UNITED
      STATES


SECURITIES
      AND EXCHANGE COMMISSION


Washington,
      D.C. 20549


**FORM
      10-Q**








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







**For
                the quarterly period ended****September
                30, 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
        October 26, 2006, (i) the number of shares of Puget Energy, Inc. common stock
        outstanding was 116,401,902 ($.01 par value) and (ii) all of the outstanding
        shares of Puget Sound Energy, Inc. common stock were held by Puget Energy,
        Inc.











**Table
      of Contents**





**Definitions****Filing
                Format****Forward
                Looking Statements****Part
                I.**
            **Financial
                Information****Item
                1.**
            **Financial
                Statements****Puget
                Energy, Inc.**Consolidated
                Statements of Income - Three and
                Nine Months Ended
              September
                30, 2006 and 2005Consolidated
                Statements of Comprehensive
                Income - Three and Nine Months Ended September 30, 2006 and
                2005Consolidated
                Balance Sheets- September 30, 2006
                and December 31, 2005Consolidated
                Statements of Cash Flows- Nine
                Months Ended September 30, 2006 and 2005**Puget
                Sound Energy, Inc.**Consolidated
                Statements of Income - Three and
                Nine Months Ended
              September
                30, 2006 and 2005Consolidated Statements of Comprehensive
                Income - Three and Nine Months Ended
              September
                30, 2006 and 2005Consolidated
                Balance Sheets - September 30, 2006
                and December 31, 2005Consolidated
                Statements of Cash Flows - Nine
                Months Ended September 30, 2006 and 2005**Notes**Combined
                Notes to Consolidated Financial Statements**Item
                2.**
            **Management’s
                Discussion and Analysis of Financial Condition**
              **and
                Results of Operations****Item
                3.**
            **Quantitative
                and Qualitative Disclosure About Market
                Risk****Item
                4.**
            **Controls
                and Procedures****Part
                II.**
            **Other
                Information****Item
                1.**
            **Legal
                Proceedings****Item
                1A.**
            **Risk
                Factors****Item
                6.**
            **Exhibits****Signatures****Exhibit
                Index**







**DEFINITIONS**





AFUDC
            Allowance
                for Funds Used During ConstructionCAISO
            California
                Independent System OperatorFASB
            Financial
                Accounting Standards BoardFERC
            Federal
                Energy Regulatory CommissionFIN
            Financial
                Accounting Standards Board InterpretationFoundation
            Puget
                Sound Energy FoundationFPA
            Federal
                Power ActGTN
            Gas
                Transmission NorthwestInfrastruX
            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)NWP
            Northwest
                PipelinePCA
            Power
                Cost AdjustmentPCORC
            Power
                Cost Only Rate CasePGA
            Purchased
                Gas AdjustmentPSE
            Puget
                Sound Energy, Inc.Puget
                Energy
            Puget
                Energy, Inc.Tenaska
            Tenaska
                Power Fund, L.P.SFAS
            Statement
                of Financial Accounting StandardsWashington
                Commission
            Washington
                Utilities and Transportation
                Commission








**FILING
      FORMAT**


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








**FORWARD-LOOKING
      STATEMENTS**


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


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


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





·
            Governmental
                policies and regulatory actions, including those of the Federal Energy
                Regulatory Commission (FERC) and the Washington Utilities and
                Transportation Commission (Washington Commission), with respect to
                allowed
                rates of return, cost recovery, industry and rate structures, transmission
                and generation business structures within PSE, acquisition and disposal
                of
                assets and facilities, operation, maintenance and construction of
                electric
                generating facilities, operation of distribution and transmission
                facilities (gas and electric), licensing of hydroelectric operations
                and
                gas storage facilities, recovery of other capital investments, recovery
                of
                power and gas costs, recovery of regulatory assets and present or
                prospective wholesale and retail competition;·
            Changes
                in, adoption of and compliance with laws and regulations, including
                decisions and policies concerning the environment, climate change
                (greenhouse gases), emissions, natural resources, and fish and wildlife
                (including the Endangered Species Act);·
            The
                ability to recover changes in enacted federal state or local tax
                laws
                through revenue in a timely manner;·
            Natural
                disasters, such as hurricanes, earthquakes, floods, fires and landslides,
                which can cause temporary supply disruptions and/or price spikes
                in the
                cost of fuel and raw materials;·
            Commodity
                price risks associated with procuring natural gas and power in wholesale
                markets that impact customer loads;·
            Wholesale
                market disruption, which may result in a deterioration of market
                liquidity, increase the risk of counterparty default, affect the
                regulatory and legislative process in unpredictable ways, negatively
                affect wholesale energy prices and/or impede PSE’s ability to manage its
                energy portfolio risks and procure energy supply, affect the availability
                and access to capital and credit markets and/or impact delivery of
                energy
                to PSE from its suppliers;·
            Financial
                difficulties of other energy companies and related events, which
                may
                affect the regulatory and legislative process in unpredictable ways
                and
                also adversely affect the availability of and access to capital and
                credit
                markets and/or impact delivery of energy to PSE from it
                suppliers;·
            The
                effect of wholesale market structures (including, but not limited
                to,
                regional market designs or transmission organizations) or other related
                federal initiatives;·
            PSE
                electric or gas distribution system failure, which may impact PSE’s
                ability to deliver energy supply to its customers;·
            Weather,
                which can have a potentially serious impact on PSE’s revenues and/or
                impact its ability to procure adequate supplies of gas, fuel or purchased
                power to serve its customers and on the cost of procuring such supplies;·
            Variable
                hydro conditions, which can impact streamflow and PSE’s ability to
                generate electricity from hydroelectric facilities;·
            Plant
                outages, which can have an adverse impact on PSE’s expenses with respect
                to repair costs, added costs to replace energy or higher costs associated
                with dispatching a more expensive resource;·
            The
                ability of gas or electric plant to operate as intended;·
            The
                ability to renew contracts for electric and gas supply and the price
                of
                renewal;·
            Blackouts
                or large curtailments of transmission systems, whether PSE’s or others’,
                which can affect PSE’s ability to deliver power or natural gas to its
                customers;·
            The
                ability to restart generation following a regional transmission
                disruption;·
            Failure
                of the interstate gas pipeline delivering to PSE’s system, which may
                impact PSE’s ability to adequately deliver gas supply to its customers;·
            The
                amount of collection, if any, of PSE’s receivables from the California
                Independent System Operator (CAISO) and other parties and the amount
                of
                refunds found to be due from PSE to the CAISO or other parties;·
            Industrial,
                commercial and residential growth and demographic patterns in the
                service
                territories of PSE;·
            General
                economic conditions in the Pacific Northwest, which might impact
                customer
                consumption or affect PSE’s accounts receivable;·
            The
                loss of significant customers or changes in the business of significant
                customers, which may result in changes in demand for PSE’s services;·
            The
                impact of acts of terrorism, flu pandemic or similar significant
                events;·
            Capital
                market conditions, including changes in the availability of capital
                or
                interest rate fluctuations;·
            Employee
                workforce factors, 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;·
            Future
                losses related to corporate guarantees provided by Puget Energy as
                a part
                of the sale of its InfrastruX subsidiary; and·
            The
                ability to maintain effective internal controls over financial reporting.




Any
      forward-looking statement speaks only as of the date on which such statement
      is
      made, and, except as required by law, Puget Energy and PSE undertake no
      obligation to update any forward-looking statement to reflect events or
      circumstances after the date on which such statement is made or to reflect
      the
      occurrence of unanticipated events. New factors emerge from time to time and
      it
      is not possible for management to predict all such factors, nor can it assess
      the impact of any such factor on the business or the extent to which any factor,
      or combination of factors, may cause results to differ materially from those
      contained in any forward-looking statement. You are also advised to consult
      Item
      1A-“Risk Factors” in our most recent annual report on Form 10-K and this
      quarterly report for updates.








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


Item
      1.  **Financial
      Statements**





**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF INCOME


(Dollars
      in thousands except per share amounts)


(Unaudited)




Three
                  Months Ended
                September
                  30,
              
              Nine
                  Months Ended
                September
                  30,2006
              
              2005
              
              2006
              
              2005Operating
                  Revenues:Electric
              
              $
              399,246
              
              $
              375,035
              
              $
              1,247,650
              
              $
              1,140,545Gas
              
              
              119,610
              
              
              111,042
              
              
              718,655
              
              
              594,737Other
              
              
              607
              
              
              4,306
              
              
              5,115
              
              
              6,866Total
                  operating revenues
              
              
              519,463
              
              
              490,383
              
              
              1,971,420
              
              
              1,742,148Operating
                  Expenses:Energy
                  costs:Purchased
                  electricity
              
              
              183,723
              
              
              200,861
              
              
              623,793
              
              
              587,983Electric
                  generation fuel
              
              
              36,282
              
              
              21,058
              
              
              72,158
              
              
              54,400Residential
                  exchange
              
              
              (35,923
              )
              
              (34,525
              )
              
              (131,226
              )
              
              (126,676
              )Purchased
                  gas
              
              
              68,294
              
              
              59,151
              
              
              453,335
              
              
              359,037Net
                  unrealized loss (gain) on derivative instruments
              
              
              (611
              )
              
              477
              
              
              214
              
              
              395Utility
                  operations and maintenance
              
              
              87,687
              
              
              81,645
              
              
              258,653
              
              
              240,299Other
                  operations and maintenance
              
              
              494
              
              
              745
              
              
              2,038
              
              
              2,045Depreciation
                  and amortization
              
              
              65,530
              
              
              60,550
              
              
              193,959
              
              
              178,284Conservation
                  amortization
              
              
              7,127
              
              
              5,633
              
              
              22,638
              
              
              16,746Taxes
                  other than income taxes
              
              
              46,325
              
              
              44,784
              
              
              180,236
              
              
              165,005Income
                  taxes
              
              
              8,281
              
              
              2,476
              
              
              64,004
              
              
              54,649Total
                  operating expenses
              
              
              467,209
              
              
              442,855
              
              
              1,739,802
              
              
              1,532,167Operating
                  income
              
              
              52,254
              
              
              47,528
              
              
              231,618
              
              
              209,981Other
                  income (deductions):Charitable
                  foundation funding
              
              
              --
              
              
              --
              
              
              (15,000
              )
              
              --Other
                  income
              
              
              5,242
              
              
              1,350
              
              
              13,453
              
              
              5,071Income
                  taxes
              
              
              (841
              )
              
              72
              
              
              3,956
              
              
              (887
              )Interest
                  charges:AFUDC
              
              
              5,189
              
              
              2,680
              
              
              10,238
              
              
              6,183Interest
                  expense
              
              
              (45,900
              )
              
              (45,695
              )
              
              (134,129
              )
              
              (130,307
              )Mandatorily
                  redeemable securities interest expense
              
              
              (23
              )
              
              (23
              )
              
              (68
              )
              
              (68
              )Income
                  from continuing operations
              
              
              15,921
              
              
              5,912
              
              
              110,068
              
              
              89,973Income
                  (loss) from discontinued segment (net of tax)
              
              
              1
              
              
              (1
              )
              
              51,903
              
              
              908Net
                  income before cumulative effect of accounting change
              
              
              15,922
              
              
              5,911
              
              
              161,971
              
              
              90,881Cumulative
                  effect of implementation of accounting change (net of tax)
              
              
              --
              
              
              --
              
              
              (89
              )
              
              --Net
                  income
              
              $
              15,922
              
              $
              5,911
              
              $
              162,060
              
              $
              90,881Common
                  shares outstanding weighted average (in thousands)
              
              
              116,101
              
              
              100,371
              
              
              115,910
              
              
              100,160Diluted
                  shares outstanding weighted average (in thousands)
              
              
              116,568
              
              
              100,964
              
              
              116,311
              
              
              100,754Basic
                  earnings per common share before cumulative effect of accounting
                  change
                  from continuing operations
              
              $
              0.14
              
              $
              0.06
              
              $
              0.95
              
              $
              0.90Basic
                  earnings per common share from discontinued operations
              
              
              --
              
              
              --
              
              
              0.45
              
              
              0.01Cumulative
                  effect from accounting change
              
              
              --
              
              
              --
              
              
              --
              
              
              --Basic
                  earnings per common share
              
              $
              0.14
              
              $
              0.06
              
              $
              1.40
              
              $
              0.91Diluted
                  earnings per common share before cumulative effect of accounting
                  change
                  from continuing operations
              
              $
              0.14
              
              $
              0.06
              
              $
              0.95
              
              $
              0.89Diluted
                  earnings per common share from discontinued operations
              
              
              --
              
              
              --
              
              
              0.44
              
              
              0.01Cumulative
                  effect from accounting change
              
              
              --
              
              
              --
              
              
              --
              
              
              --Diluted
                  earnings per common share
              
              $
              0.14
              
              $
              0.06
              
              $
              1.39
              
              $
              0.90




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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended September 30,
            
            Nine
                Months Ended
              September
                30,2006
            
            2005
            
            2006
            
            2005Net
                income
            
            $
            15,922
            
            $
            5,911
            
            $
            162,060
            
            $
            90,881Other
                comprehensive income, net of tax at 35%:Foreign
                currency translation adjustment
            
            
            --
            
            
            2
            
            
            (327
            )
            
            (10
            )Minimum
                pension liability adjustment
            
            
            --
            
            
            --
            
            
            145
            
            
            --Net
                unrealized gains (losses) on derivative instruments during the
                period
            
            
            (11,220
            )
            
            37,896
            
            
            (29,133
            )
            
            48,484Reversal
                of net unrealized gains (losses) on derivative instruments settled
                during
                the period
            
            
            1,281
            
            
            (4,353
            )
            
            (8,603
            )
            
            (3,243
            )Settlement
                of cash flow hedge contracts
            
            
            (416
            )
            
            --
            
            
            13,444
            
            
            (22,960
            )Amortization
                of cash flow hedge contracts to earnings
            
            
            76
            
            
            191
            
            
            457
            
            
            264Deferral
                of cash flow hedges related to the power cost adjustment
                mechanism
            
            
            --
            
            
            (12,914
            )
            
            6,252
            
            
            (4,937
            )Other
                comprehensive income (loss)
            
            
            (10,279
            )
            
            20,822
            
            
            (17,765
            )
            
            17,598Comprehensive
                income
            
            $
            5,643
            
            $
            26,733
            
            $
            144,295
            
            $
            108,479




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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)




**ASSETS**





September
                30,
              2006
                (Unaudited)
            
            December
                31,
              2005Utility
                plant: (at original cost, including construction work in progress
                of$512,432
                and $216,513, respectively)Electric
            
            $
            5,203,771
            
            $
            4,802,363Gas
            
            
            2,093,787
            
            
            1,991,456Common
                plant
            
            
            447,079
            
            
            439,599Less:
                Accumulated depreciation and amortization
            
            
            (2,713,179
            )
            
            (2,602,500
            )Net
                utility plant
            
            
            5,031,458
            
            
            4,630,918Other
                property and investments
            
            
            155,357
            
            
            157,321Current
                assets:Cash
            
            
            10,038
            
            
            16,710Restricted
                cash
            
            
            837
            
            
            1,047Accounts
                receivable, net of allowance for doubtful accounts
            
            
            199,390
            
            
            294,509Secured
                pledged accounts receivable
            
            
            --
            
            
            41,000Unbilled
                revenues
            
            
            90,292
            
            
            160,207Purchased
                gas adjustment receivable
            
            
            83,652
            
            
            67,335Materials
                and supplies, at average cost
            
            
            41,816
            
            
            36,491Fuel
                and gas inventory, at average cost
            
            
            130,163
            
            
            91,058Unrealized
                gain on derivative instruments
            
            
            19,365
            
            
            75,037Deferred
                income taxes
            
            
            2,348
            
            
            --Prepayments
                and other
            
            
            21,606
            
            
            7,596Current
                assets of discontinued operations
            
            
            --
            
            
            107,434Total
                current assets
            
            
            599,507
            
            
            898,424Other
                long-term assets:Restricted
                cash
            
            
            3,739
            
            
            --Regulatory
                asset for deferred income taxes
            
            
            119,269
            
            
            129,693Regulatory
                asset for PURPA contract buyout costs
            
            
            173,748
            
            
            191,170Unrealized
                gain on derivative instruments
            
            
            10,145
            
            
            28,464Power
                cost adjustment mechanism
            
            
            2,411
            
            
            18,380Other
            
            
            556,875
            
            
            388,468Long-term
                assets of discontinued operations
            
            
            --
            
            
            167,113Total
                other long-term assets
            
            
            866,187
            
            
            923,288Total
                assets
            
            $
            6,652,509
            
            $
            6,609,951





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








**PUGET
      ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)





**CAPITALIZATION
      AND LIABILITIES**




September
                  30,
                2006
                  (Unaudited)
              
              December
                  31,
                2005Capitalization:Common
                  shareholders’ investment:Common
                  stock $0.01 par value, 250,000,000 shares authorized, 116,394,795
                  and
                  115,695,463 shares outstanding, respectively
              
              $
              1,164
              
              $
              1,157Additional
                  paid-in capital
              
              
              1,964,007
              
              
              1,948,975Earnings
                  reinvested in the business
              
              
              144,473
              
              
              69,407Accumulated
                  other comprehensive income (loss), net of tax at 35%
              
              
              (10,257
              )
              
              7,508Total
                  shareholders’ equity
              
              
              2,099,387
              
              
              2,027,047Redeemable
                  securities and long-term debt:Preferred stock subject to mandatory redemption
              
              
              1,889
              
              
              1,889Junior subordinated debentures of the corporation payable to a
                  subsidiary
                  trust holding mandatorily redeemable preferred securities
              
              
              37,750
              
              
              237,750Long-term debt
              
              
              2,608,360
              
              
              2,183,360Total redeemable securities and long-term debt
              
              
              2,647,999
              
              
              2,422,999Total capitalization
              
              
              4,747,386
              
              
              4,450,046Minority
                  interest in discontinued operations
              
              
              --
              
              
              6,816Current
                  liabilities:Accounts
                  payable
              
              
              224,233
              
              
              346,490Short-term
                  debt
              
              
              103,154
              
              
              41,000Current
                  maturities of long-term debt
              
              
              160,000
              
              
              81,000Accrued
                  expenses:Taxes
              
              
              30,445
              
              
              112,860Salaries and wages
              
              
              22,331
              
              
              15,034Interest
              
              
              50,492
              
              
              31,004Unrealized
                  loss on derivative instruments
              
              
              86,318
              
              
              9,772Deferred
                  income taxes
              
              
              --
              
              
              10,968Other
              
              
              32,859
              
              
              35,694Current
                  liabilities of discontinued operations
              
              
              --
              
              
              55,791Total current liabilities
              
              
              709,832
              
              
              739,613Long-term
                  liabilities:Deferred
                  income taxes
              
              
              731,008
              
              
              738,809Unrealized
                  loss on derivative instruments
              
              
              770
              
              
              --Other
                  deferred credits
              
              
              463,513
              
              
              513,023Long-term
                  liabilities of discontinued operations
              
              
              --
              
              
              161,644Total long-term liabilities
              
              
              1,195,291
              
              
              1,413,476Total
                  capitalization and liabilities
              
              $
              6,652,509
              
              $
              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)




Nine
                Months Ended
              September
                30,2006
            
            2005Operating
                activities:Net
                income
            
            $
            162,060
            
            $
            90,881Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation
                and amortization
            
            
            193,959
            
            
            178,284Deferred
                income taxes and tax credits, net
            
            
            (11,309
            )
            
            (32,329
            )Net
                unrealized loss on derivative instruments
            
            
            214
            
            
            395Amortization
                of gas pipeline capacity assignment
            
            
            (7,951
            )
            
            --Non-cash
                return on regulatory assets
            
            
            8,167
            
            
            --Impairment
                on InfrastruX investment
            
            
            (7,269
            )
            
            13,204Gain
                on sale of InfrastruX
            
            
            (29,765
            )
            
            --Cash
                collateral (paid) received from energy suppliers
            
            
            (22,020
            )
            
            31,050Increase
                in residential exchange program
            
            
            434
            
            
            4,984Chelan
                PUD contract initiation prepayment
            
            
            (89,000
            )
            
            --Other
            
            
            10,198
            
            
            18,733Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            198,243
            
            
            70,084Materials
                and supplies
            
            
            (4,408
            )
            
            (2,781
            )Fuel
                and gas inventory
            
            
            (39,105
            )
            
            (29,201
            )Prepayments
                and other
            
            
            (16,696
            )
            
            (28,301
            )Purchased
                gas adjustment receivable
            
            
            (16,318
            )
            
            (18,419
            )Accounts
                payable
            
            
            (119,308
            )
            
            (9,269
            )Taxes
                payable
            
            
            (78,357
            )
            
            7,339Tenaska
                disallowance reserve
            
            
            --
            
            
            (3,156
            )Accrued
                expenses and other
            
            
            20,718
            
            
            9,503Net
                cash provided by operating activities
            
            
            152,487
            
            
            301,001Investing
                activities:Construction
                and capital expenditures - excluding equity AFUDC
            
