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,
      2008
              
              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 4th
      Street, Suite 1200
              Bellevue,
      Washington 98004-5591
              (425)
      454-6363
            91-1969407








1-4393
            PUGET
      SOUND ENERGY, INC.
              A
      Washington Corporation
              10885
      NE 4th
      Street, 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, a non-accelerated filer or a smaller reporting company.  See
definition of “large accelerated filer, accelerated filer and smaller reporting
company” in Rule 12b-2 of the Exchange Act.




Puget
      Energy, Inc.
            Large
      accelerated filer
            /X/
            Accelerated
      filer
            /  /
            Non-accelerated
      filer
            /  /
            Smaller
      reporting company
            /  /Puget
      Sound Energy, Inc.
            Large
      accelerated filer
            /  /
            Accelerated
      filer
            /  /
            Non-accelerated
      filer
            /X/
            Smaller
      reporting company
            /  /





Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act)


Puget
      Energy, Inc.
            Yes
            /  /
            No
            /X/
            
            Puget
      Sound Energy, Inc.
            Yes
            /  /
            No
            /X/





As of
October 31, 2008, (i) the number of shares of Puget Energy, Inc. common stock
outstanding was 129,678,489 ($.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


DefinitionsFiling FormatForward Looking StatementsPart I.
            Financial InformationItem 1.
            Financial StatementsPuget
      Energy, Inc.Consolidated Statements of Income – Three and Nine Months
      Ended September 30, 2008 and 2007Consolidated Statements of Comprehensive Income –
      Three and Nine Months Ended
              September 30, 2008 and 2007Consolidated Balance Sheets – September 30, 2008 and December
      31, 2007Consolidated Statements of Cash Flows – Nine Months Ended
      September 30, 2008 and 2007Puget
      Sound Energy, Inc.Consolidated Statements of Income – Three and Nine
      Months Ended September 30, 2008 and 2007Consolidated Statements of Comprehensive Income –
      Three and Nine Months Ended
              September 30, 2008 and 2007Consolidated Balance Sheets – September 30, 2008 and
      December 31, 2007Consolidated Statements of Cash Flows – Nine Months Ended
      September 30, 2008 and 2007NotesCombined
      Notes to Consolidated Financial StatementsItem 2.
            Management’s Discussion and
      Analysis of Financial Condition and Results of
      OperationsItem 3.
            Quantitative and Qualitative Disclosure About Market
      RiskItem 4.
            Controls and ProceduresPart II.
            Other InformationItem 1.
            Legal ProceedingsItem 1A.
            Risk FactorsItem 5.
            Other InformationItem 6.
            ExhibitsSignaturesExhibit Index







DEFINITIONS









AFUDC
            Allowance
      for Funds Used During ConstructionALJ
            Administrative
      Law JudgeASC
            Average
      System CostBPA
            Bonneville
      Power AdministrationConsortium
            Infrastructure
      investors led by Macquarie Infrastructure Partners, the Canada Pension
      Plan Investment Board and British Columbia Investment Management
      Corporation, and also includes Alberta Investment Management Corporation,
      Macquarie-FSS Infrastructure Trust and Macquarie Capital Group
      LimitedDOR
            Montana
      Department of RevenueEITF
            Emerging
      Issues Task ForceEPA
            U.
      S. Environmental Protection AgencyFASB
            Financial
      Accounting Standards BoardFERC
            Federal
      Energy Regulatory CommissionFIN
            Financial
      Accounting Standards Board InterpretationFSP
            FASB
      Staff PositionGAAP
            Generally
      Accepted Accounting PrinciplesGoldendale
            Goldendale
      Electric Generating FacilityInfrastruX
            InfrastruX
      Group, Inc.ISDA
            International
      Swaps and Derivatives AssociationkW
            KilowattkWh
            Kilowatt
      HourLehman
            Lehman
      Brothers Bank FSBLIBOR
            London
      Interbank Offered RateMMS
            Mineral
      Management Service of the United StatesMW
            Megawatt
      (one MW equals one thousand kW)MWh
            Megawatt
      Hour (one MWh equals one thousand kWh)NAESB
            North
      American Energy Standards BoardNERC
            North
      American Electric Reliability CorporationNinth
      Circuit
            United
      States Court of Appeals for the Ninth CircuitNPNS
            Normal
      Purchase Normal SalePCA
            Power
      Cost AdjustmentPCORC
            Power
      Cost Only Rate CasePF
            BPA
      Preference RatePGA
            Purchased
      Gas AdjustmentPSE
            Puget
      Sound Energy, Inc.PSE
      Funding
            PSE
      Funding, Inc.Puget
      Energy
            Puget
      Energy, Inc.PURPA
            Public
      Utility Regulatory Policy ActREP
            Residential
      Exchange ProgramRPSA
            Residential
      Purchase and Sale AgreementSFAS
            Statement
      of Financial Accounting StandardsTenaska
            Tenaska
      Power Fund, L.P.Washington
      Commission
            Washington
      Utilities and Transportation CommissionWECC
            Western
      Electricity Coordinating CouncilWECO
            Western
      Energy CoWSPP
            Western
      Systems Power Pool









FILING FORMAT


This
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 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 and 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.  However, 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 (natural gas and electric), licensing of hydroelectric
      operations and natural gas storage facilities, recovery of other capital
      investments, recovery of power and natural gas costs, recovery of
      regulatory assets and present or prospective wholesale and retail
      competition;·
            Failure
      to comply with FERC or Washington Commission standards and/or rules, which
      could result in penalties based on the discretion of either
      commission;·
            Failure
      to comply with electric reliability standards developed by the North
      American Electric Reliability Corporation (NERC) for users, owners and
      operators of the power system, which could result in penalties of up to
      $1.0 million per day per violation;·
            Changes
      in, adoption of, and compliance with, laws and regulations, including
      decisions and policies concerning the environment, climate change,
      emissions, natural resources, and fish and wildlife (including the
      Endangered Species Act);·
            The
      ability to recover costs arising from changes in enacted federal, state or
      local tax laws through revenue in a timely manner;·
            Changes
      in tax law, related regulations, or differing interpretation or
      enforcement of applicable law by the Internal Revenue Service or other
      taxing jurisdiction, which could have a material adverse impact on the
      financial statements;·
            Natural
      disasters, such as hurricanes, windstorms, earthquakes, floods, fires and
      landslides, which can interrupt service and/or cause temporary supply
      disruptions and/or price spikes in the cost of fuel and raw materials and
      impose extraordinary costs;·
            Commodity
      price risks associated with procuring natural gas and power in wholesale
      markets;·
            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 natural gas distribution system failure, which may impact
      PSE’s ability to deliver energy supply to its
customers;·
            Changes
      in weather conditions in the Pacific Northwest, which could have effects
      on customer usage and PSE’s revenues, thus impacting net
      income;·
            Weather,
      which can have a potentially serious impact on PSE’s ability to procure
      adequate supplies of natural 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 natural gas or electric plant to operate as
      intended;·
            The
      ability to renew contracts for electric and natural 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 and generating facilities;·
            The
      ability to restart generation following a regional transmission
      disruption;·
            Failure
      of the interstate natural gas pipeline delivering to PSE’s system, which
      may impact PSE’s ability to adequately deliver natural gas supply or
      electric power 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 or the condemnation of PSE’s facilities, which may result in
      changes in demand for PSE’s services;·
            The
      failure of information systems or the failure to secure information system
      data which may impact the operations and cost of PSE’s customer service,
      generation, distribution and transmission;·
            The
      impact of acts of God, terrorism, flu pandemic or similar significant
      events;·
            Capital
      market conditions, including changes in the availability of capital and
      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 insurance coverage and the cost of such
      insurance;·
            The
      ability to maintain effective internal controls over financial reporting
      and operational processes; and·
            With
      respect to the merger transaction Puget Energy announced on October 26,
      2007:§
            The
      risk that the merger may not be consummated in a timely manner, if at all,
      including due to the failure to receive any required regulatory
      approvals;§
            The
      risk that the merger agreement may be terminated in circumstances that
      require Puget Energy to pay a termination fee of up to $40.0 million, plus
      out-of-pocket expenses of the acquiring entity and its members of up to
      $10.0 million (or if no termination fee is payable, up to $15.0 million);
      and§
            The
      effect of the announcement of the merger on our business relationships,
      operating results and business generally, including our ability to retain
      key employees.




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





PART
I            FINANCIAL
INFORMATION





Item
1.              Financial
Statements


PUGET
ENERGY, INC.


CONSOLIDATED
STATEMENTS OF INCOME


(Dollars
in thousands except per share amounts)


(Unaudited)


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues:Electric
            
            $
            467,355
            
            
            $
            456,100
            
            
            $
            1,551,528
            
            
            $
            1,418,980Gas
            
            
            133,249
            
            
            
            142,120
            
            
            
            810,326
            
            
            
            834,304Other
            
            
            5,558
            
            
            
            3,460
            
            
            
            7,646
            
            
            
            13,439Total
      operating revenues
            
            
            606,162
            
            
            
            601,680
            
            
            
            2,369,500
            
            
            
            2,266,723Operating
      expenses:Energy
      costs:Purchased
      electricity
            
            
            173,667
            
            
            
            185,778
            
            
            
            645,385
            
            
            
            640,627Electric
      generation fuel
            
            
            64,899
            
            
            
            43,528
            
            
            
            144,599
            
            
            
            93,312Residential
      exchange
            
            
            (170
            )
            
            
            (384
            )
            
            
            (20,475
            )
            
            
            (52,424
            )Purchased
      gas
            
            
            70,125
            
            
            
            80,914
            
            
            
            484,038
            
            
            
            530,616Net
      unrealized loss on derivative instruments
            
            
            3,516
            
            
            
            5,276
            
            
            
            1,240
            
            
            
            1,031Utility
      operations and maintenance
            
            
            105,995
            
            
            
            94,433
            
            
            
            334,608
            
            
            
            291,539Non-utility
      expense and other
            
            
            5,002
            
            
            
            3,301
            
            
            
            7,063
            
            
            
            8,199Merger
      related costs
            
            
            1,271
            
            
            
            --
            
            
            
            8,320
            
            
            
            --Depreciation
      and amortization
            
            
            77,678
            
            
            
            68,909
            
            
            
            229,366
            
            
            
            204,351Conservation
      amortization
            
            
            13,832
            
            
            
            8,530
            
            
            
            42,723
            
            
            
            27,608Taxes
      other than income taxes
            
            
            56,873
            
            
            
            56,907
            
            
            
            214,820
            
            
            
            207,269Total
      operating expenses
            
            
            572,688
            
            
            
            547,192
            
            
            
            2,091,687
            
            
            
            1,952,128Operating
      income
            
            
            33,474
            
            
            
            54,488
            
            
            
            277,813
            
            
            
            314,595Other
      income (deductions):Other
      income
            
            
            6,865
            
            
            
            6,725
            
            
            
            21,782
            
            
            
            17,710Other
      expense
            
            
            (2,281
            )
            
            
            (686
            )
            
            
            (4,098
            )
            
            
            (4,546
            )Interest
      charges:AFUDC
            
            
            2,167
            
            
            
            3,554
            
            
            
            6,378
            
            
            
            8,915Interest
      expense
            
            
            (50,730
            )
            
            
            (54,681
            )
            
            
            (150,322
            )
            
            
            (158,133
            )Income
      (loss) from continuing operations before income taxes
            
            
            (10,505
            )
            
            
            9,400
            
            
            
            151,553
            
            
            
            178,541Income
      tax (benefit) expense
            
            
            (2,280
            )
            
            
            (2,218
            )
            
            
            46,310
            
            
            
            49,262Income
      (loss) from continuing operations
            
            
            (8,225
            )
            
            
            11,618
            
            
            
            105,243
            
            
            
            129,279Loss
      from discontinued segment (net of tax)
            
            
            --
            
            
            
            (224
            )
            
            
            --
            
            
            
            (212
            )Net
      income (loss)
            
            $
            (8,225
            )
            
            $
            11,394
            
            
            $
            105,243
            
            
            $
            129,067Common
      shares outstanding weighted-average (in thousands)
            
            
            129,447
            
            
            
            116,821
            
            
            
            129,433
            
            
            
            116,650Diluted
      shares outstanding weighted-average (in thousands)
            
            
            130,045
            
            
            
            117,365
            
            
            
            129,924
            
            
            
            117,225Basic
      earnings (loss) per common share
            
            $
            (0.06
            )
            
            $
            0.10
            
            
            $
            0.81
            
            
            $
            1.11Basic
      earnings per common share from discontinued operations
            
            
            --
            
            
            
            --
            
            
            
            --
            
            
            
            --Basic
      earnings (loss) per common share
            
            $
            (0.06
            )
            
            $
            0.10
            
            
            $
            0.81
            
            
            $
            1.11Diluted
      earnings (loss) per common share
            
            $
            (0.06
            )
            
            $
            0.10
            
            
            $
            0.81
            
            
            $
            1.10Diluted
      earnings per common share from discontinued operations
            
            
            --
            
            
            
            --
            
            
            
            --
            
            
            
            --Diluted
      earnings (loss) per common share
            
            $
            (0.06
            )
            
            $
            0.10
            
            
            $
            0.81
            
            
            $
            1.10





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
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Net
      income (loss)
            
            $
            (8,225
            )
            
            $
            11,394
            
            
            $
            105,243
            
            
            $
            129,067Other
      comprehensive income:Unrealized
      gain (loss) from pension and postretirement plans, net of tax of $2,754,
      $943, $(1,459) and $2,228, respectively
            
            
            5,114
            
            
            
            1,752
            
            
            
            (2,709
            )
            
            
            4,138Net
      unrealized losses on energy derivative instruments during the period, net
      of tax of $(90,975), $(5,752), $(4,808) and $(11,303),
      respectively
            
            
            (168,954
            )
            
            
            (10,683
            )
            
            
            (8,930
            )
            
            
            (20,992
            )Reversal
      of net unrealized gains (losses) on energy derivative instruments settled
      during the period, net of tax of $(13,158), $2,488, $(14,003) and $3,556,
      respectively
            
            
            (24,436
            )
            
            
            4,620
            
            
            
            (26,005
            )
            
            
            6,604Amortization
      of financing cash flow hedge contracts to earnings, net of tax of $43,
      $43, $128 and $128, respectively
            
            
            79
            
            
            
            79
            
            
            
            238
            
            
            
            238Other
      comprehensive loss
            
            
            (188,197
            )
            
            
            (4,232
            )
            
            
            (37,406
            )
            
            
            (10,012
            )Comprehensive
      income (loss)
            
            $
            (196,422
            )
            
            $
            7,162
            
            
            $
            67,837
            
            
            $
            119,055





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







PUGET ENERGY, INC.


CONSOLIDATED
BALANCE SHEETS


(Dollars
in thousands)








ASSETS





September
      30,
              2008
              (Unaudited)
            
            
            December
      31,
              2007Utility
      plant: (at original cost, including construction work in progress
      of$309,247
      and $267,595, respectively)Electric
      plant
            
            $
            6,225,756
            
            
            $
            5,914,127Gas
      plant
            
            
            2,436,155
            
            
            
            2,313,477Common
      plant
            
            
            529,666
            
            
            
            506,211Less:  Accumulated
      depreciation and amortization
            
            
            (3,319,165
            )
            
            
            (3,091,176
            )Net
      utility plant
            
            
            5,872,412
            
            
            
            5,642,639Other
      property and investments:Investment
      in Bonneville Exchange Power contract
            
            
            30,858
            
            
            
            33,503Other
      property and investments
            
            
            109,179
            
            
            
            114,083Total
      other property and investments
            
            
            140,037
            
            
            
            147,586Current
      assets:Cash
            
            
            157,929
            
            
            
            40,797Restricted
      cash
            
            
            18,957
            
            
            
            4,793Accounts
      receivable, net of allowance for doubtful accounts
            
            
            38,585
            
            
            
            218,781Secured
      pledged accounts receivable
            
            
            171,000
            
            
            
            152,000Unbilled
      revenues
            
            
            109,466
            
            
            
            210,025Materials
      and supplies, at average cost
            
            
            60,035
            
            
            
            62,114Fuel
      and gas inventory, at average cost
            
            
            132,471
            
            
            
            99,772Unrealized
      gain on derivative instruments
            
            
            15,831
            
            
            
            17,130Prepaid
      income tax
            
            
            30,025
            
            
            
            44,303Prepaid
      expense and other
            
            
            30,435
            
            
            
            11,910Deferred
      income taxes
            
            
            3,049
            
            
            
            4,011Total
      current assets
            
            
            767,783
            
            
            
            865,636Other
      long-term and regulatory assets:Regulatory
      asset for deferred income taxes
            
            
            94,747
            
            
            
            104,928Regulatory
      asset for PURPA buyout costs
            
            
            117,906
            
            
            
            140,520Power
      cost adjustment mechanism
            
            
            2,018
            
            
            
            3,114Other
      regulatory assets
            
            
            617,175
            
            
            
            510,998Unrealized
      gain on derivative instruments
            
            
            6,391
            
            
            
            11,845Other
            
            
            156,348
            
            
            
            171,470Total
      other long-term and regulatory assets
            
            
            994,585
            
            
            
            942,875Total
      assets
            
            $
            7,774,817
            
            
            $
            7,598,736





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,
              2008
              (Unaudited)
            
            
            December
      31, 2007Capitalization:Common
      shareholders’ investment:Common
      stock $0.01 par value, 250,000,000 shares authorized, 129,678,489 and
      129,678,489 shares outstanding, respectively
            
            $
            1,297
            
            
            $
            1,297Additional
      paid-in capital
            
            
            2,274,542
            
            
            
            2,278,500Earnings
      reinvested in the business
            
            
            242,216
            
            
            
            240,079Accumulated
      other comprehensive income (loss), net of tax
            
            
            (43,748
            )
            
            
            2,078Total
      shareholders’ equity
            
            
            2,474,307
            
            
            
            2,521,954Redeemable
      securities and long-term debt:Preferred
      stock subject to mandatory redemption
            
            
            1,889
            
            
            
            1,889Junior
      subordinated notes
            
            
            250,000
            
            
            
            250,000Long-term
      debt
            
            
            2,278,860
            
            
            
            2,428,860Total
      redeemable securities and long-term debt
            
            
            2,530,749
            
            
            
            2,680,749Total
      capitalization
            
            
            5,005,056
            
            
            
            5,202,703Current
      liabilities:Accounts
      payable
            
            
            230,765
            
            
            
            310,398Short-term
      debt
            
            
            581,485
            
            
            
