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****March
                31, 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
      April 25, 2006, (i) the number of shares of Puget Energy, Inc. common stock
      outstanding was 116,030,932 ($.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
                Months Ended March 31, 2006 and 2005Consolidated
                Statements of Comprehensive
                Income - Three Months Ended
              March
                31, 2006 and 2005Consolidated
                Balance Sheets - March 31, 2006
                and December 31, 2005Consolidated
                Statements of Cash Flows - Three Months
                Ended March 31, 2006 and 2005**Puget
                Sound Energy, Inc.**Consolidated
                Statements of Income - Three
                Months Ended March 31, 2006 and 2005Consolidated
                Statements of Comprehensive
                Income - Three Months Ended
              March
                31, 2006 and
                2005Consolidated
                Balance Sheets - March 31, 2006 and
                December 31, 2005Consolidated
                Statements of Cash Flows - Three Months
                Ended March 31, 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
                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 InterpretationFPA
            Federal
                Power ActInfrastruX
            InfrastruX
                Group, Inc.kWh
            Kilowatt
                HourLIBOR
            London
                Interbank Offered RateMW
            Megawatt
                (one MW equals one thousand kW)MWh
            Megawatt
                Hour (one MWh equals one thousand kWh)PCA
            Power
                Cost AdjustmentPCORC
            Power
                Cost Only Rate CasePGA
            Purchased
                Gas AdjustmentPSE
            Puget
                Sound Energy, Inc.Puget
                Energy
            Puget
                Energy, Inc.SFAS
            Statement
                of Financial Accounting StandardsWashington
                Commission
            Washington
                Utilities and Transportation
                Commission








**FILING
      FORMAT**


This
      Quarterly Report on Form 10-Q is a combined quarterly report 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-LOOKINGSTATEMENTS**


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;·
            
            Natural
                disasters, such as hurricanes, 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;·
            
            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
                hydroelectric conditions, which can impact streamflow and PSE’s ability to
                generate electricity from hydroelectric facilities;·
            
            Plant
                outages, which can have an adverse impact on PSE’s expenses with respect
                to repair costs, added costs to replace energy or higher costs associated
                with dispatching a more expensive resource;·
            
            The
                ability of gas or electric plant to operate as intended;·
            
            The
                ability to renew contracts for electric and gas supply and the price
                of
                renewal;·
            
            Blackouts
                or large curtailments of transmission systems, whether PSE’s or others’,
                which can affect PSE’s ability to deliver load to its customers;·
            
            The
                ability to restart generation following a regional transmission
                disruption;·
            
            Failure
                of the interstate gas pipeline delivering to PSE’s system, which may
                impact PSE’s ability to adequately deliver gas supply to its customers;·
            
            The
                amount of collection, if any, of PSE’s receivables from the 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;·
            
            The
                impacts of natural disasters such as earthquakes, hurricanes, floods,
                fires or landslides;·
            
            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; 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.








**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
              March
                31,2006
            
            2005Operating
                Revenues:Electric
            
            $
            467,424
            
            $
            420,090Gas
            
            
            406,588
            
            
            321,129Other
            
            
            3,723
            
            
            434Total
                operating revenues
            
            
            877,735
            
            
            741,653Operating
                Expenses:Energy
                costs:Purchased
                electricity
            
            
            252,125
            
            
            208,178Electric
                generation fuel
            
            
            21,584
            
            
            20,448Residential
                exchange
            
            
            (56,633
            )
            
            (55,046
            )Purchased
                gas
            
            
            266,679
            
            
            201,744Net
                unrealized loss on derivative instruments
            
            
            975
            
            
            509Utility
                operations and maintenance
            
            
            87,364
            
            
            75,522Other
                operations and maintenance
            
            
            855
            
            
            741Depreciation
                and amortization
            
            
            63,884
            
            
            58,077Conservation
                amortization
            
            
            8,048
            
            
            5,162Taxes
                other than income taxes
            
            
            79,732
            
            
            69,700Income
                taxes
            
            
            40,345
            
            
            46,084Total
                operating expenses
            
            
            764,958
            
            
            631,119Operating
                income
            
            
            112,777
            
            
            110,534Other
                income (deductions):Other
                income, net of tax
            
            
            2,339
            
            
            1,164Interest
                charges:AFUDC
            
            
            2,022
            
            
            1,462Interest
                expense
            
            
            (43,542
            )
            
            (41,044
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )Income
                from continuing operations
            
            
            73,573
            
            
            72,093Income
                (loss) from discontinued segment (net of tax)
            
            
            18,947
            
            
            (1,018
            )Net
                income before cumulative effect of accounting change
            
            
            92,520
            
            
            71,075Cumulative
                effect of implementation of accounting change (net of tax)
            
            
            (89
            )
            
            --Net
                income
            
            $
            92,609
            
            $
            71,075Common
                shares outstanding weighted average (in thousands)
            
            
            115,725
            
            
            99,953Diluted
                shares outstanding weighted average (in thousands)
            
            
            116,190
            
            
            100,446Basic
                earnings per common share before cumulative effect from accounting
                change
            
            $
            0.64
            
            $
            0.72Basic
                earnings per common share from discontinued operations
            
            
            0.16
            
            
            (0.01
            )Cumulative
                effect from accounting change
            
            
            --
            
            
            --Basic
                earnings per common share
            
            $
            0.80
            
            $
            0.71Diluted
                earnings per common share before cumulative effect from accounting
                change
            
            $
            0.63
            
            $
            0.72Diluted
                earnings per common share from discontinued operations
            
            
            0.16
            
            
            (0.01
            )Cumulative
                effect from accounting change
            
            
            --
            
            
            --Diluted
                earnings per common share
            
            $
            0.79
            
            $
            0.71





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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended
              March
                31,2006
            
            2005Net
                income
            
            $
            92,609
            
            $
            71,075Other
                comprehensive income, net of tax at 35%:Foreign
                currency translation adjustment
            
            
            (17
            )
            
            3Net
                unrealized (losses) gains on derivative instruments during the
                period
            
            
            (5,281
            )
            
            15,658Reversal
                of net unrealized gains on derivative instruments settled
              during
                the period
            
            
            (7,607
            )
            
            (1,817
            )Amortization
                of cash flow hedge contracts to earnings
            
            
            191
            
            
            --Deferral
                of cash flow hedges related to power cost adjustment
                mechanism
            
            
            5,557
            
            
            (5,563
            )Other
                comprehensive income (loss)
            
            
            (7,157
            )
            
            8,281Comprehensive
                income
            
            $
            85,452
            
            $
            79,356





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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





March
                31,
              2006
            
            December
                31,
              2005Utility
                Plant: (at original cost, including construction work in progress
                of
                $228,557 and $216,513, respectively)Electric
            
            $
            4,842,555
            
            $
            4,802,363Gas
            
            
            2,013,902
            
            
            1,991,456Common
                plant
            
            
            444,421
            
            
            439,599Less:
                Accumulated depreciation and amortization
            
            
            (2,632,990
            )
            
            (2,602,500
            )Net
                utility plant
            
            
            4,667,888
            
            
            4,630,918Other
                property and investments
            
            
            156,230
            
            
            157,321Current
                assets:Cash
            
            
            17,873
            
            
            16,710Restricted
                cash
            
            
            1,048
            
            
            1,047Accounts
                receivable, net of allowance for doubtful accounts
            
            
            299,279
            
            
            294,509Secured
                pledged accounts receivable
            
            
            24,000
            
            
            41,000Unbilled
                revenues
            
            
            120,037
            
            
            160,207Purchased
                gas adjustment receivable
            
            
            72,414
            
            
            67,335Materials
                and supplies, at average cost
            
            
            37,028
            
            
            36,491Fuel
                and gas inventory, at average cost
            
            
            45,973
            
            
            91,058Unrealized
                gain on derivative instruments
            
            
            32,475
            
            
            75,037Prepayments
                and other
            
            
            9,723
            
            
            7,596Current
                assets of discontinued operations
            
            
            108,535
            
            
            107,434Total
                current assets
            
            
            768,385
            
            
            898,424Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            125,431
            
            
            129,693Regulatory
                asset for PURPA contract buyout costs
            
            
            185,363
            
            
            191,170Unrealized
                gain on derivative instruments
            
            
            20,190
            
            
            28,464Power
                cost adjustment mechanism
            
            
            25,879
            
            
            18,380Other
            
            
            517,888
            
            
            388,468Long-term
                assets of discontinued operations
            
            
            178,794
            
            
            167,113Total
                other long-term assets
            
            
            1,053,545
            
            
            923,288Total
                assets
            
            $
            6,646,048
            
            $
            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**




March
                31,
              2006
            
            December
                31,
              2005Capitalization:Common
                shareholders’ investment:Common
                stock $0.01 par value, 250,000,000 shares authorized, 116,055,501
                and
                115,695,463 shares outstanding, respectively
            
            $
            1,160
            
            $
            1,157Additional
                paid-in capital
            
            
            1,957,294
            
            
            1,948,975Earnings
                reinvested in the business
            
            
            133,090
            
            
            69,407Accumulated
                other comprehensive income, net of tax at 35%
            
            
            351
            
            
            7,508Total
                shareholders’ equity
            
            
            2,091,895
            
            
            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
            
            
            237,750
            
            
            237,750Long-term
                debt
            
            
            2,083,360
            
            
            2,183,360Total
                redeemable securities and long-term debt
            
            
            2,322,999
            
            
            2,422,999Total
                capitalization
            
            
            4,414,894
            
            
            4,450,046Minority
                interest in discontinued operations
            
            
            7,141
            
            
            6,816Current
                liabilities:Accounts
                payable
            
            
            339,179
            
            
            346,490Short-term
                debt
            
            
            25,600
            
            
            41,000Current
                maturities of long-term debt
            
            
            181,000
            
            
            81,000Accrued
                expenses:Taxes
            
            
            134,599
            
            
            112,860Salaries
                and wages
            
            
            12,796
            
            
            15,034Interest
            
            
            46,473
            
            
            31,004Unrealized
                loss on derivative instruments
            
            
            33,476
            
            
            9,772Deferred
                income taxes
            
            
            5,902
            
            
            10,968Other
            
            
            45,261
            
            
            35,694Current
                liabilities of discontinued operations
            
            
            58,222
            
            
            55,791Total
                current liabilities
            
            
            882,508
            
            
            739,613Long-term
                liabilities:Deferred
                income taxes
            
            
            724,619
            
            
            738,809Other
                deferred credits
            
            
            455,822
            
            
            513,023Long-term
                liabilities of discontinued operations
            
            
            161,064
            
            
            161,644Total
                long-term liabilities
            
            
            1,341,505
            
            
            1,413,476Total
                capitalization and liabilities
            
            $
            6,646,048
            
            $
            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)


Three
                Months Ended
              March
                31,2006
            
            2005Operating
                activities:Net
                income
            
            $
            92,609
            
            $
            71,075Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation
                and amortization
            
            
            63,884
            
            
            60,074Deferred
                income taxes and tax credits, net
            
            
            (11,267
            )
            
