
      addition, shareholders ratified the appointment of PricewaterhouseCoopers LLP.
      The vote was as follows:





Number
                of SharesFor
            Against
            AbstainRatify
                PricewaterhouseCoopers LLP
            97,706,262
            1,081,293
            471,738





Item
      6.  **Exhibits**




See
      Exhibit Index for list of exhibits.











**SIGNATURES**





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







**PUGET
                ENERGY, INC.****PUGET
                SOUND ENERGY, INC.****/s/
                James W. Eldredge****James
                W. Eldredge**Vice
                President, Corporate Secretary and Chief Accounting
                OfficerDate:
                August 3, 2006Chief
                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
                (2001
                through 2005 and 12 months ended June 30, 2006) for Puget
                Energy.12.2
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2001
                through 2005 and 12 months ended June 30, 2006) 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.