            
            (579,384
            )
            
            (406,346
            )Energy
                efficiency expenditures
            
            
            (21,859
            )
            
            (10,763
            )Cash
                proceeds from property sales
            
            
            196
            
            
            15,830Refundable
                cash received for customer construction projects
            
            
            12,004
            
            
            10,221Restricted
                cash
            
            
            (3,529
            )
            
            587Gross
                proceeds from sale of InfrastruX, net of cash disposed
            
            
            263,575
            
            
            --Other
            
            
            5,835
            
            
            2,348Net
                cash used by investing activities
            
            
            (323,162
            )
            
            (388,123
            )Financing
                activities:Change
                in short-term debt and leases, net
            
            
            65,323
            
            
            230,855Dividends
                paid
            
            
            (78,123
            )
            
            (65,956
            )Payments
                to minority shareholders of InfrastruX
            
            
            (10,451
            )
            
            --Issuance
                of common stock
            
            
            4,241
            
            
            3,769Issuance
                of bonds and notes
            
            
            550,000
            
            
            250,000Redemption
                of bonds, notes and leases
            
            
            (190,096
            )
            
            (250,753
            )Redemption
                of trust preferred stock
            
            
            (200,000
            )
            
            (42,500
            )Settlement
                of cash flow hedge of interest rate derivative
            
            
            20,682
            
            
            (34,776
            )Issuance
                and redemption costs of bonds and other
            
            
            (3,760
            )
            
            (8,356
            )Net
                cash provided by financing activities
            
            
            157,816
            
            
            82,283Net
                decrease in cash
            
            
            (12,859
            )
            
            (4,839
            )Cash
                at beginning of year
            
            
            22,897
            
            
            19,771Cash
                at end of period
            
            $
            10,038
            
            $
            14,932Supplemental
                cash flow information:Cash
                paid for interest (net of capitalized interest)
            
            $
            118,848
            
            $
            123,499Income
                taxes paid
            
            
            97,725
            
            
            72,940




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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF INCOME


(Dollars
      in thousands)


(Unaudited)




Three
                    Months Ended
                  September
                    30,
                
                Nine
                    Months Ended
                  September
                    30,2006
                
                2005
                
                2006
                
                2005Operating
                    revenues:Electric
                
                $
                399,246
                
                $
                375,035
                
                $
                1,247,650
                
                $
                1,140,545Gas
                
                
                119,610
                
                
                111,042
                
                
                718,655
                
                
                594,737Other
                
                
                607
                
                
                4,306
                
                
                5,115
                
                
                6,866Total
                    operating revenues
                
                
                519,463
                
                
                490,383
                
                
                1,971,420
                
                
                1,742,148Operating
                    expenses:Energy
                    costs:Purchased
                    electricity
                
                
                183,723
                
                
                200,861
                
                
                623,793
                
                
                587,983Electric
                    generation fuel
                
                
                36,282
                
                
                21,058
                
                
                72,158
                
                
                54,400Residential
                    exchange
                
                
                (35,923
                )
                
                (34,525
                )
                
                (131,226
                )
                
                (126,676
                )Purchased
                    gas
                
                
                68,294
                
                
                59,151
                
                
                453,335
                
                
                359,037Net
                    unrealized loss (gain) on derivative instruments
                
                
                (611
                )
                
                477
                
                
                214
                
                
                395Utility
                    operations and maintenance
                
                
                87,687
                
                
                81,645
                
                
                258,653
                
                
                240,299Other
                    operations and maintenance
                
                
                243
                
                
                425
                
                
                805
                
                
                925Depreciation
                    and amortization
                
                
                65,530
                
                
                60,550
                
                
                193,959
                
                
                178,284Conservation
                    amortization
                
                
                7,127
                
                
                5,633
                
                
                22,638
                
                
                16,746Taxes
                    other than income taxes
                
                
                46,325
                
                
                44,784
                
                
                180,235
                
                
                165,005Income
                    taxes
                
                
                8,481
                
                
                2,619
                
                
                64,720
                
                
                55,449Total
                    operating expenses
                
                
                467,158
                
                
                442,678
                
                
                1,739,284
                
                
                1,531,847Operating
                    income
                
                
                52,305
                
                
                47,705
                
                
                232,136
                
                
                210,301Other
                    income (deductions):Other
                    income
                
                
                5,242
                
                
                1,350
                
                
                13,097
                
                
                5,071Income
                    taxes
                
                
                (799
                )
                
                72
                
                
                (1,289
                )
                
                (887
                )Interest
                    charges:AFUDC
                
                
                5,189
                
                
                2,680
                
                
                10,238
                
                
                6,183Interest
                    expense
                
                
                (45,900
                )
                
                (45,614
                )
                
                (134,129
                )
                
                (130,083
                )Interest
                    expense on Puget Energy note
                
                
                (382
                )
                
                --
                
                
                (503
                )
                
                --Mandatorily
                    redeemable securities interest expense
                
                
                (23
                )
                
                (23
                )
                
                (68
                )
                
                (68
                )Net
                    income before cumulative effect of accounting change
                
                
                15,632
                
                
                6,170
                
                
                119,482
                
                
                90,517Cumulative
                    effect of implementation of accounting change (net of tax)
                
                
                --
                
                
                --
                
                
                (89
                )
                
                --Net
                    Income
                
                $
                15,632
                
                $
                6,170
                
                $
                119,571
                
                $
                90,517





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







**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
      in thousands)


(Unaudited)





Three
                Months Ended
              September
                30,
            
            Nine
                Months Ended
              September
                30,2006
            
            2005
            
            2006
            
            2005Net
                income
            
            $
            15,632
            
            $
            6,170
            
            $
            119,571
            
            $
            90,517Other
                comprehensive income, net of tax at 35%:Minimum
                pension liability adjustment
            
            
            --
            
            
            --
            
            
            145
            
            
            --Net
                unrealized gains (losses) on derivative instruments during the
                period
            
            
            (11,220
            )
            
            37,896
            
            
            (29,133
            )
            
            48,484Reversal
                of net unrealized gains (losses) on derivative instruments settled
                during
                the period
            
            
            1,281
            
            
            (4,353
            )
            
            (8,603
            )
            
            (3,243
            )Settlement
                of cash flow hedge contracts
            
            
            (416
            )
            
            --
            
            
            13,444
            
            
            (22,960
            )Amortization
                of cash flow hedge contracts to earnings
            
            
            76
            
            
            191
            
            
            457
            
            
            264Deferral
                of cash flow hedges related to the power cost adjustment
                mechanism
            
            
            --
            
            
            (12,914
            )
            
            6,252
            
            
            (4,937
            )Other
                comprehensive income (loss)
            
            
            (10,279
            )
            
            20,820
            
            
            (17,438
            )
            
            17,608Comprehensive
                income
            
            $
            5,353
            
            $
            26,990
            
            $
            102,133
            
            $
            108,125





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








**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)





**ASSETS**





September
                30,
              2006
                (Unaudited)
            
            December
                31,
              2005Utility
                plant: (at original cost, including construction work in progress
                of
                $512,432 and $216,513, respectively)Electric
            
            $
            5,203,771
            
            $
            4,802,363Gas
            
            
            2,093,787
            
            
            1,991,456Common
                plant
            
            
            447,079
            
            
            439,599Less:
                Accumulated depreciation and amortization
            
            
            (2,713,179
            )
            
            (2,602,500
            )Net
                utility plant
            
            
            5,031,458
            
            
            4,630,918Other
                property and investments
            
            
            155,357
            
            
            157,321Current
                assets:Cash
            
            
            9,995
            
            
            16,709Restricted
                cash
            
            
            837
            
            
            1,047Accounts
                receivable, net of allowance for doubtful accounts
            
            
            200,273
            
            
            299,938Secured
                pledged accounts receivable
            
            
            --
            
            
            41,000Unbilled
                revenues
            
            
            90,292
            
            
            160,207Purchased
                gas adjustment receivable
            
            
            83,652
            
            
            67,335Materials
                and supplies, at average cost
            
            
            41,816
            
            
            36,491Fuel
                and gas inventory, at average cost
            
            
            130,163
            
            
            91,058Unrealized
                gain on derivative instruments
            
            
            19,365
            
            
            75,037Deferred
                income taxes
            
            
            2,348
            
            
            --Prepayments
                and other
            
            
            21,035
            
            
            7,023Total
                current assets
            
            
            599,776
            
            
            795,845Other
                long-term assets:Regulatory
                asset for deferred income taxes
            
            
            119,269
            
            
            129,693Regulatory
                asset for PURPA contract buyout costs
            
            
            173,748
            
            
            191,170Unrealized
                gain on derivative instruments
            
            
            10,145
            
            
            28,464Power
                cost adjustment mechanism
            
            
            2,411
            
            
            18,380Other
            
            
            556,598
            
            
            388,009Total
                other long-term assets
            
            
            862,171
            
            
            755,716Total
                assets
            
            $
            6,648,762
            
            $
            6,339,800





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







**PUGET
      SOUND ENERGY, INC.**


CONSOLIDATED
      BALANCE SHEETS


(Dollars
      in thousands)





**CAPITALIZATION
      AND LIABILITIES**


September
                  30,
                2006
                  (Unaudited)
              
              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
              
              
              994,760
              
              
              924,154Earnings
                  reinvested in the business
              
              
              232,269
              
              
              196,248Accumulated
                  other comprehensive income (loss), net of tax at 35%
              
              
              (10,257
              )
              
              7,181Total
                  shareholder’s equity
              
              
              2,075,810
              
              
              1,986,621Redeemable
                  securities and long-term debt:Preferred
                  stock subject to mandatory redemption
              
              
              1,889
              
              
              1,889Junior
                  subordinated debentures of the corporation payable to a subsidiary
                  trust
                  holding mandatorily redeemable preferred securities
              
              
              37,750
              
              
              237,750Long-term
                  debt
              
              
              2,608,360
              
              
              2,183,360Total
                  redeemable securities and long-term debt
              
              
              2,647,999
              
              
              2,422,999Total
                  capitalization
              
              
              4,723,809
              
              
              4,409,620Current
                  liabilities:Accounts
                  payable
              
              
              224,233
              
              
              346,490Short-term
                  debt
              
              
              103,154
              
              
              41,000Short-term
                  note due Puget Energy
              
              
              24,211
              
              
              --Current
                  maturities of long-term debt
              
              
              160,000
              
              
              81,000Accrued
                  expenses:Taxes
              
              
              31,780
              
              
              111,900Salaries
                  and wages
              
              
              21,547
              
              
              15,034Interest
              
              
              50,611
              
              
              31,004Unrealized
                  loss on derivative instruments
              
              
              86,318
              
              
              9,772Deferred
                  income taxes
              
              
              --
              
              
              10,968Other
              
              
              32,854
              
              
              30,932Total
                  current liabilities
              
              
              734,708
              
              
              678,100Long-term
                  liabilities:Deferred
                  income taxes
              
              
              734,862
              
              
              739,162Unrealized
                  loss on derivative instruments
              
              
              770
              
              
              --Other
                  deferred credits
              
              
              454,613
              
              
              512,918Total
                  long-term liabilities
              
              
              1,190,245
              
              
              1,252,080Total
                  capitalization and liabilities
              
              $
              6,648,762
              
              $
              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)




Nine
                Months Ended
              September
                30,2006
            
            2005Operating
                activities:Net
                income
            
            $
            119,571
            
            $
            90,517Adjustments
                to reconcile net income to net cashprovided
                by operating activities:Depreciation
                and amortization
            
            
            193,959
            
            
            178,284Deferred
                income taxes and tax credits, net
            
            
            2,276
            
            
            (31,137
            )Net
                unrealized loss on derivative instruments
            
            
            214
            
            
            395Amortization
              of gas pipeline capacity assignment
            
            
            (7,951
            )
            
            --Non-cash
                return on regulatory assets
            
            
            8,167
            
            
            --Cash
                collateral (paid) received from energy suppliers
            
            
            (22,020
            )
            
            31,050Increase
                in residential exchange program
            
            
            434
            
            
            4,984Chelan
                PUD contract initiation prepayment
            
            
            (89,000
            )Other
            
            
            14,096
            
            
            12,968Change
                in certain current assets and liabilities:Accounts
                receivable and unbilled revenue
            
            
            210,578
            
            
            85,585Materials
                and supplies
            
            
            (5,324
            )
            
            (2,249
            )Fuel
                and gas inventory
            
            
            (39,105
            )
            
            (29,201
            )Prepayments
                and other
            
            
            (14,012
            )
            
            (27,628
            )Purchased
                gas adjustment receivable
            
            
            (16,318
            )
            
            (18,419
            )Accounts
                payable
            
            
            (122,257
            )
            
            (13,080
            )Taxes
                payable
            
            
            (80,119
            )
            
            (3,926
            )Tenaska
                disallowance reserve
            
            
            --
            
            
            (3,156
            )Accrued
                expenses and other
            
            
            26,393
            
            
            3,786Net
                cash provided by operating activities
            
            
            179,582
            
            
            278,773Investing
                activities:Construction
                expenditures - excluding equity AFUDC
            
            
            (575,108
            )
            
            (393,619
            )Energy
                efficiency expenditures
            
            
            (21,859
            )
            
            (10,763
            )Cash
                proceeds from property sales
            
            
            196
            
            
            15,830Restricted
                cash
            
            
            209
            
            
            587Refundable
                cash received for customer construction projects
            
            
            12,004
            
            
            10,221Other
            
            
            5,939
            
            
            2,359Net
                cash used by investing activities
            
            
            (578,619
            )
            
            (375,385
            )Financing
                activities:Change
                in short-term debt, net
            
            
            62,154
            
            
            223,871Loan
                from Puget Energy
            
            
            24,211
            
            
            --Dividends
                paid
            
            
            (83,550
            )
            
            (67,085
            )Investment
                from Puget Energy
            
            
            68,635
            
            
            --Issuance
                of bonds and notes
            
            
            550,000
            
            
            250,000Redemption
                of bonds and notes
            
            
            (46,000
            )
            
            (231,000
            )Redemption
                of trust preferred stock
            
            
            (200,000
            )
            
            (42,500
            )Settlement
                of cash flow hedge interest rate derivative
            
            
            20,682
            
            
            (34,776
            )Issuance
                and redemption cost of bonds and other
            
            
            (3,809
            )
            
            (5,037
            )Net
                cash provided by financing activities
            
            
            392,323
            
            
            93,473Net
                decrease in cash
            
            
            (6,714
            )
            
            (3,139
            )Cash
                at beginning of year
            
            
            16,709
            
            
            12,955Cash
                at end of period
            
            $
            9,995
            
            $
            9,816Supplemental
                cash flow information:Cash
                paid for interest (net of capitalized interest)
            
            $
            115,951
            
            $
            116,857Income
                taxes paid
            
            
            91,621
            
            
            75,482




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


The
      consolidated financial statements of Puget Energy reflect the accounts of Puget
      Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the
      common shares of PSE and owned a 90.9% interest in InfrastruX until it was
      sold
      on May 7, 2006. The results of PSE and InfrastruX are presented on a
      consolidated basis. The financial position and results of operations for
      InfrastruX are presented as discontinued operations. At the time that it was
      owned by Puget Energy, InfrastruX was a non-regulated utility construction
      service company incorporated in the State of Washington, which provides
      construction services to the electric and gas utility industries primarily
      in
      the Midwest, Texas, south-central and eastern United States regions. PSE’s
      consolidated financial statements include the accounts of PSE and its
      subsidiaries. Puget Energy and PSE are collectively referred to herein as “the
      Company.” The consolidated financial statements are presented after elimination
      of all significant intercompany items and transactions. Certain amounts
      previously reported have been reclassified to conform with current year
      presentations with no effect on total equity or net income.


The
      consolidated financial statements contained in this Form 10-Q are unaudited.
      In
      the respective opinions of the management of Puget Energy and PSE, all
      adjustments necessary for a fair statement of the results for the interim
      periods have been reflected and were of a normal recurring nature. These
      condensed financial statements should be read in conjunction with the audited
      financial statements (and the Combined Notes thereto) included in the combined
      Puget Energy and PSE annual report on Form 10-K for the year ended December
      31,
      2005. With the treatment of InfrastruX as discontinued operations, Puget Energy
      has one reportable segment.


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








**(2)**
            **Discontinued
                Operations and Corporate Guarantees**(Puget
                Energy Only)





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


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


For
      the
      nine months ended September 30, 2006, Puget Energy reported InfrastruX related
      income from discontinued operations (net of taxes and minority interest),
      including gain on sale, of $51.9 million compared to $0.9 million (net of taxes
      and minority interest) for the nine months ended September 30, 2005. Puget
      Energy’s income from discontinued operations for the nine months ended September
      30, 2006 includes $7.3 million related to the reversal of a carrying value
      adjustment recorded in 2005 as well as $10.0 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.”





Three
                Months Ended
              September
                30,
            
            Nine
                Months Ended
              September
                30,(Dollars
                in thousands)
            
            2006
            
            2005
            
            2006
            
            2005Revenues
            
            $
            --
            
            $
            111,667
            
            $
            138,573
            
            $
            286,665Operating
                expenses (including interest expense)
            
            
            --
            
            
            (98,063
            )
            
            (128,605
            )
            
            (261,272
            )Pre-tax
                income
            
            
            --
            
            
            13,604
            
            
            9,968
            
            
            25,393Income
                tax expense
            
            
            --
            
            
            (4,684
            )
            
            (3,544
            )
            
            (8,637
            )Puget
                Energy carrying value adjustment of InfrastruX
            
            
            --
            
            
            (8,094
            )
            
            7,269
            
            
            (13,204
            )Puget
                Energy cost of sale related to InfrastruX, net of tax
            
            
            --
            
            
            (23
            )
            
            (937
            )
            
            (1,140
            )Puget
                Energy deferred tax basis adjustment of InfrastruX
            
            
            --
            
            
            --
            
            
            9,966
            
            
            --Gain
                on sale, net of tax
            
            
            1
            
            
            --
            
            
            29,765
            
            
            --Minority
                interest in income of discontinued operations
            
            
            --
            
            
            (804
            )
            
            (584
            )
            
            (1,504
            )Income
                (loss) from discontinued operations
            
            $
            1
            
            $
            (1
            )
            $
            51,903
            
            $
            908





In
      accordance with SFAS No. 144, InfrastruX discontinued depreciation and
      amortization of its assets effective February 8, 2005.  This
      discontinuation of depreciation and amortization resulted in $4.7 million ($2.9
      million after-tax) lower depreciation and amortization expense than otherwise
      would have been recorded as continuing operations for the three months ended
      September 30, 2005. Depreciation and amortization was $6.7 million ($4.3 million
      after-tax) and $12 million ($7.3 million after-tax) lower than otherwise would
      have been recorded as continuing operations for the nine months ended September
      30, 2006 and 2005, respectively.


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





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












(Dollars
              in thousands)
            
            December
                31,
              2005Liabilities:Accounts
                payable
            
            $
            9,178Short-term
                debt
            
            
            3,809Current
                maturities of long-term debt
            
            
            6,477Other
                current liabilities
            
            
            36,327Total
                current liabilities
            
            
            55,791Deferred
                income taxes
            
            
            24,645Long-term
                debt
            
            
            120,013Other
                deferred credits
            
            
            16,986Total
                long-term liabilities
            
            
            161,644Total
                liabilities
            
            $
            217,435








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





Puget
      Energy’s basic earnings per common share have been computed based on weighted
      average common shares outstanding of 116,101,000 and 115,910,000 for the three
      and nine months ended September 30, 2006, respectively, and 100,371,000 and
      100,160,000 for the three and nine months ended September 30, 2005,
      respectively.


Puget
      Energy’s diluted earnings per common share have been computed based on weighted
      average common shares outstanding of 116,568,000 and 116,311,000 for the three
      and nine months ended September 30, 2006, respectively, and 100,964,000 and
      100,754,000 for the three and nine months ended September 30, 2005,
      respectively. These shares include the dilutive effect of securities related
      to
      employee and director equity plans.








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





SFAS
      No.
      133, “Accounting for Derivative Instruments and Hedging Activities,” as amended
      by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to
      be
      derivative instruments be recorded on the balance sheet at their fair value.
      The
      Company enters into 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 PSE deems 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 September 30, 2006,
      the
      Company was subject to a range of netting provisions, including both stand
      alone
      agreements and the provisions associated with the Western Systems Power Pool
      agreement, of which many energy suppliers in the western United States are
      a
      part.


During
      the three months ended September 30, 2006, the Company recorded an increase
      in
      earnings for the change in the market value of derivative instruments not
      meeting NPNS nor cash flow hedge criteria of approximately $0.6 million compared
      to a decrease in earnings of approximately $0.5 million for the three months
      ended September 30, 2005. At September 30, 2006, the Company had a net
      unrealized gain recorded in other comprehensive income of $5.5 million after-tax
      related to energy and financial contracts which meet the criteria for
      designation as cash flow hedges under SFAS No. 133. At September 30, 2006,
      PSE
      had a net short-term liability of $0.2 million related to non-cash flow hedges,
      as well as a net short-term liability of $1.4 million and a net long-term asset
      of $9.8 million related to energy contracts designated as cash flow hedges
      that
      represent forward financial purchases of gas supply for electric generation
      from
      PSE-owned electric plants in future periods. If it is determined that it is
      uneconomical to run the plants in the future period, the hedging relationship
      is
      ended and the cash flow hedge is de-designated and any unrealized gains and
      losses are recorded in the income statement. Gains and losses when these
      de-designated cash flow hedges are settled are recognized in energy costs and
      are included as part of the PCA mechanism.