            6,075Net
                unrealized loss on derivative instruments
            
            
            975
            
            
            509Accrual
                of contract initiation payment
            
            
            (89,000
            )
            
            --InfrastruX
                impairment adjustment
            
            
            (7,269
            )
            
            --Power
                cost adjustment mechanism
            
            
            (7,499
            )
            
            (15,020
            )Cash
                collateral received from (returned to) energy suppliers
            
            
            (14,850
            )
            
            3,100Decrease
                in residential exchange program
            
            
            (12,746
            )
            
            (11,159
            )Other
            
            
            (268
            )
            
            12,091Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            51,861
            
            
            (97,786
            )Materials
                and supplies
            
            
            (122
            )
            
            (751
            )Fuel
                and gas inventory
            
            
            45,085
            
            
            11,453Prepayments
                and other
            
            
            (5,231
            )
            
            (8,656
            )Purchased
                gas adjustment receivable
            
            
            (5,079
            )
            
            (3,242
            )Accounts
                payable
            
            
            (4,913
            )
            
            (23,352
            )Taxes
                payable
            
            
            23,055
            
            
            31,720Tenaska
                disallowance reserve
            
            
            --
            
            
            (3,156
            )Accrued
                expenses and other
            
            
            19,175
            
            
            12,679Net
                cash provided by operating activities
            
            
            138,400
            
            
            45,654Investing
                activities:Construction
                and capital expenditures-excluding equity AFUDC
            
            
            (105,389
            )
            
            (124,376
            )Energy
                efficiency expenditures
            
            
            (6,884
            )
            
            (4,738
            )Refundable
                cash received for customer construction projects
            
            
            2,554
            
            
            3,582Restricted
                cash
            
            
            (1
            )
            
            486Other
            
            
            6,255
            
            
            5,515Net
                cash used by investing activities
            
            
            (103,465
            )
            
            (119,531
            )Financing
                activities:Change
                in short-term debt, net
            
            
            (13,157
            )
            
            100,035Dividends
                paid
            
            
            (25,929
            )
            
            (21,924
            )Issuance
                of common stock
            
            
            1,788
            
            
            1,017Issuance
                of bonds and notes
            
            
            1,264
            
            
            --Redemption
                of bonds and notes
            
            
            --
            
            
            (2,946
            )Issuance
                costs of bonds and other
            
            
            137
            
            
            (737
            )Net
                cash provided (used) by financing activities
            
            
            (35,897
            )
            
            75,445Net
                increase (decrease) in cash
            
            
            (962
            )
            
            1,568Cash
                at beginning of year
            
            
            22,897
            
            
            19,771Cash
                at end of period
            
            $
            21,935
            
            $
            21,339Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            30,823
            
            $
            32,511Income
                taxes
            
            
            30,000
            
            
            22,000





*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
              March
                31,2006
            
            2005Operating
                revenues:Electric
            
            $
            467,424
            
            $
            420,090Gas
            
            
            406,588
            
            
            321,129Other
            
            
            3,723
            
            
            434Total
                operating revenues
            
            
            877,735
            
            
            741,653Operating
                expenses:Energy
                costs:Purchased
                electricity
            
            
            252,125
            
            
            208,178Electric
                generation fuel
            
            
            21,584
            
            
            20,448Residential
                exchange
            
            
            (56,633
            )
            
            (55,046
            )Purchased
                gas
            
            
            266,679
            
            
            201,744Net
                unrealized loss on derivative instruments
            
            
            975
            
            
            509Utility
                operations and maintenance
            
            
            87,364
            
            
            75,522Other
                operations and maintenance
            
            
            320
            
            
            259Depreciation
                and amortization
            
            
            63,884
            
            
            58,077Conservation
                amortization
            
            
            8,048
            
            
            5,162Taxes
                other than income taxes
            
            
            79,732
            
            
            69,700Income
                taxes
            
            
            40,703
            
            
            46,545Total
                operating expenses
            
            
            764,781
            
            
            631,098Operating
                income
            
            
            112,954
            
            
            110,555Other
                income (deductions):Other
                income, net of tax
            
            
            2,339
            
            
            1,164Interest
                charges:AFUDC
            
            
            2,022
            
            
            1,462Interest
                expense
            
            
            (43,542
            )
            
            (40,976
            )Mandatorily
                redeemable securities interest expense
            
            
            (23
            )
            
            (23
            )Net
                income before cumulative effect of accounting change
            
            $
            73,750
            
            $
            72,182Cumulative
                effect of implementation of accounting change (net of tax)
            
            
            (89
            )
            
            --Net
                income
            
            $
            73,839
            
            $
            72,182





*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
              March
                31,2006
            
            2005Net
                income
            
            $
            73,839
            
            $
            72,182Other
                comprehensive income, net of tax at 35%:Net
                unrealized (losses) gains on derivative instruments during the
                period
            
            
            (5,281
            )
            
            15,658Reversal
                of net unrealized gains on derivative instruments settled
              during
                the period
            
            
            (7,607
            )
            
            (1,817
            )Amortization
                of cash flow hedge contracts to earnings
            
            
            191
            
            
            --Deferral
                of cash flow hedges related to power cost adjustment
                mechanism
            
            
            5,557
            
            
            (5,563
            )Other
                comprehensive income (loss)
            
            
            (7,140
            )
            
            8,278Comprehensive
                income
            
            $
            66,699
            
            $
            80,460





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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)


(Unaudited)





**ASSETS**





March
                31,
              2006
            
            December
                31,
              2005Utility
                plant: (at original cost, including construction work in progress
                of
                $228,557 and $216,513, respectively)Electric
            
            $
            4,842,555
            
            $
            4,802,363Gas
            
            
            2,013,902
            
            
            1,991,456Common
                plant
            
            
            444,421
            
            
            439,599Less:
                Accumulated depreciation and amortization
            
            
            (2,632,990
            )
            
            (2,602,500
            )Net
                utility plant
            
            
            4,667,888
            
            
            4,630,918Other
                property and investments
            
            
            156,230
            
            
            157,321Current
                assets:Cash
            
            
            17,872
            
            
            16,709Restricted
                cash
            
            
            1,048
            
            
            1,047Accounts
                receivable, net of allowance for doubtful accounts
            
            
            300,021
            
            
            299,938Secured
                pledged accounts receivable
            
            
            24,000
            
            
            41,000Unbilled
                revenues
            
            
            120,037
            
            
            160,207Purchased
                gas adjustment receivable
            
            
            72,414
            
            
            67,335Materials
                and supplies, at average cost
            
            
            37,028
            
            
            36,491Fuel
                and gas inventory, at average cost
            
            
            45,973
            
            
            91,058Unrealized
                gain on derivative instruments
            
            
            32,475
            
            
            75,037Prepayments
                and other
            
            
            9,150
            
            
            7,023Total
                current assets
            
            
            660,018
            
            
            795,845Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            125,431
            
            
            129,693Regulatory
                asset for PURPA contract buyout costs
            
            
            185,363
            
            
            191,170Unrealized
                gain on derivative instruments
            
            
            20,190
            
            
            28,464Power
                cost adjustment mechanism
            
            
            25,879
            
            
            18,380Other
            
            
            517,489
            
            
            388,009Total
                other long-term assets
            
            
            874,352
            
            
            755,716Total
                assets
            
            $
            6,358,488
            
            $
            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**





March
                31,
              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
            
            
            928,676
            
            
            924,154Earnings
                reinvested in the business
            
            
            238,731
            
            
            196,248Accumulated
                other comprehensive income, net of tax at 35%
            
            
            41
            
            
            7,181Total
                shareholder’s equity
            
            
            2,026,486
            
            
            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
            
            
            237,750
            
            
            237,750Long-term
                debt
            
            
            2,083,360
            
            
            2,183,360Total
                redeemable securities and long-term debt
            
            
            2,322,999
            
            
            2,422,999Total
                capitalization
            
            
            4,349,485
            
            
            4,409,620Current
                liabilities:Accounts
                payable
            
            
            339,179
            
            
            346,490Short-term
                debt
            
            
            25,600
            
            
            41,000Current
                maturities of long-term debt
            
            
            181,000
            
            
            81,000Accrued
                expenses:Taxes
            
            
            133,915
            
            
            111,900Salaries
                and wages
            
            
            12,796
            
            
            15,034Interest
            
            
            46,473
            
            
            31,004Unrealized
                loss on derivative instruments
            
            
            33,476
            
            
            9,772Deferred
                income taxes
            
            
            5,902
            
            
            10,968Other
            
            
            39,942
            
            
            30,932Total
                current liabilities
            
            
            818,283
            
            
            678,100Long-term
                liabilities:Deferred
                income taxes
            
            
            735,021
            
            
            739,162Other
                deferred credits
            
            
            455,699
            
            
            512,918Total
                long-term liabilities
            
            
            1,190,720
            
            
            1,252,080Total
                capitalization and liabilities
            
            $
            6,358,488
            
            $
            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)


Three
                Months Ended
              March
                31,2006
            
            2005Operating
                activities:Net
                income
            
            $
            73,839
            
            $
            72,182Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation
                and amortization
            
            
            63,884
            
            
            58,077Deferred
                income taxes and tax credits, net
            
            
            (1,101
            )
            
            5,735Net
                unrealized loss on derivative instruments
            
            
            975
            
            
            509Accrual
                of contract initiation payment
            
            
            (89,000
            )
            
            --Power
                cost adjustment mechanism
            
            
            (7,499
            )
            
            (15,020
            )Cash
                collateral received from (returned to) energy suppliers
            
            
            (14,850
            )
            
            3,100Decrease
                in residential exchange program
            
            
            (12,746
            )
            
            (11,159
            )Other
            
            
            639
            
            
            10,394Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            57,085
            
            
            (102,060
            )Materials
                and supplies
            
            
            (537
            )
            
            (1,106
            )Fuel
                and gas inventory
            
            
            45,085
            
            
            11,453Prepayments
                and other
            
            
            (2,128
            )
            
            (4,962
            )Purchased
                gas adjustment receivable
            
            
            (5,079
            )
            
            (3,243
            )Accounts
                payable
            
            
            (7,310
            )
            
            (23,865
            )Taxes
                payable
            
            
            22,016
            
            
            32,843Tenaska
                disallowance reserve
            
            
            --
            
            
            (3,156
            )Accrued
                expenses and other
            
            
            22,242
            
            
            10,263Net
                cash provided by operating activities
            
            
            145,515
            
            
            39,985Investing
                activities:Construction
                expenditures - excluding equity AFUDC
            
            
            (101,268
            )
            
            (117,931
            )Energy
                efficiency expenditures
            
            
            (6,884
            )
            
            (4,738
            )Refundable
                cash received for customer construction projects
            
            
            2,554
            
            
            3,582Restricted
                cash
            
            
            (1
            )
            
            487Other
            
            
            6,273
            
            
            5,514Net
                cash used by investing activities
            
            
            (99,326
            )
            
            (113,086
            )Financing
                activities:Change
                in short-term debt, net
            
            
            (15,400
            )
            
            97,051Dividends
                paid
            
            
            (31,356
            )
            
            (23,053
            )Investment
                from Puget Energy
            
            
            1,569
            
            
            --Issuance
                cost of bonds and other
            
            
            161
            
            
            132Net
                cash provided (used) by financing activities
            
            
            (45,026
            )
            
            74,130Net
                increase in cash
            
            
            1,163
            
            
            1,029Cash
                at beginning of year
            
            
            16,709
            
            
            12,955Cash
                at end of period
            
            $
            17,872
            
            $
            13,984Supplemental
                cash flow information:Cash
                payments for:Interest
                (net of capitalized interest)
            
            $
            28,394
            
            $
            30,549Income
                taxes
            
            
            30,000
            
            
            22,000





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





**COMBINED
      NOTES TO CONSOLIDATED FINANCIAL
      STATEMENTS**








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





**Basis
      of Presentation**


Puget
      Energy is a holding company that owns Puget Sound Energy (PSE) and a 90.9%
      ownership interest in InfrastruX Group, Inc. (InfrastruX). PSE is a public
      utility incorporated in the State of Washington and furnishes electric and
      gas
      services in a territory covering 6,000 square miles, primarily in the Puget
      Sound region. InfrastruX is a non-regulated utility construction 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.