            260,486Current
      maturities of long-term debt
            
            
            150,000
            
            
            
            179,500Accrued
      expenses:Purchased
      gas liability
            
            
            16,191
            
            
            
            77,864Taxes
            
            
            58,816
            
            
            
            84,756Salaries
      and wages
            
            
            29,500
            
            
            
            28,516Interest
            
            
            57,966
            
            
            
            45,133Unrealized
      loss on derivative instruments
            
            
            146,675
            
            
            
            27,089Other
            
            
            67,444
            
            
            
            48,918Total
      current liabilities
            
            
            1,338,842
            
            
            
            1,062,660Long-term
      liabilities and regulatory liabilities:Deferred
      income taxes
            
            
            852,973
            
            
            
            818,161Unrealized
      loss on derivative instruments
            
            
            64,235
            
            
            
            --Regulatory
      liabilities
            
            
            211,872
            
            
            
            210,311Other
      deferred credits
            
            
            301,839
            
            
            
            304,901Total
      long-term liabilities and regulatory liabilities
            
            
            1,430,919
            
            
            
            1,333,373Total
      capitalization and liabilities
            
            $
            7,774,817
            
            
            $
            7,598,736





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
      30,2008
            
            
            2007Operating
      activities:Net
      income
            
            $
            105,243
            
            
            $
            129,067Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depreciation
      and amortization
            
            
            229,366
            
            
            
            204,351Conservation
      amortization
            
            
            42,723
            
            
            
            27,608Deferred
      income taxes and tax credits, net
            
            
            71,729
            
            
            
            38,567Power
      cost adjustment mechanism
            
            
            1,096
            
            
            
            11,198Goldendale
      deferred costs
            
            
            (883
            )
            
            
            (11,211
            )Amortization
      of gas pipeline capacity assignment
            
            
            (6,869
            )
            
            
            (8,169
            )Non
      cash return on regulatory assets
            
            
            (7,427
            )
            
            
            (7,676
            )Net
      unrealized loss on derivative instruments
            
            
            1,240
            
            
            
            1,031Change
      in residential exchange program
            
            
            32,303
            
            
            
            (27,205
            )Storm
      damage deferred costs
            
            
            (252
            )
            
            
            (16,460
            )Other
            
            
            18,695
            
            
            
            7,835Cash
      receipt from lease purchase option settlement
            
            
            --
            
            
            
            18,898Change
      in certain current assets and liabilities:Accounts
      receivable and unbilled revenue
            
            
            261,755
            
            
            
            215,363Materials
      and supplies
            
            
            2,078
            
            
            
            (17,698
            )Fuel
      and gas inventory
            
            
            (32,699
            )
            
            
            (1,045
            )Prepaid
      income taxes
            
            
            14,278
            
            
            
            13,122Prepayments
      and other
            
            
            (18,525
            )
            
            
            (51,816
            )Purchased
      gas receivable/payable
            
            
            (61,673
            )
            
            
            100,980Accounts
      payable
            
            
            (76,048
            )
            
            
            (134,002
            )Taxes
      payable
            
            
            (25,940
            )
            
            
            5,766Accrued
      expenses and other
            
            
            9,249
            
            
            
            (6,874
            )Net
      cash provided by operating activities
            
            
            559,439
            
            
            
            491,630Investing
      activities:Construction
      and capital expenditures - excluding equity AFUDC
            
            
            (424,280
            )
            
            
            (548,043
            )Energy
      efficiency expenditures
            
            
            (43,730
            )
            
            
            (30,054
            )Restricted
      cash
            
            
            (14,164
            )
            
            
            (139
            )Refundable
      cash received for customer construction projects
            
            
            8,806
            
            
            
            16,950Cash
      proceeds from property sales
            
            
            2,221
            
            
            
            5,747Other
            
            
            (13,783
            )
            
            
            (340
            )Net
      cash used by investing activities
            
            
            (484,930
            )
            
            
            (555,879
            )Financing
      activities:Change
      in short-term debt and leases, net
            
            
            320,999
            
            
            
            49,984Dividends
      paid
            
            
            (97,257
            )
            
            
            (79,135
            )Issuance
      of common stock
            
            
            --
            
            
            
            4,379Long
      term bond issued
            
            
            --
            
            
            
            250,000Redemption
      of trust preferred stock
            
            
            --
            
            
            
            (37,750
            )Redemption
      of bonds, notes and leases
            
            
            (179,500
            )
            
            
            (125,000
            )Issuance
      and redemption costs of bonds and other
            
            
            (1,619
            )
            
            
            3,423Net
      cash  provided by financing activities
            
            
            42,623
            
            
            
            65,901Net
      increase in cash
            
            
            117,132
            
            
            
            1,652Cash
      at beginning of year
            
            
            40,797
            
            
            
            28,117Cash
      at end of period
            
            $
            157,929
            
            
            $
            29,769Supplemental
      cash flow information:Cash
      payments for interest (net of capitalized interest)
            
            $
            132,290
            
            
            $
            128,755Cash
      payments (refunds) from income taxes
            
            
            (42,392
            )
            
            
            23,000





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







PUGET
SOUND ENERGY, INC.


CONSOLIDATED
STATEMENTS OF INCOME


(Dollars
in thousands)


(Unaudited)





Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues:Electric
            
            $
            467,355
            
            
            $
            456,100
            
            
            $
            1,551,528
            
            
            $
            1,418,980Gas
            
            
            133,249
            
            
            
            142,120
            
            
            
            810,326
            
            
            
            834,304Other
            
            
            5,558
            
            
            
            3,460
            
            
            
            7,646
            
            
            
            13,439Total
      operating revenues
            
            
            606,162
            
            
            
            601,680
            
            
            
            2,369,500
            
            
            
            2,266,723Operating
      expenses:Energy
      costs:Purchased
      electricity
            
            
            173,667
            
            
            
            185,778
            
            
            
            645,385
            
            
            
            640,627Electric
      generation fuel
            
            
            64,899
            
            
            
            43,528
            
            
            
            144,599
            
            
            
            93,312Residential
      exchange
            
            
            (170
            )
            
            
            (384
            )
            
            
            (20,475
            )
            
            
            (52,424
            )Purchased
      gas
            
            
            70,125
            
            
            
            80,914
            
            
            
            484,038
            
            
            
            530,616Net
      unrealized loss on derivative instruments
            
            
            3,516
            
            
            
            5,276
            
            
            
            1,240
            
            
            
            1,031Utility
      operations and maintenance
            
            
            105,995
            
            
            
            94,433
            
            
            
            334,608
            
            
            
            291,539Non-utility
      expense and other
            
            
            4,977
            
            
            
            2,178
            
            
            
            6,690
            
            
            
            6,755Depreciation
      and amortization
            
            
            77,678
            
            
            
            68,909
            
            
            
            229,366
            
            
            
            204,351Conservation
      amortization
            
            
            13,832
            
            
            
            8,530
            
            
            
            42,723
            
            
            
            27,608Taxes
      other than income taxes
            
            
            56,873
            
            
            
            56,907
            
            
            
            214,820
            
            
            
            207,269Total
      operating expenses
            
            
            571,392
            
            
            
            546,069
            
            
            
            2,082,994
            
            
            
            1,950,684Operating
      income
            
            
            34,770
            
            
            
            55,611
            
            
            
            286,506
            
            
            
            316,039Other
      income (deductions):Other
      income
            
            
            6,865
            
            
            
            6,725
            
            
            
            21,747
            
            
            
            17,710Other
      expense
            
            
            (2,281
            )
            
            
            (686
            )
            
            
            (4,098
            )
            
            
            (4,546
            )Interest
      charges:AFUDC
            
            
            2,167
            
            
            
            3,554
            
            
            
            6,378
            
            
            
            8,915Interest
      expense
            
            
            (50,730
            )
            
            
            (54,681
            )
            
            
            (150,322
            )
            
            
            (158,133
            )Interest
      expense on Puget Energy note
            
            
            (187
            )
            
            
            (352
            )
            
            
            (633
            )
            
            
            (1,027
            )Income
      (loss) before income taxes
            
            
            (9,396
            )
            
            
            10,171
            
            
            
            159,578
            
            
            
            178,958Income
      tax (benefit) expense
            
            
            (2,120
            )
            
            
            (1,875
            )
            
            
            46,840
            
            
            
            49,777Net
      income (loss)
            
            $
            (7,276
            )
            
            $
            12,046
            
            
            $
            112,738
            
            
            $
            129,181





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
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Net
      income (loss)
            
            $
            (7,276
            )
            
            $
            12,046
            
            
            $
            112,738
            
            
            $
            129,181Other
      comprehensive income:Unrealized
      gain (loss) from pension and postretirement plans, net of tax of $2,754,
      $943, $(1,459) and $2,228, respectively
            
            
            5,114
            
            
            
            1,752
            
            
            
            (2,709
            )
            
            
            4,138Net
      unrealized losses on energy derivative instruments during the period, net
      of tax of $(90,975), $(5,752), $(4,808) and $(11,303),
      respectively
            
            
            (168,954
            )
            
            
            (10,683
            )
            
            
            (8,930
            )
            
            
            (20,992
            )Reversal
      of net unrealized gains (losses) on energy derivative instruments settled
      during the period, net of tax of $(13,158), $2,488, $(14,003) and $3,556,
      respectively
            
            
            (24,436
            )
            
            
            4,620
            
            
            
            (26,005
            )
            
            
            6,604Amortization
      of financing cash flow hedge contracts to earnings, net of tax of $43,
      $43, $128 and $128, respectively
            
            
            79
            
            
            
            79
            
            
            
            238
            
            
            
            238Other
      comprehensive loss
            
            
            (188,197
            )
            
            
            (4,232
            )
            
            
            (37,406
            )
            
            
            (10,012
            )Comprehensive
      income (loss)
            
            $
            (195,473
            )
            
            $
            7,814
            
            
            $
            75,332
            
            
            $
            119,169





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





PUGET
SOUND ENERGY, INC.


CONSOLIDATED
BALANCE SHEETS


(Dollars
in thousands)





ASSETS





September
      30,
              2008
              (Unaudited)
            
            
            December
      31,
              2007Utility
      plant: (at original cost, including construction work in progress of
      $309,247 and $267,595, respectively)Electric
      plant
            
            $
            6,225,756
            
            
            $
            5,914,127Gas
      plant
            
            
            2,436,155
            
            
            
            2,313,477Common
      plant
            
            
            529,666
            
            
            
            506,211Less:  Accumulated
      depreciation and amortization
            
            
            (3,319,165
            )
            
            
            (3,091,176
            )Net
      utility plant
            
            
            5,872,412
            
            
            
            5,642,639Other
      property and investments:Investment
      in Bonneville Exchange Power contract
            
            
            30,858
            
            
            
            33,503Other
      property and investments
            
            
            109,179
            
            
            
            114,083Total
      other property and investments
            
            
            140,037
            
            
            
            147,586Current
      assets:Cash
            
            
            157,873
            
            
            
            40,773Restricted
      cash
            
            
            18,957
            
            
            
            798Accounts
      receivable, net of allowance for doubtful accounts
            
            
            42,416
            
            
            
            219,345Secured
      pledged accounts receivable
            
            
            171,000
            
            
            
            152,000Unbilled
      revenues
            
            
            109,466
            
            
            
            210,025Materials
      and supplies, at average cost
            
            
            60,035
            
            
            
            62,114Fuel
      and gas inventory, at average cost
            
            
            132,471
            
            
            
            99,772Unrealized
      gain on derivative instruments
            
            
            15,831
            
            
            
            17,130Prepaid
      income taxes
            
            
            26,994
            
            
            
            41,814Prepaid
      expenses and other
            
            
            29,890
            
            
            
            11,365Deferred
      income taxes
            
            
            3,049
            
            
            
            4,011Total
      current assets
            
            
            767,982
            
            
            
            859,147Other
      long-term and regulatory assets:Regulatory
      asset for deferred income taxes
            
            
            94,747
            
            
            
            104,928Regulatory
      asset for PURPA buyout costs
            
            
            117,906
            
            
            
            140,520Power
      cost adjustment mechanism
            
            
            2,018
            
            
            
            3,114Other
      regulatory assets
            
            
            617,175
            
            
            
            512,103Unrealized
      gain on derivative instruments
            
            
            6,391
            
            
            
            11,845Other
            
            
            156,293
            
            
            
            170,328Total
      other long-term and regulatory assets
            
            
            994,530
            
            
            
            942,838Total
      assets
            
            $
            7,774,961
            
            
            $
            7,592,210





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,
              2008
              (Unaudited)
            
            
            December
      31,
              2007Capitalization: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
            
            
            1,295,323
            
            
            
            1,297,076Earnings
      reinvested in the business
            
            
            339,368
            
            
            
            345,899Accumulated
      other comprehensive income (loss), net of tax
            
            
            (43,748
            )
            
            
            2,078Total
      shareholder’s equity
            
            
            2,449,981
            
            
            
            2,504,091Redeemable
      securities and long-term debt:Preferred
      stock subject to mandatory redemption
            
            
            1,889
            
            
            
            1,889Junior
      subordinated notes
            
            
            250,000
            
            
            
            250,000Long-term
      debt
            
            
            2,278,860
            
            
            
            2,428,860Total
      redeemable securities and long-term debt
            
            
            2,530,749
            
            
            
            2,680,749Total
      capitalization
            
            
            4,980,730
            
            
            
            5,184,840Current
      liabilities:Accounts
      payable
            
            
            229,771
            
            
            
            310,083Short-term
      debt
            
            
            581,485
            
            
            
            260,486Short-term
      note owed to Puget Energy
            
            
            24,728
            
            
            
            15,766Current
      maturities of long-term debt
            
            
            150,000
            
            
            
            179,500Accrued
      expenses:Purchased
      gas liability
            
            
            16,191
            
            
            
            77,864Taxes
            
            
            58,816
            
            
            
            84,756Salaries
      and wages
            
            
            29,500
            
            
            
            28,516Interest
            
            
            58,029
            
            
            
            45,209Unrealized
      loss on derivative instruments
            
            
            146,675
            
            
            
            27,089Other
            
            
            67,443
            
            
            
            48,918Total
      current liabilities
            
            
            1,362,638
            
            
            
            1,078,187Long-term
      liabilities and regulatory liabilities:Deferred
      income taxes
            
            
            853,647
            
            
            
            821,382Unrealized
      loss on derivative instruments
            
            
            64,235
            
            
            
            --Regulatory
      liabilities
            
            
            211,872
            
            
            
            210,372Other
      deferred credits
            
            
            301,839
            
            
            
            297,429Total
      long-term liabilities and regulatory liabilities
            
            
            1,431,593
            
            
            
            1,329,183Total
      capitalization and liabilities
            
            $
            7,774,961
            
            
            $
            7,592,210





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
      30,2008
            
            
            2007Operating
      activities:Net
      income
            
            $
            112,738
            
            
            $
            129,181Adjustments
      to reconcile net income to net cash provided by operating
         activities:Depreciation
      and amortization
            
            
            229,366
            
            
            
            204,351Conservation
      amortization
            
            
            42,723
            
            
            
            27,608Deferred
      income taxes and tax credits, net
            
            
            69,182
            
            
            
            38,216Power
      cost adjustment mechanism
            
            
            1,096
            
            
            
            11,198Goldendale
      deferred costs
            
            
            (883
            )
            
            
            (11,211
            )Amortization
      of gas pipeline capacity assignment
            
            
            (6,869
            )
            
            
            (8,169
            )Non
      cash return on regulatory assets
            
            
            (7,427
            )
            
            
            (7,676
            )Net
      unrealized loss on derivative instruments
            
            
            1,240
            
            
            
            1,031Change
      in residential exchange program
            
            
            32,303
            
            
            
            (27,205
            )Storm
      damage deferred costs
            
            
            (252
            )
            
            
            (16,460
            )Other
            
            
            28,325
            
            
            
            8,118Cash
      receipt from lease purchase option settlement
            
            
            --
            
            
            
            18,898Change
      in certain current assets and liabilities:Accounts
      receivable and unbilled revenue
            
            
            258,487
            
            
            
            215,142Materials
      and supplies
            
            
            2,078
            
            
            
            (17,698
            )Fuel
      and gas inventory
            
            
            (32,699
            )
            
            
            (1,045
            )Prepaid
      income taxes
            
            
            14,820
            
            
            
            13,122Prepayments
      and other
            
            
            (18,525
            )
            
            
            (50,774
            )Purchased
      gas receivable/payable
            
            
            (61,673
            )
            
            
            100,980Accounts
      payable
            
            
            (76,727
            )
            
            
            (134,503
            )Taxes
      payable
            
            
            (25,940
            )
            
            
            5,378Accrued
      expenses and other
            
            
            9,236
            
            
            
            (6,340
            )Net
      cash provided by operating activities
            
            
            570,599
            
            
            
            492,142Investing
      activities:Construction
      expenditures - excluding equity AFUDC
            
            
            (424,280
            )
            
            
            (548,043
            )Energy
      efficiency expenditures
            
            
            (43,730
            )
            
            
            (30,054
            )Restricted
      cash
            
            
            (18,159
            )
            
            
            (3
            )Refundable
      cash received for customer construction projects
            
            
            8,806
            
            
            
            16,950Cash
      proceeds from property sales
            
            
            2,221
            
            
            
            5,747Other
            
            
            (13,783
            )
            
            
            (340
            )Net
      cash used by investing activities
            
            
            (488,925
            )
            
            
            (555,743
            )Financing
      activities:Change
      in short-term debt, net
            
            
            320,999
            
            
            
            49,984Dividends
      paid
            
            
            (113,421
            )
            
            
            (79,136
            )Loan
      from/to Puget Energy
            
            
            8,962
            
            
            
            (21
            )Long
      term bond issued
            
            
            --
            
            
            
            250,000Redemption
      of trust preferred stock
            
            
            --
            
            
            
            (37,750
            )Redemption
      of bonds and notes
            
            
            (179,500
            )
            
            
            (125,000
            )Investment
      from Puget Energy
            
            
            --
            
            
            
            3,684Issuance
      and redemption cost of bonds and other
            
            
            (1,614
            )
            
            
            3,425Net
      cash provided by financing activities
            
            
            35,426
            
            
            
            65,186Net
      increase in cash from net income
            
            
            117,100
            
            
            
            1,585Cash
      at beginning of year
            
            
            40,773
            
            
            
            28,092Cash
      at end of period
            
            $
            157,873
            
            
            $
            29,677Supplemental
      cash flow information:Cash
      payments for interest (net of capitalized interest)
            
            $
            132,290
            
            
            $
            128,755Cash
      payments (refunds) from income taxes
            
            
            (39,730
            )
            
            
            23,000





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







COMBINED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)
              Summary
      of Consolidation Policy


Basis
of Presentation


Puget
Energy, Inc. (Puget Energy) is a holding company that owns Puget Sound Energy,
Inc. (PSE).  PSE is a public utility incorporated in the state of
Washington that furnishes electric and natural gas services in a territory
covering 6,000 square miles, primarily in the Puget Sound
region.