During
      the nine months ended September 30, 2006, the Company recorded a decrease in
      earnings for the change in the market value of derivative instruments not
      meeting cash flow hedge criteria of approximately $0.2 million compared to
      a
      decrease in earnings of approximately $0.4 million for the nine months ended
      September 30, 2005.


At
      September 30, 2006, the Company also had a net short-term liability of
      approximately $65.4 million and a net long-term liability of $0.5 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
      third quarter 2006, the Company settled two forward starting interest rate
      swap
      contracts originating in September 2006. The purpose of the forward starting
      swap contracts was to hedge interest rate volatility of a $300 million debt
      offering that was priced on September 13, 2006. Since interest rates decreased
      relative to the hedged rate, the debt was priced at a rate lower than the hedged
      rate. PSE paid $0.6 million to the counterparties when the contracts were
      settled. The forward starting swap contracts were designated and documented
      under SFAS No. 133 criteria as cash flow hedges, with all changes in market
      value presented net of tax in other comprehensive income. In accordance with
      SFAS No. 133, the loss will be amortized out of other comprehensive income
      to
      current earnings as an increase to interest expense over the life of the new
      debt issued. The ending balance in other comprehensive income related to the
      forward starting swaps and previously settled treasury lock contracts at
      September 30, 2006 was a loss of $8.6 million after-tax and accumulated
      amortization.








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





Prior
      to
      2006, the Company had various stock-based compensation plans which were
      accounted for according to Accounting Principles Board (APB) No. 25, “Accounting
      for Stock Issued to Employees,” and related interpretations as allowed by SFAS
      No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted
      the fair value based accounting of SFAS No. 123 using the prospective method
      under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock
      compensation awards granted subsequent to January 1, 2003, while grants prior
      to
      2003 continued to be accounted for using the intrinsic value method of APB
      No.
      25. Effective January 1, 2006, the Company adopted the fair value recognition
      provisions of SFAS No. 123R, “Share-Based Payment,” using the
      modified-prospective transition method. Under that transition method,
      compensation cost recognized in 2006 includes: (a) compensation cost for all
      share-based payments granted prior to, but not yet vested as of January 1,
      2006,
      based on the grant date fair value estimated in accordance with the original
      provisions of SFAS No. 123 and (b) compensation cost for all share-based
      payments granted subsequent to January 1, 2006, based on the grant-date fair
      value estimated in accordance with the provisions of SFAS No. 123R. Results
      for
      prior periods have not been restated, as provided for under the
      modified-prospective method.


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


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


Had
      Puget
      Energy applied the fair value method of accounting specified by SFAS No. 123
      for
      all grants at their grant date rather than prospectively implementing SFAS
      No.
      123, net income and earnings per share would have been as follows:




(Dollars
                in thousands, except per share amounts)
            
            ThreeMonths
              Ended
              September
                30,
              2005
            
            NineMonths
              Ended
              September
                30,
              2005Net
                income, as reported
            
            $
            5,911
            
            $
            90,881Add:
                Total stock-based employee compensation expense included in net income,
                net of tax
            
            
            995
            
            
            2,800Less:
                Total stock-based employee compensation expense per the fair value
                method
                of SFAS No. 123, net of tax
            
            
            (992
            )
            
            (2,891
            )Pro
                forma net income
            
            $
            5,914
            
            $
            90,790Earnings
                per share:Basic
                per common share as reported
            
            $
            0.06
            
            $
            0.91Diluted
                per common share as reported
            
            $
            0.06
            
            $
            0.90Basic
                per common share pro forma
            
            $
            0.06
            
            $
            0.91Diluted
                per common share pro forma
            
            $
            0.06
            
            $
            0.90





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





**Performance
      Share Grants**


The
      Company generally awards performance share grants annually under the LTI Plan.
      These are granted to key employees and vest at the end of three years for grants
      made in 2004, 2005 and 2006. Grants made prior to 2004 vest in four years.
      The
      number of shares awarded and expense recorded depends on Puget Energy’s
      performance as compared to other companies and service quality indices for
      customer service. Compensation expense related to performance share grants
      was
      $(1.0) million and $1.1 million for the three months ended September 30, 2006
      and 2005, respectively, and $(2.4) million and $3.1 million for the nine months
      ended September 30, 2006 and 2005, respectively. The weighted average fair
      value
      per share of the performance awards granted for the 2006, 2005, 2004 and 2003
      cycles was $22.52, $21.20, $19.70 and $16.92, respectively. There were a total
      of 152,254 performance awards granted for the 2006 cycle of which the company
      estimates a forfeiture rate of 10.1% or 15,378 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 September 30, 2006, there were
      four active grant cycles for a total of 854,387 share grants outstanding. As
      of
      December 31, 2005, there were four active grant cycles for a total of 907,983
      share grants outstanding. As of September 30, 2006, there was $3.6 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 1.8 years. During the three and nine months ended
      September 30, 2006, 5,446 and 53,218 performance shares, respectively, were
      forfeited. No performance shares vested during the three or nine months ended
      September 30, 2006 and 2005. The fair value of the 2006 performance share grants
      takes into consideration the historical performance of the performance share
      grants and prospective analysis using the Capital Asset Pricing Model and
      expected EPS growth rates. Shares granted prior to 2006 were valued using the
      Black-Scholes option pricing model.





**Measurement
      of Performance Share Grants**


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





**Stock
      Options**


In
      2002,
      Puget Energy’s Board of Directors granted 40,000 stock options under the LTI
      Plan and an additional 260,000 options outside of the LTI Plan (for a total
      of
      300,000 non-qualified stock options) to the Chairman, President and Chief
      Executive Officer. These options can be exercised at the grant date market
      price
      of $22.51 per share and vest annually over four and five years although the
      options would become fully vested upon a change of control of the Company or
      an
      employment termination without cause. The options expire 10 years from the
      grant
      date and have a remaining contractual term of approximately 6 years. All 300,000
      options remained outstanding at September 30, 2006, with 270,000 options
      exercisable. At September 30, 2005, 202,500 options were exercisable. The fair
      value of the options at the grant date was $3.33 per share. Compensation expense
      related to stock options was immaterial to the financial statements for the
      three and nine months ended September 30, 2006. As of September 30, 2006, there
      was an immaterial amount of total unrecognized compensation cost related to
      nonvested stock options which will be recognized in 2006. The total fair value
      of stock options vested during the nine months ended September 30, 2006 and
      2005, was $0.2 million and $0.2 million, respectively. The fair value of the
      stock option award was estimated on the date of grant using the Black-Scholes
      option valuation model.





**Restricted
      Stock**


In
      2006,
      2005, 2004 and 2003, the Company granted 107,555 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 nine months
      ended September 30, 2006, 107,555 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 September
      30,
      2006, there were 209,222 total shares of nonvested restricted stock and the
      weighted average grant date fair value of these shares was $22.19. Compensation
      expense related to the restricted shares, including the restricted shares
      granted as part of the 2006 LTIP cycle, was $0.5 million and $0.2 million for
      the three months ended September 30, 2006 and 2005, respectively, and $1.5
      million and $0.6 million for the nine months ended September 30, 2006 and 2005,
      respectively. Dividends are paid on all outstanding shares of restricted stock
      and are accounted for as a Puget Energy common stock dividend, not as
      compensation expense. The weighted average grant date fair value for all
      outstanding shares of restricted stock granted in 2006 and 2005 was $22.19
      and
      $21.86, respectively. As of September 30, 2006, there was $2.2 million of total
      unrecognized compensation cost related to nonvested restricted stock. That
      cost
      is expected to be recognized over a weighted-average period of 1.8 years. During
      the three months ended September 30, 2006, 3,333 shares of restricted stock
      vested. Restricted stock forfeited during the three and nine months ended
      September 30, 2006 was 417 shares and 1,000 shares, respectively. No restricted
      stock vested or was forfeited during the three and nine months ended September
      30, 2005. The fair value of the restricted stock is based on the closing price
      of the Company’s common stock on the date of grant.





**Restricted
      Stock Units**


In
      2004,
      the Company granted 10,000 restricted stock units outside of the LTI Plan but
      subject to the terms and conditions of the plan. The units vest 2,000 shares
      in
      three years and the remaining 8,000 shares in four years. At September 30,
      2006,
      there were 10,000 total shares of nonvested restricted stock units and the
      weighted average fair value of these units was $22.73. There were no restricted
      stock units granted or forfeited during the three and nine months ended
      September 30, 2006 and 2005. The restricted stock units will be settled in
      cash
      when they become vested at the end of each cycle. Dividends are paid on the
      outstanding stock units and are accounted for as compensation expense.
      Compensation expense related to the restricted stock units agreement was
      immaterial for the three and nine months ended September 30, 2006 and 2005.
      The
      weighted average grant date fair value for the restricted stock units was
      $23.55. As of September 30, 2006, there was $0.1 million of total unrecognized
      compensation cost related to nonvested restricted stock units. That cost is
      expected to be recognized over a weighted-average period of 1.6 years. The
      fair
      value of the restricted stock units is based on the closing price of the
      Company’s common stock at each reporting period.





**Retirement
      Equivalent Stock**


The
      Company has a retirement equivalent stock agreement under which in lieu of
      participating in the Company’s executive supplemental retirement plan, the
      Chairman, President and Chief Executive Officer is granted performance-based
      stock equivalents in January of each year, which are deferred under the
      Company’s deferred compensation plan. In 2006, 2005, 2004 and 2003, the Company
      awarded 8,218, 6,063, 6,469 and 4,319, shares, respectively, which vest over
      a
      period from January 1, 2002 to May 2008 at 15% per year for the first six years
      and the remaining 10% in the seventh year. At September 30, 2006, there were
      5,966 total shares of nonvested retirement equivalent stock units and the
      weighted average grant date fair value of these units was $22.71. During the
      nine months ended September 30, 2006, 8,218 retirement equivalent stock units
      were granted. The equivalent value of dividends is paid on the accumulated
      retirement equivalent stock units and added to the deferred compensation
      account. Compensation expense related to the retirement equivalent stock
      agreement was immaterial to the financial statements. The weighted average
      grant
      date fair value for the retirement equivalent stock was $20.42, $24.70, $23.77
      and $22.05 for 2006, 2005, 2004 and 2003, respectively. As of September 30,
      2006, there was an immaterial amount of unrecognized compensation cost related
      to nonvested retirement equivalent stock units. That cost is expected to be
      recognized over a weighted-average period of 1.7 years. During the three and
      nine months ended September 30, 2006, 778 and 7,265 retirement equivalent stock
      units vested, respectively. No retirement equivalent stock units were forfeited
      during the quarter ended September 30, 2006. The fair value of the restricted
      stock is based on the closing price of the Company’s common stock on the date of
      grant.





**Employee
      Stock Purchase Plan**


The
      Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open
      to
      all employees. Offerings occur at six-month intervals at the end of which the
      participating employees receive shares for 85% of the lower of the stock’s fair
      market price at the beginning or the end of the six-month period. A maximum
      of
      500,000 shares may be sold to employees under the plan through May 2007. At
      September 30, 2006, 117,393 shares could still be sold to employees under the
      plan. Under the SFAS No. 123 accounting that the Company adopted in 2003 and
      under SFAS No. 123R, the ESPP is considered to be compensatory and the amount
      is
      immaterial to the financial statements. Purchase rights to 35,654 shares were
      granted for the three months ended September 30, 2006 and 31,421 new shares
      were
      issued for the nine months ended September 30, 2006. Purchase rights to 30,849
      shares were granted for the three months ended September 30, 2005 and 23,048
      new
      shares were issued for the nine months ended September 30, 2005. Dividends
      are
      not paid on ESPP shares until they are purchased by employees and thus are
      accounted for as dividends, not compensation expense.




**Non-Employee
      Director Stock Plan**


The
      Company has a director stock plan for all non-employee directors of Puget Energy
      and PSE. An amended and restated plan was 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 choose to continue to receive their entire retainer
      in Puget Energy stock. The compensation expense related to the director stock
      plan was $0.1 million and $0.1 million for the three months ended September
      30,
      2006 and 2005, respectively, and $0.3 million and $0.3 million for the nine
      months ended September 30, 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 September 30, 2006, 33,185 shares had been issued or
      purchased for the director stock plan and 88,313 deferred, for a total of
      121,498 shares. As of September 30, 2005, the number of shares that had been
      purchased for the director stock plan was 22,986 and deferred was 73,836, for
      a
      total of 96,822 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
            
            
            *
            
            
            *
            
            
            *
            
            
            *
            
            
            4.5Expected
                stock volatility
            
            
            *
            
            
            *
            
            
            *
            
            
            *
            
            
            23.62
            %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
            
            
            4.96
            %
            
            2.68
            %
            
            1.28
            %
            
            1.07
            %
            
            *Expected
                lives -
                years
            
            
            0.5
            
            
            0.5
            
            
            0.5
            
            
            0.5
            
            
            *Expected
                stock volatility
            
            
            9.79
            %
            
            13.98
            %
            
            9.89
            %
            
            19.47
            %
            
            *Dividend
                yield
            
            
            4.55
            %
            
            4.17
            %
            
            4.42
            %
            
            4.39
            %
            
            *


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





The
      expected lives of the securities represent 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
      September 30:





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2006
            2005
            2006
            2005Service
                cost
            
            $
            3,293
            
            $
            2,887
            
            $
            99
            
            $
            77Interest
                cost
            
            
            6,171
            
            
            5,964
            
            
            426
            
            
            359Expected
                return on plan assets
            
            
            (9,310
            )
            
            (9,482
            )
            
            (290
            )
            
            (220
            )Amortization
                of prior service cost
            
            
            585
            
            
            717
            
            
            134
            
            
            116Recognized
                net actuarial (gain) loss
            
            
            1,423
            
            
            839
            
            
            49
            
            
            (140
            )Amortization
                of transition (asset) obligation
            
            
            --
            
            
            (41
            )
            
            104
            
            
            105Net
                periodic benefit cost
            
            $
            2,162
            
            $
            884
            
            $
            522
            
            $
            297





The
      following summarizes the net periodic benefit cost for the nine months ended
      September 30:





Pension
                Benefits
            
            Other
                Benefits(Dollars
                in thousands)
            
            2006
            
            2005
            
            2006
            
            2005Service
                cost
            
            $
            9,415
            
            $
            8,662
            
            $
            270
            
            $
            229Interest
                cost
            
            
            18,501
            
            
            17,891
            
            
            1,142
            
            
            1,056Expected
                return on plan assets
            
            
            (28,179
            )
            
            (28,446
            )
            
            (653
            )
            
            (659
            )Amortization
                of prior service cost
            
            
            1,756
            
            
            2,150
            
            
            401
            
            
            349Recognized
                net actuarial (gain) loss
            
            
            3,922
            
            
            2,516
            
            
            (205
            )
            
            (458
            )Amortization
                of transition (asset) obligation
            
            
            --
            
            
            (122
            )
            
            314
            
            
            314Net
                periodic benefit cost
            
            $
            5,415
            
            $
            2,651
            
            $
            1,269
            
            $
            831





The
      Company previously disclosed in its financial statements for the year ended
      December 31, 2005 that it expected contributions by the Company to fund the
      pension and other benefits plans for the year ended December 31, 2006 to be
      $2.1
      million and $1.0 million, respectively. During the three and nine months ended
      September 30, 2006, the actual cash contributions to the pension plans were
      $0.4
      million and $2.6 million, respectively. Based on this activity, the Company
      anticipates contributing an additional $0.9 million to the Company’s
      non-qualified pension plan in 2006. The full amount of the pension plan funding
      for 2006 is for the Company’s non-qualified supplemental retirement
      plan.


During
      the three and nine months ended September 30, 2006, actual other post-retirement
      medical benefit plan contributions were less than $0.1 million and $0.7 million,
      respectively, and the Company does not expect to make additional contributions
      for the remaining period of 2006. The total contributions for 2006 will be
      $0.7
      million.


On
      September 29, 2006, Financial Accounting Standards Board (FASB) issued SFAS
      No.
      158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
      Plans.” SFAS No. 158 is effective for fiscal years ending after December 15,
      2006, which will be the year ended December 31, 2006, for the Company. SFAS
      No.
      158 will be adopted prospectively, as required by the statement. SFAS No. 158
      requires the Company to report the overfunded or underfunded status of defined
      benefit postretirement plans in the Company’s consolidated balance sheet. An
      overfunded status would result in the recognition of an asset and an underfunded
      status would result in the recognition of a liability. This amount is to be
      measured as the difference between the fair value of plan assets and the
      projected benefit obligation. At December 31, 2005, the combined fair value
      of
      plan assets and projected benefit obligation for the Company’s defined benefit
      pension and the retiree medical and life plans was $481.0 million and $439.0
      million, respectively. At September 30, 2006, the Company estimates that upon
      adoption of the standard, it will record a pre-tax charge to Accumulated Other
      Comprehensive Income of approximately $64.0 million, a reduction of
      approximately $54.0 million to the pension plan prepaid asset and an increase
      of
      approximately $10.0 million to benefit plan liabilities. Actual return on plan
      assets for the fourth quarter 2006 could influence these estimates.








**(7)**
            **Regulation
                and Rates**





On
      September 27, 2006, the Washington Commission approved a revision of PSE's
      Purchased Gas Adjustment (PGA) tariff schedule that went into effect on October
      1, 2006. The tariff changes will increase gas revenue approximately $95.1
      million, or 9.9%, on an annual basis. The rate increase authorized PSE to
      recover higher projected future gas and gas transportation costs, as well as
      to
      collect the accumulated PGA receivable balance over a 24-month period (beginning
      October 1, 2006). The PGA rate change will increase PSE's gas revenue, but
      will
      not impact the Company's net income as the increased revenue will be offset
      by
      increased purchased gas costs. The PGA Mechanism passes through to customers
      increases or decreases in the gas supply portion of the natural gas service
      rates based upon changes in gas prices.


On
      July
      10, 2006, PSE reduced its gas general rate increase request filed with the
      Washington Commission on February 15, 2006 from $40.4 million to $39.2 million,
      or 4.2%, on an annual basis. On September 15, 2006, the Company adjusted the
      requested general rate increase to $38.9 million annually. PSE also has
      requested approval of a new depreciation tracker in its original gas general
      rate case filing to recover increases in gas distribution depreciation costs
      incurred between general rate cases of $10.9 million. In addition, a gas
      decoupling mechanism, which does not have an impact on the current rate
      increase, was requested; however, it is designed to stabilize revenue changes
      due to load variations between regulatory filings. The resolution of the general
      rate case is expected by the end of 2006.


On
      September 27, 2006, the Washington Commission approved a revision of PSE's
      electric rate tariff Schedule 94 "Residential and Farm Exchange Benefit" that
      became effective October 1, 2006. The Schedule 94 credit rate was reduced from
      $0.01740 to $0.01028 per kWh, reflecting a reduction in the annual estimated
      value of the BPA Residential Exchange benefits from $174.4 million to $105.0
      million, beginning October 1, 2006. This tariff revision will have the impact
      of
      increasing PSE electric customer revenues, but will not impact PSE net income.
      Under Federal law, BPA is required to provide benefits from the low-cost federal
      power system to residential and small farm customers served by investor-owned
      utilities in the Northwest. All benefits received by an investor-owned utility
      must be passed on to its residential and small farm customers.


On
      June
      28, 2006, the Washington Commission approved a 5.9%, or $45.3 million, Power
      Cost Only Rate Case (PCORC) increase in electric rates for the period July
      1,
      2006 through December 31, 2006. The increase allows PSE to recover higher
      projected costs of power caused primarily by higher market prices for natural
      gas used as fuel for electric generators. The rate increase will not
      appreciatively impact PSE’s income. The annualized basis of the PCORC rate
      increase when applied to the general rate case test year is $96.1 million.
      Primarily as a result of this order, on July 10, 2006, PSE reduced its pending
      electric general tariff increase from $140.9 million to $42.9 million, or 2.5%,
      on an annualized basis. On September 15, 2006, the Company adjusted the
      requested increase to $33.5 million annually. Additionally, PSE has requested
      approval of a new tariff in its original general rate case filing to recover
      increases in electric transmission and distribution depreciation costs incurred
      between general rate cases of $7.9 million. The resolution of the general rate
      case is expected by the end of 2006.


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 $89.0 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 the payment as a regulatory asset with accrual of carrying
      costs at the Company’s net of tax rate of return. On April 26, 2006, the
      Washington Commission approved the accounting petition to defer the capacity
      reserve payment plus carrying costs on a temporary basis until resolution of
      PSE’s electric general rate case later this year.