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 until May 2006 owned a 90.9% interest in InfrastruX.
      The results of PSE and InfrastruX are presented on a consolidated basis. The
      financial position and results of operations for InfrastruX are presented as
      discontinued operations. 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
      now only has one reportable segment.


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








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





Following
      a strategic review of InfrastruX that was completed in February 2005, Puget
      Energy’s Board of Directors decided to exit the utility construction services
      sector. Puget Energy believes the planned disposal of InfrastruX meets the
      criteria established for recognition as a discontinued operation under SFAS
      No.
      144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and is
      accounted for as such in Puget Energy’s consolidated financial statements in
      2005 and 2006. In May 2006, Puget Energy entered into a sale agreement with
      an
      affiliate of Tenaska Power Fund L.P. to sell InfrastruX. The total purchase
      price was $275 million. After repayment of debt, adjustments for working
      capital, transaction costs and distributions to minority interests, Puget Energy
      expects to receive after-tax cash proceeds of approximately $83 million to
      $88
      million for its 90.9% interest in InfrastruX. The sale is expected to result
      in
      an after-tax gain of approximately $24 million to $29 million to Puget Energy
      in
      the second quarter of 2006.


For
      the
      three months ended March 31, 2006, Puget Energy reported InfrastruX related
      income from discontinued operations (net of taxes and minority interest) of
      $18.9 million compared to a loss of $1.0 million (net of taxes and minority
      interest) for the three months ended March 31, 2005. Puget Energy’s income from
      discontinued operations for the three months ended March 31, 2006 includes
      $7.3
      million related to the reversal of a carrying value adjustment recorded in
      2005
      as well as $10 million related to the anticipated realization of a deferred
      tax
      asset associated with the sale of the business in accordance with EITF No.
      93-17, “Recognition of Deferred Tax Assets for a Parent Company’s Excess Tax
      Basis in the Stock of a Subsidiary That is accounted for as a Discontinued
      Operation.” In accordance with SFAS No. 144, Puget Energy discontinued
      depreciation and amortization of InfrastruX’s assets effective February 8, 2005.


The
      following table summarizes Puget Energy’s income from discontinued
      operations:





Three
                Months Ended March 31,
              (Dollars
                in thousands)
            
            2006
            
            2005Net
                loss reported by InfrastruX
            
            $
            (331
            )
            $
            (1,496
            )InfrastruX
                depreciation and amortization not recorded
              by
                Puget Energy, net of tax
            
            
            3,071
            
            
            1,597Puget
                Energy tax benefit (valuation allowance) from goodwill
                deduction
            
            
            174
            
            
            --Puget
                Energy carrying value adjustment of InfrastruX
            
            
            7,269
            
            
            --Puget
                Energy cost of sale related to InfrastruX, net of tax
            
            
            (937
            )
            
            (1,116
            )Puget
                Energy deferred tax basis adjustment of InfrastruX
            
            
            9,966
            
            
            --Minority
                interest in income from discontinued operations
            
            
            (265
            )
            
            (3
            )Income
                (loss) from discontinued operations
            
            $
            18,947
            
            $
            (1,018
            )





InfrastruX’s
      bank and vendor debt under its credit agreements totaled $133.8 million at
      March
      31, 2006 compared to $130.3 million at December 31, 2005 and $159.4 million
      at
      March 31, 2005. In May 2004, InfrastruX signed a three-year agreement with
      a
      group of banks to provide up to $150 million in financing, with Puget Energy
      as
      guarantor. Certain InfrastruX subsidiaries also have borrowing capacities for
      working capital purposes of which Puget Energy is not the guarantor. Of the
      $150
      million bank facility available to InfrastruX, $112 million was outstanding
      at
      March 31, 2006 and December 31, 2005. In determining the fair value of its
      InfrastruX investment, Puget Energy has determined proceeds of a sale will
      first
      be used to extinguish all outstanding InfrastruX debt.


The
      expected net proceeds from a proposed sale of InfrastruX exceed its carrying
      value at March 31, 2006. In accordance with SFAS No. 144, Puget Energy has
      reversed the previously recorded SFAS No. 144 impairment charge to adjust the
      investment in InfrastruX to the lower of its carrying value without the
      impairment, less cost to sell, or fair value. After reflecting the adjustment,
      tax-basis adjustment and related transaction costs of $12.4 million in 2005,
      Puget Energy’s equity investment in InfrastruX was $52.9 million at March 31,
      2006 compared to $43.5 million at December 31, 2005. The following amounts
      related to InfrastruX have been segregated from continuing operations and
      reflected as discontinued operations:


Three
                Months Ended, March 31,(Dollars
                in thousands)
            
            2006
            
            2005Revenues
            
            $
            92,070
            
            $
            77,692Operating
                expenses (including interest expense)
            
            
            87,823
            
            
            77,716Carrying
                value adjustment
            
            
            (7,269
            )
            
            --Cost
                of sale
            
            
            937
            
            
            1,717Pre-tax
                income
            
            
            10,579
            
            
            (1,741
            )Income
                tax benefit
            
            
            8,633
            
            
            726Minority
                interest in income of discontinued operations
            
            
            (265
            )
            
            (3
            )Income
                (loss) from discontinued operations
            
            $
            18,947
            
            $
            (1,018
            )





In
      accordance with SFAS No. 144, InfrastruX discontinued depreciation and
      amortization of its assets effective February 8, 2005. This discontinuation
      of
      depreciation and amortization resulted in $4.8 million ($3.1 million after-tax)
      and $2.6 million ($0.9 million after-tax) lower depreciation and amortization
      expense than otherwise would have been recorded as continuing operations for
      the
      three months ended March 31, 2006 and 2005, respectively.


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


(Dollars
                in thousands)
            
            March
                31,
              2006
            
            December
                31,
              2005Assets:Cash
            
            $
            4,061
            
            $
            6,187Accounts
                receivable
            
            
            79,379
            
            
            78,842Other
                current assets
            
            
            25,095
            
            
            22,405Total
                current assets
            
            
            108,535
            
            
            107,434Goodwill
            
            
            43,886
            
            
            43,886Intangibles
            
            
            13,924
            
            
            14,443Non-utility
                property and other
            
            
            120,984
            
            
            108,784Total
                long-term assets
            
            
            178,794
            
            
            167,113Total
                assets
            
            $
            287,329
            
            $
            274,547Liabilities:Accounts
                payable
            
            $
            11,575
            
            $
            9,178Short-term
                debt
            
            
            6,052
            
            
            3,809Current
                maturities of long-term debt
            
            
            6,576
            
            
            6,477Other
                current liabilities
            
            
            34,019
            
            
            36,327Total
                current liabilities
            
            
            58,222
            
            
            55,791Deferred
                income taxes
            
            
            24,527
            
            
            24,645Long-term
                debt
            
            
            121,178
            
            
            120,013Other
                deferred credits
            
            
            15,359
            
            
            16,986Total
                long-term liabilities
            
            
            161,064
            
            
            161,644Total
                liabilities
            
            $
            219,286
            
            $
            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 115,725,000 for the three months ended
      March 31, 2006, and 99,953,000 for the three months ended March 31, 2005.


Puget
      Energy’s diluted earnings per common share have been computed based on weighted
      average common shares outstanding of 116,190,000 for the three months ended
      March 30, 2006, and 100,446,000 for the three months ended March 31, 2005.
      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
      March
      31, 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 March 31, 2006, the Company recorded a decrease in
      earnings for the change in the market value of derivative instruments not
      meeting NPNS nor cash flow hedge criteria of approximately $1.0 million compared
      to a decrease in earnings of approximately $0.5 million for the three months
      ended March 31, 2005. At March 31, 2006, the Company had a net unrealized gain
      recorded in other comprehensive income of $29.6 million after-tax related to
      energy and financial contracts which meet the criteria for designation as cash
      flow hedges under SFAS No. 133. In 2006, a portion of the total unrealized
      gain
      on cash flow hedge transactions in other comprehensive income and the
      marked-to-market loss in the income statement were deferred in accordance with
      SFAS No. 71 due to the Company exceeding the $40 million cap under the PCA
      mechanism. At March 31, 2006, PSE had a net short-term asset of $14.6 million
      on
      non-cash flow hedges and a long-term asset of $20.2 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.


At
      March
      31, 2006, the Company also has a net short-term liability of approximately
      $25.2
      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 2005, the Company entered into two forward starting interest
      rate
      swap contracts to hedge against interest rate volatility for a debt offering
      anticipated to be performed in the second half of 2006. A forward starting
      swap
      is a financial arrangement between the Company and a counterparty whereby one
      of
      the parties will be required to make a payment to the other party on a specific
      valuation date based upon the change in value of a designated treasury bond.
      If
      interest rates rise related to the hedged debt from the date of issuance of
      the
      swap instruments, the Company would receive a payment from the counterparty
      for
      the change in the bond value. Alternatively, if interest rates decrease related
      to the hedged debt from the date of issuance of the swap instruments, the
      Company would pay the counterparty for the change in the bond value. These
      swap
      contracts were designated under SFAS No. 133 criteria as cash flow hedges.
      All
      financial hedge contracts of this type are reviewed by senior management and
      presented to the Finance and Budget Committee of the Board of Directors and
      are
      approved prior to execution. At March 31, 2006, the unrealized gain associated
      with the swap contracts was $7.7 million after tax and is included in other
      comprehensive income. The swap contracts settle in 2006.








**(5)**
            **Stock
                Compensation**(Puget
                Energy Only)





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 123R resulted in a cumulative benefit from an accounting change
      amounting to $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 for which compensation expense was
      previously recognized.


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 quarter ended
      March 31, 2006, are $0.1 million and $0.1 million higher, respectively, than
      if
      it had continued to account for share-based compensation under SFAS No. 123.
      Basic and diluted earnings per share for income from continuing operations
      for
      the quarter ended March 31, 2006, would have been $0.80 and $0.79, respectively,
      if the Company had not adopted SFAS No. 123R, compared to basic and diluted
      earnings per share of $0.80 and $0.79, respectively.