The 2008
and 2007 consolidated financial statements of Puget Energy reflect the accounts
of Puget Energy and its subsidiary, PSE.  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.


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 Report on Form 10-K for
the year ended December 31, 2007.


The
preparation of financial statements in conformity with generally accepted
accounting principles (GAAP) 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.


PSE
collected Washington State excise taxes (which are a component of general retail
rates) and municipal taxes of $42.4 million and $172.3 million for the three and
nine months ended September 30, 2008, respectively, and $40.5 million and $163.4
million for the three and nine months ended September 30, 2007,
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.




(2)
            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 129,447,000 and 129,433,000 for
the three and nine months ended September 30, 2008, respectively, and
116,821,000 and 116,650,000 for the three and nine months ended September 30,
2007, respectively.


Puget
Energy’s diluted earnings per common share have been computed based on
weighted-average common shares outstanding and issuable upon exercise of options
or expiration of vesting periods of 130,045,000 and 129,924,000 for the three
and nine months ended September 30, 2008, respectively, and 117,365,000 and
117,225,000 for the three and nine months ended September 30, 2007,
respectively.  These shares include the dilutive effect of securities
related to employee and director equity plans.




(3)
            Accounting
      for Derivative Instruments and Hedging
  Activities




Statement
of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (SFAS No. 133), as amended, 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 provided
they meet certain criteria.  Generally, NPNS applies if PSE deems the
counterparty creditworthy, if the counterparty owns or controls 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 as adjusted from
time to time.  Those contracts that do not meet the 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” (SFAS No. 71), 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 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
following table presents the fair value of electric derivatives that are
designated as cash flow hedges or contracts that do not meet the NPNS exception
at September 30, 2008 and December 31, 2007:





Electric
              Derivatives(Dollars
      in Millions)
            
            September
      30,
              2008
            
            
            December
      31,
              2007Short-term
      asset
            
            $
            2.9
            
            
            $
            11.1Long-term
      asset
            
            
            2.6
            
            
            
            6.6Total
      assets
            
            $
            5.5
            
            
            $
            17.7Short-term
      liability
            
            $
            34.6
            
            
            $
            9.8Long-term
      liability
            
            
            26.9
            
            
            
            --Total
      liabilities
            
            $
            61.5
            
            
            $
            9.8





If it is
determined that it is uneconomical to operate Company-controlled electric
generating facilities in the future period, the fuel supply cash flow hedge
relationship is terminated and the hedge is de-designated which results in the
unrealized gains and losses associated with the contracts being recorded in the
income statement.  As these contracts are settled, the costs are
recognized as energy costs and are included as part of the PCA
mechanism.


At
December 31, 2007, the Company had an unrealized day one loss deferral of $9.0
million related to a three-year locational power exchange contract which was
computed based on a company model and therefore, the day one loss was deferred
under Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities” (EITF No.
02-3).  The contract has economic benefit to the Company over its
terms.  The locational exchange will help ease electric transmission
congestion across the Cascade Mountains during the winter months as PSE will
take delivery of energy at a location that interconnects with PSE’s transmission
system in western Washington.  At the same time, PSE will make
available the quantities of power at the Mid-Columbia trading hub
location.  The day one loss deferral was transferred to retained
earnings on January 1, 2008 as required by SFAS No. 157, “Fair Value
Measurements” (SFAS No. 157) and any future day one loss on contracts will be
recorded in the income statement beginning January 1, 2008 in accordance with
the statement.


The
following tables present the impact of changes in the market value of derivative
instruments not meeting the NPNS or cash flow hedge criteria, and
ineffectiveness related to highly effective cash flow hedges, to the Company’s
earnings during the three and nine months ended September 30, 2008 and September
30, 2007:





(Dollars
      in Millions)
              Three
      Months Ended September 30,
            2008
            2007
            ChangeDecrease
      in earnings
            $
      (3.5)
            $
      (5.3)
            $1.8





(Dollars
      in Millions)
              Nine
      Months Ended September 30,
            2008
            2007
            ChangeDecrease
      in earnings
            $(1.2)
            $
      (1.0)
            $
      (0.2)





The
amount of net unrealized loss, net of tax, related to the Company’s cash flow
hedges under SFAS No. 133 consisted of the following at September 30, 2008 and
December 31, 2007:





(Dollars
      in Millions, net of tax)
            September
      30,
              2008
            December
      31,
              2007Other
      comprehensive income – unrealized loss
            $  (31.5)
            $  (3.4)








The
following table presents the fair value of derivative hedges of natural gas
contracts to serve natural gas customers at September 30, 2008 and December 31,
2007:




Gas
              Derivatives(Dollars
      in Millions)
            
            September
      30,
              2008
            
            
            December
      31,
              2007Short-term
      asset
            
            $
            12.9
            
            
            $
            6.0Long-term
      asset
            
            
            3.8
            
            
            
            5.3Total
      assets
            
            $
            16.7
            
            
            $
            11.3Short-term
      liability
            
            $
            112.1
            
            
            $
            17.3Long-term
      liability
            
            
            37.3
            
            
            
            --Total
      liabilities
            
            $
            149.4
            
            
            $
            17.3





At
September 30, 2008, the Company had total assets of $16.7 million and total
liabilities of $149.4 million related to hedges of natural 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.  All increases
and decreases in the cost of natural gas supply are passed on to customers with
the PGA mechanism.  As the gains and losses on the hedges are realized
in future periods, they will be recorded as natural gas costs under the PGA
mechanism.




(4)
            Fair
      Value Measurements




As
defined in SFAS No. 157, fair value is the price that would be received to sell
an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date (exit price).  However, as
permitted under SFAS No. 157, the Company utilizes a mid-market pricing
convention (the mid-point price between bid and ask prices) as a practical
expedient for valuing the majority of its assets and liabilities measured and
reported at fair value.  The Company utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique.  These inputs can be readily observable,
market corroborated or generally unobservable.  The Company primarily
applies the market approach for recurring fair value measurements and endeavors
to utilize the best available information.  Accordingly, the Company
utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs.


The
Company values derivative instruments based on daily quoted prices from an
independent external pricing service.  When external quoted market
prices are not available for derivative contracts, PSE uses a valuation model
that uses volatility assumptions relating to future energy prices based on
specific energy markets and utilizes externally available forward market price
curves.  All derivative instruments are sensitive to market price
fluctuations that can occur on a daily basis.  The Company is focused
on commodity price exposure and risks associated with volumetric variability in
the natural gas and electric portfolios.  It is not engaged in the
business of assuming risk for the purpose of speculative trading.  The
Company hedges open natural gas and electric positions to reduce both the
portfolio risk and the volatility risk in prices.  The exposure
position is determined by using a probabilistic risk system that models 100
scenarios of how the Company’s natural gas and power portfolios will perform
under various weather, hydro and unit performance conditions.  PSE has
not made any material changes during the reporting period to those techniques or
models.


The
Company is able to classify fair value balances based on the observability of
those inputs.  SFAS No. 157 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value.  The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (Level 1 measurement) and the lowest priority to
unobservable inputs (Level 3 measurement).  The three levels of the
fair value hierarchy defined by SFAS No. 157 are as follows:





Level 1 –
Quoted prices are available in active markets for identical assets or
liabilities as of the reporting date.  Active markets are those in
which transactions for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.  Level 1
primarily consists of financial instruments such as exchange-traded derivatives
and listed equities. Equity securities that are also classified as cash
equivalents are considered Level 1 if there are unadjusted quoted prices in
active markets for identical assets or liabilities.





Level 2 –
Pricing inputs are other than quoted prices in active markets included in Level
1, which are either directly or indirectly observable as of the reported
date.  Level 2 includes those financial instruments that are valued
using models or other valuation methodologies.  These models are
primarily industry-standard models that consider various assumptions, including
quoted forward prices for commodities, time value, volatility factors, and
current market and contractual prices for the underlying instruments, as well as
other relevant economic measures.  Substantially all of these
assumptions are observable in the marketplace throughout the full term of the
instrument, can be derived from observable data or are supported by observable
levels at which transactions are executed in the
marketplace.  Instruments in this category include non-exchange-traded
derivatives such as over the counter forwards and options.





Level 3 –
Pricing inputs include significant inputs that are generally less observable
from objective sources.  These inputs may be used with internally
developed methodologies that result in management’s best estimate of fair
value.  Level 3 instruments include those that may be more structured
or otherwise tailored to customers’ needs.  At each balance sheet
date, the Company performs an analysis of all instruments subject to SFAS No.
157 and includes in Level 3 all of those whose fair value is based on
significant unobservable inputs.





The
following table sets forth by level within the fair value hierarchy the
Company’s financial assets and liabilities that were accounted for at fair value
on a recurring basis as of September 30, 2008.  As required by SFAS
No. 157, financial assets and liabilities are classified in their entirety based
on the lowest level of input that is significant to the fair value
measurement.  The Company’s assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect
the valuation of fair value assets and liabilities and their placement within
the fair value hierarchy levels.  The determination of the fair values
incorporates various factors required under SFAS No. 157.  These
factors include not only the credit standing of the counterparties involved and
the impact of credit enhancements (such as cash deposits, letters of credit and
priority interests), but also the impact of the Company’s nonperformance risk on
its liabilities.




Recurring
      Fair Value Measures
            At
      Fair Value as of September 30, 2008(Dollars
      in Millions)
            Level
      1
            Level
      2
            Level
      3
            TotalAssets:Energy
      derivative instruments
            $         --
            $   21.2
            $    1.0
            $   22.2Credit
      reserves on energy derivative instruments
            --
            --
            --
            --Money
      market accounts
            119.7
            --
            1.4
            121.1Total
      assets
            $   119.7
            $   21.2
            $  2.4
            $
      143.3Liabilities:Energy
      derivative instruments
            $         --
            $
      175.2
            $  39.0
            $
      214.2Credit
      reserves on energy derivative instruments
            --
            (2.5)
            (0.8)
            (3.3)Total
      liabilities
            $         --
            $
      172.7
            $  38.2
            $
      210.9





The
following table sets forth a reconciliation of changes in the fair value of
derivatives classified as Level 3 in the fair value hierarchy:


(Dollars
      in Millions)
            
            Three
      Months Ended
              September
      30, 2008
            
            
            Nine
      Months Ended
              September
      30, 2008Balance
      at beginning of period  (net credit reserve on energy
      derivatives)
            
            $
            148.8
            
            
            $
            (6.1
            )Changes
      during period (reported gross credit reserve):Realized
      energy derivatives
            
            
            1.0
            
            
            
            (0.7
            )Unrealized
      energy derivatives-
      included in earnings
            
            
            1.5
            
            
            
            (1.5
            )-
      included in other comprehensive income
            
            
            (93.9
            )
            
            
            (21.6
            )-
      included in regulatory assets/liabilities
            
            
            (11.3
            )
            
            
            (10.8
            )Energy
      derivatives transferred in/out of Level 3
            
            
            (41.8
            )
            
            
            (1.8
            )Terminations
            
            
            (41.4
            )
            
            
            (1.5
            )Other
      financial items settled
            
            
            --
            
            
            
            7.2Money
      market accounts
            
            
            --
            
            
            
            0.2Credit
      reserve
            
            
            1.3
            
            
            
            0.8Balance
      as of September 30, 2008 (net credit reserve on energy
      derivatives)
            
            $
            (35.8
            )
            
            $
            (35.8
            )





The
Company believes energy derivative instruments classified as Level 3 should take
into account items that are generally economically hedged as a portfolio with
instruments that may be classified in Levels 1 and 2.  Realized gains
and losses on energy derivatives for Level 3 recurring items are included in
Energy Costs in the Company's income statement under purchased electricity,
electric generation fuel or purchased gas when settled.


Unrealized
gains and losses for Level 3 on energy derivatives recurring items are included
in net unrealized (gain) loss on derivative instruments in the Company's income
statement and other comprehensive income.  SFAS No. 157 requires that
financial assets and liabilities be classified in their entirety based on the
lowest level of input that is significant to the fair value
measurement.  As of September 30, 2008, energy derivative instruments
are classified in Level 3 because Level 3 inputs are significant to their fair
value measurement; however, the valuation of these derivative instruments is
primarily based upon observable inputs (Level 2).  The net unrealized
lossrecognized during the reporting period is primarily due to a significant
decrease in market prices.


Energy
derivatives transferred out of Level 3 represent existing assets or liabilities
that were either previously classified as Level 3 for which the lowest
significant input became observable during the period.


As a
result of the recent credit crisis, the FASB recently issued FSP FAS No. 157-3,
“Determining the Fair Value of a Financial Asset in a Market That is Not
Active.”  This FSP clarifies the application of SFAS No. 157 in a
market that is not active.  As of September 30, 2008, the Company
considers the markets for its electric and natural gas derivative instruments to
be actively traded.  Management’s assessment is based on the trading
activity volume in real-time and forward electric and natural gas
markets.  The Company regularly confirms the validity of broker quoted
prices (e.g. Level 2 in the fair value hierarchy) used to value commodity
contracts to the actual prices of commodity contracts entered into during the
most recent quarter. The Company has concluded that markets are liquid and there
was no impact to the Company’s regular practice of classifying fair value
measurements summarized within the SFAS No. 157 hierarchy for the third quarter
2008.


The
Company does not believe that the fair values diverge materially from the
amounts the Company currently anticipates realizing on settlement or
maturity.




(5)
            Retirement
      Benefits




The
Company has a defined benefit pension plan covering substantially all PSE
employees, with a cash balance feature for all but International Brotherhood of
Electrical Workers employees.  Benefits are a function of age, salary
and service.  Puget Energy also maintains a non-qualified supplemental
retirement plan for officers and certain director-level
employees.


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





Pension
      Benefits
            
            
            Other
      Benefits(Dollars
      in Thousands)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            3,421
            
            
            $
            3,328
            
            
            $
            28
            
            
            $
            33Interest
      cost
            
            
            7,205
            
            
            
            6,628
            
            
            
            296
            
            
            
            204Expected
      return on plan assets
            
            
            (10,391
            )
            
            
            (9,715
            )
            
            
            (197
            )
            
            
            (210
            )Amortization
      of prior service cost
            
            
            315
            
            
            
            510
            
            
            
            21
            
            
            
            43Recognized
      net actuarial (gain) loss
            
            
            419
            
            
            
            1,297
            
            
            
            (177
            )
            
            
            (493
            )Amortization
      of transition obligation
            
            
            --
            
            
            
            --
            
            
            
            13
            
            
            
            12Net
      periodic benefit cost
            
            $
            969
            
            
            $
            2,048
            
            
            $
            (16
            )
            
            $
            (411
            )





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





Pension
      Benefits
            
            
            Other
      Benefits(Dollars
      in Thousands)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            10,264
            
            
            $
            9,983
            
            
            $
            115
            
            
            $
            216Interest
      cost
            
            
            21,614
            
            
            
            19,884
            
            
            
            862
            
            
            
            962Expected
      return on plan assets
            
            
            (31,172
            )
            
            
            (29,144
            )
            
            
            (592
            )
            
            
            (620
            )Amortization
      of prior service cost
            
            
            946
            
            
            
            1,532
            
            
            
            63
            
            
            
            310Recognized
      net actuarial (gain) loss
            
            
            1,257
            
            
            
            3,890
            
            
            
            (575
            )
            
            
            (605
            )Amortization
      of transition obligation
            
            
            --
            
            
            
            --
            
            
            
            38
            
            
            
            222Net
      periodic benefit cost
            
            $
            2,909
            
            
            $
            6,145
            
            
            $
            (89
            )
            
            $
            485





The
Company previously disclosed in its financial statements for the year ended
December 31, 2007 that it expected to pay benefits of $4.0 million and make a
contribution of less than $0.1 million to the non-qualified pension and other
benefits plans for the year ending December 31, 2008,
respectively.  During the three and nine months ended September 30,
2008, payments of benefits related to the Company’s non-qualified pension plans
were $0.4 million and $0.9 million, respectively.  Based on this
activity, the Company anticipates paying additional benefits of $2.9 million for
the Company’s non-qualified pension plan during the fourth quarter
2008.


During
the three and nine months ended September 30, 2008, actual other post-retirement
medical benefit plan contributions were less than $0.1 million, respectively,
and the Company does not expect to make additional contributions during the
fourth quarter 2008.


The
Company’s qualified pension plan includes investments that are invested by
professional managers in a diversified portfolio of equity, fixed income
securities and short-term investments.  During the three months ended
September 30, 2008, the Company made a one time pension plan contribution in the
amount of $0.4 million to the qualified retirement plan.  The
qualified pension plan was also amended during the same time period to approve
an ad hoc monthly benefit increase for plan participants receiving current
benefits and who retired and commenced receiving benefits prior to January 1,
1999 which resulted in a prior service cost adjustment of $5.3 million to the
benefit obligation.  During September 2008 and subsequent to the close
at September 30, 2008, equity market conditions have been unpredictable and
extremely volatile.  The qualified pension plan assets declined by more
than 13.0% during the third quarter 2008 and as a result, PSE is evaluating if a
qualified pension plan contribution will be made in the fourth quarter
2008.  Management will continue to monitor conditions, plan assets and
obligations.




(6)
            Regulation
      and Rates




On
October 8, 2008, the Washington Utilities and Transportation Commission
(Washington Commission) issued its order in PSE’s consolidated electric and
natural gas general rate case filed in December 2007, approving a general rate
increase for electric customers of $130.2 million or 7.1% annually, and an
increase in natural gas rates of $49.2 million or 4.6% annually.  The
rate increases for electric and natural gas customers were effective November 1,
2008.  In its order, the Washington Commission approved a weighted
cost of capital of 8.25% and a capital structure that included 46.0% common
equity with a return on equity of 10.15%.  The Washington Commission
will determine by a separate order certain contested issues related to the Power
Cost Only Rate Case (PCORC) mechanism.