At
      September 30, 2006, PSE had a net receivable totaling $21.2 million in
      connection with wholesale sales in 2000 to the California Independent System
      Operator (CAISO) and counterparties where payment to PSE was conditioned on
      the
      counterparties being paid by the California Power Exchange Corporation
      (California PX). In August 2005, PSE submitted its audited Fuel Cost Allowance
      Claim with the CAISO. That claim was challenged by the California Parties,
      but
      on August 23, 2006, FERC issued an order approving PSE’s Fuel Cost Allowance
      Claim. In addition, PSE filed a portfolio cost claim, and 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 stated
      claim. PSE does not agree with all of FERC’s rulings and sought rehearing, which
      is still pending at FERC. PSE’s ability to recover all or a portion of these
      claims is uncertain at the present time.


In
      addition, on August 2, 2006, the United States Court of Appeals for the Ninth
      Circuit issued a decision in *CPUC
      v. FERC* regarding the scope of refunds and the transactions subject to refunds, and
      ordered the matter remanded to FERC for further proceedings. The August 2,
      2006
      decision, discussed below at “Proceedings Relating to the Western Power Market,”
may adversely impact PSE’s ability to recover the full amount of its CAISO
      Receivable. As a result of the August 2, 2006 decision, PSE cannot assess the
      ultimate resolution of its California Receivable. Accordingly, PSE has estimated
      a range related to its CAISO receivable to be between $21.2 million (PSE’s net
      receivable balance) and $29.5 million, including interest, on its past due
      receivables as of September 30, 2006. As a result of the Ninth Circuit decision
      of August 2, 2006, PSE cannot assess the ultimate resolution of its California
      Receivable. At this time there is no reasonable basis to adjust PSE’s receivable
      balance of $21.2 million because the procedural outcome of a rehearing or remand
      to FERC is uncertain and any financial impact cannot be quantified.








**(8)**
            **Litigation
                and Contingencies**





There
      are
      several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville
      Power Administration (BPA), in which the petitioners assert or may assert that
      BPA acted contrary to law or without authority in deciding to enter into, or
      in
      entering into or performing or implementing, a number of agreements, including
      the amended settlement agreement (and the May 2004 agreement) between BPA and
      PSE regarding the BPA Residential Purchase and Sale Program. BPA rates used
      in
      such agreements between BPA and PSE for determining the amounts of money to
      be
      paid to PSE by BPA under such agreements during the period October 1, 2001
      through September 30, 2006 have been confirmed, approved and allowed to go
      into
      effect by FERC. There are also several actions in the U.S. Ninth Circuit Court
      of Appeals against BPA, in which petitioners assert that BPA acted contrary
      to
      law in adopting or implementing the rates or rate adjustment clause upon which
      the benefits received or to be received from BPA during the October 1, 2001
      through September 30, 2006 period are based. The parties to these various
      actions presented oral arguments to the U.S. Ninth Circuit Court of Appeals
      in
      November 2005. A decision from the Court is anticipated in 2006 or early 2007.
      A
      number of parties have claimed that the BPA rates proposed or adopted in the
      BPA
      rate proceeding to develop BPA rates to be used in the agreements for
      determining the amounts of money to be paid to PSE by BPA during the period
      October 1, 2006 through September 30, 2009 are contrary to law and that BPA
      acted contrary to law or without authority in deciding to enter into, or in
      entering into or performing or implementing such agreements. It is not clear
      what impact, if any, development or review of such rates, review of such
      agreements and the above described U.S. Ninth Circuit Court of Appeals actions
      may have on PSE.


On
      April
      29, 2004, the Minerals Management Service of the United States Department of
      the
      Interior (MMS) issued an order to Western Energy Company (WECO) to pay
      additional royalties concerning coal purchased by PSE for Colstrip Units 3
&
4. The order seeks payment of an additional $1.1 million in royalties for coal
      mined from federal land between April 1997 and June 30, 2000. During that
      period, PSE’s coal price was reduced by a settlement agreement entered into in
      February 1997 among PSE, WECO and Montana Power Company that resolved disputes
      that were then pending. The order seeks to impute the price charged to PSE
      based
      on the other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is
      supporting WECO’s appeal of the order. In addition, the State of Montana issued
      a demand to WECO based upon an audit in May 2005 for allegedly unpaid royalties,
      asserting this same theory. The amount claimed in that demand is $0.2 million.
      PSE accrued a loss reserve in the amount of $1.1 million in connection with
      this
      matter in the second quarter 2004 and updated that amount to $1.8 million in
      the
      third quarter 2006.


In
      addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional
      royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders
      assert that additional royalties are owed as a result of WECO not paying
      royalties in connection with revenue received by WECO from the Colstrip Units
      3
& 4 owners under a coal transportation agreement during the period October
      1, 1991 through December 31, 2001. On April 28, 2005, the appeals division
      of
      the MMS issued an order that reduced the amount claimed due to the application
      of statute of limitations. PSE’s share of the alleged additional royalties is
      approximately $1.7 million, which is equivalent to PSE’s 25% ownership interest
      in Colstrip Units 3 & 4. The state of Montana issued a demand to WECO in May
      2005 consistent with the MMS position outlined above on these transportation
      revenues. The state’s position, if correct, would result in an additional $0.1
      million claim against PSE. The transportation agreement provides for the
      construction and operation of a conveyor system that runs several miles from
      the
      mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is
      monitoring the process. PSE believes that the Colstrip Units 3 & 4 owners
      have reasonable defenses in this matter based upon its review. However, if
      the
      MMS position prevails, this issue could create ongoing expenses as the conveyor
      system continues to be used. Further, on September 28, 2006, the MMS issued
      an
      order to pay additional royalties in the amount of $1.5 million on the basis
      of
      an audit of WECO’s royalty payments during the three years 2002 to 2004 and that
      applies the same theory to the transportation revenues. PSE’s share of that
      claim is approximately $0.4 million based upon PSE’s ownership of the projects.
      If litigated, this claim would follow the same process as the two already
      pending, involving a multiple-layer appellate process before a final decision.
      It is likely that any result would be substantially identical to the resolution
      on the two periods already pending.








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





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


On
      June
      1, 2006, PSE entered into a revolving credit facility with its parent, Puget
      Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE
      may borrow up to $30.0 million from Puget Energy, subject to approval by Puget
      Energy. Under the terms of the Note, PSE pays interest on the outstanding
      borrowings based on the lowest of the weighted average interest rate of (a)
      PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured
      revolving credit facility; or (c) the interest rate available under the
      receivable securitization facility of PSE Funding, Inc., a PSE subsidiary,
      which
      is the LIBOR rate plus a marginal rate. At September 30, 2006, the outstanding
      balance of the Note was $24.2 million. The outstanding balance and the related
      interest under the Note are eliminated by Puget Energy upon consolidation of
      PSE’s financial statements.








**(10)**
            **Financings**





On
      September 18, 2006, PSE completed the issuance of $300 million of senior secured
      notes at a rate of 6.274%, which are due on March 15, 2037. The net proceeds
      from the issuance of the senior notes of approximately $297.4 million were
      used
      to repay PSE’s outstanding short-term debt which was incurred primarily to fund
      construction programs. The yield to maturity of the $300 million senior secured
      notes was 6.29% after the settlement of two forward starting swap interest
      rate
      contracts.


On
      June
      30, 2006, PSE redeemed for $200 million all of the outstanding shares of the
      8.40% Trust Originated Preferred Securities of the Puget Sound Energy Capital
      Trust II (classified as Junior Subordinated Debentures of the Corporation
      Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred
      Securities on the balance sheet) at $25 par value per share plus accrued
      interest to the redemption date.


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





**(11)**
            **Other**





PSE
      leases the Whitehorn power generating facility, a 147 MW net capacity dual-fuel
      combustion turbine, under a noncancelable operating lease expiring in February
      2009. PSE entered into an agreement on October 17, 2006 with the lessor under
      which PSE agreed to purchase the generation facilities after the lease term
      expires in February 2009, provided that all conditions precedent are satisfied
      or waived. In the fourth quarter 2006, the lease will be treated as a capital
      lease over its remaining lease period.


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


For
      the
      three purchase power agreements that may be considered variable interest
      entities under FIN 46R, PSE is required to buy all the generation from these
      plants, subject to displacement by PSE, at rates set forth in the purchase
      power
      agreements. If at any time the counterparties cannot deliver energy to PSE,
      PSE
      would have to buy energy in the wholesale market at prices which could be higher
      or lower than the purchase power agreement prices. PSE’s purchased electricity
      expense for the three months ended September 30, 2006 and 2005 for these three
      entities was $78.8 million and $73.2 million, respectively. PSE’s purchased
      electricity expense for the nine months ended September 30, 2006 and 2005 for
      these three entities was $174.7 million and $186.7 million,
      respectively.


The
      US
      Environmental Protection Agency requires states to produce regulations by
      November 15, 2006 that will bring their mercury emissions in line with those
      mandated by the Clean Air Mercury Rule (CAMR). The Montana Board of
      Environmental Review approved the state’s regulation to limit mercury emissions
      from coal-fired plants on October 16, 2006. The new rule takes a two-tiered
      approach to reducing mercury emissions, allowing power plants burning
      lower-quality lignite coal to release more emissions than plants burning cleaner
      sub-bituminous coal, such as Colstrip. The new rule has a more stringent limit
      than the federal rule (0.9 lbs/Trillion British thermal unit (TBtu), instead
      of
      the federal 1.4 lbs/TBtu), but includes a cap-and-trade provision as well as
      alternative emission limits for plants that have tried to meet the new standards
      but have demonstrated that they cannot. The Colstrip owners are still evaluating
      the potential impact of the new rule and it is still unknown whether the new
      rule will be appealed.








**(12)**
            **New
                Accounting Pronouncements**





At
      its
      June 15, 2006 meeting, FASB's Emerging Issues Task Force (EITF) approved the
      issuance of EITF Issue No. 06-3, “How Taxes Collected from Customers and
      Remitted to Governmental Authorities Should Be Presented in the Income Statement
      (That Is, Gross versus Net Presentation).” EITF No. 06-3 will require disclosure
      whether or not the taxes collected from customers and remitted to government
      authorities are reported on a gross (included in revenues and costs) or a net
      (excluded from revenues) basis. In addition, for any such taxes that are
      reported on a gross basis, a company should disclose the amounts of those taxes
      in interim and annual financial statements for each period for which an income
      statement is presented if those amounts are significant. The EITF concluded
      that
      these requirements should be applied to financial reports for interim and annual
      periods beginning after December 15, 2006, which will be the quarter ended
      March
      31, 2007, for the Company. PSE collected Washington State excise taxes (which
      are a component of general retail rates) and municipal taxes of $35.9 million
      and $141.2 million for the three and nine months ended September 30, 2006,
      respectively, and $31.7 million and $122.6 million for the three and nine months
      ended September 30, 2005, respectively. The Company’s policy is to report such
      taxes on a gross basis in operating revenues and taxes other than income taxes
      in the accompanying consolidated statements of income.


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


On
      September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS
      No. 157 standardizes the measurement of fair value when it is required under
      generally accepted accounting principles (GAAP). SFAS No. 157 is effective
      for
      fiscal years beginning after November 15, 2007, which will be the year beginning
      January 1, 2008, for the Company. The adoption of SFAS No. 157 is not expected
      to have a material impact on the Company’s financial statements.


On
      September 29, 2006, FASB issued SFAS No. 158, “Employers’ Accounting for Defined
      Benefit Pension and Other Postretirement Plans.” See Note 6, “Retirement
      Benefits” for discussion of the new statement.








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





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








**Overview**





Puget
      Energy is an energy services holding company and all of its operations are
      conducted through its subsidiary Puget Sound Energy (PSE), a regulated electric
      and gas utility company, and until May 7, 2006, InfrastruX Group, Inc.
      (InfrastruX). Puget Energy owned a 90.9% interest in InfrastruX, a utility
      construction and services company, until it was sold to an affiliate of Tenaska
      Power Fund, L.P. on May 7, 2006. After repayment of debt, adjustments for
      working capital, transaction costs and distributions to minority interests,
      Puget Energy received $95.9 million for its 90.9% interest in InfrastruX in
      the
      second quarter 2006. The sale resulted in an after-tax gain of $29.8 million
      for
      the nine months ended September 30, 2006. Puget Energy accounted for InfrastruX
      as a discontinued operation under Statement of Financial Accounting Standards
      (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
in 2005 and 2006. See section titled “InfrastruX” for further discussion. The
      $95.9 million net proceeds Puget Energy received from the sale of InfrastruX
      were used to support PSE through an equity contribution of $65.0 million and
      a
      loan of $24.2 million. In addition, Puget Energy established a charitable
      foundation, Puget Sound Energy Foundation (Foundation), in the second quarter
      2006 with a contribution of $15.0 million from the net proceeds from the sale
      of
      InfrastruX along with investment income of $0.4 million on the cash proceeds
      and
      a federal income tax benefit of $5.3 million from funding the Puget Sound Energy
      Foundation.





**Puget
      Sound Energy**


PSE
      generates revenues from the sale of electric and gas services, mainly to
      residential and commercial customers within Washington State. Variations in
      energy usage by customers occur from season to season primarily as a result
      of
      weather conditions. PSE normally experiences higher retail energy sales and
      subsequently higher power costs during the winter heating season in the first
      and fourth quarters of the year and its lowest sales in the third quarter of
      the
      year.


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


PSE’s
      main operational objective is to provide reliable, safe and cost-effective
      energy to its customers. To help accomplish this objective, PSE is implementing
      a strategy to be more self-sufficient in energy generation resources. PSE is
      continually exploring new electric-power resource generation and long-term
      purchase power agreements to meet this goal. The completion of the Hopkins
      Ridge
      wind project in the fourth quarter 2005 and progress on construction of the
      Wild
      Horse wind project are two steps in reaching this goal. The Hopkins Ridge wind
      project provides approximately 150 MW of capacity or 52 average MW. The Company
      expects to complete construction of the Wild Horse wind project in the fourth
      quarter 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.


In
      August
      2006, PSE announced the selection of seven projects for further discussion
      and
      possible negotiation as a result of the 2005 RFP process. In aggregate, these
      outside sources, if completed, would generate approximately 1,100 megawatts
      (MW)
      of long-term power supply in total. The outcome of such discussion and
      negotiation cannot now be determined.








**Results
      of Operations**





**Puget
      Energy**


All
      the
      operations of Puget Energy are conducted through PSE and until May 7, 2006,
      InfrastruX. Net income for the three months ended September 30, 2006 was $15.9
      million on operating revenues from continuing operations of $519.5 million
      compared to net income of $5.9 million on operating revenues from continuing
      operations of $490.4 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 September 30, 2006 were
      $0.14 compared to basic and diluted earnings per share for the three months
      ended September 30, 2005 of $0.06. The discontinued operations of InfrastruX
      had
      no impact on the basic and diluted earnings per share for the three months
      ended
      September 30, 2006 and 2005.


Net
      income for the three months ended September 30, 2006 was positively impacted
      by
      increased electric margins of $22.2 million compared to the same period in
      2005
      primarily from increased sales volumes and overrecovery of power costs under
      the
      Power Cost Adjustment (PCA) mechanism. Higher electric margins were also the
      result of two Power Cost Only Rate Cases (PCORC) effective November 1, 2005
      and
      July 1, 2006 which increased rates by 3.65% and 5.9%, respectively. The
      overrecovery of power costs in the third quarter is seasonal as power costs
      are
      normally below the benchmark rate set in the PCA mechanism. PSE expects to
      underrecover in the fourth quarter 2006 as power costs are likely to exceed
      the
      benchmark rate set in the PCA mechanism. The increase in electric margin was
      offset by an increase of $6.0 million related to utility operation and
      maintenance expense and a $5.0 million increase in depreciation and amortization
      expense of which $2.3 million is related to Hopkins Ridge which is recovered
      in
      electric rates.


For
      the
      nine months ended September 30, 2006, Puget Energy’s net income was $162.1
      million on operating revenues from continuing operations of $2.0 billion
      compared to net income of $90.9 million on operating revenues from continuing
      operations of $1.7 billion for the same period in 2005. Basic earnings per
      share
      for the nine months ended September 30, 2006 was $1.40 compared to basic
      earnings per share of $0.91 for the same period in 2005 and diluted earnings
      per
      share for the nine months ended September 30, 2006 was $1.39 compared to basic
      and diluted earnings per share of $0.90 for the same period in 2005. Included
      in
      the basic earnings per share for the nine months ended September 30, 2006 and
      2005 was $0.45 and $0.01 respectively, earnings per share related to
      discontinued operations of InfrastruX. Included in the diluted earnings per
      share for the nine months ended September 30, 2006 and 2005 was $0.44 and $0.01
      respectively, earnings per share related to discontinued operations of
      InfrastruX.


Net
      income for the nine months ended September 30, 2006 was positively impacted
      by
      income from discontinued operations of InfrastruX of $51.9 million (after-tax)
      compared to $0.9 million (after-tax) for the nine months ended September 30,
      2005. The income from discontinued operations for the nine months ended
      September 30, 2006 includes a gain on disposal of $29.8 million (after-tax)
      resulting from the sale of InfrastruX. The reversal of an InfrastruX carrying
      value charge recognized in 2005 of $7.3 million contributed to the gain on
      disposal as well as $10.0 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.” Natural gas and electric margins increased by $18.7
      million and $44.2 million, respectively, for the nine months ended September
      30,
      2006 compared to the same period in 2005, which positively impacted net income.
      The increase in natural gas margins resulted from increased natural gas general
      tariff rates, increased sales volumes and the non-occurrence of a purchased
      gas
      true-up of previously reported gas costs in 2005 of $4.5 million. The increase
      in electric margins was the result of increased sales volumes, overrecovery
      of
      power costs under the PCA mechanism and two PCORC rate increases effective
      November 1, 2005 and July 1, 2006. The overrecovery of power costs in the third
      quarter is seasonal as power costs are normally below the benchmark rate set
      in
      the PCA mechanism. PSE expects to underrecover in the fourth quarter 2006 as
      power costs will exceed the benchmark set in the PCA mechanism. Income from
      continuing operations was $119.9 million for the nine months ended September
      30,
      2006, excluding the impact of the charitable contribution to the Foundation.
      Management of the Company believes it is useful to present income from
      continuing operations and diluted earnings excluding the impact of the
      charitable contribution because it represents a more accurate measure of
      operating performance and facilitates period-to-period comparisons. Basic and
      diluted earnings per share from continuing operations were $1.03 for the nine
      months ended September 30, 2006, excluding the impact of the charitable
      contribution to the Foundation. A reconciliation to amounts under generally
      accepted accounting principles is as follows:





(Dollars
                in millions, except per share amounts)
            
            Nine
                Months Ended
              September
                30, 2006Income
                from continuing operations, as reported
            
            $
            110.1Add:
                Impact of charitable contribution to Foundation, net of
                tax
            
            
            9.8Income
                from continuing operations, excluding charitable
                contribution
            
            $
            119.9Earnings
                per share:Basic
                and diluted earnings per share before cumulative effect of accounting
                change from continuing operations, as reported
            
            $
            0.95Add:
                Impact of charitable contribution to Foundation
            
            
            0.08Basic
                and diluted earnings per share before cumulative effect of accounting
                change from continuing operations, excluding charitable
                contribution
            
            $
            1.03





**Puget
      Sound Energy**


PSE’s
      operating revenues and associated expenses are not generated evenly during
      the
      year. Variations in energy usage by customers 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 and
      subsequently higher power costs during the winter 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 September 30, 2006 compared to the same period in 2005. Electric
      margin is electric sales to retail and transportation customers less
      pass-through tariff items and revenue-sensitive taxes, and the cost of
      generating and purchasing electric energy sold to customers, including
      transmission costs to bring electric energy to PSE’s service
      territory.