Had
      the
      Company 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:





Three
                Months Ended March 31,(Dollars
                in thousands, except per share amounts)
            
            2005Net
                income, as reported
            
            $
            71,075Add:
                Total stock-based employee compensation expense included in net income,
                net of tax
            
            
            636Less:
                Total stock-based employee compensation expense per the fair value
                method
                of SFAS No. 123, net of tax
            
            
            (810
            )Pro
                forma net income
            
            $
            70,901Earnings
                per share:Basic
                per common share as reported
            
            $
            0.71Diluted
                per common share as reported
            
            $
            0.71Basic
                per common share pro forma
            
            $
            0.71Diluted
                per common share pro forma
            
            $
            0.71





The
      Company’s Long-Term Incentive Plan (LTI Plan), established in 1995, 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 $0.8 million for the quarters ended March 31, 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 $21.18, $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 March 31, 2006, there were four active grant
      cycles for a total of 863,394 grants outstanding. As of December 31, 2005,
      there
      were four active grant cycles for a total of 907,983 share grants outstanding.
      As of March 31, 2006, there was $3.8 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 2.25 years.
      During the quarter ended March 31, 2006, 42,892 performance shares were
      forfeited. No performance shares vested during the quarters ended March 31,
      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 are classified
      and accounted for as liabilities 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 the quarterly expense recognized during
      the
      performance period to be 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 March 31, 2006, with 270,000 options
      exercisable. There is no aggregate intrinsic value of options vested (or
      expected to vest) or options currently exercisable at March 31, 2006. At March
      31, 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 $0.02 million for the quarter ended March 31, 2006. As of March 31, 2006,
      there was $0.1 million 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 quarters ended March 31, 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 quarter
      ended March 31, 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 March 31,
      2006, there were 213,181 total shares of nonvested restricted stock and the
      weighted average grant date fair value of these shares was $22.01. Compensation
      expense related to the restricted shares, including the restricted shares
      granted as part of the 2006 LTIP cycle, was $0.5 million and $0.1 million for
      the quarter ended March 31, 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 March 31, 2006, there
      was $1.7 million of total unrecognized compensation cost related to nonvested
      restricted stock. That cost is expected to be recognized over a weighted-average
      period of 2.7 years. No restricted stock vested or was forfeited during the
      quarters ended March 31, 2006 and 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**


The
      Company also 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 March 31, 2006,
      there were 4,216 total shares of nonvested restricted stock units and the
      weighted average fair value of these units was $21.18. There were no restricted
      stock units granted or forfeited during the quarter ended March 31, 2006. There
      were 643 restricted stock units accrued during the quarter ended March 31,
      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 quarter ended March
      31,
      2006 and 2005. The weighted average grant date fair value for the restricted
      stock units was $23.55. As of March 31, 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 2 years.
      The
      fair value of the restricted stock 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 in 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 March 31, 2006 there were 7,522
      total shares of nonvested retirement equivalent stock units and the weighted
      average grant date fair value of these units was $22.72. During the quarter
      ended March 31, 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 $0.1 million and $0.1 million for
      the
      quarter ended March 31, 2006 and 2005, respectively. 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 March 31, 2006,
      there was $0.2 million of total unrecognized compensation cost related to
      nonvested retirement equivalent stock units. That cost is expected to be
      recognized over a weighted-average period of 2.17 years. There were 5,709
      retirement equivalent stock units that vested during the quarter ended March
      31,
      2006. No retirement equivalent stock units were forfeited during the quarter
      ended March 31, 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
      December 31, 2005, 148,814 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. As of March 31, 2006, 32,609
      purchase rights had been granted. Dividends are not paid on ESPP shares until
      they are purchased by employees and thus are accounted for as dividends, not
      compensation expense. No purchase rights vested or were forfeited for the
      quarter ended March 31, 2006 and 2005, respectively.





**Non-Employee
      Director Stock Plan**


The
      Company has a director stock plan approved 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
      for
      the quarter ended March 31, 2006 and 2005, 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 March 31, 2006, 30,617 shares had been issued or purchased
      for the director stock plan and 78,650 deferred, for a total of 109,268 shares.
      As of March 31, 2005, the number of shares that had been purchased for the
      director stock plan was 19,095 and 66,866 deferred, for a total of 85,961
      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*





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
      March 31:





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2006
            
            2005
            
            2006
            
            2005Service
                cost
            
            $
            3,061
            
            $
            3,014
            
            $
            86
            
            $
            84Interest
                cost
            
            
            6,167
            
            
            5,949
            
            
            358
            
            
            419Expected
                return on plan assets
            
            
            (9,434
            )
            
            (9,514
            )
            
            (182
            )
            
            (219
            )Amortization
                of prior service cost
            
            
            585
            
            
            717
            
            
            134
            
            
            116Recognized
                net actuarial (gain) loss
            
            
            1,253
            
            
            767
            
            
            (127
            )
            
            (24
            )Amortization
                of transition (asset) obligation
            
            
            --
            
            
            (41
            )
            
            105
            
            
            105Net
                periodic benefit cost
            
            $
            1,632
            
            $
            892
            
            $
            374
            
            $
            481





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 months ended March
      31,
      2006, the actual cash contributions to the pension plans were $0.5 million.
      Based on this activity, the Company anticipates contributing an additional
      $1.6
      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 months ended March 31, 2006, actual other post-retirement medical
      benefit plan contributions were $0.4 million, and the Company expects to make
      additional contributions of $0.3 million for a total of $0.7 in
      2006.


On
      March
      31, 2006, FASB issued a Proposed Statement of Financial Accounting Standard
      titled “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 benefit obligation. At December 31, 2005, the
      combined fair value of plan assets and 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.








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





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
      interest 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 interest on a temporary basis until resolution of PSE’s
      electric general rate case later this year.


At
      March
      31, 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 $28.0 million,
      including interest, on its past due receivables as of March 31,
      2006.


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


For
      the
      three purchase power agreements that may be considered variable interest
      entities under FIN 46R, PSE is required to buy all the generation from these
      plants, subject to displacement by PSE, at rates set forth in the purchase
      power
      agreements. If at any time the counterparties cannot deliver energy to PSE,
      PSE
      would have to buy energy in the wholesale market at prices which could be higher
      or lower than the purchase power agreement prices. PSE’s purchased electricity
      expense for the three months ended March 31, 2006 and 2005 for these three
      entities was $58.8 million and $71.8 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 contracts, including
      the amended settlement agreement and the May 2004 agreement between BPA and
      PSE.
      BPA rates used in such amended settlement agreement between BPA and PSE for
      determining the amounts of money to be paid to PSE by BPA under the amended
      settlement agreement and other agreements described above 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.
      It is not clear what impact, if any, review of such rates and contracts and
      the
      above described U.S. Ninth Circuit Court of Appeals actions may have on PSE.








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





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








**Overview**





Puget
      Energy is an energy services holding company and all of its operations are
      conducted through its two subsidiaries. These subsidiaries are Puget Sound
      Energy (PSE), a regulated electric and gas utility company, and until May 2006,
      InfrastruX, a utility construction and services company. Following a strategic
      review of Puget Energy’s unregulated subsidiary, InfrastruX, that was completed
      in February 2005, Puget Energy’s Board of Directors decided to exit the utility
      construction services sector. InfrastruX is presented in the financial
      statements as discontinued operations. On April 29, 2006, the board of directors
      of Puget Energy, Inc. approved the merger of InfrastruX with an affiliate of
      Tenaska Power Fund L.P. (“Tenaska”), through which Tenaska will acquire
      InfrastruX and in May 2006, Puget Energy entered into a sale agreement with
      an
      affiliate of Tenaska Power Fund L.P. to sell InfrastruX. The total purchase
      price was $275 million. After repayment of debt, adjustments for working
      capital, transaction costs and distributions to minority interests, Puget Energy
      expects to receive after-tax cash proceeds of approximately $83 million to
      $88
      million for its 90.9% interest in InfrastruX. The sale is expected to result
      in
      an after-tax gain of approximately $24 million to $29 million to Puget Energy
      in
      the second quarter of 2006. See section titled “InfrastruX” for further
      discussion.





**Puget
      Sound Energy**


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


As
      a
      regulated utility company, PSE is subject to Federal Energy Regulatory
      Commission (FERC) and Washington Utilities and Transportation Commission
      (Washington Commission) regulation which may impact a large array of business
      activities, including limitation of future rate increases; directed accounting
      requirements that may negatively impact earnings; licensing of PSE-owned
      generation facilities; and other FERC and Washington Commission directives
      that
      may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent
      to the utility industry as a whole, including weather changes affecting
      purchases and sales of energy; outages at owned and non-owned generation plants
      where energy is obtained; storms or other events which can damage electric
      distribution and transmission lines; and 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 for 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 its subsidiaries, PSE and
      until
      May 2006, InfrastruX. Net income for the three months ended March 31, 2006
      was
      $92.6 million on operating revenues from continuing operations of $877.7 million
      compared to net income of $71.1 million on operating revenues from continuing
      operations of $741.7 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 March 31, 2006 was $0.80
      and $0.79, respectively, compared to basic and diluted earnings per share for
      the three months ended March 31, 2005 of $0.71. Included in the basic and
      diluted earnings per share for the three months ended March 31, 2006 and 2005
      was $0.16 and $(0.01), respectively, earnings per share related to discontinued
      operations of InfrastruX.


Net
      income for the three months ended March 31, 2006 reflects the reversal of an
      InfrastruX carrying value charge recognized in 2005 of $7.3 million and a
      deferred tax benefit on the carrying value and tax basis difference amounting
      to
      $10.0 million. The InfrastruX carrying value adjustment and deferred tax benefit
      contributed to income from discontinued operations of $18.9 million for the
      three months ended March 31, 2006 compared to a loss of $1.0 million in the
      same
      period in 2005. Net income for the three months ended March 31, 2006 was also
      positively impacted by increased natural gas and electric margins of $12.7
      million and $4.4 million, respectively, compared to the same period in 2005
      primarily from increased electric and natural gas sales volumes. The increase
      was offset by higher storm damage repair costs 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 March 31, 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 March 31,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeElectric
                retail sales revenue
            
            $
            435.2
            
            $
            387.0
            
            $
            48.2
            
            
            12.5
            %Electric
                transportation revenue
            
            
            2.7
            
            
            2.7
            
            
            --
            
            
            --
            %Other
                electric revenue-gas supply resale
            
            
            5.9
            
            
            4.2
            
            
            1.7
            
            
            40.5
            %Total
                electric revenue for margin1
            
            
            443.8
            
            
            393.9
            
            
            49.9
            
            
            12.7
            %Adjustments
                for amounts included in revenue:Pass-through
                production tax credits (PTCs)
            
            
            3.9
            
            
            --
            
            
            3.9
            
            
            *Pass-through
                tariff items
            
            
            (8.6
            )
            
            (6.5
            )
            
            (2.1
            )
            
            (32.3
            )%Pass-through
                revenue-sensitive taxes
            
            
            (31.9
            )
            
            (28.6
            )
            
            (3.3
            )
            