On
September 25, 2008, the Washington Commission approved PSE’s requested revisions
to its purchased gas adjustment (PGA) tariff schedules resulting in an increase
of $108.8 million or 11.1% on an annual basis in gas sales revenues effective
October 1, 2008.  The rate increase was the result of higher costs of
natural gas in the forward market and a reduction of the credit for the
accumulated PGA payable balance.  The PGA rate change will increase
PSE’s revenue but will not impact the Company’s net income as the increased
revenue will be offset by increased purchased gas costs.


On April
11, 2007, the Washington Commission issued an accounting order that authorized
PSE to defer certain ownership and operating costs (and associated carrying
costs) related to its purchase of the Goldendale electric generating facility
(Goldendale) during the period prior to inclusion in PSE’s retail electric rates
in the PCORC.  The deferral was for the time period from March 15,
2007 through September 1, 2007, at which time the Company began recovering
Goldendale ownership and operation costs in electric rates.  As of
September 30, 2008, PSE had established a regulatory asset of $12.4
million.  PSE began amortization of the costs on November 1, 2008 over
a three year period as determined in PSE’s electric general rate
case.


In March
2008, Bonneville Power Administration (BPA) and PSE signed an agreement pursuant
to which BPA (on April 2, 2008) paid PSE $53.7 million in Residential Exchange
Program (REP) benefits for fiscal year ending September 30, 2008, which payment
is subject to true-up depending upon the amount of any REP benefits ultimately
determined to be payable to PSE.  In April 2008, the Washington
Commission approved PSE’s tariff filing seeking to pass-through the net amount
of the benefits under the interim agreements to residential and small farm
customers.  The Washington Commission also approved PSE’s request to
credit the regulatory asset amount of $33.7 million against the $53.7 million
payment and pass-through to customers the remaining amount of approximately
$20.0 million, which occurred during the second quarter 2008.  These
amounts did not affect PSE’s net income.  PSE began amortization of
the accrued carrying charges on the regulatory asset totaling $3.1 million at
September 30, 2008 on November 1, 2008 over a two year period as determined in
PSE’s electric general rate case.  On October 8, 2008, the Washington
Commission approved PSE’s tariff request to resume the REP pass-through credits
to residential electric customers. The result is a 9.9% reduction to residential
electric customers bill without an impact on earnings.


In
November 2007, the Western Electricity Coordinating Council (WECC) audited PSE’s
compliance with electric reliability standards adopted by Federal Energy
Regulatory Commission (FERC), the North American Electric Reliability
Corporation (NERC) and/or WECC.  Compliance with these standards
includes periodic self-certifications of compliance, self-reports of violations
after discovery of the violation, spot checks to review self-certifications and
external audits that review compliance with designated standards in
detail.  The WECC audit team identified four potential violations of
the standards that PSE had not previously self-reported.  Several
months after the audit, WECC issued a “Notice of Alleged Violations” to PSE,
adding details and proposed penalties to the proposed findings.  Under
the rules for the process, PSE met with WECC representatives in July 2008 to
discuss settlement.  PSE believes that all issues concerning the four
potential violations will be resolved.  Resolution of reliability
standards issues will be an ongoing concern; however, PSE self-reports
violations when they are discovered.  Such self-reports could result
in settlement of issues or issuances of penalties in the future.  PSE
has established a loss reserve of $0.6 million related to these alleged
violations.


On
October 17, 2008, FERC issued a new license for the Baker River hydroelectric
project for a 50-year term.  The new license incorporates the measures
proposed in the comprehensive Settlement Agreement that was filed on November
30, 2004 and signed by PSE and 23 parties (federal, state and local governmental
organizations, Native American Indian tribes, environmental and other
non-governmental entities).  The new license will require an
investment of approximately $360.0 million (capital expenditures and operations
and maintenance cost) over 30 years in order to implement the license
conditions.  The license provides protection and enhancements for fish
and wildlife, water quality, recreation and cultural and historic
resources.  Parties may seek rehearing of the order issuing the new
license within 30 days of license issuance.


On
December 18, 2007, PSE received a data request from the Investigations Division
of the Office of Enforcement at FERC seeking information about certain natural
gas pipeline capacity release transactions PSE entered into in 2005 and
2006.  PSE responded to the data requests on January 23, 2008 and met
with FERC staff on January 31, 2008.  At this meeting, PSE discussed
with FERC staff additional transactions discovered in the course of responding
to the data requests that potentially may be in violation of FERC
regulations.  PSE received additional data requests from FERC on
February 20, 2008.  In October 2008, PSE received preliminary
notification from FERC staff that PSE had violated several FERC regulations and
was subject to potential civil penalties and other remedies.  FERC has
not yet issued a formal investigation report and thus, PSE is not able to
predict the ultimate outcome of this investigation, including the amount of any
penalties, at this time.





(7)
            Litigation




Residential
Exchange.  Petitioners in several actions in the United States
Court of Appeals for the Ninth Circuit (Ninth Circuit) against BPA asserted that
BPA acted contrary to law 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 REP.  Petitioners in
several actions in the Ninth Circuit against BPA also asserted that BPA acted
contrary to law in adopting or implementing the rates upon which the benefits
received or to be received from BPA during the October 1, 2001 through September
30, 2006 period were based.  A number of parties 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.


On May 3,
2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA,
No. 01-70003, in which proceeding the actions of BPA in entering into settlement
agreements regarding the REP with PSE and with other investor-owned utilities
were challenged.  In this opinion, the Ninth Circuit granted petitions
for review and held the settlement agreements entered into between BPA and the
investor-owned utilities being challenged in that proceeding to be inconsistent
with statute.  On May 3, 2007, the Ninth Circuit also issued an
opinion in Golden Northwest
Aluminum v. BPA, No. 03-73426, in which proceeding the petitioners sought
review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth
Circuit granted petitions for review and held that BPA unlawfully shifted onto
its preference customers the costs of its settlements with the investor-owned
utilities.  On October 5, 2007, petitions for rehearing of these two
opinions were denied.  On February 1, 2008, PSE and other utilities
filed in the Supreme Court of the United States a petition for a writ of
certiorari to review the decisions of the Ninth Circuit, which petition was
denied in June 2008.


In May
2007, following the Ninth Circuit’s issuance of these two opinions, BPA
suspended payments to PSE under the amended settlement agreement (and the May
2004 agreement).  On October 11, 2007, the Ninth Circuit remanded the
May 2004 agreement to BPA in light of the Portland Gen. Elec. v. BPA
opinion and dismissed the remaining three pending cases regarding settlement
agreements.


In March
2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to
PSE related to the REP benefits for the fiscal year ending September 30, 2008,
which payment is subject to true-up depending upon the amount of any REP
benefits ultimately determined to be payable to PSE.  This BPA's
authority to enter into, and the validity of, this agreement and similar
agreements with other utilities is being challenged by several BPA customers in
the Ninth Circuit Court of Appeals.  In March and April 2008,
Clatskanie People’s Utility District (PUD) filed petitions in the Ninth Circuit
for review of BPA actions in connection with offering or entering into such
agreement with PSE and similar agreements with other investor-owned
utilities.  Clatskanie PUD asserts that BPA’s actions in entering into
and executing the 2008 REP agreements were contrary to law or without authority
and that such agreements are null and void and result in overpayments of REP
benefits to PSE and other regional investor-owned utilities.


In
September 2008, BPA issued its record of decision in its reopened WP-07 rate
proceeding to respond to the various Ninth Circuit opinions.  In the
record of decision, BPA adjusted its fiscal year 2009 rates, determined the
amounts of REP benefits it considered to have been improperly paid after fiscal
year 2001 to PSE and the other regional investor-owned utilities and determined
that such amounts are to be recovered through reductions in REP benefit payments
to be made over a number of years.  The amount to be recovered (with
interest) through reductions in REP payments for PSE’s residential and small
farm customers is approximately $207.2 million to the extent that PSE receives
any REP benefits in the future.  However, this BPA determination is
subject to subsequent administrative and judicial review which may alter or
reverse such determination.  PSE is also reviewing its options in
determining if it will contest the amounts withheld as improper payments made
after 2001.


In
September 2008, BPA and PSE signed a Residential Purchase and Sale Agreement
(RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending
September 30, 2009–2011.  Generally, REP benefit payments under a RPSA
are based on the amount, if any, by which a utility’s average system cost (ASC)
exceeds BPA’s Preference Rate (PF) Exchange rate for such
utility.  The ASC for a utility is determined using an ASC methodology
adopted by BPA.  The ASC methodology adopted by BPA and the ASC
determinations, REP overpayment determinations and the PF Exchange rate
determinations by BPA are all subject to FERC review or judicial review or both
and are subject to adjustment, which may affect the amount of REP benefits paid
or to be paid by BPA to PSE.  As discussed above, BPA has determined
to reduce such payments based on its determination of REP benefit overpayments
after fiscal year 2001.


It is not
clear what impact, if any, such development or review of such BPA rates, review
of such ASC, ASC Methodology, BPA determination of REP overpayments, review of
such agreements and the above described Ninth Circuit litigation may ultimately
have on PSE.


Colstrip
Matters.  In
May 2003, approximately 50 plaintiffs initiated an action against the owners of
Colstrip alleging that (1) seepage from two different wastewater pond areas
caused groundwater contamination and threatened to contaminate domestic water
wells and the Colstrip water supply pond, and (2) seepage from the Colstrip
water supply pond caused structural damage to buildings and toxic
mold.  The defendants reached agreement on a global settlement with
all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in the
amount of $10.7 million in July 2008.  PSE had previously expensed the
settlement in the first quarter 2008.  PSE has also filed an
accounting petition with the Washington Commission to recover such costs in the
future.
 The
Minerals Management Service of the United States Department of Interior
(MMS) has issued a series of orders to Western Energy Company (WECO) to pay
additional taxes and royalties concerning coal WECO sold to the owners of
Colstrip 3 & 4, and similar orders have been issued in the administrative
appellate process.  The orders assert that additional royalties are
owed in connection with payments received by WECO from Colstrip 3
& 4 owners (including
PSE) for the construction and operation of a conveyor system that runs
several miles from the mine to Colstrip 3 & 4.  The state of Montana
has also issued a demand to WECO consistent with the MMS position.  WECO
has challenged these orders, and the issue has been on appeal for
several years.WECO
has won some points during the appellate process that have reduced the claims;
however under applicable law, to pursue the appeals, the principal in dispute
cannot be paid, which causes interest to accrue.  Moreover, because
the conveyor system continues to be used, the amount in
dispute grows.  PSE and the other Colstrip 3 & 4 owners
authorized WECO to make a settlement offer to the Montana Department of Revenue
(DOR) and the MMS in connection with these claims.  Discussions with
the DOR and with the MMS continue.  PSE has recorded a $1.7 million
pre-tax loss reserve in this matter.
 Proceedings
Related to the Western Power Market.Puget
Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31,
2007 includes a summary relating to the western power market
proceedings.  The following discussion provides a summary of material
developments during the third quarter 2008.  PSE is vigorously
defending each of these cases.  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/or
adversely affect PSE’s financial condition, results of operations or
liquidity.
 Lockyer
Case.In March and April 2008, FERC issued orders establishing
procedures for the Lockyer
remand.  The
orders commence a seller-by-seller inquiry into the transaction reports filed by
entities that sold power in California during 2000.  The inquiry is to
determine if the transaction reports as filed masked the gathering of more than
20% of the market during the period by that seller.  The California
parties sought rehearing on a variety of these issues.  On October 6,
2008, FERC issued a decision on the rehearing request that reaffirmed its intent
to impose seller-specific remedies rather than the market-wide remedy sought by
the California parties.  The rehearing decision also reconfirms the
Commission’s method for determining market share, limits the scope of the
proceeding and declines to defer the proceeding pending remand from the Ninth
Circuit of the California Refund Proceeding and the Port of Seattle (Pacific
Northwest Refund) case.  PSE believes that it will not be found to
have possessed 20% of any relevant market during any relevant
time.  The proceeding continues, including a settlement process before
an Administrative Law Judge (ALJ).  Settlement talks among various
parties continue but PSE cannot predict the ultimate outcome of any negotiations
or subsequent process before FERC or the ALJ.
 California
Receivable and California Refund Proceeding.The California Independent
System Operator (CAISO) filed status reports in this matter from time to time,
but has yet to report its “who owes what to whom”
calculation.
 Orders
to Show Cause.  On June 25, 2003, FERC issued two show cause
orders pertaining to its western market investigations that commenced individual
proceedings against many sellers.  One show cause order investigated
26 entities that allegedly had potential “partnerships” with
Enron.  PSE was not named in that show cause order.  On
January 22, 2004, FERC stated that it did not intend to proceed further against
other parties.


The
second show cause order named PSE (Docket No. EL03-169) and approximately 54
other entities that alleg­edly had engaged in potential “gaming” practices
in the CAISO and California PX markets.  PSE and FERC staff filed a
proposed settlement of all issues pending against PSE in those proceedings on
August 28, 2003.  The proposed settlement, which admits no wrongdoing
on the part of PSE, would result in a payment of a nominal amount to settle all
claims.  FERC approved the settlement on January 22,
2004.  The California parties filed for rehearing of that
order.  On March 17, 2004, PSE moved to dismiss the California
parties’ rehearing request and awaits FERC action on that motion.
 Pacific Northwest Refund
Proceeding.In October 2000, PSE filed a complaint at FERC
(Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific
Northwest seeking prospective price caps consistent with any result FERC ordered
for the California markets.  FERC dismissed PSE’s complaint, but PSE
challenged that dismissal.  On June 19, 2001, FERC ordered price
caps on energy sales throughout the West.  Various parties, including
the Port of Seattle and the cities of Seattle and Tacoma, then moved to
intervene in the proceeding seeking retroactive refunds for numerous
transactions.  The proceeding became known as the “Pacific Northwest
Refund Proceeding,” though refund claims were outside the scope of the
original complaint.  On June 25, 2003, FERC terminated the proceeding
on procedural, jurisdictional and equitable grounds and on November 10, 2003,
FERC on rehearing, confirmed the order terminating the proceeding.  On
August 24, 2007, the Ninth Circuit issued a decision concluding that FERC should
have evaluated and considered evidence of market manipulation in California and
its potential impact in the Pacific Northwest.  It also decided that
FERC should have considered purchases made by the California Energy Resources
Scheduler and/or the California Department of Water Resources in the Pacific
Northwest Proceeding.  On December 17, 2007, PSE and PowerEx Corp.
separately filed requests for rehearing with the Ninth Circuit of this
decision.  Those requests remain pending.  PSE intends to
vigorously defend its position in this proceeding, but it is unable to predict
the outcome of this matter.


Proceeding Relating to the Proposed
Merger.On February 6, 2008, the Company entered into a
memorandum of understanding providing for the settlement of the consolidated
shareholder lawsuit, subject to customary conditions including completion of
appropriate settlement documentation, confirmatory discovery and court
approval.  Pursuant to the memorandum of understanding, the Company
agreed to include certain additional disclosures in its proxy statement relating
to the merger.  The Company does not admit, however, that its prior
disclosures were in any way materially misleading or inadequate.  In
addition, the Company and the other defendants in the consolidated lawsuit deny
the plaintiffs’ allegations of wrongdoing and violation of law in connection
with the merger.  The settlement, if completed and approved by the
court, will result in dismissal with prejudice and release of all claims of the
plaintiffs and settlement class of the Company’s shareholders that were or could
have been brought on behalf of the plaintiffs and the settlement
class.  In connection with such settlement, the plaintiffs intend to
seek a court-approved award of attorneys’ fees and expenses in an amount up to
$290,000, which the Company has agreed to pay.  As of September 30,
2008, the Company has a loss reserve of $290,000 related to this
matter.


Snoqualmie Falls
project.The Snoqualmie Falls project was granted a new
40-year operating license by FERC on June 29, 2004.  The Snoqualmie
Tribe asked for rehearing of the order and requested a stay of the new
license.  On March 1, 2005, FERC issued an Order on Rehearing and
Dismissing Stay Request.  The order required additional flows at
Snoqualmie Falls during certain times of the year, but otherwise denied the
Snoqualmie Tribe’s request.  The Snoqualmie Tribe sought further
review by the U.S. Court of Appeals arguing, among other issues, that FERC
violated the Religious Freedom Restoration Act (RFRA) and that the license
decision substantially burdened the Snoqualmie Tribe’s free exercise of
religion.  PSE also sought review of FERC’s decision to require
additional flows during certain times of the year because the action appeared to
interfere with the Washington State Department of Ecology’s jurisdiction to
determine water quality issues.  On October 7, 2008, the court issued
a decision denying the appeals and determined that FERC did not violate RFRA and
that FERC’s adoption of water flows greater than those prescribed in the water
quality certification did not contradict or weaken the water quality
certification’s minimum flow requirements.  Parties may seek review of
the decision by the United States Supreme Court.  Such review is
discretionary and PSE is unable to determine whether the Supreme Court will
elect to review the matter if further review is sought.  In addition,
on December 6, 2007, PSE filed an application for a non-capacity amendment to
the 2004 license.  The application seeks to amend the license to
account for technology improvements and hydrologic and other changes that
occurred post-license.  The license amendment application remains
pending and its ultimate outcome remains uncertain.




(8)
            Related
      Party Transactions




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. (PSE Funding), a PSE
subsidiary, which is the London Interbank Offered Rate (LIBOR) plus a marginal
rate.  At September 30, 2008 and December 31, 2007, the outstanding
balance of the Note was $24.7 million and $15.8 million, respectively and the
interest rate was 3.05% and 5.31% respectively.  The outstanding
balance and the related interest under the Note are eliminated by Puget Energy
upon consolidation of PSE’s financial statements.  The $30.0 million
credit facility with Puget Energy is unaffected by the pending
merger.


The
Company has a general liability claim from AEGIS Insurance Services Inc. (AEGIS)
for $7.0 million as of September 30, 2008.  One nonemployee director
of Puget Energy and PSE also serves on the board of AEGIS and a PSE management
employee serves on one of AEGIS’ risk management committees.


PSE has
property insurance with various companies and approximately 35% of the property
insurance coverage is with American International Group, Inc
(AIG).  On October 23, 2008, AIG named the wife of Puget Energy’s and
PSE’s Chairman, President and Chief Executive as its Vice Chairman and Chief
Restructuring Officer.




(9)
            Other




Financial
Accounting Standards Board (FASB) Interpretation No. 46R, “Consolidation of
Variable Interest Entities” (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 power purchase agreements and determined that two counterparties
during the nine months ended September 30, 2008 may be considered variable
interest entities.  Consistent with FIN 46R, PSE submitted requests
for information to those two entities; however, the entities 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
two power purchase agreements that may be considered variable interest entities
under FIN 46R as of the third quarter 2008, PSE is required to buy all the
generation from these plants, subject to displacement by PSE, at rates set forth
in the power purchase 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 power purchase
agreement prices.  PSE’s purchased electricity expense for the three
months ended September 30, 2008 and 2007 was $55.9 million and $60.0 million,
respectively, and for the nine months ended September 30, 2008, and 2007 was
$147.7 million and $157.2 million, respectively.