Electric
                Margin(Dollars
                in Millions)
              Three
                Months Ended September 30,
            2006
            2005
            Change
            Percent
              ChangeElectric
                retail sales revenue
            $
            363.3
            
            $
            315.3
            
            $
            48.0
            
            15.2
            %Electric
                transportation revenue
            
            3.4
            
            
            1.7
            
            
            1.7
            
            100.0
            %Other
                electric revenue-gas supply resale
            
            (0.1
            )
            
            9.1
            
            
            (9.2
            )
            (101.1
            )
                %Total
                electric revenue for margin1
            
            366.6
            
            
            326.1
            
            
            40.5
            
            12.4
            %Adjustments
                for amounts included in revenue:Production
                tax credits (PTCs)
            
            3.1
            
            
            --
            
            
            3.1
            
            *Pass-through
                tariff items
            
            (8.3
            )
            
            (6.5
            )
            
            (1.8
            )
            (27.7
            )
                %Pass-through
                revenue-sensitive taxes
            
            (26.7
            )
            
            (23.2
            )
            
            (3.5
            )
            (15.1
            )
                %Residential
                exchange credit
            
            35.9
            
            
            34.5
            
            
            1.4
            
            4.1
            %Net
                electric revenue for margin
            
            370.6
            
            
            330.9
            
            
            39.7
            
            12.0
            %Minus
                power costs:Electric
                generation fuel
            
            (36.3
            )
            
            (21.1
            )
            
            (15.2
            )
            (72.0
            )
                %Purchased
                electricity, net of sales to other utilities and marketers2
            
            (155.5
            )
            
            (160.2
            )
            
            4.7
            
            2.9
            %Total
                electric power costs3
            
            (191.8
            )
            
            (181.3
            )
            
            (10.5
            )
            (5.8
            )
                %Electric
                margin before PCA
            
            178.8
            
            
            149.6
            
            
            29.2
            
            19.5
            %Tenaska
                disallowance reserve
            
            (3.9
            )
            
            --
            
            
            (3.9
            )
            *Electric
                margin before PTCs revenue credit4
            
            174.9
            
            
            149.6
            
            
            25.3
            
            16.9
            %Production
                tax credits revenue reduction
            
            (3.1
            )
            
            --
            
            
            (3.1
            )
            *Electric
                margin including PTCs revenue credit4
            $
            171.8
            
            $
            149.6
            
            $
            22.2
            
            14.8
            %





____________________________*
            *Percent
                change not applicable or meaningful.*1
            *For
                the three months ended September 30, 2006, total electric revenue
                for
                margin was $366.6 million, which does not include $24.3 million in
                sales
                to other utilities and marketers and $8.3 million in other miscellaneous
                electric revenue included in electric operating revenues of $399.2
                million. For the three months ended September 30, 2005, total electric
                revenue for margin was $326.1 million, which does not include $40.6
                million in sales to other utilities and marketers and $8.3 million
                in
                other miscellaneous electric revenues included in electric operating
                revenues of $375.0 million.*2
            *For
                the three months ended September 30, 2006, purchased electricity,
                net of
                sales to other utilities and marketers, was $155.5 million, excluding
                sales to other utilities and marketers of $24.3 million and including
                power cost deferral under the PCA mechanism of $3.9 million, purchased
                electricity was $183.7 million. For the three months ended September
                30,
                2005, purchased electricity, net of sales to other utilities and
                marketers, was $160.2 million, excluding sales to other utilities
                and
                marketers of $40.7 million, purchased electricity was $200.9
                million.*3
            *For
                the three months ended September 30, 2006, total electric power costs
                were
                $191.8 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 $(35.9)
                million, unrealized net gain on derivative instruments of $(0.6)
                million
                and power cost deferral of $3.9 million. These amounts, excluding
                sales of
                electricity to other utilities and marketers, provide electric energy
                costs of $183.5 million. For the three months ended September 30,
                2005,
                total electric power costs were $181.3 million, which includes electric
                generation fuel and purchased electricity, net of sales to other
                utilities
                and marketers (see note 2 above), but does not include the residential
                exchange credit of $(34.5) million, and unrealized net loss on derivative
                instruments of $0.5 million. These amounts, excluding sales of electricity
                to other utilities and marketers, provide electric energy costs of
                $187.9
                million.*4
            *Electric
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Electric
      margin increased $22.2 million for the three months ended September 30, 2006
      compared to the same period in 2005 primarily due to overrecovery of power
      costs
      under the PCA mechanism which increased margin by $12.2 million. Retail customer
      kWh sales (residential, commercial and industrial customers) increased 3.4%
      for
      the three months ended September 30, 2006 compared to 2005, which provided
      $5.4
      million to electric margin. In addition, electric margin increased by $7.7
      million as a result of the effects of the PCORC rate increases effective
      November 1, 2005 and July 1, 2006. These amounts were offset by a $3.1 million
      decrease related to production tax credits (PTCs), which are federal income
      tax
      credits received for wind generation, provided to customers through tariff
      rates.


The
      overrecovery of power costs in the third quarter is seasonal as power costs
      are
      normally below the benchmark rate set in the PCA mechanism. PSE expects to
      underrecover in the fourth quarter 2006 as power costs are likely to exceed
      the
      benchmark rate set in the PCA mechanism.


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





Electric
                Margin(Dollars
                in Millions)
              Nine
                Months Ended September 30,
            2006
            2005
            Change
            Percent
              ChangeElectric
                retail sales revenue
            $
            1,143.7
            
            $
            1,018.9
            
            $
            124.8
            
            12.2
            %Electric
                transportation revenue
            
            8.8
            
            
            6.7
            
            
            2.1
            
            31.3
            %Other
                electric revenue-gas supply resale
            
            11.9
            
            
            14.3
            
            
            (2.4
            )
            (16.8
            )
                %Total
                electric revenue for margin1
            
            1,164.4
            
            
            1,039.9
            
            
            124.5
            
            12.0
            %Adjustments
                for amounts included in revenue:Production
                tax credits (PTCs)
            
            10.0
            
            
            --
            
            
            10.0
            
            *Pass-through
                tariff items
            
            (25.4
            )
            
            (19.0
            )
            
            (6.4
            )
            (33.7
            )
                %Pass-through
                revenue-sensitive taxes
            
            (83.4
            )
            
            (75.4
            )
            
            (8.0
            )
            (10.6
            )
                %Residential
                exchange credit
            
            131.2
            
            
            126.7
            
            
            4.5
            
            3.6
            %Net
                electric revenue for margin
            
            1,196.8
            
            
            1,072.2
            
            
            124.6
            
            11.6
            %Minus
                power costs:Electric
                generation fuel
            
            (72.1
            )
            
            (54.4
            )
            
            (17.7
            )
            (32.5
            )
                %Purchased
                electricity, net of sales to other utilities and marketers2
            
            (550.4
            )
            
            (522.5
            )
            
            (27.9
            )
            (5.3
            )
                %Total
                electric power costs3
            
            (622.5
            )
            
            (576.9
            )
            
            (45.6
            )
            (7.9
            )
                %Electric
                margin before PCA
            
            574.3
            
            
            495.3
            
            
            79.0
            
            16.0
            %Tenaska
                disallowance reserve
            
            --
            
            
            5.3
            
            
            (5.3
            )
            *Power
                cost deferred under the PCA mechanism
            
            (16.5
            )
            
            3.0
            
            
            (19.5
            )
            *Electric
                margin before PTCs revenue credit4
            
            557.8
            
            
            503.6
            
            
            54.2
            
            10.8
            %Production
                tax credits revenue reduction
            
            (10.0
            )
            
            --
            
            
            (10.0
            )
            *Electric
                margin including PTC revenue credit4
            $
            547.8
            
            $
            503.6
            
            $
            44.2
            
            8.8
            %


_________________________________


*
            *Percent
                change not applicable or meaningful.*1
            *For
                the nine months ended September 30, 2006, total electric revenue
                for
                margin was $1,164.4 million, which does not include $56.9 million
                in sales
                to other utilities and marketers and $26.3 million in other miscellaneous
                electric revenue included in electric operating revenues of $1,247.6
                million. For the nine months ended September 30, 2005, total electric
                revenue for margin was $1,039.9 million, which does not include $73.8
                million in sales to other utilities and marketers and $26.8 million
                in
                other miscellaneous electric revenues included in electric operating
                revenues of $1,140.5 million.*2
            *For
                the nine months ended September 30, 2006, purchased electricity,
                net of
                sales to other utilities and marketers, was $550.4 million. Excluding
                sales to other utilities and marketers of $56.9 million and including
                power cost deferral under the PCA mechanism of $16.5 million, purchased
                electricity was $623.8 million. For the nine months ended September
                30,
                2005, purchased electricity, net of sales to other utilities and
                marketers, was $522.5 million, excluding sales to other utilities
                and
                marketers of $73.8 million and including the Tenaska disallowance
                reserve
                turnaround of $(5.3) million and power cost deferral under the PCA
                mechanism of $(3.0) million, purchased electricity was $588.0
                million.*3
            *For
                the nine months ended September 30, 2006, total electric power costs
                were
                $622.5 million, which includes electric generation fuel and purchased
                electricity, net of sales to other utilities and marketers (see note
                2
                above), but does not include the residential exchange credit of $(131.2)
                million, unrealized net loss on derivative instruments of $0.2 million
                and
                power cost deferral of $16.5 million. These amounts, excluding sales
                of
                electricity to other utilities and marketers, provide electric energy
                costs of $564.9 million. For the nine months ended September 30,
                2005,
                total electric power costs were $576.9 million, which includes electric
                generation fuel and purchased electricity, net of sales to other
                utilities
                and marketers (see note 2 above), but does not include the residential
                exchange credit of $(126.7) million, unrealized net loss on derivative
                instruments of $0.4 million and including the Tenaska disallowance
                reserve
                turnaround of $(5.3) million and power cost deferral under the PCA
                mechanism of $(3.0) million. These amounts, excluding sales of electricity
                to other utilities and marketers, provide electric energy costs of
                $516.1
                million.*4
            *Electric
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Electric
      margin increased $44.2 million for the nine months ended September 30, 2006
      compared to the same period in 2005 primarily due to overrecovery of power
      costs
      under the PCA mechanism which increased margin by $23.2 million. Retail customer
      kWh sales (residential, commercial and industrial customers) increased 3.8%
      for
      the nine months ended September 30, 2006 compared to 2005, which provided $19.4
      million to electric margin. Electric margin increased as a result of the effects
      of the PCORC rate increases effective November 1, 2005, and July 1, 2006, which
      increased margin by $16.6 million. In addition, the reduction in the Tenaska
      disallowance in the PCA mechanism provided $1.0 million to margin. These
      increases were partially offset by a $10.0 million decrease related to PTCs
      provided to customers through tariff rates and 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.


The
      overrecovery of power costs in the third quarter is seasonal as power costs
      are
      normally below the benchmark rate set in the PCA mechanism. PSE expects to
      underrecover in the fourth quarter 2006 as power costs are likely to exceed
      the
      benchmark rate set in the PCA mechanism.


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





Gas
                Margin(Dollars
                in Millions)
              Three Months Ended September 30,
            2006
            2005
            Change
            Percent
                ChangeGas
                retail revenue
            $
            112.7
            
            $
            103.8
            
            $
            8.9
            
            8.6
            %Gas
                transportation revenue
            
            3.1
            
            
            3.3
            
            
            (0.2
            )
            (6.1
            )
                %Total
                gas revenue for margin1
            
            115.8
            
            
            107.1
            
            
            8.7
            
            8.1
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            (0.7
            )
            
            (0.6
            )
            
            (0.1
            )
            (16.7
            )
                %Pass-through
                revenue-sensitive taxes
            
            (9.2
            )
            
            (8.4
            )
            
            (0.8
            )
            (9.5
            )
                %Net
                gas revenue for margin
            
            105.9
            
            
            98.1
            
            
            7.8
            
            8.0
            %Minus
                purchased gas costs
            
            (68.3
            )
            
            (59.2
            )
            
            (9.1
            )
            (15.4
            )
                %Gas
                margin2
            $
            37.6
            
            $
            38.9
            
            $
            (1.3
            )
            (3.3
            )
                %


_________________________________


1
            *For
                the three months ended September 30, 2006, total gas revenue for
                margin
                was $115.8 million, which does not include $3.8 million related to
                other
                gas operating revenues that is included in gas operating revenues
                of
                $119.6 million. For the three months ended September 30, 2005, total
                gas
                revenue for margin was $107.1 million, which does not include $3.9
                million
                related to other gas operating revenues that is included in gas operating
                revenues of $111.0 million.*2
            *Gas
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Gas
      margin decreased $1.3 million for the three months ended September 30, 2006
      compared to the same period in 2005 primarily due to a 1.2% decline in therm
      sale volumes and customer mix volumes.


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





Gas
                Margin(Dollars
                in Millions)
              Nine Months Ended September 30,
            2006
            2005
            Change
            Percent
                ChangeGas
                retail revenue
            $
            696.4
            
            $
            571.8
            
            $
            124.6
            
            21.8
            %Gas
                transportation revenue
            
            9.8
            
            
            9.9
            
            
            (0.1
            )
            (1.0
            )
%Total
                gas revenue for margin1
            
            706.2
            
            
            581.7
            
            
            124.5
            
            21.4
            %Adjustments
                for amounts included in revenue:Pass-through
                tariff items
            
            (4.5
            )
            
            (3.5
            )
            
            (1.0
            )
            (28.6
            )
              %Pass-through
                revenue-sensitive taxes
            
            (57.7
            )
            
            (47.2
            )
            
            (10.5
            )
            (22.2
            )
                %Net
                gas revenue for margin
            
            644.0
            
            
            531.0
            
            
            113.0
            
            21.3
            %Minus
                purchased gas costs
            
            (453.3
            )
            
            (359.0
            )
            
            (94.3
            )
            (26.3
            )
                %Gas
                margin2
            $
            190.7
            
            $
            172.0
            
            $
            18.7
            
            10.9
            %


_________________________________


1
            *For
                the nine months ended September 30, 2006, total gas revenue for margin
                was
                $706.2 million, which does not include $12.4 million related to other
                gas
                operating revenues that is included in gas operating revenues of
                $718.6
                million. For the nine months ended September 30, 2005, total gas
                revenue
                for margin was $581.7 million, which does not include $13.0 million
                related to other gas operating revenues that is included in gas operating
                revenues of $594.7 million.*2
            *Gas
                margin does not include any allocation for amortization/depreciation
                expense or electric generation operations and maintenance
                expense.*





Gas
      margin increased $18.7 million for the nine months ended September 30, 2006
      compared to the same period in 2005. Gas margin increased $10.0 million due
      to a
      5.6% increase in gas therm volume sales, $7.0 million of the increase was a
      result of the gas general tariff rate case which was effective March 4, 2005
      and
      $4.5 million of the increase was due to the one-time true-up of previously
      reported gas costs in the second quarter 2005. These increases were partially
      offset by a $2.8 million decrease in margin related to customer mix and
      pricing.





**Electric
      Operating Revenues**


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





(Dollars
                in Millions)
              Three
                Months Ended September 30,
            2006
            2005
            Change
            Percent
              ChangeElectric
                operating revenues:Residential
                sales
            $
            150.2
            
            $
            131.7
            
            $
            18.5
            
            14.0
            %Commercial
                sales
            
            174.7
            
            
            153.1
            
            
            21.6
            
            14.1
            %Industrial
                sales
            
            26.0
            
            
            23.7
            
            
            2.3
            
            9.7
            %Other
                retail sales, including unbilled revenue
            
            12.4
            
            
            6.8
            
            
            5.6
            
            82.4
            %Total
                retail sales
            
            363.3
            
            
            315.3
            
            
            48.0
            
            15.2
            %Transportation
                sales
            
            3.4
            
            
            1.6
            
            
            1.8
            
            112.5
            %Sales
                to other utilities and marketers
            
            24.3
            
            
            40.6
            
            
            (16.3
            )
            (40.1
            )%Other
            
            8.2
            
            
            17.5
            
            
            (9.3
            )
            (53.1
            )%Total
                electric operating revenues
            $
            399.2
            
            $
            375.0
            
            $
            24.2
            
            6.5
            %





Electric
      retail sales increased $48.0 million for the three months ended September 30,
      2006 compared to the same period in 2005 due primarily to rate increases related
      to the PCORC rate increases of November 7, 2005 and July 1, 2006 and increased
      retail sales volumes. The PCORC rate increases provided $32.8 million to
      electric operating revenues for the three months ended September 30, 2006
      compared to the same period in 2005. Retail electricity usage increased 152,648
      MWh or 3.4% for the three months ended September 30, 2006 compared to the same
      period in 2005, which resulted in an approximate $10.7 million increase in
      electric operating revenue. During the three month period ended September 30,
      2006, the benefits of the Residential and Farm Energy Exchange Benefit credited
      to customers reduced electric operating revenues by $37.6 million compared
      to
      $36.2 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 September 30, 2006, the benefits of PTCs were
      passed through to electric customers by crediting customers’ bills, which
      reduced electric operating revenues by $3.1 million. The PTCs that reduce income
      taxes are based on generation from the wind plants. The PTCs began November
      2005
      when the Hopkins Ridge wind generation facility was placed in
      service.


Transportation
      sales increased $1.8 million for the three months ended September 30, 2006
      compared to the same period in 2005 due to an increase in sales volume of 34,626
      MWh or 6.7%.


Sales
      to
      other utilities and marketers decreased $16.3 million for the three months
      ended
      September 30, 2006 compared to the same period in 2005. Increased retail
      customer usage was served by PSE’s generation portfolio resulting in less
      generation available for resale in the wholesale market. The decrease in sales
      to other utilities and marketers was also related to slightly lower wholesale
      market prices as compared to the same period in 2005.


Other
      electric revenues decreased $9.3 million for the three months ended September
      30, 2006 compared to the same period in 2005, primarily due to gains that
      occurred in 2005 from gas financial hedges on gas sold and gains from physical
      sales of gas that had been purchased for the Tenaska, Frederickson and Encogen
      plants that did not recur. Lower prices for gas in 2006 resulted in an increased
      usage of the combustion turbines and reduced sales of gas in the wholesale
      market.


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





(Dollars
                in Millions)
              Nine
                Months Ended September 30,
            2006
            2005
            Change
            Percent
              ChangeElectric
                operating revenues:Residential
                sales
            $
            559.3
            
            $
            496.5
            
            $
            62.8
            
            12.6
            %Commercial
                sales
            
            516.9
            
            
            461.1
            
            
            55.8
            
            12.1
            %Industrial
                sales
            
            76.4
            
            
            68.9
            
            
            7.5
            
            10.9
            %Other
                retail sales, including unbilled revenue
            
            (8.9
            )
            
            (7.6
            )
            
            (1.3
            )
            17.1
            %Total
                retail sales
            
            1,143.7
            
            
            1,018.9
            
            
            124.8
            
            12.2
            %Transportation
                sales
            
            8.8
            
            
            6.7
            
            
            2.1
            
            31.3
            %Sales
                to other utilities and marketers
            
            56.9
            
            
            73.8
            
            
            (16.9
            )
            (22.9
            )%Other
            
            38.3
            
            
            41.1
            
            
            (2.8
            )
            (6.8
            )%Total
                electric operating revenues
            $
            1,247.7
            
            $
            1,140.5
            
            $
            107.2
            
            9.4
            %





Electric
      retail sales increased $124.8 million for the nine months ended September 30,
      2006 compared to the same period in 2005 due primarily to increased retail
      sales
      volumes, rate increases related to the PCORC rate increases of November 1,
      2005
      and July 1, 2006 and an increase in electric general tariff rates of March
      4,
      2005. The PCORC and electric general rate increases provided an additional
      $50.7
      million to electric operating revenues for the nine months ended September
      30,
      2006 compared to the same period in 2005. Retail electricity usage increased
      554,821 MWh or 3.8% for the nine months ended September 30, 2006 compared to
      the
      same period in 2005. The increase in electricity usage was mainly the result
      of
      a 1.5% higher average number of customers served in the nine month period ended
      September 30, 2006 compared to the same period in 2005.


During
      the nine month period ended September 30, 2006, the benefits of the Residential
      and Farm Energy Exchange Benefit credited to customers reduced electric
      operating revenues by $137.4 million compared to $132.6 million for the same
      period in 2005. This credit also reduced power costs by a corresponding amount
      with no impact on earnings as this payment is passed through to customers
      through a lower residential exchange tariff credit.


During
      the nine month period ended September 30, 2006, transportation sales increased
      by $2.1 million due to an increase in sales volumes of 87,106 MWh or 5.7% as
      compared to the same period in 2005.


Sales
      to
      other utilities and marketers decreased $16.9 million compared to the nine
      month
      period ended September 30, 2005. Increased retail customer usage was served
      by
      PSE’s generation portfolio resulting in less generation available for resale in
      the wholesale market. The decrease was also related to lower wholesale market
      prices in 2006 as compared to the nine month period ended September 30,
      2005.


Other
      electric revenues decreased $2.8 million for the nine month period ended
      September 30, 2006 compared to the same period in 2005, primarily from reduction
      in sale of excess non-core gas. Non-core gas sales are included in the PCA
      mechanism calculation as a reduction in determining net power
      costs.