            (11.5
            )%Residential
                exchange credit
            
            
            56.6
            
            
            55.0
            
            
            1.6
            
            
            2.9
            %Net
                electric revenue for margin
            
            
            463.8
            
            
            413.8
            
            
            50.0
            
            
            12.1
            %Minus
                power costs:Electric
                generation fuel
            
            
            (21.6
            )
            
            (20.4
            )
            
            (1.2
            )
            
            (5.9
            )%Purchased
                electricity, net of sales to other utilities and marketers2
            
            
            (243.5
            )
            
            (209.8
            )
            
            (33.7
            )
            
            (16.1
            )%Total
                electric power costs3
            
            
            (265.1
            )
            
            (230.2
            )
            
            (34.9
            )
            
            (15.2
            )%Electric
                margin before PCA
            
            
            198.7
            
            
            183.6
            
            
            15.1
            
            
            8.2
            %Tenaska
                disallowance reserve
            
            
            --
            
            
            5.3
            
            
            (5.3
            )
            
            *Power
                cost deferred under the PCA mechanism
            
            
            7.2
            
            
            12.6
            
            
            (5.4
            )
            
            (42.9
            )%Electric
                margin4
            
            $
            205.9
            
            $
            201.5
            
            $
            4.4
            
            
            2.2
            %


_________________________________




*
            *Percent
                change not applicable or unmeaningful**.*1
            *For
                the three months ended March 31, 2006, total electric revenue for
                margin
                was $443.8 million, which does not include $15.8 million in sales
                to other
                utilities and marketers and $7.8 million in other miscellaneous electric
                revenue included in electric operating revenues of $467.4 million.
                For the
                three months ended March 31, 2005, total electric revenue for margin
                was
                $393.9 million, which does not include $16.3 million in sales to
                other
                utilities and marketers and $9.8 million in other miscellaneous electric
                revenues included in electric operating revenues of $420.0
                million.*2
            *For
                the three months ended March 31, 2006, purchased electricity, net
                of sales
                to other utilities and marketers, was $243.5 million, excluding sales
                to
                other utilities and marketers of $15.8 million and including power
                cost
                deferral under the PCA mechanism of $(7.2) million, purchased electricity
                was $252.1 million. For the three months ended March 31, 2005, purchased
                electricity, net of sales to other utilities and marketers, was $209.8
                million, excluding sales to other utilities and marketers of $16.3
                million
                and including the Tenaska disallowance reserve turnaround of $(5.3)
                million and power cost deferral under the PCA mechanism of $(12.6)
                million, purchased electricity was $208.2 million.*3
            *For
                the three months ended March 31, 2006, total electric power costs
                were
                $265.1 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 $(56.6)
                million and unrealized net loss on derivative instruments of $1.0
                million.
                These amounts, excluding sales of electricity to other utilities
                and
                marketers, provide electric energy costs of $218.1 million. For the
                three
                months ended March 31, 2005, total electric power costs were $230.2
                million, which includes electric generation fuel and purchased
                electricity, net of sales to other utilities and marketers (see note
                2
                above), but does not include the residential exchange credit of $(55.0)
                million and unrealized net loss on derivative instruments of $0.5
                million.
                These amounts excluding sales of electricity to other utilities and
                marketers provide electric energy costs of $174.1
                million.*4
            *Electric
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense**.*





Electric
      margin increased $4.4 million for the three months ended March 31, 2006 compared
      to the same period in 2005, primarily due to increase in retail customer usage
      and varied usage among customer classes as compared to 2005. Retail customer
      kWh
      sales (residential, commercial and industrial customers) increased 4.4% for
      the
      three months ended March 31, 2006 compared to 2005. 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 for the three months ended March 31, 2006 compared to the same
      period in 2005. The electric general rate increase effective March 4, 2005
      primarily recovers increases in power costs and thus does not have a material
      effect on margin.


The
      following table displays the details of gas margin changes for the three months
      ended March 31, 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 March 31,
              
              2006
              
              2005
              
              Change
              
              Percent
                ChangeGas
                  retail revenue
              
              $
              398.7
              
              $
              312.9
              
              $
              85.8
              
              
              27.4
              %Gas
                  transportation revenue
              
              
              3.6
              
              
              3.4
              
              
              0.2
              
              
              5.9
              %Total
                  gas revenue for margin1
              
              
              402.3
              
              
              316.3
              
              
              86.0
              
              
              27.2
              %Adjustments
                  for amounts included in revenue:Pass-through
                  tariff items
              
              
              (2.6
              )
              
              (1.9
              )
              
              (0.7
              )
              
              (36.8
              )%Pass-through
                  revenue-sensitive taxes
              
              
              (32.7
              )
              
              (25.1
              )
              
              (7.6
              )
              
              (30.3
              )%Net
                  gas revenue for margin
              
              
              367.0
              
              
              289.3
              
              
              77.7
              
              
              26.9
              %Minus
                  purchased gas costs
              
              
              (266.7
              )
              
              (201.7
              )
              
              (65.0
              )
              
              (32.2
              )%Gas
                  margin2
              
              $
              100.3
              
              $
              87.6
              
              $
              12.7
              
              
              14.5
              %
 _________________________________




1
            *For
                the three months ended March 31, 2006, total gas revenue for margin
                was
                $402.3 million, which does not include $4.3 million related to other
                gas
                operating revenues that is included in gas operating revenues of
                $406.6
                million. For the three months ended March 31, 2005, total gas revenue
                for
                margin was $316.3 million, which does not include $4.8 million related
                to
                other gas operating revenues that is included in gas operating revenues
                of
                $321.1 million.*2
            *Gas
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Gas
      margin increased $12.7 million for the three months ended March 31, 2006
      compared to the same period in 2005 primarily due to increased gas general
      tariff rates and increased usage by customers. Gas margin increased $7.0 million
      as a result of the gas general tariff increase effective March 4, 2005. Therm
      sales increased 8.5% for the three months ended March 31, 2006 compared to
      the
      same period in 2005, which provided $7.4 million to gas margin. Gas margin
      decreased $1.7 million for the three months ended March 31, 2006 compared to
      the
      same period in 2005 as a result of changes in customer class usage.





**Electric
      Operating Revenues**


The
      table
      below sets forth changes in electric operating revenues for PSE for the three
      months ended March 31, 2006 compared to the same period in 2005.




(Dollars
                  in Millions)
                Three
                  Months Ended March 31,
              
              2006
              
              2005
              
              Change
              
              Percent
                ChangeElectric
                  operating revenues:Residential
                  sales
              
              $
              241.9
              
              $
              211.8
              
              $
              30.1
              
              
              14.2
              %Commercial
                  sales
              
              
              182.8
              
              
              157.9
              
              
              24.9
              
              
              15.8
              %Industrial
                  sales
              
              
              26.3
              
              
              22.1
              
              
              4.2
              
              
              19.0
              %Other
                  retail sales, including unbilled revenue
              
              
              (15.8
              )
              
              (4.8
              )
              
              (11.0
              )
              
              *Total
                  retail sales
              
              
              435.2
              
              
              387.0
              
              
              48.2
              
              
              12.5
              %Transportation
                  sales
              
              
              2.7
              
              
              2.7
              
              
              --
              
              
              --
              %Sales
                  to other utilities and marketers
              
              
              15.8
              
              
              16.3
              
              
              (0.5
              )
              
              (3.1
              )%Other
              
              
              13.7
              
              
              14.0
              
              
              (0.3
              )
              
              (2.1
              )%Total
                  electric operating revenues
              
              $
              467.4
              
              $
              420.0
              
              $
              47.4
              
              
              11.3
              %


___________________


*
            *Percent
                change not applicable or
                meaningful*





Electric
      retail sales increased $48.2 million for the three months ended March 31, 2006
      compared to the same period in 2005 due primarily to rate increases related
      to
      the Power Cost Only Rate Case (PCORC), the electric general rate case and
      increased retail customer usage. The PCORC and electric general rate case
      provided $21.1 million and $6.4 million to electric operating revenues,
      respectively, for the three months ended March 31, 2006 compared to the same
      period in 2005. Retail electricity usage increased 246,635 MWh or 4.4% for
      the
      three months ended March 31, 2006 compared to the same period in 2005, which
      resulted in an approximate $16.8 million increase in electric operating revenue.
      During the three month period ended March 31, 2006, the benefits of the
      Residential and Farm Energy Exchange Benefit credited to customers reduced
      electric operating revenues by $59.3 million compared to $57.6 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 March 31, 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 $3.9 million. The PTCs also reduced
      income taxes. The PTCs began November 2005 when the Hopkins Ridge wind
      generation facility was placed in service.


Sales
      to
      other utilities and marketers decreased $0.5 million compared to the three
      month
      period ended March 31, 2005 primarily due to a decrease of 25,877 MWh sold
      related to excess energy available for sale on the wholesale market. The
      decrease in MWh sold was due to differences in timing of the need for power
      to
      serve base load and actual weather conditions. Sales to other utilities and
      marketers are included in the PCA mechanism as a reduction in determining net
      power costs.


Other
      electric revenues decreased $0.3 million for the three months ended March 31,
      2006 compared to the same period in 2005, primarily from the reduction of
      miscellaneous customer revenue and transmission revenue, which reduced other
      electric revenues by $2.1 million for the three months ended March 31, 2006
      compared to the same period in 2005. This decrease was partially offset by
      an
      increase in the sale of non-core gas purchased for intended electric generation
      of $1.8 million during the three months ended March 31, 2006 compared to the
      same period in 2005. 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
            %
            55.6





**Gas
      Operating Revenues**


The
      table
      below sets forth changes in gas operating revenues for PSE for the three months
      ended March 31, 2006 compared to the same period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended March 31,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            265.1
            
            $
            208.7
            
            $
            56.4
            
            
            27.0
            %Commercial
                sales
            
            
            116.8
            
            
            91.2
            
            
            25.6
            
            
            28.1
            %Industrial
                sales
            
            
            16.8
            
            
            13.0
            
            
            3.8
            
            
            29.2
            %Total
                retail sales
            
            
            398.7
            
            
            312.9
            
            
            85.8
            
            
            27.4
            %Transportation
                sales
            
            
            3.6
            
            
            3.4
            
            
            0.2
            
            
            5.9
            %Other
            
            
            4.3
            
            
            4.8
            
            
            (0.5
            )
            
            (10.4
            )%Total
                gas operating revenues
            
            $
            406.6
            
            $
            321.1
            
            $
            85.5
            
            
            26.6
            %




Gas
      retail sales increased $85.8 million for the three months ended March 31, 2006
      compared to the same period in 2005 due to higher Purchased Gas Adjustment
      (PGA)
      mechanism rates in 2006, approval of a 3.5% general gas rate increase in the
      gas
      general rate case effective March 4, 2005, and higher customer gas usage. The
      Washington Commission approved a PGA mechanism rate increase effective October
      1, 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 March 31, 2006, the effects of the PGA
      mechanism rate increases provided an increase of $47.9 million in gas operating
      revenues. In addition, the gas general rate case increased gas rates by 3.5%,
      which provided an additional $7.0 million in gas operating revenue for the
      three
      months ended March 31, 2006 compared to the same period in 2005. An increase
      of
      3.0% in the average number of customers increased customer usage by 28.9 million
      therms or approximately $29.3 million in gas operating revenues.