In
November 2006, PSE’s Crystal Mountain Generation Station had an accidental
release of approximately 18,000 gallons of diesel fuel.  PSE crews and
consultants responded and worked with applicable state and federal agencies to
control and remove the spilled diesel.  On July 11, 2007, PSE received
a Notice of Completion for work performed pursuant to the Administrative Order
for Removal from the U. S. Environmental Protection Agency (EPA).  The
Notice stated that PSE had met the requirements of the Order and the
accompanying scope of work.  Total removal costs as of September 30,
2008 were approximately $14.5 million.  PSE estimates the total
remediation cost to be approximately $15.0 million, which has been accrued or
paid.  PSE received a partial insurance payment of $5.0 million on
this receivable in January 2008.  At September 30, 2008, PSE had an
insurance receivable recorded in the amount of $7.0 million associated with this
fuel release.  PSE is in discussions with the insurance provider on
the remaining outstanding balance which management believes to be
collectible.


On
September 25, 2008, PSE executed a purchase agreement to acquire a 310 megawatt
(MW) natural gas-fired power plant, the Mint Farm project, located in Washington
State, for approximately $240.0 million.  The transaction is expected
to close by the end of 2008 and is subject to FERC approval.


On
November 4, 2008, Election Day, there will be three measures appearing on the
ballot in three Washington State counties for voter approval to form or
authorize, in each case, a public utility district to pursue efforts to acquire
or construct electric facilities within PSE service territory.  These
ballot measures impact an aggregate of approximately 109,000 current PSE
customers across the three counties.  If these ballots measures are
passed, the Company believes it will take several years before any change in
PSE’s service territory takes effect.




(10)
            New
      Accounting Pronouncements




On
September 15, 2006, FASB issued SFAS No. 157, which clarifies how companies
should use fair value measurements in accordance with GAAP for recognition and
disclosure purposes.  SFAS No. 157 establishes a common definition of
fair value and a framework for measuring fair value under GAAP, along with
expanding disclosures about fair value to eliminate differences in current
practice that exist in measuring fair value under the existing accounting
standards.  The definition of fair value in SFAS No. 157 retains the
notion of exchange price; however, it focuses on the price that would be
received to sell the asset or paid to transfer a liability (i.e. an exit price),
rather than the price that would be paid to acquire the asset or received to
assume the liability (i.e. an entrance price).  Under SFAS No. 157, a
fair value measure should reflect all of the assumptions that market
participants would use in pricing the asset or liability, including assumptions
about the risk inherent in a particular valuation technique, the effect of a
restriction on the sale or use of an asset, and the risk of
nonperformance.  To increase consistency and comparability in fair
value measures, SFAS No. 157 establishes a three-level fair value hierarchy to
prioritize the inputs used in valuation techniques between observable inputs
that reflect quoted market prices in active markets, inputs other than quoted
prices with observable market data, and unobservable data (e.g. a company’s own
data).


SFAS No.
157 is effective for fiscal years beginning after November 15, 2007, which was
the year beginning January 1, 2008, for the Company.  On February 28,
2008, the FASB issued a final FASB Staff Position (FSP) that partially deferred
the effective date of SFAS No. 157 for one year for non-financial assets and
non-financial liabilities that are recognized or disclosed at fair value, except
for those that are recognized or disclosed at fair value on an annual or more
frequent basis.  The Company adopted SFAS No. 157 on January 1, 2008,
prospectively, as required by the Statement, with certain
exceptions,  including the initial impact of changes in fair value
measurements of existing derivative financial instruments measured initially
using the transaction price under EITF No. 02-3.  On January 1, 2008,
the difference between the carrying amounts and the fair values of those
instruments originally recorded under guidance in EITF No. 02-3 was recognized
as a cumulative-effect adjustment to the opening balance of retained
earnings.  SFAS No. 157 nullified a portion of EITF No.
02-3.  Under EITF No. 02-3, the transaction price presumption
prohibited recognition of a trading profit at inception of a derivative unless
the positive fair value of that derivative was substantially based on quoted
prices or a valuation process incorporating observable inputs.  For
transactions that did not meet this criterion at inception, trading profits that
had been deferred were recognized in the period that inputs to value the
derivative became observable or when the contract performed.


As a
result of the recent credit crisis, on October 10, 2008, the FASB issued FSP FAS
No. 157-3, “Determining the Fair Value of a Financial Asset in a Market That is
Not Active.”  This FSP clarifies the application of SFAS No. 157 “Fair
Value Measurements,” in a market that is not active.  The FSP
addresses how management should consider measuring fair value when relevant
observable data does not exist.  The FSP also provides guidance on how
observable market information in a market that is not active should be
considered when measuring fair value, as well as how the use of market quotes
should be considered when assessing the relevance of observable and unobservable
data available to measure fair value. This FSP was effective upon issuance,
including prior periods for which financial statement have not been
issued.  Revisions resulting from a change in the valuation technique
or its application shall be accounted for as a change in accounting estimate
(FASB Statement No. 154, “Accounting Changes and Error Corrections,” (SFAS No.
154) paragraph 19).  The disclosure provisions of SFAS No. 154 for a
change in accounting estimate are not required for revisions resulting from a
change in valuation technique or its application.  The Company has
reviewed the statement and has assessed that there will be no significant impact
to the financial statements.


In
December 2007, the FASB issued SFAS No. 141(R), “Business Combinations”
(SFAS No. 141(R)).  This Statement replaces FASB Statement No. 141,
“Business Combinations,” and addresses the accounting for all transactions or
other events in which an entity obtains control of one or more
businesses.  The objective of this Statement is to improve the
relevance, representational faithfulness and comparability of the information
that a reporting entity provides in its financial reports about a business
combination and its effects. To accomplish that, this Statement establishes
principles and requirements for how the acquirer: 1) Recognizes and measures in
its financial statements the identifiable assets acquired, the liabilities
assumed and any noncontrolling interest in the acquiree; 2) Recognizes and
measures the goodwill acquired in the business combination or a gain from a
bargain purchase; and 3) Determines what information to disclose to enable users
of the financial statements to evaluate the nature and financial effects of the
business combination.  This Statement shall be applied prospectively
to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008.  The Company is currently assessing the impact of SFAS No.
141(R).


On March
19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No.
161).  SFAS No. 161 is effective for the fiscal years and interim
years beginning after November 15, 2008, which will be the quarter ending March
31, 2009 for the Company.  SFAS No. 161 requires companies with
derivative instruments to disclose information that should enable financial
statement users to understand how and why a company uses derivative instruments,
how derivative instruments and related hedged items are accounted for under SFAS
No. 133 and how derivative instruments and related hedged items affect a
company’s financial position, financial performance and cash
flows.  SFAS No. 161 requirements will impact the following derivative
and hedging disclosures: objectives and strategies, balance sheet, financial
performance, contingent features and counterparty credit risk.  The
Company is currently assessing the impact of SFAS No. 161.


In May
2008, FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting
Principles” (SFAS No. 162), which identifies the sources of accounting
principles and the framework for selecting the principles to be used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting
principles.  The FASB Board is responsible for identifying the sources
of accounting principles and providing entities with a framework for selecting
the principles used in the preparation of financial statements.  The
Company has reviewed the statement and has assessed that there will be no
significant impact to the financial statements.


On June
16, 2008, FSP EITF No. 03-6-1, “Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities,” (EITF No.
03-6-1) was issued.  This FSP addresses whether instruments granted in
share-based payment transactions are participating securities prior to vesting
and, therefore, need to be included in the earnings allocation in computing
earnings per share under the two-class method.  Unvested share-based
payment awards that contain nonforfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating securities and shall be
included in the computation of earnings per share pursuant to the two-class
method.  This FSP will be effective for financial statements issued
for fiscal years beginning after December 15, 2008, which will be the year
ending December 31, 2009 for the Company.  The Company is currently
assessing the financial statement presentation impact of FSP EITF No.
03-6-1.






(11)
            Corporate Guarantees(Puget Energy Only)




On May 7,
2006, Puget Energy sold InfrastruX Group Inc. (InfrastruX) to an affiliate of
Tenaska Power Fund, L.P. (Tenaska) in an all-cash transaction.  Puget
Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144,
“Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144)
in 2006.  As a part of the transaction, Puget Energy made certain
representations and warrantees concerning InfrastruX and indemnified Tenaska
against certain future losses not to exceed $15.0 million.  At the
time of the sale, Puget Energy purchased a warrantee insurance policy and
deposited $3.7 million into an escrow account, representing the full retention
under the insurance policy.  Additionally at the time of sale, Puget
Energy recorded a $5.0 million loss reserve in connection with the
indemnifications, which represented management’s measurement of the fair value
of the corporate guarantees using a probability weighted approach.


On April
29, 2008, Puget Energy and Tenaska entered into a Joint Notice of Distribution
and Termination Agreement (Termination Agreement) which resulted in the
extinguishment of all InfrastruX corporate guarantees made by Puget Energy which
management believed involved a risk of loss in connection with the sale of
InfrastruX.  In the second quarter 2008, Puget Energy made the
remaining payments under the terms of the Termination Agreement totaling $7.1
million bringing total cash outlays equal to the Company’s original aggregate
loss reserve amounts recorded in the second quarter of 2006.




(12)
            Agreement
      and Plan of Merger (Puget Energy
only)




On
October 26, 2007, Puget Energy announced that it had entered into a definitive
Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which
Puget Energy will be acquired by a consortium of long-term infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension Plan
Investment Board and British Columbia Investment Management Corporation and
which also includes Alberta Investment Management Corporation, Macquarie-FSS
Infrastructure Trust and Macquarie Capital Group (collectively, the
Consortium).  At the effective time of the merger, each issued and
outstanding share of common stock of Puget Energy, other than any shares in
respect of which dissenter’s rights are perfected and other than any shares
owned by the Consortium, shall be cancelled and shall be converted automatically
into the right to receive $30.00 in cash, without interest.


The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including the receipt of shareholder approval of the merger
and approval of it by various state and federal regulatory
authorities.  As of the date of this Quarterly Report, these
conditions have either been satisfied or are in process.  On April 16,
2008, Puget Energy shareholders approved the merger by more than the required
two-thirds vote.  Also, on April 17, 2008, FERC conditionally approved
the transaction pursuant to section 203 of the Federal Power Act subject to
reviewing the final conditions of merger approval by the Washington
Commission.  On December 17, 2007, PSE and the Consortium filed a
joint application seeking approval of the merger with the Washington
Commission.


On July
22, 2008, Puget Energy, the Consortium and several parties involved in the
merger proceeding reached a settlement to resolve all issues before the
Washington Commission.  On July 23, 2008, the parties to the merger
agreement filed a multiparty stipulated settlement with the Washington
Commission.  On October 9, 2008, the Washington Commission issued a
notice to all parties to the merger case that they may submit reply briefs in
the proceeding.  These documents were filed on October 23,
2008.  The filing of reply briefs by the parties is expected to be the
last step before a final order is issued by the Washington
Commission.  If approved by the Washington Commission in the fourth
quarter 2008, closing is expected to occur during the fourth quarter
2008.







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 or phrases 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.  Readers 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, Inc. (Puget Energy) is an energy services holding company and all of its
operations are conducted through its subsidiary Puget Sound Energy, Inc. (PSE),
a regulated electric and natural gas utility company.  Puget Energy is
dependent upon the results of PSE since PSE is its most significant
asset.  PSE is the largest electric and natural gas utility in the
state of Washington, primarily engaged in the business of electric transmission,
distribution, generation and natural gas distribution.  Puget Energy’s
business strategy is to generate stable earnings and cash flow by offering
reliable electric and natural gas service in a cost effective manner through
PSE.





Puget Energy
Merger


On
October 26, 2007, Puget Energy announced that it had entered into a definitive
Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which
Puget Energy will be acquired by a consortium of long-term infrastructure
investors led by Macquarie Infrastructure Partners, the Canada Pension Plan
Investment Board and British Columbia Investment Management Corporation and
which also includes Alberta Investment Management Corporation, Macquarie-FSS
Infrastructure Trust and Macquarie Capital Group (collectively, the
Consortium).  At the effective time of the merger, each issued and
outstanding share of common stock of Puget Energy, other than any shares in
respect of which dissenter’s rights are perfected and other than any shares
owned by the Consortium, shall be cancelled and shall be converted automatically
into the right to receive $30.00 in cash, without interest.


The
consummation of the merger is subject to the satisfaction or waiver of certain
closing conditions, including the receipt of shareholder approval of the merger
and approval of it by various state and federal regulatory
authorities.  As of the date of this Quarterly Report, these
conditions have either been satisfied or are in process.  On April 16,
2008, Puget Energy shareholders approved the merger.  Also, on April
17, 2008 the Federal Energy Regulatory Commission (FERC) conditionally approved
the transaction pursuant to section 203 of the Federal Power Act subject to
reviewing the final conditions of merger approval by the Washington Utilities
and Transportation Commission (Washington Commission).  On December
17, 2007, PSE and the Consortium filed a joint application seeking approval of
the merger with the Washington Commission.


On July
22, 2008, Puget Energy, the Consortium and several parties involved in the
merger proceeding reached a settlement to resolve all issues before the
Washington Commission.  On July 23, 2008, the parties to the merger
agreement filed a multiparty stipulated settlement with the Washington
Commission.  On October 9, 2008, the Washington Commission issued a
notice to all parties to the merger case that they may submit reply briefs in
the proceeding.  These documents were filed on October 23,
2008.  The filing of reply briefs by the parties is expected to be the
last step before a final order is issued by the Washington
Commission.  If approved by the Washington Commission in the fourth
quarter 2008, closing is expected to occur during the fourth quarter
2008.





Puget Sound
Energy


PSE
generates revenues primarily from the sale of electric and natural gas services
to residential and commercial customers within Washington
State.  PSE’s operating revenues and associated expenses are not
generated evenly throughout the year.  Variations in energy usage by
consumers occur from season to season and from month to month within a season,
primarily as a result of weather conditions.  PSE normally experiences
its highest retail energy sales 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.


As a
regulated utility company, PSE is subject to FERC and 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 contracted generation plants where energy is
obtained; storms or other events which can damage natural gas and electric
distribution and transmission lines; increasing regulatory standards for system
reliability; wholesale market stability over time; and significant evolving
environmental legislation.


PSE is
investing heavily in its utility infrastructure and customer service functions
in order to meet increasing regulatory requirements, customer growth and aging
infrastructure needs.  Such investments and operating requirements
give rise to significant growth in depreciation expense and operating expense
which costs are not timely recovered via the ratemaking process which relies
predominately on a historic test year to fix rates and revenue
requirements.  Such “regulatory lag” is expected to continue for the
foreseeable future.


PSE’s
main business objective is to provide reliable, safe and cost-effective energy
to its customers.  To help accomplish this objective, PSE seeks to
become more energy efficient and environmentally responsible in its energy
supply portfolio on an ongoing basis.  PSE filed its most recent
Integrated Resource Plan on May 31, 2007 with the Washington
Commission.  The plan supports a strategy of significantly increasing
energy efficiency programs, pursuing additional renewable resources (primarily
wind) and additional base load natural gas fired generation to meet the growing
needs of its customers.  On July 28, 2008, PSE announced that it had
completed the purchase of the 125 megawatt (MW) Sumas cogeneration power
plant.  On September 25, 2008, PSE executed a purchase agreement to
acquire a 310 MW natural gas-fired power plant, the Mint Farm project, which is
located in Washington State, for approximately $240.0 million.  The
transaction is expected to close by the end of 2008 and is subject to FERC
approval.  These acquisitions are part of PSE’s long-range initiative
for meeting its customers’ steadily growing electricity needs.








Non-GAAP
Financial Measures – Energy Margins


The
following discussion includes financial information prepared in accordance with
generally accepted accounting principles (GAAP), as well as two other financial
measures, Electric Margin and Gas Margin, that are considered “non-GAAP
financial measures.”  Generally, a non-GAAP financial measure is a
numerical measure of a company’s financial performance, financial position or
cash flows that exclude (or include) amounts that are included in (or excluded
from) the most directly comparable measure calculated and presented in
accordance with GAAP.  The presentation of Electric Margin and Gas
Margin is intended to supplement investors’ understanding of the Company’s
operating performance.  Electric Margin and Gas Margin are used by the
Company to determine whether the Company is collecting the appropriate amount of
energy costs from its customers to allow recovery of operating
costs.  The Company’s Electric Margin and Gas Margin measures may not
be comparable to other companies’ Electric Margin and Gas Margin
measures.  Furthermore, these measures are not intended to replace
operating income as determined in accordance with GAAP as an indicator of
operating performance.








Results
of Operations


Puget
Energy


All the
operations of Puget Energy are conducted through its subsidiary
PSE.  Net loss for the three months ended September 30, 2008 was $8.2
million on operating revenues of $606.2 million as compared to net income of
$11.4 million on operating revenues of $601.7 million for the same period in
2007.


Basic and
diluted loss per share for the three months ended September 30, 2008 was $0.06
as compared to basic and diluted earnings per share for the three months ended
September 30, 2007 of $0.10.  Net income for the three months ended
September 30, 2008 as compared to the same period in 2007 was negatively
impacted by a $4.6 million decrease in electric margin while it was positively
impacted by a $2.1 million increase in gas margin.  Net income was
negatively impacted by an $11.6 million increase in utility operation and
maintenance and an increase in depreciation and amortization of $8.8 million.
The increase in expenses was partially offset by a decrease in interest expense
of $2.7 million.  In the third quarter 2008, Puget Energy incurred
$1.3 million in costs related to the proposed merger with the
Consortium.


For the
nine months ended September 30, 2008, Puget Energy’s net income was $105.2
million on operating revenues of $2.4 billion compared to net income of $129.1
million on operating revenues of $2.3 billion for the same period in
2007.  Basic and diluted earnings per share for the nine months ended
September 30, 2008 was $0.81 compared to basic and diluted earnings per share of
$1.11 and $1.10, respectively, for the same period in 2007.