The
      following electric rate changes were approved by the Washington Commission
      in
      2006 and 2005:




Type
                  of Rate
                Adjustment
              Effective Date
              Average
                Percentage
                  Increase
                in
                  Rates
              Annual
                  Increase
                in
                  Revenues
                (Dollars
                  in Millions)Electric
                  General Rate Case
              March
                  4, 2005
              4.1
              %
              $
              57.7Power
                  Cost Only Rate Case
              November
                  1, 2005
              3.7
              %
              
              55.6Power
                  Cost Only Rate Case
              July
                  1, 2006
              5.9
              %
              
              45.31


1
            *The
                rate increase is for the period July 1, 2006 through December 31,
                2006.
                The annualized basis of the PCORC rate increase is $96.1
                million.*




**Gas
      Operating Revenues**


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





(Dollars
                in Millions)
              Three
                Months Ended September 30,
            
            2006
            2005
            Change
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            60.9
            
            $
            57.3
            
            $
            3.6
            
            
            6.3
            %Commercial
                sales
            
            
            41.8
            
            
            37.2
            
            
            4.6
            
            
            12.4
            %Industrial
                sales
            
            
            10.0
            
            
            9.2
            
            
            0.8
            
            
            8.7
            %Total
                retail sales
            
            
            112.7
            
            
            103.7
            
            
            9.0
            
            
            8.7
            %Transportation
                sales
            
            
            3.1
            
            
            3.3
            
            
            (0.2
            )
            
            (6.1
            )%Other
            
            
            3.8
            
            
            4.0
            
            
            (0.2
            )
            
            (5.0
            )%Total
                gas operating revenues
            
            $
            119.6
            
            $
            111.0
            
            $
            8.6
            
            
            7.7
            %





Gas
      retail sales increased $9.0 million for the three months ended September 30,
      2006 compared to the same period in 2005 due to higher PGA mechanism rates
      in
      2006 slightly offset by decreased 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 September 30, 2006, the effects of the PGA mechanism rate increases
      provided an increase of $12.2 million in gas operating revenues. Increases
      in
      temperatures for the three months ended September 30, 2006 compared to the
      same
      period in 2005 resulted in a decrease in heating degree days and a corresponding
      decrease in customer usage by 1.6 million therms or approximately $1.2 million
      in gas operating revenues.


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





(Dollars
                in Millions)
              Nine
                Months Ended September 30,
            
            2006
            2005
            Change
            Percent
              ChangeGas
                operating revenues:Residential
                sales
            
            $
            436.0
            
            $
            360.7
            
            $
            75.3
            
            
            20.9
            %Commercial
                sales
            
            
            221.0
            
            
            178.9
            
            
            42.1
            
            
            23.5
            %Industrial
                sales
            
            
            39.4
            
            
            32.2
            
            
            7.2
            
            
            22.4
            %Total
                retail sales
            
            
            696.4
            
            
            571.8
            
            
            124.6
            
            
            21.8
            %Transportation
                sales
            
            
            9.8
            
            
            9.9
            
            
            (0.1
            )
            
            (1.0
            )%Other
            
            
            12.4
            
            
            13.0
            
            
            (0.6
            )
            
            (4.6
            )%Total
                gas operating revenues
            
            $
            718.6
            
            $
            594.7
            
            $
            123.9
            
            
            20.8
            %





Gas
      retail sales increased $124.6 million for the nine months ended September 30,
      2006 compared to the same period in 2005 due to higher PGA mechanism rates
      in
      2006, approval of a 3.5% general gas rate increase in the gas general rate
      case
      and higher retail customer gas usage. The Washington Commission approved a
      PGA
      mechanism rate increase effective October 1, 2005 that provided $81.3 million
      in
      gas revenues for the nine months ended September 30, 2006 compared to the same
      period in 2005. In addition, the gas general rate case increase provided an
      additional $7.0 million in gas operating revenues for the nine months ended
      September 30, 2006 compared to the same period in 2005. The remaining increase
      in gas retail revenues was primarily due to an increase in customers which
      increased 3.0% and higher gas sales of 38.8 million therms or $32.8 million
      for
      the nine months ended September 30, 2006 compared to the same period in
      2005.


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




Type
                  of Rate
                Adjustment
              Effective
                  Date
              Average
                Percentage
                  Increase
                in
                  Rates
              Annual
                  Increase
                in
                  Revenues
                (Dollars
                  in Millions)Gas
                  General Rate Case
              March
                  4, 2005
              3.5
              %
              $
              26.3Purchased
                  Gas Adjustment
              October
                  1, 2005
              14.7
              %
              
              121.6Purchased
                  Gas Adjustment
              September
                  27, 2006
              10.2
              %
              
              95.1




**Operating
      Expenses**


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





(Dollars
                in Millions)
              Three
                Months Ended September 30,
            
            2006
            2005
            Change
            Percent
              ChangePurchased
                electricity
            
            $
            183.7
            
            $
            200.9
            
            $
            (17.2
            )
            
            (8.6
            )%Electric
                generation fuel
            
            
            36.3
            
            
            21.1
            
            
            15.2
            
            
            72.0
            %Residential
                exchange credit
            
            
            (35.9
            )
            
            (34.5
            )
            
            (1.4
            )
            
            (4.1
            )%Purchased
                gas
            
            
            68.3
            
            
            59.1
            
            
            9.2
            
            
            15.6
            %Unrealized
                (gain) loss on derivative instruments
            
            
            (0.6
            )
            
            0.5
            
            
            (1.1
            )
            
            *Utility
                operations and maintenance
            
            
            87.7
            
            
            81.7
            
            
            6.0
            
            
            7.3
            %Depreciation
                and amortization
            
            
            65.5
            
            
            60.5
            
            
            5.0
            
            
            8.3
            %Conservation
                amortization
            
            
            7.1
            
            
            5.6
            
            
            1.5
            
            
            26.8
            %Taxes
                other than income taxes
            
            
            46.3
            
            
            44.8
            
            
            1.5
            
            
            3.3
            %Income
                taxes
            
            
            8.5
            
            
            2.6
            
            
            5.9
            
            
            *




*
            *Percent
                change not applicable or
                meaningful*





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





(Dollars
                in Millions)
              Nine
                Months Ended September 30,
            
            2006
            2005
            Change
            Percent
              ChangePurchased
                electricity
            
            $
            623.8
            
            $
            588.0
            
            $
            35.8
            
            
            6.1
            %Electric
                generation fuel
            
            
            72.2
            
            
            54.4
            
            
            17.8
            
            
            32.7
            %Residential
                exchange credit
            
            
            (131.2
            )
            
            (126.7
            )
            
            (4.5
            )
            
            (3.6
            )%Purchased
                gas
            
            
            453.3
            
            
            359.0
            
            
            94.3
            
            
            26.3
            %Utility
                operations and maintenance
            
            
            258.7
            
            
            240.3
            
            
            18.4
            
            
            7.7
            %Depreciation
                and amortization
            
            
            194.0
            
            
            178.3
            
            
            15.7
            
            
            8.8
            %Conservation
                amortization
            
            
            22.6
            
            
            16.8
            
            
            5.8
            
            
            34.5
            %Taxes
                other than income taxes
            
            
            180.2
            
            
            165.0
            
            
            15.2
            
            
            9.2
            %Income
                taxes
            
            
            64.7
            
            
            55.4
            
            
            9.3
            
            
            16.8
            %





**Purchased
      electricity** expenses
      decreased $17.2 million and increased $35.8 million for the three and nine
      months ended September 30, 2006, respectively, compared to the same periods
      in
      2005. The decrease for the three months ended September 30, 2006 was primarily
      the result of lower wholesale market prices and reduced purchase volumes related
      to increased electric generation. Total purchased power for the three months
      ended September 30, 2006 decreased 217,863 MWh or 5.8% compared to the same
      period in 2005. The increase for the nine months ended September 30, 2006 was
      primarily the result of the overrecovery of power costs and higher customer
      MWh
      sales. Total purchased power for the nine months ended September 30, 2006
      increased 620,671 MWh or 5.1% compared to the same period in 2005. Increases
      in
      the purchases offset by slightly lower wholesale prices of power contributed
      $6.4 million to the increase for the nine months ended September 30, 2006.
      The
      increase also reflected the reversal of previously deferred excess power costs
      of $16.6 million due to lower power costs than what is in the baseline PCA
      mechanism rate. 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 that did not reoccur in
      2006.
      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 $5.1 million
      due
      in part to increased kWh sales to customers.


PSE’s
      hydroelectric production and related power costs in 2005 were negatively
      impacted by below-normal precipitation and reduced snow pack in the Pacific
      Northwest region. PSE cannot determine if lower than normal runoff will continue
      in future years nor what impact lower runoff may have on the amount of
      electricity that will need to be purchased. The July 10, 2006 Columbia Basin
      Runoff Forecast published by the National Weather Service Northwest River
      Forecast Center indicated that the total forecasted runoff above Grand Coulee
      Reservoir for the period January through September 2006 would be 106% of normal,
      which compares to 86% of normal observed runoff for the same period in 2005.
      The
      2007 Columbia Basin Runoff Forecast will be available in December
      2006.


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 $15.2 million and $17.8 million for the three and nine months ended
      September 30, 2006, respectively, compared to the same periods in 2005. The
      increase for the three months ended September 30, 2006 was primarily the result
      of an increase of $12.9 million in the cost of fuel due to higher volumes of
      electricity generated at PSE-controlled combustion turbine generating facilities
      and an increase in the cost of coal at Colstrip generating facilities of $2.3
      million compared to the same period in 2005. The increase for the nine months
      ended September 30, 2006 was primarily the result of an increase of $13.2
      million in the cost of fuel at PSE-controlled combustion turbine generating
      facilities due to higher volumes of electricity generated and an increase in
      the
      cost of coal at Colstrip generating facilities of $4.5 million compared to
      the
      same period in 2005.


**Residential
      exchange credits** associated with the Residential Purchase and Sale Agreement with BPA increased
      $1.4 million and $4.5 million for the three and nine months ended September
      30,
      2006, respectively, compared to the same periods in 2005, as a result of
      increased residential and small farm customer electric load. The residential
      exchange credit is a pass-through tariff item with a corresponding credit in
      electric operating revenue; thus, it has no impact on electric margin or net
      income. Effective October 1, 2006, the annual payment PSE receives from
      Bonneville Power Administration will decrease to $105.5 million for the period
      through September 30, 2007. This will have no impact on PSE’s earnings as this
      payment is passed through to customers through a lower residential exchange
      tariff credit.


**Purchased
      gas** expenses
      increased $9.2 million and $94.3 million for the three and nine months ended
      September 30, 2006, respectively, compared to the same periods in 2005 primarily
      due to an increase in PGA rates as approved by the Washington Commission and
      higher customer therm sales. The PGA mechanism allows PSE to recover expected
      gas costs, and defer, as a receivable or liability, any gas costs that exceed
      or
      fall short of this expected gas cost amount in PGA mechanism rates, including
      accrued interest. The PGA mechanism receivable balance at September 30, 2006
      and
      December 31, 2005 was $83.7 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.


On
      June
      30, 2006 Northwest Pipeline (NWP) filed a Section 4 rate case with the FERC.
      New
      rates for NWP will become effective, subject to refund, on January 1, 2007.
      This
      is the first increase in rates from NWP since 1997 and the increase
      (approximately 42%) reflects costs related to a substantial reconstruction
      of
      the pipeline system in Western Washington. The proposed new rates, if approved,
      will increase PSE’s gas costs by approximately $26.0 million annually. PSE
      expects settlement discussions with the pipeline to commence in the fourth
      quarter 2006. PSE anticipates a settlement can be achieved by first quarter
      2007. The new higher rates for service from NWP are already reflected in PSE’s
      PGA rates that became effective October 1, 2006. Any reduction in the proposed
      rates, as a result of settlement, will be flowed back to PSE’s customers through
      the PGA.


On
      June
      30, 2006 Gas Transmission Northwest (GTN) filed a Section 4 rate case with
      the
      FERC. New rates for GTN will become effective, subject to refund, on January
      1,
      2007. This is the first increase in rates from GTN since 1995 and the increase
      (approximately 70%) primarily results from spreading annual cost over fewer
      contracted volumes. The proposed new rates, if approved, will increase PSE’s gas
      costs by approximately $2.0 million annually. PSE expects settlement discussions
      with the pipeline to commence in the fourth quarter 2006. PSE anticipates a
      settlement by second quarter 2007. The new higher rates for service from GTN
      are
      already reflected in PSE’s PGA rates that became effective October 1, 2006. Any
      reduction in the proposed rates, as a result of settlement, will be flowed
      back
      to PSE’s customers through the PGA.


**Unrealized
      gain on derivative instruments** increased
      $1.1 million for **** the
      three
      months ended September 30, 2006, compared to the same period in 2005 primarily
      as a result of the reversal of prior quarter unrealized gains and losses on
      contracts that did not qualify for normal purchase normal sale exception to
      derivative accounting rules and de-designated gas hedges for electric generation
      that were no longer probable.


**Utility
      operations and maintenance** expense
      increased $6.0 million and $18.4 million for the three and nine months ended
      September 30, 2006, compared to the same period in 2005. The increase for the
      three months ended September 30, 2006 was due to an increase of $3.5 million
      in
      production costs at Colstrip as a result of a major overhaul at Unit 1 and
      as a
      result of PSE’s Hopkins Ridge wind project that became operational on November
      26, 2005. In addition, electric transmission and distribution costs increased
      by
      $3.0 million compared to three months ended September 30, 2005 primarily due
      to
      planned infrastructure maintenance work. The increase for the nine months ended
      September 30, 2006 was primarily due to higher electric distribution system
      restoration costs as a result of a series of strong winter storms with high
      winds in Western Washington during the first quarter 2006. Storm damage related
      costs increased $7.2 million compared to the same period in 2005. In addition,
      maintenance of electric and gas distribution system increased $3.8 million,
      customer service and call center costs increased $2.9 million and gas operations
      and distribution costs increased $2.8 million for the nine months ended
      September 30, 2006 compared to the same period in 2005. In addition, production
      costs increased by $3.4 million primarily related to Colstrip and the Hopkins
      Ridge wind project. These increases were slightly offset by a decrease of $1.7
      million in other expenses. 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 $5.0 million and $15.7 million for the three and nine months ended
      September 30, 2006, respectively, compared to the same periods in 2005 due
      to
      additional utility plant placed in service. Included in the increase for the
      three and nine months ended September 30, 2006 is a $2.3 million and $6.6
      million increase, respectively, related to PSE’s Hopkins Ridge wind project that
      became operational on November 26, 2005. PSE anticipates depreciation expense
      will increase in future years as investments in new generating resources and
      energy delivery infrastructure is completed.


**Conservation
      amortization** increased $1.5 million and $5.8 million for the three and nine months ended
      September 30, 2006, respectively, compared to the same periods in 2005 due
      to
      higher authorized recovery of electric conservation expenditures. Conservation
      amortization is a pass-through tariff item with no impact on
      earnings.


**Taxes
      other than income taxes** increased $1.5 million and $15.2 million for the three and nine months ended
      September 30, 2006, respectively, compared to the same periods in 2005 due
      primarily to increases in revenue-based Washington State excise tax and
      municipal tax due to increased operating revenues. Revenue sensitive Washington
      State excise and municipal taxes have no impact on earnings. For the nine months
      ended September 30, 2006, the increase was slightly offset by a 2006 property
      tax reduction that was settled with the Washington State Department of Revenue
      in August 2006 resulting in a lower valuation than in 2005.


**Income
      taxes** increased $5.9 million and $9.3 million for the three and nine months ended
      September 30, 2006, respectively, compared to the same periods in 2005. The
      increase for the three months ended September 30, 2006 was the result of higher
      taxable income and a higher effective tax rate related to the true-up of the
      prior year federal income tax provision which resulted in an expense in 2006
      versus a benefit in 2005. The increase for the nine months ended September
      30,
      2006 as compared to the same period in 2005 was due to higher taxable income
      offset by a lower effective tax rate influenced by PTCs of $4.9
      million.




**Other
      Income And Interest Charges**


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





(Dollars
                in Millions)
              Three
                Months Ended September 30,
            2006
            2005
            Change
            Percent
              ChangeOther
                income (net of tax)
            $
                4.4
            $
                1.4
            $
                3.0
            **


___________________


*
            *Percent
                change not applicable or
                meaningful*





**Other
      income** increased
      $3.0 million for the three months ended September 30, 2006 compared to the
      same
      period in 2005 primarily due to an increase of $2.6 million related to the
      return of regulatory assets and a decrease of $1.2 million in long-term
      incentive plan expense. These increases were offset by an increase of $0.8
      million in various other expenses.


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





(Dollars
                in Millions)
              Nine
                Months Ended September 30,
            2006
            2005
            Change
            Percent
              ChangeOther
                income (net of tax)
            $
                11.8
            $
                4.2
            $
                7.6
            **


___________________


*
            *Percent
                change not applicable or
                meaningful*





**Other
      income** increased
      $7.6 million for the nine months ended September 30, 2006 compared to the same
      period in 2005 primarily due to an increase of $5.3 million related to the
      return on regulatory assets, a decrease of $3.1 million in long-term incentive
      plan expenses and an increase of $1.5 million related to the equity portion
      of
      allowance for funds used during construction (AFUDC). These increases were
      offset by a decrease of $2.3 million in various other income items.





**InfrastruX**


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


Under
      the
      terms of the sale agreement, Puget Energy is obligated for certain
      representations and warranties made by InfrastruX concerning its business.
      Puget
      Energy obtained a representation and warranty insurance policy and deposited
      $3.7 million into an escrow account to serve as retention under the policy.
      As
      of September 30, 2006, long-term restricted cash in the amount of $3.7 million
      is included in the accompanying balance sheets; that amount represents
      management’s estimate of the aggregate fair value of the amount potentially
      payable under those representations and warranties and is Puget Energy’s maximum
      exposure. The obligation expires May 7, 2008. Should Tenaska make any claims
      against Puget Energy, payment for the claims will be made from the escrow
      account, and total payments are limited to $3.7 million plus any interest earned
      while the funds are in the escrow account. Puget Energy also agreed to indemnify
      the purchaser for certain potential future losses related to one of InfrastruX’s
      subsidiary companies. Under the indemnity agreement, Puget Energy is liable
      for
      certain costs with the maximum amount of loss not to exceed $15.0 million.
      As of
      September 30, 2006, a liability in the amount of $5 million is included in
      the
      accompanying balance sheets; that amount represents Puget Energy’s estimate of
      the fair value of the amount potentially payable using a probability-weighted
      approach to a range of future cash flows. The obligation expires May 7, 2011.
      Puget Energy also provided an environmental guaranty as part of the sale
      agreement. Under the terms of the agreement, Tenaska will be responsible for
      the
      first $0.1 million of environmental claims, Tenaska and Puget Energy will share
      the next $6.4 million equally and Puget Energy will be responsible for the
      next
      $3.5 million. Puget Energy believes it will not have a future loss in connection
      with the environmental guarantee.


For
      the
      nine months ended September 30, 2006, Puget Energy reported InfrastruX related
      income from discontinued operations (net of taxes and minority interest),
      including gain on sale, of $51.9 million compared to $0.9 million (net of taxes
      and minority interest) for the nine months ended September 30, 2005,
      respectively. Puget Energy’s income from discontinued operations for the nine
      months ended September 30, 2006 includes $7.3 million related to the reversal
      of
      a carrying value adjustment recorded in 2005 as well as $10.0 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.”


InfrastruX's
      operating revenue for the nine months ended September 30, 2006 was $138.6
      million compared to $286.7 million for the same period in 2005. Pre-tax income
      for the nine months ended September 30, 2006 was $9.9 million for the same
      period in 2005.