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 March 31, 2006 compared to the same
      period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended March 31,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangePurchased
                electricity
            
            $
            252.1
            
            $
            208.2
            
            $
            43.9
            
            
            21.1
            %Electric
                generation fuel
            
            
            21.6
            
            
            20.4
            
            
            1.2
            
            
            5.9
            %Purchased
                gas
            
            
            266.7
            
            
            201.7
            
            
            65.0
            
            
            32.2
            %Utility
                operations and maintenance
            
            
            87.4
            
            
            75.5
            
            
            11.9
            
            
            15.8
            %Depreciation
                and amortization
            
            
            63.9
            
            
            58.1
            
            
            5.8
            
            
            10.0
            %Conservation
                amortization
            
            
            8.0
            
            
            5.2
            
            
            2.8
            
            
            53.8
            %Taxes
                other than income taxes
            
            
            79.7
            
            
            69.7
            
            
            10.0
            
            
            14.3
            %Income
                taxes
            
            
            40.7
            
            
            46.5
            
            
            (5.8
            )
            
            (12.5
            )%





**Purchased
      electricity** expenses
      increased $43.9 million for the three months ended March 31, 2006 compared
      to
      the same period in 2005. The increase was primarily the result of increased
      power purchases from higher customer kWh sales and higher wholesale market
      prices. Total purchased power for the three months ended March 31, 2006
      increased 95,182 MWh or 2.0% compared to the same period in 2005. Increases
      in
      the purchases and wholesale price of power contributed $29.3 million to the
      increase. 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 $8.6 million.


PSE’s
      hydroelectric production and related power costs in 2005 was 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 such a trend may have on the amount of electricity that
      will need to be purchased. The April 20, 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 103% of normal, which compares to
      83%
      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 $1.2 million for the three months ended March 31, 2006, compared
      to
      the same period in 2005. The increase is primarily related to an increase in
      the
      cost of coal at Colstrip generating facilities of $2.6 million for the three
      months ended March 31, 2006 compared to the same period in 2005. Offsetting
      the
      increase is a decrease in the cost of gas of PSE-controlled combustion turbine
      generating facilities due to a reduction in generation at the combustion turbine
      generation facilities.


**Purchased
      gas** expenses
      increased $65.0 million for the three months ended March 31, 2006, compared
      to
      the same period 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 March 31, 2006 and December 31, 2005 was $ 72.4 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 $11.9 million for the three months ended March 31, 2006, compared
      to
      the same period in 2005. The increase for the three months ended March 31,
      2006
      includes higher electric distribution system restoration costs as a result
      of a
      series of strong winter storms with high winds in Western Washington during
      2006. Storm damage related costs increased $7.1 million compared to the same
      period in 2005. Operations and maintenance costs at PSE-owned electric
      generating facilities increased $2.0 million due primarily to the Hopkins Ridge
      wind generating facility which was placed in service in November 2005. In
      addition, maintenance of electric and gas distribution system increased $2.7
      million for the three months ended March 31, 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 $5.8 million for the three months ended March 31, 2006, compared
      to
      the same period in 2005 due to additional utility plant placed into service,
      including $2.0 million 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 $2.8 million for the three months ended March 31, 2006 compared to
      the
      same period 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 $10.0 million for the three months ended March 31, 2006, compared
      to
      the same period 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. The increase in revenue based excise taxes was partially offset by
      a
      reduction of property taxes of $1.7 million for the three months ended March
      31,
      2006 compared to the same period in 2005.


**Income
      taxes** decreased $5.8 million for the three months ended March 31, 2006, compared
      to
      the same period in 2005. The decrease was the result of a lower effective tax
      rate as compared to the same period in 2005. Included
      in the lower effective tax rates are production tax credits related to energy
      production from the Hopkins Ridge wind generating facility. The production
      tax
      credits are passed through to electric customers through reduction in electric
      rates.





**Other
      Income And Interest Charges**


The
      table
      below sets forth significant changes in other income and interest charges for
      PSE and its subsidiaries for the three months ended March 31, 2006 compared
      to
      the same period in 2005.





(Dollars
                in Millions)
              Three
                Months Ended March 31,
            
            2006
            
            2005
            
            Change
            
            Percent
              ChangeOther
                income (net of tax)
            
            $
            2.3
            
            $
            1.2
            
            $
            1.1
            
            
            91.7
            %Interest
                charges
            
            
            41.5
            
            
            39.5
            
            
            2.0
            
            
            5.1
            %





**Other
      income** increased
      $1.1 million (after-tax) for the three months ended March 31, 2006 compared
      to
      the same period is 2005 primarily due to increases in the equity portion of
      allowance for funds used during construction and a decrease in long-term
      incentive plan costs.


**Interest
      charges** increased
      $2.0 million for the three months ended March 31, 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 three months ended
      March
      31, 2006 compared to the same period in 2005.




**InfrastruX**


Following
      a strategic review of InfrastruX that was completed in February 2005, Puget
      Energy’s Board of Directors decided to exit the utility construction services
      sector. Puget Energy believes the planned disposal of InfrastruX meets the
      criteria established for recognition as a discontinued operation under SFAS
      No.
      144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and is
      accounted for as such in Puget Energy’s consolidated financial statements in
      2006 and 2005. In May 2006, Puget Energy entered into a sale agreement with
      Tenaska Power Fund L.P. to sell InfrastruX. The
      total
      purchase price was $275 million. After repayment of debt, adjustments for
      working capital, transaction costs and distributions to minority interests,
      Puget Energy expects to receive after-tax cash proceeds of approximately $83
      million to $88 million for its 90.9% interest in InfrastruX. The sale is
      expected to result in an after-tax gain of approximately $24 million to $29
      million to Puget Energy in the second quarter of 2006.


For
      the
      three months ended March 31, 2006, Puget Energy reported InfrastruX related
      income from discontinued operations (net of taxes and minority interest) of
      $18.9 million compared to a loss of $1.0 million (net of taxes and minority
      interest) for the three months ended March 31, 2005. Puget Energy’s income from
      discontinued operations for the three months ended March 31, 2006 includes
      $7.3
      million related to the reversal of a carrying value adjustment recorded in
      2005
      as well as $10 million related to the anticipated realization of a deferred
      tax
      asset associated with the sale of the business in accordance with EITF No.
      93-17, “Recognition of Deferred Tax Assets for a Parent Company’s Excess Tax
      Basis in the Stock of a Subsidiary That is accounted for as a Discontinued
      Operation.” In accordance with SFAS No. 144, Puget Energy discontinued
      depreciation and amortization of InfrastruX’s assets effective February 8, 2005.


The
      following table summarizes Puget Energy’s income from discontinued
      operations:





Three
                Months Ended March 31,
              (Dollars
                in Thousands)
            
            2006
            
            2005Net
                loss reported by InfrastruX
            
            $
            (331
            )
            $
            (1,496
            )InfrastruX
                depreciation and amortization not recorded
              by
                Puget Energy, net of tax
            
            
            3,071
            
            
            1,597Puget
                Energy tax benefit (valuation allowance) from goodwill
                deduction
            
            
            174
            
            
            --Puget
                Energy carrying value adjustment of InfrastruX
            
            
            7,269
            
            
            --Puget
                Energy cost of sale related to InfrastruX, net of tax
            
            
            (937
            )
            
            (1,116
            )Puget
                Energy deferred tax basis adjustment of InfrastruX
            
            
            9,966
            
            
            --Minority
                interest in income from discontinued operations
            
            
            (265
            )
            
            (3
            )Income
                (loss) from discontinued operations
            
            $
            18,947
            
            $
            (1,018
            )





InfrastruX’s
      operating revenue for the three months ended March 31, 2006 was $92.1 million,
      compared to $77.7 million, for the same period in 2005. Pre-tax operating income
      for the three months ended March 31, 2006 was $10.6 million compared to a loss
      of $1.7 million for the same period in 2005. InfrastruX’s bank and vendor debt
      under its credit agreements totaled $133.8 million at March 31, 2006 compared
      to
      $130.3 million at December 31, 2005 and $159.4 million at March 31, 2005. In
      May
      2004, InfrastruX signed a three-year agreement with a group of banks to provide
      up to $150 million in financing. Under the credit agreement, Puget Energy is
      the
      guarantor of the line of credit. Certain InfrastruX subsidiaries also have
      borrowing capacities for working capital purposes of which Puget Energy is
      not
      the guarantor. Of the $150 million bank facility available to InfrastruX, $112
      million was outstanding at March 31, 2006 and at December 31, 2005. In
      determining the fair value of its InfrastruX investment, Puget Energy has
      determined proceeds on a sale will first be used to extinguish all InfrastruX
      debt outstanding.


The
      expected net proceeds from a proposed sale of InfrastruX exceed its carrying
      value. In accordance with SFAS No. 144, Puget Energy has reversed the previously
      recorded SFAS No. 144 impairment charge to adjust the investment in InfrastruX
      to the lower of its carrying value without the impairment, less cost to sell,
      or
      fair value. After reflecting the adjustment, tax-basis adjustment and related
      transaction cost of $12.4 million in 2005, Puget Energy’s equity investment in
      InfrastruX was $52.9 million at March 31, 2006 compared to $43.5 million at
      December 31, 2005.





**Capital
      Requirements**


**Contractual
      Obligations and Commercial Commitments**


**Puget
      Energy and Puget Sound Energy.** The
      following are Puget Energy and Puget Sound Energy’s aggregate consolidated
      contractual and commercial commitments as of March 31, 2006:




Puget
                Energy and Puget Sound Energy
            
            
            
            Payments
                Due Per PeriodContractual
                Obligations
              (Dollars
                in Millions)
            
            Total
            
            2006
            
            2007-
                2008
            
            2009-
              2010
            
            2011
                &
              ThereafterLong-term
                debt including interest
            
            $
            4,021.8
            
            $
            190.6
            
            $
            567.6
            
            $
            606.8
            
            $
            2,656.8Short-term
                debt including interest
            
            
            25.6
            
            
            25.6
            
            
            --
            
            
            --
            
            
            --Junior
                subordinated debentures payable to a subsidiary trust including
                interest1
            