Net
income for the nine months ended September 30, 2008 was positively impacted by
increased electric and gas margins of $19.9 million and $23.1 million,
respectively, compared to the same period in 2007.  Net income was
negatively impacted by an increase in utility operations and maintenance of
$43.1 million and a $25.0 million increase in depreciation and
amortization.  The increase in expenses was partially offset by an
increase in other income of $4.0 million and a decrease in interest expense of
$5.7 million due to lower average debt outstanding as a result of the equity
issuance in December 2007.  For the nine months ended September 30,
2008, Puget Energy incurred $8.3 million in costs related to the proposed merger
with the Consortium.





Puget Sound
Energy


PSE’s
operating revenues and expenses are not generated evenly throughout 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.  Power cost recovery is seasonal, with underrecovery
normally in the first and fourth quarters when electric sales volumes and power
costs are higher and overrecovery in the second and third
quarters.  Varying wholesale electric prices and the amount of
hydroelectric energy supplies available to PSE also make quarter to quarter
comparisons difficult.




Energy
Margins


The
following table displays the details of electric margin changes for the three
months ended September 30, 2008 as compared to the same period in
2007.  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,
            
            2008
            
            
            2007
            
            
            Change
            
            
            Percent
              ChangeElectric
      operating revenue1
            
            $
            467.4
            
            
            $
            456.1
            
            
            $
            11.3
            
            
            
            2.5
            %Less:
      Other electric operating revenue
            
            
            (15.9
            )
            
            
            (3.2
            )
            
            
            (12.7
            )
            
            
            *Add:
      Other electric operating revenue-gas supply resale
            
            
            7.4
            
            
            
            (6.6
            )
            
            
            14.0
            
            
            
            *Total
      electric revenue for margin
            
            
            458.9
            
            
            
            446.3
            
            
            
            12.6
            
            
            
            2.8Adjustments
      for amounts included in revenue:Pass-through
      tariff items
            
            
            (15.1
            )
            
            
            (9.8
            )
            
            
            (5.3
            )
            
            
            (54.1
            )Pass-through
      revenue-sensitive taxes
            
            
            (31.9
            )
            
            
            (29.5
            )
            
            
            (2.4
            )
            
            
            (8.1
            )Net
      electric revenue for margin
            
            
            411.9
            
            
            
            407.0
            
            
            
            4.9
            
            
            
            1.2Minus
      power costs:Purchased
      electricity1
            
            
            (173.7
            )
            
            
            (185.8
            )
            
            
            12.1
            
            
            
            6.5Electric
      generation fuel1
            
            
            (64.9
            )
            
            
            (43.5
            )
            
            
            (21.4
            )
            
            
            (49.2
            )Residential
      exchange1
            
            
            0.2
            
            
            
            0.4
            
            
            
            (0.2
            )
            
            
            (50.0
            )Total
      electric power costs
            
            
            (238.4
            )
            
            
            (228.9
            )
            
            
            (9.5
            )
            
            
            (4.2
            )Electric
      margin2
            
            $
            173.5
            
            
            $
            178.1
            
            
            $
            (4.6
            )
            
            
            (2.6
            )
      %


____________________________


1
            As
      reported on PSE’s Consolidated Statement of Income.2
            Electric
      margin does not include any allocation for amortization/depreciation
      expense or electric generation operation and maintenance
      expense.*
            Percent
      change not applicable or
meaningful.




Electric
margin decreased $4.6 million for the three months ended September 30, 2008
compared to the same period in 2007.  The decrease in electric margin
was impacted by a decrease of $1.8 million in retail sales volumes and higher
power supply costs driven by a reduction in hydroelectric generation and an
increase in natural gas fuel prices which decreased margin by approximately $4.1
million.





The
following table displays the details of electric margin changes for the nine
months ended September 30, 2008 compared to the same period in
2007.  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)
                Nine
      Months Ended September 30,
              
              2008
              
              
              2007
              
              
              Change
              
              
              Percent
                ChangeElectric
      operating revenue1
              
              $
              1,551.5
              
              
              $
              1,419.0
              
              
              $
              132.5
              
              
              
              9.3
              %Less:
      Other electric operating revenue
              
              
              (48.4
              )
              
              
              (29.9
              )
              
              
              (18.5
              )
              
              
              (61.9
              )Add:
      Other electric revenue-gas supply resale
              
              
              18.4
              
              
              
              (0.2
              )
              
              
              18.6
              
              
              
              *Total
      electric revenue for margin
              
              
              1,521.5
              
              
              
              1,388.9
              
              
              
              132.6
              
              
              
              9.5Adjustments
      for amounts included in revenue:Pass-through
      tariff items
              
              
              (44.2
              )
              
              
              (30.7
              )
              
              
              (13.5
              )
              
              
              (44.0
              )Pass-through
      revenue-sensitive taxes
              
              
              (106.5
              )
              
              
              (95.3
              )
              
              
              (11.2
              )
              
              
              (11.8
              )Net
      electric revenue for margin
              
              
              1,370.8
              
              
              
              1,262.9
              
              
              
              107.9
              
              
              
              8.5Minus
      power costs:Purchased
      electricity1
              
              
              (645.4
              )
              
              
              (640.6
              )
              
              
              (4.8
              )
              
              
              (0.7
              )Electric
      generation fuel1
              
              
              (144.6
              )
              
              
              (93.3
              )
              
              
              (51.3
              )
              
              
              (55.0
              )Residential
      exchange1
              
              
              20.5
              
              
              
              52.4
              
              
              
              (31.9
              )
              
              
              (60.9
              )Total
      electric power costs
              
              
              (769.5
              )
              
              
              (681.5
              )
              
              
              (88.0
              )
              
              
              (12.9
              )Electric
      margin2
              
              $
              601.3
              
              
              $
              581.4
              
              
              $
              19.9
              
              
              
              3.4
              %


1
            As
      reported on PSE’s Consolidated Statement of Income.2
            Electric
      margin does not include any allocation for amortization/depreciation
      expense or electric generation operation and maintenance
      expense.*
            Percent
      change not applicable or
meaningful.




Electric
margin increased $19.9 million for the nine months ended September 30, 2008
compared to the same period in 2007.  This is primarily due to a 2.8%
increase in retail sales volumes which increased electric margin by $15.3
million and $12.4 million related to the recovery of Goldendale electric
generating facility (Goldendale) ownership and operating costs.  The
increase was partially offset by higher power supply costs of approximately $9.1
million driven by a reduction in hydroelectric generation and an increase in
natural gas fuel prices.


The
following table displays the details of gas margin changes for the three months
ended September 30, 2008 as compared to the same period in 2007.  Gas
margin is natural gas sales to retail and transportation customers less
pass-through tariff items and revenue-sensitive taxes, and the cost of natural
gas purchased, including transportation costs to bring natural gas to PSE’s
service territory.


Gas
      Margin(Dollars
      in Millions)
                Three
      Months Ended September 30,
              
              2008
              
              
              2007
              
              
              Change
              
              
              Percent
                ChangeGas
      operating revenue1
              
              $
              133.2
              
              
              $
              142.1
              
              
              $
              (8.9
              )
              
              
              (6.3
              )
      %Less:
      Other gas operating revenue
              
              
              (4.3
              )
              
              
              (4.1
              )
              
              
              (0.2
              )
              
              
              (4.9
              )Total
      gas revenue for margin
              
              
              128.9
              
              
              
              138.0
              
              
              
              (9.1
              )
              
              
              (6.6
              )Adjustments
      for amounts included in revenue:Pass-through
      tariff items
              
              
              (1.2
              )
              
              
              (1.1
              )
              
              
              (0.1
              )
              
              
              (9.1
              )Pass-through
      revenue-sensitive taxes
              
              
              (10.5
              )
              
              
              (11.0
              )
              
              
              0.5
              
              
              
              4.5Net
      gas revenue for margin
              
              
              117.2
              
              
              
              125.9
              
              
              
              (8.7
              )
              
              
              (6.9
              )Minus
      purchased gas costs1
              
              
              (70.1
              )
              
              
              (80.9
              )
              
              
              10.8
              
              
              
              13.3Gas
      margin2
              
              $
              47.1
              
              
              $
              45.0
              
              
              $
              2.1
              
              
              
              4.7
              %
 ____________________


1
            As
      reported on PSE’s Consolidated Statement of Income.2
            Gas
      margin does not include any allocation for amortization/depreciation
      expense or electric generation operations and maintenance
      expense.





Gas
margin increased $2.1 million for the three months ended September 30, 2008 as
compared to the same period in 2007 primarily due to a 3.2% gas therm volume
sales increase resulting in a $1.4 million increase to gas
margin.  The remainder of the increase is due to a change in customer
mix and other favorable pricing variances.


The following
table displays the details of gas margin changes for the nine months ended
September 30, 2008 compared to the same period in 2007.  Gas margin is
natural gas sales to retail and transportation customers less pass-through
tariff items and revenue-sensitive taxes, and the cost of natural gas purchased,
including transportation costs to bring natural gas to PSE’s service
territory.





Gas
      Margin(Dollars
      in Millions)
                Nine
      Months Ended September 30,
              
              2008
              
              
              2007
              
              
              Change
              
              
              Percent
                ChangeGas
      operating revenue1
              
              $
              810.3
              
              
              $
              834.3
              
              
              $
              (24.0
              )
              
              
              (2.9
              )
      %Less:
      Other gas operating revenue
              
              
              (13.2
              )
              
              
              (13.3
              )
              
              
              0.1
              
              
              
              0.8Total
      gas revenue for margin
              
              
              797.1
              
              
              
              821.0
              
              
              
              (23.9
              )
              
              
              (2.9
              )Adjustments
      for amounts included in revenue:Pass-through
      tariff items
              
              
              (7.9
              )
              
              
              (6.0
              )
              
              
              (1.9
              )
              
              
              (31.7
              )Pass-through
      revenue-sensitive taxes
              
              
              (65.8
              )
              
              
              (68.1
              )
              
              
              2.3
              
              
              
              3.4Net
      gas revenue for margin
              
              
              723.4
              
              
              
              746.9
              
              
              
              (23.5
              )
              
              
              (3.1
              )Less:
      Purchased gas costs1
              
              
              (484.0
              )
              
              
              (530.6
              )
              
              
              46.6
              
              
              
              8.8Gas
      margin2
              
              $
              239.4
              
              
              $
              216.3
              
              
              $
              23.1
              
              
              
              10.7
              %
 ____________________


1
            As
      reported on PSE’s Consolidated Statement of Income.2
            Gas
      margin does not include any allocation for amortization/depreciation
      expense or electric generation operations and maintenance
      expense.





Gas
margin increased $23.1 million for the nine months ended September 30, 2008
compared to the same period in 2007 primarily due to an increase in margin of
$20.8 million related to a 9.6% gas therm volume sales increase and a 2.8%
general rate increase effective January 13, 2007 which, combined with a change
in customer mix and other pricing variances, resulted in an increase to gas
margin of $2.3 million.








Electric
Operating Revenues


The table
below sets forth changes in electric operating revenues for PSE for the three
months ended September 30, 2008 as compared to the same period in
2007.





(Dollars
      in Millions)
                Three
      Months Ended September 30,
              
              2008
              
              
              2007
              
              
              Change
              
              
              Percent
                ChangeElectric
      operating revenues:Residential
      sales
              
              $
              199.7
              
              
              $
              184.2
              
              
              $
              15.5
              
              
              
              8.4
              %Commercial
      sales
              
              
              191.6
              
              
              
              177.6
              
              
              
              14.0
              
              
              
              7.9Industrial
      sales
              
              
              25.7
              
              
              
              25.5
              
              
              
              0.2
              
              
              
              0.8Other
      retail sales, including unbilled revenue
              
              
              4.3
              
              
              
              17.6
              
              
              
              (13.3
              )
              
              
              (75.6
              )Total
      retail sales
              
              
              421.3
              
              
              
              404.9
              
              
              
              16.4
              
              
              
              4.1Transportation
      sales
              
              
              2.6
              
              
              
              2.8
              
              
              
              (0.2
              )
              
              
              (7.1
              )Sales
      to other utilities and marketers
              
              
              27.6
              
              
              
              45.3
              
              
              
              (17.7
              )
              
              
              (39.1
              )Other
              
              
              15.9
              
              
              
              3.1
              
              
              
              12.8
              
              
              
              *Total
      electric operating revenues
              
              $
              467.4
              
              
              $
              456.1
              
              
              $
              11.3
              
              
              
              2.5
              %
 ____________________


*
            Percent
      change not applicable or
meaningful.





Electric
retail sales increased $16.4 million for the three months ended September 30,
2008 as compared to the same period in 2007.  The Power Cost Only Rate
Case (PCORC) rate increase effective September 1, 2007 increased operating
revenues $14.4 million for the three months ended September 30, 2008 as compared
to the same period in 2007.  Retail electricity usage decreased 45,863
megawatt hours (MWh) or 1.0% compared to the same period in 2007, which resulted
in a decrease of approximately $4.1 million in electric operating
revenue.


Sales to
other utilities and marketers decreased $17.7 million for the three months ended
September 30, 2008 as compared to the same period in 2007 primarily due to a
decrease in sales volume of 390,867 MWh or 44.8% as a result of decreased
surplus energy due in part to lower hydroelectric generation, which resulted in
a decrease of $20.3 million.  This decrease was offset by higher
wholesale electric prices in the third quarter 2008 as compared to the same
period in 2007, which increased sales by $2.6 million.


Other
electric operating revenues increased $12.8 million for the three months ended
September 30, 2008 as compared to the same period in 2007 primarily due to an
increase of $14.1 million in noncore gas sales.





The table
below sets forth changes in electric operating revenues for PSE for the nine
months ended September 30, 2008 compared to the same period in
2007.





(Dollars
      in Millions)
              Nine
      Months Ended September 30,
            
            2008
            
            
            2007
            
            
            Change
            
            
            Percent
              ChangeElectric
      operating revenues:Residential
      sales
            
            $
            783.3
            
            
            $
            675.7
            
            
            $
            107.6
            
            
            
            15.9
            %Commercial
      sales
            
            
            593.1
            
            
            
            550.6
            
            
            
            42.5
            
            
            
            7.7Industrial
      sales
            
            
            79.2
            
            
            
            77.8
            
            
            
            1.4
            
            
            
            1.8Other
      retail sales, including unbilled revenue
            
            
            (28.1
            )
            
            
            (14.0
            )
            
            
            (14.1
            )
            
            
            (100.7
            )Total
      retail sales
            
            
            1,427.5
            
            
            
            1,290.1
            
            
            
            137.4
            
            
            
            10.7Transportation
      sales
            
            
            5.5
            
            
            
            7.6
            
            
            
            (2.1
            )
            
            
            (27.6
            )Sales
      to other utilities and marketers
            
            
            70.1
            
            
            
            91.5
            
            
            
            (21.4
            )
            
            
            (23.4
            )Other
            
            
            48.4
            
            
            
            29.8
            
            
            
            18.6
            
            
            
            62.4Total
      electric operating revenues
            
            $
            1,551.5
            
            
            $
            1,419.0
            
            
            $
            132.5
            
            
            
            9.3
            %





Electric
retail sales increased $137.4 million for the nine months ended September 30,
2008 compared to the same period in 2007 due primarily to an increase in
customer growth and colder average temperatures in the Pacific Northwest during
the first half of 2008.  Retail electricity usage increased 436,979
MWh or 2.8% for the nine months ended September 30, 2008 compared to the same
period in 2007, which resulted in an increase of approximately $38.9 million in
electric operating revenue.  The increase was also related to the
PCORC rate increase of September 1, 2007 offset by the electric general rate
decrease of January 13, 2007 which resulted in an increase of $65.8
million.  During the nine month period ended September 30, 2008, the
benefits of the Residential and Farm Energy Exchange Benefit credited to
customers reduced electric operating revenues by $21.4 million compared to $54.9
million for the same period in 2007.  This credit also reduced power
costs by a corresponding amount with no impact on earnings.


The
following electric rate changes were approved by the Washington Commission in
2007:





Type
      of Rate
                Adjustment
              Effective
      Date
              Average
                Percentage
                Increase
      (Decrease)
                in
      Rates
              Annual
                Increase
      (Decrease)
                in
      Revenues
                (Dollars
      in Millions)Electric
      General Rate Case
              January
      13, 2007
              (1.3
              )
      %
              $
      (22.8)Power
      Cost Only Rate Case
              September
      1, 2007
              3.7
              
              64.7




Gas
Operating Revenues


The table
below sets forth changes in gas operating revenues for PSE for the three months
ended September 30, 2008 as compared to the same period in 2007.





(Dollars
      in Millions)
              Three
      Months Ended September 30,
            
            2008
            
            
            2007
            
            
            Change
            
            
            Percent
              ChangeGas
      operating revenues:Residential
      sales
            
            $
            71.3
            
            
            $
            74.7
            
            
            $
            (3.4
            )
            
            
            (4.6
            )
      %Commercial
      sales
            
            
            46.3
            
            
            
            49.3
            
            
            
            (3.0
            )
            
            
            (6.1
            )Industrial
      sales
            
            
            8.0
            
            
            
            10.6
            
            
            
            (2.6
            )
            
            
            (24.5
            )Total
      retail sales
            
            
            125.6
            
            
            
            134.6
            
            
            
            (9.0
            )
            
            
            (6.7
            )Transportation
      sales
            
            
            3.3
            
            
            
            3.4
            
            
            
            (0.1
            )
            
            
            (2.9
            )Other
            
            
            4.3
            
            
            
            4.1
            
            
            
            0.2
            
            
            
            4.9Total
      gas operating revenues
            
            $
            133.2
            
            
            $
            142.1
            
            
            $
            (8.9
            )
            
            
            (6.3
            )
      %





Gas
retail sales decreased $9.0 million for the three months ended September 30,
2008 as compared to the same period in 2007 due to a $16.2 million reduction in
gas operating revenues as a result of a 13.0% Purchased Gas Adjustment (PGA)
mechanism rate decrease for retail customers effective October 1,
2007.  The PGA mechanism passes through to customers increases or
decreases in the natural 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 natural gas pipeline transportation
costs.  PSE’s gas margin and net income are not affected by changes
under the PGA mechanism.  Offsetting the decrease was a $6.9 million
increase in gas therm sales of 4.5 million or 3.2% reflecting customer growth
and colder average temperatures in the Pacific Northwest.





The table
below sets forth changes in gas operating revenues for PSE for the nine months
ended September 30, 2008 compared to the same period in 2007.