**Capital
      Requirements**


**Contractual
      Obligations and Commercial Commitments**


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





**Puget
              Energy**
            Payments
                Due Per Period**Contractural Obligations**
              **(Dollars in Millions)**
            Total
            2006
            2007-
              2008
            2009-
              2010
            2011
                & ThereafterLong-term
                debt including interest
            $
            5,524.6
            
            $
            80.2
            
            $
            638.8
            
            $
            678.0
            
            $
            4,127.6Short-term
                debt including interest
            
            103.2
            
            
            103.2
            
            
            --
            
            
            --
            
            
            --Junior subordinated debentures payable to a subsidiary trust including
                interest1
            
            102.0
            
            
            0.8
            
            
            6.2
            
            
            6.2
            
            
            88.8Mandatorily
                redeemable preferred stock
            
            1.9
            
            
            --
            
            
            --
            
            
            --
            
            
            1.9Service
                contract obligations
            
            166.5
            
            
            7.3
            
            
            67.2
            
            
            60.8
            
            
            31.2Non-cancelable
                operating leases
            
            91.7
            
            
            3.2
            
            
            29.1
            
            
            21.8
            
            
            37.6Fredonia
                combustion turbines lease2
            
            57.1
            
            
            1.0
            
            
            8.2
            
            
            8.2
            
            
            39.7Energy
                purchase obligations
            
            6,329.5
            
            
            290.3
            
            
            1,812.0
            
            
            1,284.2
            
            
            2,943.0Contract initiation payment/collateral requirement
            
            18.5
            
            
            --
            
            
            --
            
            
            --
            
            
            18.5Financial
                hedge obligations
            
            8.4
            
            
            (4.7
            )
            
            13.1
            
            
            --
            
            
            --Purchase
                obligations
            
            67.7
            
            
            35.3
            
            
            9.7
            
            
            22.7
            
            
            --Non-qualified pension and other benefits funding
            
            49.7
            
            
            2.4
            
            
            11.1
            
            
            10.2
            
            
            26.0Total
                contractual cash obligations
            $
            12,520.8
            
            $
            519.0
            
            $
            2,595.4
            
            $
            2,092.1
            
            $
            7,314.3




**Puget
              Energy**
            ****Amount
                of Commitment
              Expiration
                Per Period**Commercial Commitments**
              **(Dollars in
                Millions)**
            Total
            2006
            2007-
              2008
            2009-
              2010
            2011
                & ThereafterIndemnity
                agreements3
            $
            8.7
            
            $
            --
            
            $
            3.7
            
            $
            --
            
            $
            5.0Credit
                agreement - available4
            
            396.3
            
            
            --
            
            
            --
            
            
            --
            
            
            396.3Unsecured
                credit agreement
            
            20.0
            
            
            --
            
            
            --
            
            
            --
            
            
            20.0Receivable
                securitization facility5
            
            171.7
            
            
            --
            
            
            --
            
            
            171.7
            
            
            --Energy
                operations letter of credit
            
            0.5
            
            
            0.5
            
            
            --
            
            
            --
            
            
            --Total
                commercial commitments
            $
            597.2
            
            $
            0.5
            
            $
            3.7
            
            $
            171.7
            
            $
            421.3




1
            *In
                1997, PSE formed Puget Sound Energy Capital Trust I for the sole
                purpose
                of issuing and selling preferred securities (Trust Securities) to
                investors and issuing common securities to PSE. The proceeds from
                the sale
                of Trust Securities were used by the Trust to purchase Junior Subordinated
                Debentures (Debentures) from PSE. The Debentures are the sole assets
                of
                the Trusts and PSE owns all common securities of the
                Trusts.*2
            *See
                “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
                below.*3
            *Under
                the InfrastruX sale agreement, Puget Energy is obligated for certain
                representations and warranties concerning InfrastruX’s business and
                anti-trust inquiries. The fair value of the business warranty is
                $3.7
                million at September 30, 2006 and the obligation expires on May 7,
                2008.
                Puget Energy also agreed to indemnify the buyer relating to an anti-trust
                inquiry of an InfrastruX subsidiary that had a fair value of $5.0
                million
                at September 30, 2006. See “InfrastruX” above for further
                discussion.*4
            *At
                September 30, 2006, PSE had available a $500 million unsecured credit
                agreement expiring in April 2011. The credit agreement provides credit
                support for letters of credit and commercial paper. At September
                30, 2006,
                PSE had $0.5 million for an outstanding letter of credit and $103.2
                million commercial paper outstanding, effectively reducing the available
                borrowing capacity to $396.3 million.*5
            *At
                September 30, 2006, PSE had available a $171.7 million receivables
                securitization facility that expires in December 2010. There were
                no
                amounts outstanding under the receivables securitization facility
                at
                September 30, 2006. The facility allows receivables to be used as
                collateral to secure short-term loans, not exceeding the lesser of
                $200
                million or the borrowing base of eligible receivables, which fluctuate
                with the seasonality of energy sales to customers. The borrowing
                base of
                eligible receivables at September 30, 2006 was $171.7 million. See
                “Receivables Securitization Facility" below for further discussion.*







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





**Puget
              Sound Energy**
            Payments
                Due Per Period**Contractural Obligations**
              **(Dollars in
                Millions**)
            Total
            2006
            2007-
              2007
            2009-
              2010
            2011
                &
              ThereafterLong-term
                debt including interest
            $
            5,524.6
            
            $
            80.2
            
            $
            638.8
            
            $
            678.0
            
            $
            4,127.6Short-term
                debt including interest1
            
            127.5
            
            
            127.5
            
            
            --
            
            
            --
            
            
            --Junior subordinated debentures payable to a subsidiary trust including
                interest2
            
            102.0
            
            
            0.8
            
            
            6.2
            
            
            6.2
            
            
            88.8Mandatorily
                redeemable preferred stock
            
            1.9
            
            
            --
            
            
            --
            
            
            --
            
            
            1.9Service
                contract obligations
            
            166.5
            
            
            7.3
            
            
            67.2
            
            
            60.8
            
            
            31.2Non-cancelable
                operating leases
            
            91.7
            
            
            3.2
            
            
            29.1
            
            
            21.8
            
            
            37.6Fredonia
                combustion turbines lease3
            
            57.1
            
            
            1.0
            
            
            8.2
            
            
            8.2
            
            
            39.7Energy
                purchase obligations
            
            6,329.5
            
            
            290.3
            
            
            1,812.0
            
            
            1,284.2
            
            
            2,943.0Contract initiation payment/collateral requirement
            
            18.5
            
            
            --
            
            
            --
            
            
            --
            
            
            18.5Financial
                hedge obligations
            
            8.4
            
            
            (4.7
            )
            
            13.1
            
            
            --
            
            
            --Purchase
                obligations
            
            67.7
            
            
            35.3
            
            
            9.7
            
            
            22.7
            
            
            --Non-qualified pension and other benefits funding
            
            49.7
            
            
            2.4
            
            
            11.1
            
            
            10.2
            
            
            26.0Total
                contractual cash obligations
            $
            12,545.1
            
            $
            543.3
            
            $
            2,595.4
            
            $
            2,092.1
            
            $
            7,314.3





**Puget
              Sound Energy**
            Amount
                of Commitment
              Expiration
                Per Period**Commercial Commitments**
              **(Dollars
                in
                Millions)**
            Total
            2006
            2007-
              2008
            2009-
              2010
            2011
                &
              ThereafterCredit
                agreement - available4
            $
            396.3
            
            $
            --
            
            $
            --
            
            $
            --
            
            $
            396.3Unsecured
                credit agreement
            
            20.0
            
            
            --
            
            
            --
            
            
            --
            
            
            20.0Receivable
                securitization facility5
            
            171.7
            
            
            --
            
            
            --
            
            
            171.7
            
            
            --Energy
                operations letter of credit
            
            0.5
            
            
            0.5
            
            
            --
            
            
            --
            
            
            --Total
                commercial commitments
            $
            588.5
            
            $
            0.5
            
            $
            --
            
            $
            171.7
            
            $
            416.3


_______________________


1
            *Short-term
                borrowing includes $24.3 million outstanding debt and interest under
                a
                Demand Promissory Note owed to Puget Energy. The outstanding balance
                under
                the Demand Promissory Note is eliminated by Puget Energy upon
                consolidation of PSE’s financial statements.*2
            *See
                note 1 under Puget Energy above.*3
            *See
                note 2 under Puget Energy above.*4
            *See
                note 4 under Puget Energy above.*5
            *See
                note 5 under Puget Energy
                above.*





**Off-Balance
      Sheet Arrangements**


**Fredonia
      3 and 4 Operating Lease** **.** PSE
      leases two combustion turbines for its Fredonia 3 and 4 electric generating
      facility pursuant to a master operating lease that was amended for this lease
      in
      April 2001. The lease has a term expiring in 2011, but can be canceled by PSE
      at
      any time. Payments under the lease vary with changes in the London Interbank
      Offered Rate (LIBOR). At September 30, 2006, PSE’s outstanding balance under the
      lease was $51.8 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 $575.1 million for the nine months ended September 30,
      2006.
      Utility construction expenditures, excluding AFUDC and excluding new generation
      resources other than the Wild Horse project (which will be determined as the
      Company proceeds through the least cost planning process) are anticipated to
      be
      the following in 2006 and 2007:





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


_______________________


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





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





**Capital
      Resources**


**Cash
      From Operations**


Cash
      generated from operations for the nine months ended September 30, 2006 was
      $152.5 million. During that period the debt portion of AFUDC, which reduced
      interest expense, was $10.2 million and $78.1 million was used for payment
      of
      dividends. Consequently, cash flows available for utility construction
      expenditures and other capital expenditures were $64.2 million or 11.1% of
      the
      $579.0 million in construction expenditures (net of the equity portion of AFUDC
      and customer refundable contributions) and other capital expenditure
      requirements for the nine months ended September 30, 2006. For the nine months
      ended September 30, 2005, cash generated from operations was $301.0 million,
      the
      debt portion of AFUDC, which reduced interest expense, was $6.2 million, and
      $65.9 million was used for payment of dividends. Therefore, cash flows available
      for utility **** construction
      expenditures and other capital **** expenditures
      were $228.9 million, or 57.1% of the $400.7 million in construction expenditures
      (net of the equity portion of AFUDC and customer refundable contributions)
      and
      other capital expenditure requirements for the nine months ended September
      30,
      2005.


The
      following table provides a summary of cash available and construction
      expenditures:




(Dollars
                in Millions)
              (Unaudited)
              Nine Months Ended September 30,
            
            2006
            2005Cash
                from operations
            
            $
            152.5
            
            $
            301.0Less:
                Dividends paid
            
            
            (78.1
            )
            
            (65.9
            )AFUDC
            
            
            (10.2
            )
            
            (6.2
            )Cash
                available for construction expenditures
            
            $
            64.2
            
            $
            228.9Construction
                and energy efficiency expenditures
            
            $
            601.2
            
            $
            417.1Less:
                AFUDC
            
            
            (10.2
            )
            
            (6.2
            )Cash
                received from refundable customer contributions
            
            
            (12.0
            )
            
            (10.2
            )Net
                construction and energy efficiency expenditures
            
            $
            579.0
            
            $
            400.7





The
      overall cash generated from operating activities for the nine month period
      ended
      September 30, 2006 decreased $148.5 million compared to the same period in
      2005.
      This decrease in cash from operations is primarily attributable to a
      non-refundable capacity reservation prepayment of $89.0 million in April 2006
      for the Chelan PUD power sales agreement. This agreement will begin providing
      power to PSE at the end of 2011. In addition, cash from operations decreased
      $24.8 million due to an increase in the amount of taxes paid in 2006 as compared
      to 2005. Cash from operations was also negatively impacted by a $22.0 million
      refund of collateral deposits related to energy counterparties compared to
      a
      $31.0 million receipt in 2005; a $15.0 million payment to fund Puget Sound
      Energy charitable foundation; and an increase of $110.0 million in payments
      made
      for accounts payable related to energy purchases. Offsetting the decrease in
      cash from operations is an increase in accounts receivable of $128.2 million.
      The increase in accounts receivable is primarily attributable to Rainier
      Receivables accounts receivable securitization sale of $150 million in December
      2004 that was collected from customers and directly provided to Rainier
      Receivables in the first quarter 2005. This compares to no activity under the
      Rainier Receivables accounts receivable securitization at December 31, 2005
      due
      to termination of the Rainier Receivables accounts receivable securitization
      program in December 2005. As a result, cash from operations increased due to
      collection of accounts receivable in 2006. Collections of accounts receivable
      will increase in the second and third quarters of the year due to the higher
      accounts receivable balances in the first and fourth quarters of the year
      resulting from the seasonality of PSE’s business.





**Financing
      Program**


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





**Restrictive
      Covenants**


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


·
            approximately
                $245 million of additional first mortgage bonds under PSE’s electric
                mortgage indenture based on approximately $408 million of electric
                bondable property available for issuance, subject to an interest
                coverage
                ratio limitation of 2.0 times net earnings available for interest
                (as
                defined in the electric utility mortgage), which PSE exceeded at
                September
                30, 2006;


·
            approximately
                $361 million of additional first mortgage bonds under PSE’s gas mortgage
                indenture based on approximately $602 million of gas bondable property
                available for issuance, subject to interest coverage ratio limitations
                of
                1.75 times and 2.0 times net earnings available for interest (as
                defined
                in the gas utility mortgage), which PSE exceeded at September 30,
                2006;


·
            approximately
                $660 million of additional preferred stock at an assumed dividend
                rate of
                7.0%; and


·
            approximately
                $689 million of unsecured long-term
                debt.


At
      September 30, 2006, PSE had approximately $3.9 billion in electric and gas
      ratebase to support the interest coverage ratio limitation test for net earnings
      available for interest. SFAS No. 158 will not have an impact on PSE’s
      ratebase.





**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 October 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.


On
      September 18, 2006, PSE completed the issuance of $300 million of senior secured
      notes at a rate of 6.274%, which are due on March 15, 2037. The net proceeds
      from the issuance of the senior notes of approximately $297.4 million will
      be
      used to repay PSE’s outstanding short-term debt which was incurred primarily to
      fund construction programs. The yield to maturity of the $300 million senior
      secured notes was 6.29% after the settlement of two forward starting swap
      interest rate contracts.


On
      June
      30, 2006, PSE redeemed for $200 million all of the outstanding shares of 8.40%
      Trust Originated Preferred Securities of The Puget Sound Energy Capital Trust
      II
      (classified as Junior Subordinated Debentures of the Corporation Payable to
      a
      Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities on the
      balance sheet) at $25 par value per share plus accrued interest to the
      redemption date.


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





**Forward
      Starting Interest Rate Swap Settlement**


In
      the
      third quarter 2006, the Company entered into two forward starting swap
      instruments that were designated by PSE as cash flow hedges at the inception
      of
      the contracts. The purpose of the forward starting swap contracts was to hedge
      interest rate volatility for a debt offering of $300 million that was priced
      on
      September 13, 2006. The settlement loss of $0.6 million ($0.4 million after-tax)
      was recorded in other comprehensive income. In accordance with SFAS No. 133,
      this loss will be amortized out of other comprehensive income as an increase
      to
      interest expense over 30 years.


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





**Liquidity
      Facilities and Commercial Paper**


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





**PSE
      Credit Facilities** ****


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





**Demand
      Promissory Note** **.** On
      June
      1, 2006, PSE entered into a revolving credit facility with its parent, Puget
      Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE
      may borrow up to $30 million from Puget Energy, subject to approval by Puget
      Energy. Under the terms of the Note, PSE pays interest on the outstanding
      borrowings based on the lowest of the weighted average interest rate of (a)
      PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured
      revolving credit facility; or (c) the interest rate available under the
      receivable securitization facility of PSE Funding, Inc., a PSE subsidiary,
      which
      is the LIBOR rate plus a marginal rate. At September 30, 2006, the outstanding
      balance of the Note was $24.2 million. The outstanding balance and the related
      interest under the Note are eliminated by Puget Energy upon consolidation of
      PSE’s financial statements.





**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 September 30, 2006, there was
      $0.5
      million outstanding under a letter of credit and $103.2 million commercial
      paper
      outstanding, effectively reducing the available borrowing capacity under the
      credit facility to $396.3 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 nine months ended September 30,
      2006, PSE Funding borrowed a cumulative amount of $288 million secured by
      accounts receivable. There were no loans secured by accounts receivable pledged
      as collateral at September 30, 2006. The borrowing base of eligible receivables
      at September 30, 2006 was $171.7 million.





**Stock
      Purchase and Dividend Reinvestment Plan**


Puget
      Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which
      shareholders and other interested investors may invest cash and cash dividends
      in shares of Puget Energy common stock. Since new shares of common stock may
      be
      purchased directly from Puget Energy, funds received may be used for general
      corporate purposes. Puget Energy issued common stock under the Stock Purchase
      and Dividend Reinvestment Plan of $3.3 million (150,295 shares) and $10.2
      million (481,930 shares) for the three and nine months ended September 30,
      2006,
      respectively, compared to $3.6 million (159,985shares) and $10.9 million
      (480,005 shares) for the three and nine months ended September 30, 2005,
      respectively.





**Common
      Stock Offering Programs**


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








**Other**





**FERC
      Hydroelectric Projects And Licenses**


**Baker
      River project.** The
      Baker
      River project consists of the Lower Baker Development (constructed in 1925)
      and
      the Upper Baker Development (constructed in 1959). The Baker River project’s
      current license expires on April 30, 2007, and PSE submitted an application
      for
      a new license to FERC on April 30, 2004. On November 30, 2004, PSE and 23
      parties comprised of federal, state and local governmental organizations, Native
      American Indian tribes, environmental and other non-governmental entities filed
      a proposed comprehensive settlement agreement on all issues relating to the
      relicensing of the Baker River project. The proposed settlement includes a
      set
      of proposed license articles and, if approved by FERC without material
      modification, would allow for a new license of 45 years or more. The proposed
      settlement would require an investment of approximately $360 million over the
      next 30 years (capital expenditures and operations and maintenance cost) in
      order to implement the conditions of the new license. The proposed settlement
      is
      subject to contingencies that have yet to be resolved and is subject to
      additional regulatory approvals yet to be attained from various agencies. On
      April 7, 2006, FERC issued a Draft Environmental Impact Statement discussing
      the
      proposed settlement. A Final Environmental Impact Statement was issued on
      September 8, 2006. However, FERC has not yet ruled on the proposed settlement
      and its ultimate outcome remains uncertain.





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


In
      the
      PCORC Order issued on April 7, 2004, the Washington Commission approved PSE’s
      recovery on the unamortized White River plant investment. At September 30,
      2006,
      the White River project net book value totaled $68.5 million, which included
      $43.8 million of net utility plant, $16.9 million of capitalized FERC licensing
      costs, $5.3 million of costs related to construction work in progress and $1.7
      million related to dam operations and safety On February 18, 2005, the
      Washington Commission approved the recovery of the White River net utility
      plant
      costs but did not allow current recovery of FERC licensing costs and other
      related costs until all costs associated with selling the White River plant
      and
      any sales proceeds are known.


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


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


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


In
      June
      2003, Ecology approved an application for new municipal water rights related
      to
      the White River project reservoir. This approval was sought in connection with
      PSE’s ongoing efforts to sell the White River project to be used for commercial
      purposes. An appeal of Ecology’s decision approving the new municipal water
      rights was subsequently filed with the Washington State Pollution Control
      Hearings Board. In July 2004, this decision was remanded back to Ecology for
      further analysis of non-hydropower operations. Ecology issued a revised decision
      on September 25, 2006 in draft form for public comment. Any proceeds from the
      sale of the White River water rights will reduce the balance of the deferred
      regulatory asset. Neither the outcome of this matter nor any potential
      associated costs can be predicted at this time.





**Snoqualmie
      Falls project.** The
      Snoqualmie Falls project, built in 1898, had its original license issued May
      13,
      1975, which was made effective retroactive to March 1, 1956, and expired on
      December 31, 1993. PSE filed its application to relicense the project on
      November 25, 1991, and operated the project pursuant to annual licenses issued
      by FERC after the original license expired. On June 29, 2004, FERC granted
      PSE a
      new 40-year operating license for the Snoqualmie Falls project. PSE estimates
      that the investment required to implement the conditions of the new license
      agreement will cost approximately $44.0 million. These conditions include
      modified operating procedures and various project upgrades that include better
      protection of fish, development of riparian habitat to promote fish propagation,
      increased minimum flows in the Snoqualmie River during low-water periods and
      the
      development of recreational amenities near the down-river power house. On July
      29, 2004, the Snoqualmie Tribe and certain other parties filed a request for
      rehearing of the new license and a request to stay the FERC license. On March
      1,
      2005, FERC issued an Order on Rehearing and Dismissing Stay Request. The order
      requires additional flows at Snoqualmie Falls during certain times of the year.
      PSE requested rehearing of the order on the grounds that the order interferes
      with the Washington State Department of Ecology’s authority to regulate water
      quality and that FERC arbitrarily and capriciously rebalanced the public
      interest without support of substantive evidence in the record. The Snoqualmie
      Tribe appealed FERC’s operating license decision to the United States Court of
      Appeals for the Ninth Circuit and PSE intervened in that proceeding. PSE’s
      request for rehearing was denied on June 1, 2005 and on July 8, 2005, PSE asked
      for further review by the Ninth Circuit. The two petitions have been
      consolidated and briefing is anticipated to be completed by the fourth quarter
      2006.


**Electric
      Regulation and Rates**


**Power
      Cost Only Rate Case and Electric General Rate Case.** On June
      28, 2006, the Washington Commission approved a 5.9%, or $45.3 million, Power
      Cost Only Rate Case (PCORC) increase in electric rates for the period July
      1,
      2006 through December 31, 2006. The increase allows PSE to recover higher
      projected costs of power caused primarily by higher market prices for natural
      gas used as fuel for electric generators. The rate increase will not
      appreciatively impact PSE’s income. The annualized basis of the PCORC rate
      increase when applied to the general rate case test year is $96.1 million.
      Primarily as a result of this order, on July 10, 2006, PSE reduced its pending
      electric general tariff increase from $140.9 million to $42.9 million, or 2.5%,
      on an annualized basis. On September 15, 2006, the Company adjusted the
      requested increase to $33.5 million annually. Additionally, PSE has requested
      approval of a new tariff in its original general rate case filing to recover
      increases in electric transmission and distribution depreciation costs incurred
      between general rate cases of $7.9 million. The resolution of the general rate
      case is expected by the end of 2006.





**Residential
      Exchange Credit** .
      On
      September 27, 2006, the Washington Commission approved a revision of PSE's
      electric rate tariff Schedule 94 "Residential and Farm Exchange Benefit" that
      became effective October 1, 2006. The Schedule 94 credit rate was reduced from
      $0.01740 to $0.01028 per kWh, reflecting a reduction in the annual estimated
      value of the BPA Residential Exchange benefits from $174.4 million to $105.0
      million, beginning October 1, 2006. This tariff revision will have the impact
      of
      increasing PSE electric customer revenues, but will not impact PSE net income.
      Under federal law, BPA is required to provide benefits from the low-cost federal
      power system to residential and small farm customer served by investor-owned
      utilities in the northwest. All benefits received by an investor-owned utility
      must be passed on to its residential and small farm customers.