            
            895.7
            
            
            15.0
            
            
            39.8
            
            
            39.8
            
            
            801.1Mandatorily
                redeemable preferred stock
            
            
            1.9
            
            
            --
            
            
            --
            
            
            --
            
            
            1.9Service
                contract obligations
            
            
            156.9
            
            
            18.3
            
            
            55.2
            
            
            54.3
            
            
            29.1Non-cancelable
                operating leases
            
            
            92.1
            
            
            9.5
            
            
            26.6
            
            
            19.1
            
            
            36.9Fredonia
                combustion turbines lease2
            
            
            59.7
            
            
            3.3
            
            
            8.5
            
            
            8.2
            
            
            39.7Energy
                purchase obligations
            
            
            6,326.2
            
            
            717.3
            
            
            1,856.6
            
            
            1,280.2
            
            
            2,472.1Contract
                initiation payment/collateral requirement
            
            
            107.5
            
            
            89.0
            
            
            --
            
            
            --
            
            
            18.5Financial
                hedge obligations
            
            
            34.8
            
            
            9.3
            
            
            25.5
            
            
            --
            
            
            --Purchase
                obligations
            
            
            277.5
            
            
            277.5
            
            
            --
            
            
            --
            
            
            --Non-qualified
                pension and other benefits funding
            
            
            50.0
            
            
            2.7
            
            
            11.1
            
            
            10.2
            
            
            26.0Total
                contractual cash obligations
            
            $
            12,049.7
            
            $
            1,358.1
            
            $
            2,590.9
            
            $
            2,018.6
            
            $
            6,082.1




**Puget
      Energy.** The
      following are Puget Energy’s aggregate consolidated (including PSE) commercial
      commitments as of March 31, 2006:




**Puget
                Energy**
            
            
            
            Amount
                of Commitment
              Expiration
                Per PeriodCommercial
              Commitments
              (Dollars
                in Millions)
            
            Total
            
            2006
            
            2007-
              2008
            
            2009-
              2010
            
            2011
                &
              ThereafterGuarantees3
            
            $
            112.0
            
            $
            --
            
            $
            112.0
            
            $
            --
            
            $
            --Credit
                agreement - available4
            
            
            497.9
            
            
            --
            
            
            --
            
            
            --
            
            
            497.9Unsecured
                credit agreement
            
            
            20.0
            
            
            --
            
            
            --
            
            
            --
            
            
            20.0Receivable
                securitization facility5
            
            
            176.0
            
            
            --
            
            
            --
            
            
            176.0
            
            
            --Energy
                operations letter of credit
            
            
            0.5
            
            
            0.5
            
            
            --
            
            
            --
            
            
            --Total
                commercial commitments
            
            $
            806.4
            
            $
            0.5
            
            $
            112.0
            
            $
            176.0
            
            $
            517.9


_______________________




1
            *In
                1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and
                Puget
                Sound Energy Capital Trust II, respectively, for the sole purpose
                of
                issuing and selling preferred securities (Trust Securities) to investors
                and issuing common securities to PSE. The proceeds from the sale
                of Trust
                Securities were used by the Trusts to purchase Junior Subordinated
                Debentures (Debentures) from PSE. The Debentures are the sole assets
                of
                the Trusts and PSE owns all common securities of the
                Trusts.*2
            *See
                “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
                below.*3
            *In
                May 2004, InfrastruX signed a three-year credit agreement with a
                group of
                banks to provide up to $150 million in financing. Under the credit
                agreement, Puget Energy is the guarantor of the line of credit. Certain
                InfrastruX subsidiaries also have certain borrowing capacities for
                working
                capital purposes of which Puget Energy is not a guarantor. Of the
                $150
                million available to InfrastruX, $112.0 was outstanding March 31,
                2006.*4
            *At
                March 31, 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 March 31,
                2006, PSE
                had $0.5 million for an outstanding letter of credit and $1.6 million
                commercial paper outstanding, thereby effectively reducing the available
                borrowing capacity to $497.9 million.*5
            *At
                March 31, 2006, PSE had available a $200 million receivables
                securitization facility that expires in December 2010. At March 31,
                2006,
                PSE had $24.0 million outstanding under its receivables securitization
                program, thereby effectively reduced the available borrowing capacity
                to
                $176.0 million. See “Receivables Securitization Facility" below for
                further discussion.*





**Puget
      Sound Energy** .
      The
      following are PSE’s aggregate commercial commitments as of March 31,
      2006:




**Puget
                Sound Energy**
            
            
            
            Amount
                of Commitment
              Expiration
                Per PeriodCommercial
              commitments
              (Dollars
                in Millions)
            
            Total
            
            2006
            
            2007-
              2008
            
            2009-
              2010
            
            2011
                &
              ThereafterCredit
                facility - available1
            
            $
            497.9
            
            $
            --
            
            $
            --
            
            $
            --
            
            $
            497.9Unsecured
                credit agreement
            
            
            20.0
            
            
            --
            
            
            --
            
            
            --
            
            
            20.0Receivable
                securitization facility2
            
            
            176.0
            
            
            --
            
            
            --
            
            
            176.0
            
            
            --Energy
                operations letter of credit
            
            
            0.5
            
            
            0.5
            
            
            --
            
            
            --
            
            
            --Total
                commercial commitments
            
            $
            694.4
            
            $
            0.5
            
            $
            --
            
            $
            176.0
            
            $
            517.9


_______________________




1
            *See
                note 4 above.*2
            *See
                note 5 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 purpose
      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 March 31, 2006, PSE’s outstanding balance under the
      lease was $53.3 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 $107.7 million for the three months ended March 31, 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
            
            $
            454
            
            $
            500Wild
                Horse wind project
            
            
            317
            
            
            --Total
                capital expenditures
            
            
            771
            
            
            500Chelan
                contract payment1
            
            
            89
            
            
            --Total
                expenditures
            
            $
            860
            
            $
            500


_______________________




1
            *The
                Chelan contract payment represents a capacity reservation charge
                in
                conjunction with an impending 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 three months ended March 31, 2006 was $138.4
      million. During that period, $2.0 million was used for AFUDC, which reduced
      interest expense, and $25.9 million for payment of dividends. Consequently,
      cash
      flows available for utility construction expenditures and other capital
      expenditures were $110.5 million or 102.6% of the $107.7 million in construction
      expenditures (net of AFUDC and customer refundable contributions) and other
      capital expenditure requirements for the three months ended March 31, 2006.
      For
      the three months ended March 31, 2005, cash generated from operations was $45.7
      million, $1.5 million was used for AFUDC, which reduced interest expense, and
      $21.9 million was used for payment of dividends. Therefore, cash flows available
      for utility **** construction
      expenditures and other capital **** expenditures
      were $22.3 million, or 18.0% of the $124.0 million in construction expenditures
      (net of AFUDC and customer refundable contributions) and other capital
      expenditure requirements for the three month period ended March 31, 2005. The
      following table provides a summary of cash available and construction
      expenditures:





(Dollars
                in millions)
              (Unaudited)
              For
                the three months ended March 31,
            
            2006
            
            2005Cash
                from operations
            
            $
            138.4
            
            $
            45.7Less:
                Dividends paid
            
            
            (25.9
            )
            
            (21.9
            )AFUDC
            
            
            (2.0
            )
            
            (1.5
            )Cash
                available for construction expenditures
            
            $
            110.5
            
            $
            22.3Construction
                and energy efficiency expenditures
            
            $
            112.3
            
            $
            129.1Less:
                AFUDC
            
            
            (2.0
            )
            
            (1.5
            )Cash
                received from refundable customer contributions
            
            
            (2.6
            )
            
            (3.6
            )Net
                construction and energy efficiency expenditures
            
            $
            107.7
            
            $
            124.0





The
      overall cash generated from operating activities for the three month period
      ended March 31, 2006 increased $92.7 million compared to the same period in
      2005. This increase is primarily attributable to a payment of $150 million
      in
      2005 related to the Rainier Receivables accounts receivable securitization
      sales
      that were outstanding at December 31, 2004 compared to no activity under the
      Rainier Receivables accounts receivable securitization at December 31, 2005.
      This is 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. In addition,
      decrease in gas inventory resulted in an increase in cash available for
      operating activities of $33.6 million, which was collected from customers
      through the PGA mechanism. The increases in cash available for operating
      activities was offset by payments of accounts payable primarily related to
      energy purchases and repayment of collateral deposits which accounted for cash
      used of $70.6 million and $18 million, respectively.





**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
      March 31, 2006, PSE could issue:


·
            approximately
                $275 million of additional first mortgage bonds under PSE’s electric
                mortgage indenture based on approximately $458 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 March 31, 2006;


·
            approximately
                $223 million of additional first mortgage bonds under PSE’s gas mortgage
                indenture based on approximately $372 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
                March 31, 2006;


·
            approximately
                $663 million of additional preferred stock at an assumed dividend
                rate of
                6.875%; and


·
            approximately
                $406 million of unsecured long-term
                debt.


At
      March
      31, 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 April 26, 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.


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








**Liquidity
      Facilities and Commercial Paper**


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





**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 March 31, 2006.





**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 March 31, 2006, there was $0.5
      million outstanding under a letter of credit and $1.6 million commercial paper
      outstanding, effectively reducing the available borrowing capacity under the
      credit facility to $497.9 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 three months ended March 31, 2006,
      PSE Funding borrowed a cumulative amount of $67.0 million secured by accounts
      receivable and had $24.0 million of loans secured by accounts receivable pledged
      as collateral at March 31, 2006.





**Stock
      Purchase and Dividend Reinvestment Plan**


Puget
      Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which
      shareholders and other interested investors may invest cash and cash dividends
      in shares of Puget Energy’s common stock. Since new shares of common stock may
      be purchased directly from Puget Energy, funds received may be used for general
      corporate purposes. Puget Energy issued $3.5 million (166,900 shares) of common
      stock under the Stock Purchase and Dividend Reinvestment Plan for the three
      months ended March 31, 2006, respectively, compared to $3.6 million (151,800
      shares) for the three months ended March 31, 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, 2006, 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. FERC
      has not yet ruled on the proposed settlement and its ultimate outcome remains
      uncertain. On April 7, 2006, FERC issued a Draft Environmental Impact Statement
      (DEIS) for the Baker River project. The contents of the DEIS and potential
      impacts on the proposed settlement and the schedule for issuing the new license
      are being evaluated by all parties.


**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
      economically the project 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 March 31, 2006,
      the
      White River project net book value totaled $66.2 million, which included $44.6
      million of net utility plant, $15.8 million of capitalized FERC licensing costs,
      $3.9 million of costs related to construction work in progress and $1.4 million
      related to dam operations and safety. PSE sought recovery of the relicensing,
      other construction work in progress and dam operations and safety costs in
      its
      general rate filing of April 2004 over a 10-year amortization period. On
      February 18, 2005, the Washington Commission agreed to allow PSE to recover
      the
      White River net utility plant costs noted above. However, amortization of the
      FERC licensing and other costs will not begin until all costs 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 during the second
      quarter of 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.





**Electric
      Regulation and Rates**


**Rate
      Case.** On
      February 15, 2006, PSE filed a request with the Washington Commission to
      increase electric rates by 9.2% or $148.8 million annually. The
      Company is proposing in its filing to change the annual PCA sharing bands to
      the
      following:





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





In
      addition to the change in sharing bands for the PCA, the Company is requesting
      the Washington Commission to approve a new depreciation tracker mechanism that
      would allow the Company to recover increased depreciation expense associated
      with new plant investment incurred between rate filings. The electric
      depreciation tracker is 0.5%, or $7.9 million annually, of the rate increase
      over current rate levels.