(Dollars
      in Millions)
              Nine
      Months Ended September 30,
            
            2008
            
            
            2007
            
            
            Change
            
            
            Percent
              ChangeGas
      operating revenues:Residential
      sales
            
            $
            509.8
            
            
            $
            510.5
            
            
            $
            (0.7
            )
            
            
            (0.1
            )
      %Commercial
      sales
            
            
            246.2
            
            
            
            257.2
            
            
            
            (11.0
            )
            
            
            (4.3
            )Industrial
      sales
            
            
            30.5
            
            
            
            43.1
            
            
            
            (12.6
            )
            
            
            (29.2
            )Total
      retail sales
            
            
            786.5
            
            
            
            810.8
            
            
            
            (24.3
            )
            
            
            (3.0
            )Transportation
      sales
            
            
            10.6
            
            
            
            10.2
            
            
            
            0.4
            
            
            
            3.9Other
            
            
            13.2
            
            
            
            13.3
            
            
            
            (0.1
            )
            
            
            (0.8
            )Total
      gas operating revenues
            
            $
            810.3
            
            
            $
            834.3
            
            
            $
            (24.0
            )
            
            
            (2.9
            )
      %





Gas
retail sales decreased $24.3 million for the nine months ended September 30,
2008 compared to the same period in 2007 due to lower PGA mechanism rates and
increased customer natural gas usage.  The Washington Commission
approved a PGA mechanism rate decrease effective October 1,
2007.  PSE’s gas margin and net income are not affected by changes
under the PGA mechanism.  The effects of the PGA mechanism rate
decrease of 13.0% were offset by a 2.8% natural gas general rate increase
effective January 13, 2007 resulting in a decrease of $103.1 million in natural
gas operating revenues.  The decrease was offset by higher gas sales
of 72.2 million therms or 9.6% which increased gas operating revenue by $79.1
million.  A 2.3% increase in natural gas customers and colder than
average temperatures contributed to the higher natural gas sales.


The
following natural gas rate adjustments were approved by the Washington
Commission in 2007 and 2008:




Type
      of Rate
                Adjustment
              Effective
      Date
              Average
                Percentage
                Increase
      (Decrease)
                in
      Rates
              Annual
                Increase
      (Decrease)
                in
      Revenues
                (Dollars
      in Millions)Purchased
      Gas Adjustment
              October
      1, 2008
              11.1
              %
              $
      108.8Gas
      General Rate Case
              January
      13, 2007
              2.8
              
              29.5Purchased
      Gas Adjustment
              October
      1, 2007
              (13.0
              )
              (148.1
              )




Non-Utility
Operating Revenues


The table
below sets forth changes in non-utility operating revenues for PSE for the nine
months ended September 30, 2008 as compared to the same period in
2007.





(Dollars
      in Millions)
              Nine
      Months Ended September 30,
            
            2008
            
            2007
            
            Change
            
            Percent
              ChangeNon-utility
      operating revenue
            
            $
            7.6
            
            
            $
            13.4
            
            
            $
            (5.8
            )
            
            
            (43.3
            )
      %





Non-utility
operating revenues decreased $5.8 million for the nine months ended
September 30, 2008 as compared to the same period in 2007due to higher
property sales during 2007 by PSE’s real estate subsidiary.





Operating
Expenses


The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the three months ended September 30, 2008 as compared to the
same period in 2007.





(Dollars
      in Millions)
              Three
      Months Ended September 30,
            
            2008
            
            
            2007
            
            
            Change
            
            
            Percent
              ChangePurchased
      electricity
            
            $
            173.7
            
            
            $
            185.8
            
            
            $
            (12.1
            )
            
            
            (6.5
            )
      %Electric
      generation fuel
            
            
            64.9
            
            
            
            43.5
            
            
            
            21.4
            
            
            
            49.2Purchased
      gas
            
            
            70.1
            
            
            
            80.9
            
            
            
            (10.8
            )
            
            
            (13.3
            )Utility
      operations and maintenance
            
            
            106.0
            
            
            
            94.4
            
            
            
            11.6
            
            
            
            12.3Non-utility
      expense and other
            
            
            5.0
            
            
            
            2.2
            
            
            
            2.8
            
            
            
            127.3Depreciation
      and amortization
            
            
            77.7
            
            
            
            68.9
            
            
            
            8.8
            
            
            
            12.8Conservation
      amortization
            
            
            13.8
            
            
            
            8.5
            
            
            
            5.3
            
            
            
            62.4








The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the nine months ended September 30, 2008 compared to the same
period in 2007.





(Dollars
      in Millions)
              Nine
      Months Ended September 30,
            
            2008
            
            
            2007
            
            
            Change
            
            
            Percent
              ChangePurchased
      electricity
            
            $
            645.4
            
            
            $
            640.6
            
            
            $
            4.8
            
            
            
            0.7
            %Electric
      generation fuel
            
            
            144.6
            
            
            
            93.3
            
            
            
            51.3
            
            
            
            55.0Residential
      exchange credit
            
            
            (20.5
            )
            
            
            (52.4
            )
            
            
            31.9
            
            
            
            60.9Purchased
      gas
            
            
            484.0
            
            
            
            530.6
            
            
            
            (46.6
            )
            
            
            (8.8
            )Utility
      operations and maintenance
            
            
            334.6
            
            
            
            291.5
            
            
            
            43.1
            
            
            
            14.8Depreciation
      and amortization
            
            
            229.4
            
            
            
            204.4
            
            
            
            25.0
            
            
            
            12.2Conservation
      amortization
            
            
            42.7
            
            
            
            27.6
            
            
            
            15.1
            
            
            
            54.7Taxes
      other than income taxes
            
            
            214.8
            
            
            
            207.3
            
            
            
            7.5
            
            
            
            3.6





Purchased electricity expenses
decreased $12.1 million and increased $4.8 million for the three and nine months
ended September 30, 2008, respectively, as compared to the same period in
2007.  The decrease for the three months ended September 30, 2008 was
due to an underrecovery of power costs of $3.3 million for the three months
ended September 30, 2008 as compared to overrecovery of power cost of $8.3
million in the same period in 2007.  The underrecovery of power costs
for the three months ended September 30, 2008 was due to lower hydroelectric
generation and an increase in the amount of generation produced by PSE’s
combustion turbines which was lower than the wholesale price of
power.  A decrease of $0.8 million in transmission expenses also
contributed to the overall reduction in expense.


The
increase for the nine months ended September 30, 2008 was primarily the result
of higher wholesale market prices which contributed $50.6 million offset by a
decrease in purchased power of 800,927 MWh or 6.4%, resulting in a decrease of
$36.4 million.  The decrease in purchased power is related to
increased production from company-owned combustion turbines, wind facilities and
thermal generating facilities.  Also offsetting the increase were
decreased transmission costs and other expenses, which contributed $9.0
million.


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 $21.4 million and $51.3 million for the three and nine months
ended September 30, 2008, respectively, as compared to the same period in
2007.  The increase for the three months ended September 30, 2008 was
due to an increase in generation from combustion turbines which contributed
$21.0 million and an increase in market prices for natural gas used for electric
generation. The increase for the nine months ended September 30, 2008 was due to
an increase in generation from combustion turbines which contributed $50.5
million.  The increase in combustion turbine generation was due to
lower hydroelectric generation and higher wholesale market price of
electricity.


Residential exchange credits
associated with the Bonneville Power Administration (BPA) Residential Exchange
Program (REP) decreased $31.9 million for the nine months ended September 30,
2008 as compared to the same period in 2007 as a result of the suspension of the
residential and small farm customer electric credit in rates effective June 7,
2007.  The suspension was due to an adverse ruling from the U.S. Court
of Appeals for the Ninth Circuit (Ninth Circuit) which states that BPA actions
in entering into residential exchange settlement agreements with investor owned
utilities were not in accordance with the law.  In April 2008, PSE
signed an agreement pursuant to which BPA would pay PSE $53.7 million for fiscal
year 2008 REP benefits.  Of this amount PSE received approval to
pass-through to customers approximately $20.0 million over a one-month
period.  The remaining $33.7 million was used to offset PSE’s
regulatory asset.  The REP 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.  Based upon a new REP agreement, PSE
began passing through REP credit to customers on November 1, 2008.


Purchased gas expenses
decreased $10.8 million and $46.6 million for the three and nine months ended
September 30, 2008, respectively, as compared to the same period in 2007
primarily due to a decrease in PGA rates, partially offset by higher customer
therm sales.  The PGA mechanism allows PSE to recover expected natural
gas supply and transportation costs, and defer, as a receivable or liability,
any natural gas supply and transportation costs that exceed or fall short of
this expected gas cost amount in PGA mechanism rates, including accrued
interest.  The PGA mechanism payable balance at September 30, 2008 was
$16.2 million as compared to $77.9 million at December 31, 2007.  PSE
is authorized by the Washington Commission to accrue carrying costs on PGA
receivable and payable balances.  A receivable balance in the PGA
mechanism reflects an under recovery of market natural gas cost through
rates.  A payable balance reflects over recovery of market natural gas
cost through rates.


Utility operations and maintenanceexpense increased $11.6 million and $43.1 million for the three and nine
months ended September 30, 2008, respectively, as compared to the same period in
2007.  The increase for the three months ended September 30, 2008 was
primarily due to an increase in planned maintenance of PSE’s generating
facilities of $2.2 million, $5.5 million increase in administrative and general
expenses primarily related to increases in insurance expenses and self-insurance
claim reserve, $2.4 million increase in planned and unplanned gas operations and
distribution expenses and a $1.8 million increase in customer service expenses
including bad debt expenses.  The increase for the nine months ended
September 30, 2008 was primarily due to $20.8 million in planned maintenance of
PSE’s generating facilities and settlement, $8.2 million increase in planned and
unplanned gas operations and distribution expenses, $9.1 million increase in
administrative and general expenses including increases in costs for insurance,
self-insurance claim reserve and legal fees associated with general rate
filings, $1.2 million increase in planned and unplanned electric transmission
and distribution expenses and $4.7 million increase in customer service expenses
including bad debt exposure.


Non-utility expense and other
increased $2.8 million for the three months ended September 30, 2008, as
compared to the same period in 2007 primarily due to energy efficiency projects
PSE constructed for the U.S. Navy.


Depreciation and amortization
expense increased $8.8 million and $25.0 million for the three and nine months
ended September 30, 2008, respectively, as compared to the same period in
2007.  These increases include the benefit of the 2007 deferral of
Goldendale ownership and operating costs of $3.9 million and $10.8 million for
the three and nine months ended September 30, 2007, respectively, which, had it
not been included, would have resulted in an increase to depreciation and
amortization expense of $4.9 million and $14.2 million for the three and nine
months ended September 30 2008, respectively, as compared to the same periods in
2007.  The Goldendale deferral of ownership and operating costs ceased
to be effective September 1, 2007, when PSE was authorized to begin recovering
the costs in rates. The increase, excluding Goldendale deferral, was primarily
due to placing additional utility plants into service during the last 12
months.


Conservation amortization
increased $5.3 million and $15.1 million for the three and nine months ended
September 30, 2008, respectively, as compared to the same period in 2007 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 $7.5 million for the nine months ended September 30, 2008 as compared
to the same period in 2007.  The increase was due to increases in
revenue-based Washington State excise tax and municipal tax as a result of
increased operating revenues.





Other
Income, Other Expenses, Interest Expense and Income Tax Expense


The table
below sets forth significant changes in other income, other expenses, interest
expense and income tax expense for PSE and its subsidiaries for the three months
ended September 30, 2008 as compared to the same period in 2007.




(Dollars
      in Millions)
                Three
      Months Ended September 30,
              2008
              2007
              Change
              Percent
                ChangeInterest
      expense
              $
      (48.8)
              $
      (51.5)
              $  2.7
              5.2%Income
      tax benefit
              (2.1)
              (1.9)
              (0.2)
              (10.5)





Interest expensedecreased
$2.7 million due primarily to the decrease in average debt outstanding as a
result of the equity issuance in December 2007 and lower average interest rates
on outstanding debt.


Income tax benefit increased
$0.2 million due to a loss for the three months ended September 30, 2008
compared to income for the same period in 2007.  The income tax
benefit for 2008 was offset by an unfavorable federal income tax expense true-up
of $1.8 million following the filing of PSE’s 2007 federal income tax
return.  The 2007 income tax benefit included a favorable true-up of
$1.9 million following the filing of PSE’s 2006 federal income tax
return.  The increase in income tax benefit was also affected by an
unfavorable true-up of the effective tax for 2008 for such items as
depreciation, production tax credits and, injuries and damages.


The table
below sets forth significant changes in other income, interest expense and
income tax expense for PSE and its subsidiaries for the nine months ended
September 30, 2008 compared to the same period in 2007.




(Dollars
      in Millions)
                Nine
      Months Ended September 30,
              2008
              2007
              Change
              Percent
                ChangeOther
      income
              $  21.8
              $  17.7
              $  4.1
              23.2%Interest
      expense
              (144.6)
              (150.2)
              5.6
              3.7Income
      tax expense
              46.8
              49.8
              (3.0)
              (6.0)




Other incomeincreased $4.1
million for the nine months ended September 30, 2008 compared to the same period
in 2007 primarily due to an increase in Washington Commission Allowance for
Funds Used During Construction (AFUDC) and equity AFUDC.


Interest expensedecreased
$5.6 million for the nine months ended September 30, 2008 compared to the same
period in 2007 primarily due to lower average debt outstanding as a result of
the equity issuance in December 2007 and lower average interest rate on
outstanding debt.


Income tax expensedecreased
$3.0 million for the nine months ended September 30, 2008 compared to the same
period in 2007 due primarily to lower taxable income in 2008 as compared to
2007.  The decrease was offset by an unfavorable federal income tax
expense true-up of $1.8 million in the third quarter 2008 following the filing
of PSE’s 2007 federal income tax return compared to a favorable true-up in the
third quarter 2007 of $1.9 million following the filing of PSE’s 2006 federal
income tax return.  The decrease in income tax expense was also offset
by the true-up of the effective tax rate for such items as depreciation,
production tax credits and, injuries and damages.







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, 2008:





Puget
      Energy
            
            
            
            Payments
      Due Per PeriodContractual
      Obligations
              (Dollars
      in Millions)
            Total
            2008
            2009-
              2010
            2011-
              2012
            2013
      & ThereafterLong-term
      debt including interest
            $
            6,118.5
            $
            44.6
            $
            712.8
            $
            520.9
            $
            4,840.2Short-term
      debt including interest
            
            581.5
            
            581.5
            
            --
            
            --
            
            --Mandatorily
      redeemable preferred stock
            
            1.9
            
            --
            
            --
            
            --
            
            1.9Service
      contract obligations
            
            437.0
            
            16.0
            
            136.2
            
            117.8
            
            167.0Non-cancelable
      operating leases
            
            138.9
            
            1.8
            
            17.3
            
            21.2
            
            98.6Fredonia
      combustion turbines lease 1
            
            48.3
            
            1.0
            
            7.7
            
            39.6
            
            --Energy
      purchase obligations
            
            6,114.5
            
            348.5
            
            2,074.5
            
            1,208.2
            
            2,483.3Contract initiation payment/collateral requirement
            
            18.5
            
            --
            
            --
            
            18.5
            
            --Financial
      hedge obligations
            
            (43.4
            )
            (9.2
            )
            (29.0
            )
            (5.2
            )
            --Purchase
      obligations
            
            298.0
            
            259.0
            
            23.0
            
            --
            
            16.0Pension and other benefits funding and payments
            
            38.8
            
            3.0
            
            8.1
            
            8.0
            
            19.7Total
      contractual cash obligations
            $
            13,752.5
            $
            1,246.2
            $
            2,950.6
            $
            1,929.0
            $
            7,626.7








Puget
      Energy
            
            
            
            Amount
      of Commitment
              Expiration
      Per PeriodCommercial
      Commitments
              (Dollars
      in Millions)
            Total
            2008
            2009-
              2010
            2011-
              2012
            2013
      & ThereafterCredit
      agreement - available 2
            $
            762.6
            $
            --
            $
            300.00
            $
            462.6
            $
            --Receivable
      securitization facility 3
            
            29.0
            
            --
            
            29.0
            
            --
            
            --Energy
      operations letter of credit
            
            6.9
            
            6.9
            
            --
            
            --
            
            --Total
      commercial commitments
            $
            798.5
            $
            6.9
            $
            329.0
            $
            462.6
            $
            -- ________________


1
            See
      “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
      below.2
            At
      September 30, 2008, PSE had available unsecured credit agreements in the
      amount of $500.0 million and $350.0 million, each expiring in April
      2012.  The credit agreements provide credit support for letters
      of credit and commercial paper.  Lehman Brothers Bank, FSB
      (Lehman) committed $35.0 million to each of these
      facilities.  In September 2008, a large Japanese bank acquired
      $25.0 million of Lehman’s commitment to the $500.0 million
      facility.  Consequently, at September 30, 2008, Lehman had
      commitments of $10.0 million and $35.0 million under PSE’s $500.0 million
      and $350.0 million facilities, respectively.  In September 2008,
      Lehman informed PSE that it had suspended funding borrowing requests for
      its portion of these facilities.  The impact of the suspension
      is to effectively reduce the size of these facilities to $490.0 million
      and $315.0 million, respectively.  At September 30, 2008, PSE
      had $6.9 million outstanding under four letters of credit, $55.2 million
      commercial paper outstanding, and $280.3 million drawn on this facility,
      effectively reducing the available borrowing capacity to $462.6
      million.  In August 2008, PSE entered into a nine month, $375.0
      million credit agreement with four banks and as of September 30, 2008, PSE
      had $75.0 million outstanding under the agreement, effectively reducing
      the borrowing capacity to $300.0 million.  As of September 30,
      2008, PSE had $1,180.0 million in credit facilities excluding Lehman’s
      share, effectively reduced by draws or commercial paper outstanding of
      $417.4 million, leaving $762.6 million available.3
            At
      September 30, 2008, PSE had available a $200.0 million receivables
      securitization facility that expires in December 2010.  $171.0
      million was outstanding under the receivables securitization facility at
      September 30, 2008 thus leaving $29.0 million available.  The
      facility allows receivables to be used as collateral to secure short-term
      loans, not exceeding the lesser of $200.0 million or the borrowing base of
      eligible receivables, which fluctuate with the seasonality of energy sales
      to customers.  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, 2008:





Puget
      Sound Energy
            Payments
      Due Per PeriodContractual
      Obligations
              (Dollars
      in Millions)
            Total
            2008
            2009-
              2010
            2011-
              2012
            2013
      & ThereafterLong-term
      debt including interest
            $
            6,118.5
            $
            44.6
            $
            712.8
            $
            520.9
            $
            4,840.2Short-term
      debt including interest
            
            606.3
            
            606.3
            
            --
            
            --
            
            --Mandatorily
      redeemable preferred stock
            
            1.9
            
            --
            
            --
            
            --
            
            1.9Service
      contract obligations
            
            437.0
            
            16.0
            
            136.2
            
            117.8
            
            167.0Non-cancelable
      operating leases
            
            138.9
            
            1.8
            
            17.3
            
            21.2
            
            98.6Fredonia
      combustion turbines lease 1
            
            48.3
            
            1.0
            
            7.7
            
            39.6
            
            --Energy
      purchase obligations
            
            6,114.5
            
            348.5
            
            2,074.5
            
            1,208.2
            
            2,483.3Contract initiation payment/collateral requirement
            
            18.5
            
            --
            
            --
            
            18.5
            
            --Financial
      hedge obligations
            
            (43.4
            )
            (9.2
            )
            (29.0
            )
            (5.2
            )
            --Purchase
      obligations
            
            298.0
            
            259.0
            
            23.0
            
            --
            
            16.0Pension and other benefits funding and payments
            
            38.8
            
            3.0
            
            8.1
            
            8.0
            
            19.7Total
      contractual cash obligations
            $
            13,777.3
            $
            1,271.0
            $
            2,950.6
            $
            1,929.0
            $
            7,626.7





Puget
      Sound Energy
            
            
            
            Amount
      of Commitment
              Expiration
      Per PeriodCommercial
      Commitments
              (Dollars
      in Millions)
            Total
            2008
            2009-
              2010
            2011-
              2012
            2013
      & ThereafterCredit
      agreement - available 2
            $
            762.6
            $
            --
            $
            300.0
            $
            462.6
            $
            --Receivable
      securitization facility 3
            
            29.0
            
            --
            
            29.0
            
            --
            
            --Energy
      operations letter of credit
            
            6.9
            
            6.9
            
            --
            
            --
            
            --Total
      commercial commitments
            $
            798.5
            $
            6.9
            $
            329.0
            $
            462.6
            $
            -- ________________


1
            See
      note 1 under Puget Energy above.2
            See
      note 2 under Puget Energy above.3
            See
      note 3 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 purpose
in April 2001.  The lease has a term expiring in 2011, but can be
canceled by PSE at any time.  Payments under the lease vary with
changes in the London Interbank Offered Rate (LIBOR).  At September
30, 2008, PSE’s outstanding balance under the lease was $46.1
million.  The expected residual value under the lease is the lesser of
$37.4 million or 60.0% 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 87.0% of the unamortized value of the
equipment.