**Production
      Tax Credit** .
      On
      October 30, 2006, PSE revised its PTC electric tariff to increase the credit
      to
      customers from $13.1 million to $28.8 million, effective January 1, 2007. The
      credit is based on expected wind generation and reflects the true-up of prior
      years’ credits provided to customers versus credits for actual wind generation
      taken for federal income taxes.





**PCA
      Mechanism.** On June
      20, 2002, the Washington Commission approved a PCA mechanism that triggers
      if
      PSE’s costs to provide customers’ electricity falls outside certain bands from a
      normalized level of power costs established in an electric rate case. During
      the
      four-year period ended June 30, 2006, PSE’s cumulative maximum pre-tax earnings
      exposure due to power cost variations was limited to $40 million plus 1% of
      the
      excess. All significant variable power supply cost drivers are included in
      the
      PCA mechanism (hydroelectric generation variability, market price variability
      for purchased power and surplus power sales, natural gas and coal fuel price
      variability, generation unit forced outage risk and transmission cost
      variability).


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




Prior
                to July 2006
              Annual
                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.*




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





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





**Gas
      Regulation and Rates**


**Gas
      General Rate Case.** On July
      10, 2006, PSE reduced its gas general rate increase request filed with the
      Washington Commission on February 15, 2006 from $40.4 million to $39.2 million,
      or 4.2%, on an annual basis. On September 15, 2006, the Company adjusted the
      requested general rate increase to $38.9 million annually. PSE also has
      requested approval of a new depreciation tracker in its original gas general
      rate case filing to recover increases in gas distribution depreciation costs
      incurred between general rate cases of $10.9 million. In addition, a gas
      decoupling mechanism, which does not have an impact on the current rate
      increase, was requested; however, it is designed to stabilize revenue changes
      due to load variations between regulatory filings. The resolution of the general
      rate case is expected by the end of 2006.





**Purchased
      Gas Adjustment.** On
      September 27, 2006, the Washington Commission approved a revision of PSE's
      Purchased Gas Adjustment (PGA) tariff schedule that went into effect on October
      1, 2006. The tariff changes will increase gas revenue approximately $95.1
      million, or 9.9%, on an annual basis. The rate increase authorized PSE to
      recover higher projected future gas and gas transportation costs, as well as
      to
      collect an accumulated deficit (receivable) balance in its PGA balancing account
      over a 24-month period (beginning October 1, 2006). The PGA rate change will
      increase PSE's gas revenue, but will not impact the Company's net income as
      the
      increased revenue will be offset by increased purchased gas costs. The PGA
      Mechanism passes through to customers increases or decreases in gas supply
      portion of the natural gas service rates based upon changes in gas
      prices.





**Other**


**Whitehorn
      Power Generating Facility Lease** .
      PSE
      leases the Whitehorn power generating facility, a 147 MW net capacity dual-fuel
      combustion turbine, under a noncancelable operating lease expiring in February
      2009. PSE entered into an agreement on October 17, 2006 with the lessor under
      which PSE agreed to purchase the generation facilities after the lease term
      expires in February 2009, provided that all conditions precedent are satisfied
      or waived. In the fourth quarter 2006, the lease will be treated as a capital
      lease over its remaining lease period.





**Union
      Contract.** The
      contract with the United Association of Plumbers and Pipefitters (UA) which
      governs the Company’s relationship with certain of its employees expired as of
      October 1, 2006. However, PSE and the UA have been operating under the terms
      of
      collective bargaining terms of the contract since the expiration as agreed
      to by
      both parties. The employees represented by UA rejected a proposal for a
      four-year contract offer in early October 2006. PSE and the UA are continuing
      to
      negotiate a new contract. PSE anticipates reaching a conclusion on the contract
      in the fourth quarter 2006.





**Proceedings
      Relating to the Western Power Market**


Puget
      Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31,
      2005 and Quarterly Report on Form 10-Q for the quarter ended June 30, 2006
      include a summary and subsequent developments relating to the western power
      market proceedings described below. The following discussion provides a summary
      of material developments in these proceedings that occurred during and
      subsequent to the period covered by this report. PSE intends to vigorously
      defend against each of these cases and does not expect the ultimate resolution
      of these proceedings in the aggregate to have a material adverse impact on
      the
      financial condition, results of operations or liquidity of the Company. However,
      there can be no assurances in that regard because litigation is subject to
      numerous uncertainties and PSE is unable to predict the ultimate outcome of
      these matters. Accordingly, there can be no guarantee that these proceedings,
      either individually or in the aggregate, will not materially and adversely
      affect PSE’s financial condition, results of operations or
      liquidity.





**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 Power Exchange
      Corporation (California PX) for energy purchases. The CAISO in turn failed
      to
      pay various energy suppliers, including PSE, for energy sales made 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.





**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 has finished publishing settlement statements reflecting the refund rerun,
      and has begun the financial adjustment phase, in which the CAISO is making
      adjustments to its refund rerun settlement data to account for fuel cost
      allowance offsets, emissions offsets, cost-based recovery offsets and interest
      on amounts unpaid and refunds. 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. *Also
      see discussion below under CAISO Receivable.*


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
      were consolidated. The Ninth Circuit ordered on October 22, 2004 that briefing
      proceed in two rounds. The first round was limited to three issues: (1) which
      parties are subject to FERC’s refund jurisdiction in light of the exemption for
      government-owned utilities in section 201(f) of the FPA; (2) the temporal scope
      of refunds under section 206 of the FPA; and (3) which categories of
      transactions are subject to refunds.


On
      September 6, 2005, the court ruled that, as to the first issue, FERC does not
      have refund authority over wholesale electric sales made by governmental
      utilities. On August 2, 2006, the court decided the remaining issues of the
      first round, ruling that FERC erred in excluding potential relief for tariff
      violations for periods that pre-dated October 2, 2000, and ruling that FERC
      should consider remedies for certain CAISO and California PX transactions
      outside the 24-hour period previously used to define the scope of the
      proceedings.


The
      August 2, 2006 decision may adversely impact PSE’s ability to recover the full
      amount of its CAISO Receivable described below, and the decision may expose
      PSE
      to claims or liabilities for transactions outside the previously defined “refund
      period,” but at this time the ultimate financial outcome for PSE is unclear. It
      is likely that some parties will seek rehearing of the court’s decision and/or
      that settlement talks will ensue. If rehearing is denied, the matters would
      be
      remanded to FERC for further proceedings. PSE is studying the court’s decision,
      but is unable to predict either the outcome of the proceedings or the ultimate
      financial effect on PSE at this time. The Ninth Circuit and FERC are trying
      to
      facilitate settlement discussions among the parties but it is unclear whether
      any such discussions will result in settlement.





**CAISO
      Receivable** .
      At
      September 30, 2006, PSE had a net receivable totaling $21.2 million in
      connection with wholesale sales in 2000 to the CAISO and counterparties where
      payment to PSE was conditioned on the counterparties being paid by the
      California PX. In August 2005, PSE submitted its audited Fuel Cost Allowance
      Claim with the CAISO. That claim was challenged by the California Parties.
      PSE
      filed a portfolio cost claim, and 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 stated claim. PSE filed a revised
      Portfolio Claim in the amount of $2.3 million on March 3, 2006. PSE does not
      agree with all of FERC’s rulings and sought rehearing, which is still pending at
      FERC. PSE’s ability to recover all or a portion of these claims is uncertain at
      the present time.


PSE
      has
      estimated a range related to its CAISO receivable to be between $21.2 million
      (PSE’s net receivable balance) and $29.5 million, including interest, on its
      past due receivables as of September 30, 2006. As a result of the Ninth Circuit
      decision of August 2, 2006 discussed above, PSE cannot assess the ultimate
      resolution of its California Receivable. At this time there is no reasonable
      basis to adjust PSE’s net receivable balance of $21.2 million because the
      procedural outcome of a rehearing or remand to FERC is uncertain and any
      financial impact cannot be quantified.




**Colstrip
      Matters**


In
      May
      2003, approximately 50 plaintiffs brought an action against the owners of
      Colstrip. The lawsuit alleged certain domestic water wells may have been
      contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond.
      PSE recorded a $0.7 million reserve in the third quarter 2004 for its 50%
      ownership of the Colstrip Units 1 & 2 project, based upon a tentative
      settlement agreement in the third quarter 2004. However, the settlement
      agreement would not resolve certain other claims by residents within the city
      limits. Before finalizing the settlement, plaintiffs retained new counsel and
      the litigation continues and is in the discovery phase. Colstrip has extended
      city water to certain residents who live near the plant in December 2005. PSE
      reflected the costs to extend the water supply of $0.4 million against the
      reserve, reducing it to $0.3 million at December 31, 2005. Colstrip continues
      to
      address groundwater contamination from wastewater ponds by conducting certain
      groundwater investigation and remediation measures for certain residents who
      live near the plant.


On
      April
      29, 2004, the Minerals Management Service of the United States Department of
      the
      Interior (MMS) issued an order to Western Energy Company (WECO) to pay
      additional royalties concerning coal purchased by PSE for Colstrip Units 3
&
4. The order seeks payment of an additional $1.1 million in royalties for coal
      mined from federal land between 1997 and June 30, 2000. During that period,
      PSE’s coal price was reduced by a settlement agreement entered into in February
      1997 among PSE, WECO and Montana Power Company that resolved disputes that
      were
      then pending. The order seeks to impute the price charged to PSE based on the
      other Colstrip Units 3 & 4 owners’ contractual amounts. PSE is supporting
      WECO’s appeal of the order, but is also evaluating the basis of the claim. In
      addition, the State of Montana issued a demand to WECO based upon an audit
      in
      May 2005 for allegedly unpaid royalties, asserting this same theory. The amount
      claimed in that demand is $0.2 million. PSE accrued a loss reserve in the amount
      of $1.1 million in connection with this matter in the second quarter 2004,
      and
      updated that amount to $1.8 million in the third quarter 2006.


In
      addition, the MMS issued two orders to WECO in 2002 and 2003 to pay additional
      royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders
      assert that additional royalties are owed as a result of WECO not paying
      royalties in connection with revenue received by WECO from the Colstrip Units
      3
& 4 owners under a coal transportation agreement during the period October
      1, 1991 through December 31, 2001. On April 28, 2005, the appeals division
      of
      the MMS issued an order that reduced the amount claimed due to the application
      of statute of limitations. PSE’s share of the alleged additional royalties is
      approximately $1.7 million, which is equivalent to PSE’s 25% ownership interest
      in Colstrip Units 3 & 4. The state of Montana issued a demand to WECO in May
      2005 consistent with the MMS position outlined above on these transportation
      revenues. The state’s position, if correct, would result in an additional $0.1
      million claim against PSE. The transportation agreement provides for the
      construction and operation of a conveyor system that runs several miles from
      the
      mine to Colstrip Units 3 & 4. WECO has appealed these orders and PSE is
      monitoring the process. PSE believes that the Colstrip Units 3 & 4 owners
      have reasonable defenses in this matter based upon its review. However, if
      the
      MMS position prevails, this issue could create ongoing expenses as the conveyor
      system continues to be used. Further, on September 28, 2006, the MMS issued
      an
      order to pay additional royalties in the amount of $1.5 million on the basis
      of
      an audit of WECO’s royalty payments during the three years 2002 to 2004 and that
      applies the same theory to the transportation revenues. PSE’s share of that
      claim is approximately $0.4 million based upon PSE’s ownership of the projects.
      If litigated, this claim would follow the same process as the two already
      pending, involving a multiple-layer appellate process before a final decision.
      It is likely that any result would be substantially identical to the resolution
      on the two periods already pending.


The
      US
      Environmental Protection Agency requires states to produce regulations by
      November 15, 2006 that will bring their mercury emissions in line with those
      mandated by the Clean Air Mercury Rule (CAMR). The Montana Board of
      Environmental Review approved the state’s regulation to limit mercury emissions
      from coal-fired plants on October 16, 2006. The new rule takes a two-tiered
      approach to reducing mercury emissions, allowing power plants burning
      lower-quality lignite coal to release more emissions than plants burning cleaner
      sub-bituminous coal, such as Colstrip. The new rule has a more stringent limit
      than the federal rule (0.9 lbs/TBtu, instead of the federal 1.4 lbs/TBtu),
      but
      includes a cap-and-trade provision as well as alternative emission limits for
      plants that have tried to meet the new standards but have demonstrated that
      they
      cannot. The Colstrip owners are still evaluating the potential impact of the
      new
      rule and it is still unknown whether the new rule will be appealed.




**Critical
      Accounting Policies And Estimates**


Effective
      January 1, 2006, the Company adopted the fair value recognition provisions
      of
      SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition
      method. Results for prior periods have not been restated, as provided for under
      the modified-prospective method. Prior to 2006, stock-based compensation plans
      were accounted for according to Accounting Principles Board (APB) No. 25,
“Accounting for Stock Issued to Employees,” and related interpretations as
      allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the
      Company adopted the fair value based accounting of SFAS No. 123 using the
      prospective method under the guidance of SFAS No. 148, “Accounting for
      Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock
      compensation awards granted subsequent to January 1, 2003, while grants prior
      to
      2003 continued to be accounted for using the intrinsic value method of APB
      No.
      25.


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


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


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


On
      September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS
      No. 157 standardizes the measurement of fair value when it is required under
      generally accepted accounting principles (GAAP). SFAS No. 157 is effective
      for
      fiscal years beginning after November 15, 2007, which will be the year beginning
      January 1, 2008, for the Company. The adoption of SFAS No. 157 is not expected
      to have a material impact on the Company’s financial statements.


On
      September 29, 2006, FASB issued SFAS No. 158, “Employers’ Accounting for Defined
      Benefit Pension and Other Postretirement Plans.” SFAS No. 158 is effective for
      fiscal years ending after December 15, 2006, which will be the year ended
      December 31, 2006, for the Company. SFAS No. 158 will be adopted prospectively,
      as required by the statement. SFAS No. 158 requires the Company to report the
      overfunded or underfunded status of defined benefit postretirement plans in
      the
      Company’s consolidated balance sheet. An overfunded status would result in the
      recognition of an asset and an underfunded status would result in the
      recognition of a liability. This amount is to be measured as the difference
      between the fair value of plan assets and the projected benefit obligation.
      At
      December 31, 2005, the combined fair value of plan assets and projected benefit
      obligation for the Company’s defined benefit pension and the retiree medical and
      life plans were $481.0 million and $439.0 million, respectively. At September
      30, 2006, the Company estimates that upon adoption of the standard, it will
      record a pre-tax charge to Accumulated Other Comprehensive Income of
      approximately $64.0 million, a reduction of approximately $54.0 million to
      the
      pension plan prepaid asset and an increase of approximately $10.0 million to
      benefit plan liabilities. Actual return on plan assets for the fourth quarter
      2006 could influence these estimates.








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





**Energy
      Portfolio Management**


The
      regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity
      price volatility on the Company. The PGA mechanism passes through increases
      and
      decreases in the cost of natural gas supply to customers. The PCA mechanism
      provided for a sharing of costs and benefits that are graduated over four levels
      of power cost variances with an overall cap of $40 million (+/-) plus 1% of
      the
      excess over the $40 million cap over the four-year period ending June 30, 2006.
      For the period July 1, 2006 through December 31, 2006, the sharing bands will
      be
      half of the annual bands without a cap for excess power costs. The Company
      has
      proposed in its general rate case proceeding a PCA mechanism that 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 beginning January
      1,
      2007.


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


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


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


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


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


The
      Company is not engaged in the business of assuming risk for the purpose of
      speculative trading revenues. Wholesale market transactions are focused on
      balancing the Company’s energy portfolio, reducing costs and risks where
      feasible, and reducing volatility in wholesale costs and margin in the
      portfolio. In order to manage risks effectively, the Company enters into
      physical and financial transactions which are appropriate for the service
      territory of the Company and are relevant to its regulated electric and gas
      portfolios.


The
      risk
      metrics the Company employs are aimed at assessing exposure for the purpose
      of
      developing strategies to reduce the potential exposure on a cost-effective
      basis
      in regulated utility gas and electric portfolios. Specifically, the amount
      of
      risk exposure is defined by time period and by portfolio, and is determined
      through statistical methods aimed at forecasting risk.


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


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


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


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


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


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


At
      September 30, 2006, the Company had a net asset of approximately $8.4 million
      of
      energy contracts designated as qualifying cash flow hedges and a corresponding
      unrealized gain of $5.5 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. At September 30,
      2006, the Company also had a net liability of approximately $0.2 million related
      to non-cash flow hedges. Amounts settling after September 30, 2006 have not
      been
      deferred as the $40 million cap under the PCA mechanism expired June 30, 2006
      and the sharing band under the PCA mechanism reset. The Company also had energy
      contracts that were marked-to-market at a gain of $0.6 million and a loss of
      $0.2 million through current earnings for the three and nine months ended
      September 30, 2006, respectively. These mark-to-market adjustments were the
      result of excluding certain contracts from the normal purchase normal sale
      exception under SFAS No. 133 and de-designated cash flow hedges where the
      hedging relationship was ended. At September 30, 2006, the Company also has a
      net liability of approximately $65.9 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 $4.6 million after-tax and a decrease of $0.4 million on current
      earnings. 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 September 30, 2006, approximately 98% 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, 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
      third quarter 2006, the Company entered into and settled two forward starting
      interest rate swap contracts. The purpose of the forward starting swap contracts
      was to hedge interest rate volatility for a debt offering of $300 million that
      was priced on September 13, 2006. Since interest rates decreased related to
      the
      hedged rate, the debt was priced at a rate lower than the hedged rate and PSE
      paid $0.6 million to the counterparties when the contracts were settled. The
      forward starting swap contracts were designated and documented under SFAS No.
      133 criteria as cash flow hedges, with all changes in market value being
      presented net of tax in other comprehensive income. In accordance with SFAS
      No.
      133, the loss will be amortized out of other comprehensive income to current
      earnings as an increase to interest expense over the life of the new debt
      issued. The ending balance in other comprehensive income related to the forward
      starting swaps and previously settled treasury lock contracts at September
      30,
      2006 was a net loss of $8.6 million after-tax and accumulated amortization.
      All
      financial hedge contracts of this type are reviewed by senior management and
      presented to the Securities Pricing Committee of the Board of Directors and
      are
      approved prior to execution.








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





**Puget**  **Energy**


**Evaluation
      of Disclosure Controls and Procedures**


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





**Changes
      in Internal Control Over Financial Reporting**


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





**Puget
      Sound Energy**


**Evaluation
      of Disclosure Controls and Procedures**


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





**Changes
      in Internal Control Over Financial Reporting**


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








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








Item
      1.  **Legal
      Proceedings**





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


Contingencies
      arising out of the normal course of the Company’s business exist at September
      30, 2006. The ultimate resolution of these issues in part or in the aggregate
      is
      not expected to have a material adverse impact on the financial condition,
      results of operations or liquidity of the Company.





Item
      1A.  **Risk
      Factors**





There
      have been no material changes from the risk factors set forth in Part I, Item
      1A
      in the Company’s Annual Report on Form 10-K for the year ended December 31,
      2005, as updated by the information discussed under Item 1A of the Company’s
      Quarterly Report on Form 10-Q for the quarter ended June 30, 2006.








Item
      6.  **Exhibits**




See
      Exhibit Index for list of exhibits.








**SIGNATURES**





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







**PUGET
                ENERGY, INC.****PUGET
                SOUND ENERGY, INC.****/s/
                James W. Eldredge****James
                W. Eldredge**Vice
                President, Corporate Secretary and Chief Accounting
                OfficerDate:
                November 2, 2006Chief
                accounting officer and officer duly authorized to sign this report
                on
                behalf of each registrant





**EXHIBIT
      INDEX**





The
      following exhibits are filed herewith:





12.1
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2001
                through 2005 and 12 months ended September 30, 2006) for Puget
                Energy.12.2
            Statement
                setting forth computation of ratios of earnings to fixed charges
                (2001
                through 2005 and 12 months ended September 30, 2006) for
                PSE.31.1
            Chief
                Executive Officer certification of Puget Energy pursuant to 18 U.S.C.
                Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley
                Act
                of 2002.31.2
            Chief
                Financial Officer certification of Puget Energy pursuant to 18 U.S.C.
                Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley
                Act
                of 2002.31.3
            Chief
                Executive Officer certification of Puget Sound Energy pursuant to
                18
                U.S.C. Section 1350, as adopted pursuant to Section 302 of the
                Sarbanes-Oxley Act of 2002.31.4
            Chief
                Financial Officer certification of Puget Sound Energy pursuant to
                18
                U.S.C. Section 1350, as adopted pursuant to Section 302 of the
                Sarbanes-Oxley Act of 2002.32.1
            Chief
                Executive Officer certification pursuant to 18 U.S.C. Section 1350,
                as
                adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
                2002.32.2
            Chief
                Financial Officer certification pursuant to 18 U.S.C. Section 1350,
                as
                adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
                2002.