**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. The
      cumulative maximum pre-tax earnings exposure due to power cost variations over
      the four-year period ending June 30, 2006 is limited to $40 million plus 1%
      of
      the excess. Upon expiration of the $40 million cumulative cap, the annual power
      cost variability will be subject to the bands in the table below. All
      significant variable power supply cost drivers are included in the PCA mechanism
      (hydroelectric generation variability, market price variability for purchased
      power and surplus power sales, natural gas and coal fuel price variability,
      generation unit forced outage risk and transmission cost variability). PSE’s
      cumulative excess power costs at March 31, 2006 was $40.2 million but it
      anticipates being below the $40 million cap in May and June 2006.


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





Annual
                Power
              Cost
                Variability
            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.*





Based
      on
      past activity under the PCA mechanism and volatility of power costs, it is
      possible that PSE could experience higher expenses associated with excess power
      costs based on the sharing arrangement once the cumulative $40 million cap
      expires on June 30, 2006. As such, the risk dynamics change for PSE and its
      customers. On October 20, 2005, the Washington Commission approved an amendment
      to the PCA mechanism changing the PCA period to a calendar year beginning
      January 1, 2007. The Washington Commission also made provision to reduce the
      graduated scale to half the annual excess power costs for the period July 1,
      2006 through December 31, 2006 without a cap on excess power costs. In addition,
      the Washington Commission order requires PSE to update the power cost baseline
      rate accepted in the 2005 PCORC proceeding by filing a tariff change to the
      power cost rate during May 2006 which would be effective July 1,
      2006.







**Gas
      Regulation and Rates**


On
      February 15, 2006, PSE filed a gas general rate case requesting an increase
      in
      gas general rates of 5.3% or $51.3 million annually, and to approve a
      depreciation tracker mechanism and a decoupling mechanism for natural gas
      residential and small commercial customers. The natural gas depreciation tracker
      is 1.2% or $10.9 million, of the rate increase over current rate levels. The
      gas
      decoupling mechanism 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 may be
      up to
      an 11-month process from the time the general rate case is filed.








**Other**


**Chelan
      County PUD.** 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
      interest 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 interest on a temporary basis until resolution of PSE’s
      electric general rate case later this year.





**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 includes a summary of the western power market proceedings described below.
      The following discussion provides a summary of material developments in these
      proceedings that occurred during the period covered by this report and of any
      new material proceedings instituted during the period covered by this report.
      PSE intends to vigorously defend against each of these cases and does not expect
      the ultimate resolution of these proceedings in the aggregate to have a material
      adverse impact on the financial condition, results of operations or liquidity
      of
      the Company. However, there can be no assurances in that regard because
      litigation is subject to numerous uncertainties and PSE is unable to predict
      the
      ultimate outcome of these matters. Accordingly, there can be no guarantee that
      these proceedings, either individually or in the aggregate, will not materially
      and adversely affect PSE’s financial condition, results of operations or
      liquidity.





**1.**
            **California
                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 Federal Power Act (FPA);
      (2)
      the temporal scope of refunds under section 206 of the FPA; and (3) which
      categories of transactions are subject to refunds. PSE joined the brief of
      the
      Competitive Supplier Group, which argued that FERC has proposed to require
      payment of refunds without proper notice to sellers, without proper limits
      on
      the type of transactions affected and without a finding that the transactions
      subject to refund in fact produced prices that were unjust and unreasonable.
      The
      court heard oral argument on April 12 and 13, 2005. 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. No decision has
      been issued on the other issues argued in April 2005. The order remanding the
      proceeding back to FERC and the time for seeking rehearing in the governmental
      utilities case has been extended until 45 days after a decision on the other
      issues identified above. The parties await a decision from the court on the
      remaining two other issues. Procedures will be established for the remaining
      issues, if necessary, after the court’s disposition of the first round of
      issues; however, the Court issued an order April 11, 2006 that convenes a case
      management conference in San Francisco on May 26, 2006, to discuss the process
      for resolving remaining issues.





**b.**
            ***CAISO
                Receivable****.*At
                March 31, 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. 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 $28.0 million,
      including interest, on its past due receivables as of March 31,
      2006.





**2.**
            **Port
                of Seattle Suit.**On
                May 21, 2003, the Port of Seattle commenced suit in federal court
                in
                Seattle against 22 energy sellers, alleging that their conduct during
                2000
                and 2001 constituted market manipulation, violated antitrust laws
                and
                damaged the Port of Seattle. The Port had a contract to purchase
                its
                energy supply from PSE at the time. The Port’s contract linked the price
                of the energy sold to the Port to an index price for energy sold
                at
                wholesale at the Mid-Columbia trading hub. The Port alleged that
                the
                Mid-Columbia price was inten-tionally affected improperly by the
                defendants, including PSE, and alleges damages of over $30 million.
                On May
                12, 2004, the district court dismissed the lawsuit. The Port of Seattle
                filed an appeal to the United States Court of Appeals for the Ninth
                Circuit. After briefing and oral arguments on March 30, 2006, the
                Ninth
                Circuit issued an order dismissing the
                case.





**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
      amounting to $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. Under SFAS No. 123, the Company elected to reduce awards
      as forfeitures occurred instead of estimating the amount of forfeiture over
      the
      vesting period. For SFAS No. 123R, the Company has determined its forfeitures
      based on historical forfeitures.


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 quarter ended
      March 31, 2006, are $0.1 million and $0.1 million higher, respectively, than
      if
      it had continued to account for share-based compensation under SFAS No. 123.
      Basic and diluted earnings per share for income from continuing operations
      for
      the quarter ended March 31, 2006, would have been $0.80 and $0.79, respectively,
      if the Company had not adopted SFAS No. 123R, compared to basic and diluted
      earnings per share of $0.80 and $0.79, respectively. As of March 31, 2006,
      there
      was $6.0 million of total unrecognized compensation cost related to stock-based
      compensation plans. That cost is expected to be recognized over a weighted
      average period of 2.25 years.


The
      portion of stock-based grants that can be paid in cash are classified and
      accounted for as liabilities 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 the quarterly expense recognized during
      the
      performance period be 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
      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
      provides for a sharing of costs and benefits that are graduated over four levels
      of power cost variances with an overall cap of $40 million (+/-) plus 1% of
      the
      excess over the $40 million cap over the four-year period ending June 30, 2006.
      For the period July 1, 2006 through December 31, 2006 the sharing bands will
      be
      half of the annual bands without a cap for excess power costs and beginning
      January 1, 2007 the PCA mechanism will provide sharing of costs and benefits
      that are graduated over four levels for each calendar year without a maximum
      cap
      for excess power costs.


The
      Company is focused on 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 Finance and Budget 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. Therefore wholesale market transactions are
      focused on balancing the Company’s energy portfolio, reducing costs and risks
      where feasible, and reducing volatility in wholesale costs and margin in the
      portfolio. In order to manage risks effectively, the Company enters into
      physical and financial transactions, which are appropriate for the service
      territory of the Company and are relevant to its regulated electric and gas
      portfolios.


The
      risk
      metrics the Company employs are aimed at assessing exposure 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. This 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
      March
      31, 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
      March
      31, 2006, the Company had a net asset of approximately $34.8 million of energy
      contracts designated as qualifying cash flow hedges and a corresponding
      unrealized gain of $22.6 million after-tax recorded in other comprehensive
      income. These cash flow hedges represent forward financial purchases of gas
      intended to run PSE-owned electric plants in future periods. If it is determined
      that it is uneconomical to run the plants in the future period, the hedging
      relationship is ended and the cash flow hedge is de-designated and any
      unrealized gains and losses are recorded in the income statement. Gains and
      losses when these de-designated cash flow hedges are settled are recognized
      in
      energy costs and are included as part of the PCA mechanism. Of the amount in
      other comprehensive income, 99% of the mark-to-market gain for the month of
      April 2006 has been reclassified out of other comprehensive income to a deferred
      account in accordance with SFAS No. 71 due to the Company reaching the $40
      million cap under the PCA mechanism. Amounts settling after April 30, 2006
      have
      not been deferred under the PCA mechanism as the Company is forecasted to fall
      below the $40 million cap in May 2006 and the cap expires at June 30, 2006,
      and
      the sharing band under the PCA mechanism reset. The Company also had energy
      contracts that were marked-to-market at a loss of $1.0 million through current
      earnings for the three months ended March 31, 2006. These mark-to-market
      adjustments were primarily the result of excluding certain contracts from the
      normal purchase normal sale exception under SFAS No. 133. A portion of the
      mark-to-market adjustments for April 2006 has been reclassified to a deferred
      account in accordance with SFAS No. 71 due to the Company reaching the $40
      million cap under the PCA mechanism. At March 31, 2006, the Company also has
      a
      net liability of approximately $25.2 million related to the fair value of gas
      contracts to serve gas customers. All mark-to-market adjustments relating to
      the
      natural gas business have been reclassified to a deferred account in accordance
      with SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes on to
      customers increases and decreases in the cost of natural gas supply. 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 $5.8 million after-tax and would decrease current earnings for
      those contracts marked-to-market in earnings by $0.3 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 March 31, 2006, approximately 96% 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 2005, the Company entered into two forward starting swap
      contracts to hedge against interest rate volatility for a debt offering
      anticipated to be performed in the second half of 2006. A forward starting
      swap
      is a financial arrangement between the Company and a counterparty whereby one
      of
      the parties will be required to make a payment to the other party on a specific
      valuation date based upon the change in value of a designated treasury bond.
      If
      interest rates rise related to the hedged debt from the date of issuance of
      the
      swap instruments, the Company would receive a payment from the counterparty
      for
      the change in the bond value. Alternatively, if interest rates decreased related
      to the hedged debt from the date of issuance of the swap instruments, the
      Company would pay the counterparty for the change in bond value. These swap
      contracts were designated under SFAS No. 133 criteria as cash flow hedges.
      All
      financial hedge contracts of this type are reviewed by senior management and
      presented to the Finance and Budget Committee of the Board of Directors, and
      are
      approved prior to execution. At March 31, 2006, the unrealized gain associated
      with the two swap contracts was $7.7 million after-tax and is included in other
      comprehensive income. The forward starting swap contracts will settle completely
      in 2006. A hypothetical 10% decrease in the interest rate of a 30-year Treasury
      note would result in a loss of $10.5 million net of tax in other comprehensive
      income. The counterparties calculate the current market value for the existing
      forward swap positions based on market interest rates and swap rates as of
      March
      31, 2006.








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





**Puget**  **Energy**


**Evaluation
      of Disclosure Controls and Procedures**


Under
      the
      supervision and with the participation of Puget Energy’s management, including
      the 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 March 31, 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 March 31, 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 March 31, 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 March 31, 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 March 31,
      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**





There
      are
      no material changes to risk factors previously disclosed by Puget Energy and
      Puget Sound Energy on Form 10-K, Item 1A.








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:
                May 4, 2006Chief
                accounting officer and officer duly authorized to sign this report
                on
                behalf of each registrant





**EXHIBIT
      INDEX**





The
      following exhibits are filed herewith:





10.1
            First
                Amendment to the Amended and Restated Credit Agreement dated April
                4, 2006
                covering PSE and various banks named therein, Wachovia Bank National
                Association as administrative agent.12.1
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2001
                through 2005 and 12 months ended March 31, 2006) for Puget
                Energy.12.2
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2001
                through 2005 and 12 months ended March 31, 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.