Utility
Construction Program


PSE’s
construction programs for generating facilities, the electric transmission
system and the natural gas and electric distribution systems are designed to
meet continuing customer growth and to support reliable energy
delivery.  The cash flow construction expenditures, excluding equity
AFUDC and customer refundable contributions was $424.3 million for the nine
months ended September 30, 2008.  The anticipated utility construction
expenditures, excluding AFUDC, for 2008, 2009 and 2010 are:





Capital
      Expenditure Estimates
              (Dollars
      in Millions)
            
            2008
            
            
            2009
            
            
            2010Energy
      delivery, technology and facilities
            
            $
            587.0
            
            
            $
            737.0
            
            
            $
            840.0New
      supply resources
            
            
            346.0
            
            
            
            129.0
            
            
            
            148.0Total
      expenditures
            
            $
            933.0
            
            
            $
            866.0
            
            
            $
            988.0





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, 2008 was
$559.4 million, which is 119.5% of the $468.0 million cash used for utility
construction expenditures and other capital expenditures. For the nine months
ended September 30, 2007, cash from operations was $491.6 million, which was
85.0% of the $578.1 million cash used for utility construction expenditures and
other capital expenditures.


The
overall cash generated from operating activities for the nine months ended
September 30, 2008 increased $67.8 million compared to the same period in
2007.  The increase was primarily the result of the change in the
residential exchange program of $59.5 million in 2008 compared to 2007, lower
cash payments of $58.0 million related to accounts payable, $46.4 million more
cash received related to accounts receivable and income tax refunds of $42.4
million.  Further, cash from operations increased due to lower cash
payments for prepaid expenses of $33.3 million, $19.8 million recovery in
materials and supplies and a decrease in accrued expenses and other items for
the nine months ended September 30, 2008.  The increase was partially
offset by a reduction in the purchased gas liability in 2008 of $61.7 million
compared to an increase in the purchased gas liability in 2007 of $101.0 million
which accounted for a decrease in cash of $162.7 million.  The
increases were also offset by $31.7 million increase in fuel and gas inventory
costs and a cash receipt of $18.9 million in 2007 from the lease purchase option
settlement for the Bellevue offices.





Financing
Program


Financing
utility construction requirements and operational needs are dependent upon the
amount of cash available and the cost and availability of external funds through
bank credit facilities and capital markets.  Access to funds depends
upon factors such as general economic conditions, conditions in the bank and
credit markets, regulatory authorizations and policies and Puget Energy’s and
PSE’s credit ratings.





Liquidity
Facilities and Commercial Paper


PSE’s
cash investments, short-term borrowings and sales of commercial paper are used
to provide working capital to fund utility construction programs.  At
the present time, the market for commercial paper is limited for A3/P2 rated
companies and borrowing cost are significantly higher than under PSE’s credit
facilities.  The Company’s committed credit facilities with numerous
banks provide a stable liquidity position with sufficient short-term borrowing
capacity.  At September 30, 2008, PSE and its subsidiaries held $140.1
million of cash invested mostly in U.S. Treasury related money market
funds.  In the event of a credit downgrade, borrowing capacity under the
credit facilities would remain the same while borrowing spreads and fees
would increase.  PSE has not been significantly impacted by the
current credit environment.





PSE
Credit Facilities


The
Company has four committed credit facilities that provide, in aggregate, $1.4
billion in short-term borrowing capability.  These include a $500.0
million credit agreement, a $200.0 million accounts receivable securitization
facility, a $375.0 million short-term credit facility and a $350.0 million
credit agreement to support hedging activity.





Credit
Agreements.  In August 2008, PSE entered into a nine-month,
$375.0 million credit agreement with four banks.  The interest rate on
the facility is based either on the agent bank's prime rate or on LIBOR plus a
margin that increases over time.  PSE pays a commitment fee on any
unused portion of the credit agreement.  At September 30, 2008, there
was $75.0 million outstanding under the agreement.


In March
2007, PSE entered into a five-year, $350.0 million credit agreement with a group
of banks.  The agreement is used to support the Company’s energy
hedging activities and may also be used to provide letters of
credit.  The interest rate on outstanding borrowings is based either
on the agent bank’s prime rate or on LIBOR plus a marginal rate related to 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 related to
long-term credit ratings of PSE.  At September 30, 2008, there were no
borrowings or letters of credit outstanding under the credit
facility.


In March
2005, PSE entered into a five-year $500.0 million unsecured credit agreement
with a group of banks.  In March 2007, PSE restated this credit
agreement to extend the expiration date to April 2012.  The agreement
is primarily used to provide credit support for commercial paper and letters of
credit.  The terms of this agreement, as restated, are essentially
identical to those contained in the $350.0 million facility described
above.  At September 30, 2008, there was $6.9 million outstanding
under letters of credit, $55.2 million of commercial paper outstanding and
$280.3 million drawn on this facility.


The
$500.0 million and $350.0 million credit facilities described above were
originally syndicated with a group of 12 banks.  Lehman Brothers Bank,
FSB (Lehman) a subsidiary of Lehman Brothers Holdings, Inc., which filed for
liquidation on September 14, 2008, committed $35.0 million to each of these
facilities.  In September 2008, a large Japanese bank acquired $25.0
million of Lehman’s commitment to the $500.0 million
facility.  Consequently, at September 30, 2008, Lehman had commitments
of $10.0 million and $35.0 million under PSE’s $500.0 million and $350.0 million
facilities, respectively.  In September 2008, Lehman informed PSE that
it had suspended funding borrowing requests for its portion of these
facilities.  The impact of the suspension is to effectively reduce the
size of these facilities to $490.0 million and $315.0 million,
respectively.  Under this credit facility, with numerous banks, 30.0%
or $60.0 million is the greatest lending commitment exposure by any
bank.





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 $200.0 million or the
borrowing base of eligible receivables which fluctuate with the seasonality of
energy sales to customers.  All loans from this facility are 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.  There were $171.0 million in loans that were
secured by accounts receivable pledged at September 30, 2008.  The
remaining borrowing base of eligible receivables at September 30, 2008 was $29.0
million.





Demand Promissory Note.On
June 1, 2006, PSE entered into an uncommitted revolving credit facility with its
parent, Puget Energy, pursuant to a Demand Promissory Note (Note) under which
PSE may borrow up to $30.0 million from 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, a PSE subsidiary.  At September 30, 2008, the outstanding
balance of the Note was $24.7 million.  The outstanding balance and
the related interest under the Note are eliminated by Puget Energy upon
consolidation of PSE’s financial statements.





Long-term
Funding and Restrictive Covenants


In
determining the type and amount of future financing, PSE may be limited by
restrictions contained in its electric and natural gas mortgage indentures,
restated articles of incorporation and certain loan agreements.  Under
the most restrictive tests, at September 30, 2008, PSE could issue:


·
            approximately
      $721.0 million of additional first mortgage bonds under PSE’s electric
      mortgage indenture based on approximately $1.2 billion 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, 2008;


·
            approximately
      $507.0 million of additional first mortgage bonds under PSE’s natural gas
      mortgage indenture based on approximately $845.0 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 natural gas utility mortgage), which PSE
      exceeded at September 30, 2008;


·
            approximately
      $0.7 billion of additional preferred stock at an assumed dividend rate of
      9.5%; and


·
            approximately
      $732.1 million of unsecured long-term
debt.


At
September 30, 2008, PSE had approximately $4.8 billion in electric and natural
gas ratebase to support the interest coverage ratio limitation test for net
earnings available for interest.





Credit
Ratings


Neither
Puget Energy nor PSE has any debt outstanding that would accelerate debt
maturity upon a credit rating downgrade.  A ratings downgrade could
adversely affect the ability to renew existing, or obtain access to new credit
facilities and could increase the cost of such facilities.  For
example, under PSE’s revolving credit facility, the borrowing costs and
commitment fee increase as PSE’s corporate/issuer credit 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 PSE’s debt ratings may prompt counterparties to require
PSE to post a letter of credit or other collateral, make cash prepayments,
obtain a guarantee or provide other security.





The
ratings of Puget Energy and PSE, as of October 31, 2008, were as
follows:





RatingsStandard & Poor’s1,2
            Moody’s3Puget
      Sound EnergyCorporate
      credit/issuer rating
            BBB-
            Baa3Senior
      secured debt
            BBB+
            Baa2Junior
      subordinated notes
            BB
            Ba1Preferred
      stock
            BB
            Ba2Commercial
      paper
            A-3
            P-2Revolving
      credit facility
            Note
      1
            Baa3Ratings
      outlook
            Note
      2
            Note
      3Puget
      EnergyCorporate
      credit/issuer rating
            BBB-
            Ba1Ratings
      outlook
            Note
      2
            Note
      3


_______________


1
            Standard
      & Poor’s does not rate PSE’s credit
      facilities.2
            On
      October 26, 2007, Standard & Poor’s placed the ratings of Puget Energy
      (BBB-) and PSE (BBB-/A-3) on CreditWatch with negative
      implications.  The CreditWatch listing reflects the possibility
      that debt ratings for Puget Energy could be lowered dependent on the final
      outcome of regulatory approval proceedings.3
            On
      October 29, 2007, Moody’s placed the Ba1 Issuer rating of Puget Energy on
      review for possible downgrade.  Moody’s also affirmed the
      long-term ratings of PSE and changed its rating outlook to stable from
      positive.  On this same date, Moody’s placed PSE’s P-2
      short-term rating for commercial paper under review for possible
      downgrade.




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 did not issue common
stock under the Stock Purchase and Dividend Reinvestment Plan for the three and
nine months ended September 30, 2008, as compared to $3.2 million (140,079
shares) and $9.7 million (395,970 shares) for the three and months ended
September 30, 2007, respectively.  The proceeds from sales of stock
under the Stock Purchase and Dividend Reinvestment Plan are used for general
corporate needs.  Pending the outcome of the merger, Puget Energy
intends to fund the Stock Purchase and Dividend Reimbursement Plan with shares
acquired in the public markets.





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





Regulation
and Rates


On
October 8, 2008, the Washington Commission issued its order in PSE’s
consolidated electric and natural gas general rate case filed in December 2007,
approving a general rate increase for electric customers of $130.2 million or
7.1% annually, and an increase in natural gas rates of $49.2 million or 4.6%
annually.  The rates for electric and natural gas customers were
effective November 1, 2008.  In its order, the Washington Commission
approved a weighted cost of capital of 8.25% and a capital structure that
included 46.0% common equity with a return on equity of 10.15%.  The
Washington Commission will determine by a separate order certain contested
issues related to the PCORC mechanism.


On
September 25, 2008, the Washington Commission approved PSE’s requested revisions
to its purchased gas adjustment (PGA) tariff schedules resulting in an increase
of $108.8 million or 11.1% on an annual basis in gas sales revenues effective
October 1, 2008.  The rate increase was the result of higher costs of
natural gas in the forward market and a reduction of the credit for the
accumulated PGA payable balance.  The PGA rate change will increase
PSE’s revenue but will not impact the Company’s net income as the increased
revenue will be offset by increased purchased gas costs.


On
December 18, 2007, PSE received a data request from the Investigations Division
of the Office of Enforcement at FERC seeking information about certain natural
gas pipeline capacity release transactions PSE entered into in 2006 and
2005.  PSE responded to the data requests on January 23, 2008 and met
with FERC staff on January 31, 2008.  At this meeting, PSE discussed
with FERC staff additional transactions discovered in the course of responding
to the data requests that potentially may be in violation of FERC
regulations.  PSE received additional data requests from FERC on
February 20, 2008.  In October 2008, PSE received preliminary
notification from FERC staff that PSE had violated several FERC regulations and
was subject to potential civil penalties and other remedies.  FERC has
not yet issued a formal investigation report and thus, PSE is not able to
predict the ultimate outcome of this investigation, including the amount of any
penalties, at this time.


In
November 2007, the Western Electricity Coordinating Council (WECC) audited PSE’s
compliance with electric reliability standards adopted by FERC, the North
American Electric Reliability Corporation (NERC) and/or
WECC.  Compliance with these standards includes periodic
self-certifications of compliance, self-reports of violations after discovery of
the violation, spot checks to review self-certifications and external audits
that review compliance with designated standards in detail.  The WECC
audit team identified four potential violations of the standards that PSE had
not previously self-reported.  Several months after the audit, WECC
issued a “Notice of Alleged Violations” to PSE, adding details and proposed
penalties to the proposed findings.  Under the rules for the process,
PSE met with WECC representatives in July 2008 to discuss
settlement.  PSE is hopeful that all issues concerning the four
potential violations will be resolved.  Resolution of reliability
standards issues will be an ongoing concern; however, PSE self-reports
violations when they are discovered.  Such self-reports could result
in settlement of issues or issuances of penalties in the future.  PSE
has established a loss reserve of $0.6 million related to these alleged
violations.


In May
2007, the Washington Commission Staff alleged that PSE’s natural gas system
service provider had violated certain Washington Commission recordkeeping
rules.  On April 3, 2008, the Washington Commission issued an order
approving a settlement agreement that required PSE to pay a regulatory penalty
of $1.25 million, to establish a quality assurance program to better monitor its
subcontractors and to complete an independent audit of natural gas system
recordkeeping procedures.





Accounting
Petition.  On August 29, 2007, the Washington Commission
approved PSE’s accounting petition to defer as a regulatory asset the excess BPA
REP benefit provided to customers and accrue monthly carrying charges on the
deferred balance from June 7, 2007 until the deferral is recovered from
customers or BPA.


In March
2008, BPA and PSE signed an agreement pursuant to which BPA (on April 2, 2008)
paid PSE $53.7 million in REP benefits for fiscal year 2008, which payment is
subject to true-up depending upon the amount of any REP benefits ultimately
determined to be payable to PSE.  This BPA's authority to enter into,
and the validity of, this agreement and similar agreements with other utilities
is being challenged by several BPA customers in the Ninth Circuit Court of
Appeals.


On April
10, 2008, the Washington Commission approved PSE’s tariff filing seeking to
pass-through the net amount of the benefits under the interim agreements to
residential and small farm customers.  The Washington Commission also
approved PSE’s request to credit the regulatory asset amount of $33.7 million
against the $53.7 million payment and pass-through to customers the remaining
amount of approximately $20.0 million.  The accrued carrying charges
on the regulatory asset totaling $3.1 million at September 30, 2008 began
amortization on November 1, 2008 over a two year period as determined in PSE’s
electric general rate case.  On September 25, 2008, BPA and PSE signed
an agreement pursuant to which BPA will make payments to PSE related to the REP
benefit for the fiscal years beginning October 1, 2008 and ending September 30,
2011.  On October 8, 2008, the Washington Commission approved PSE’s
tariff request to resume the REP pass-through credits to residential electric
customers.  The result is a 9.9% reduction to residential electric
customers bill without an impact on earnings.





Colstrip
Matters


In May
2003, approximately 50 plaintiffs initiated an action against the owners of
Colstrip alleging that (1) seepage from two different wastewater pond areas
caused groundwater contamination and threatened to contaminate domestic water
wells and the Colstrip water supply pond, and (2) seepage from the Colstrip
water supply pond caused structural damage to buildings and toxic
mold.  The defendants reached agreement on a global settlement with
all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in the
amount of $10.7 million in July 2008.  PSE had previously expensed the
settlement in the first quarter 2008.  PSE has also filed an
accounting petition with the Washington Commission to recover such costs in the
future.


The
Minerals Management Service of the United States Department of Interior
(MMS) has issued a series of orders to Western Energy Company (WECO) to pay
additional taxes and royalties concerning coal WECO sold to the owners of
Colstrip 3 & 4, and similar orders have been issued in the administrative
appellate process.  The orders assert that additional royalties are
owed in connection with payments received by WECO from Colstrip 3
& 4 owners (including PSE) for the construction and operation of a
conveyor system that runs several miles from the mine to Colstrip 3 &
4.  The state of Montana has also issued a demand to WECO consistent
with the MMS position.  WECO has challenged these orders and the issue
has been on appeal for several years.WECO has won
some points during the appellate process that have reduced the claims; however
under applicable law, to pursue the appeals, the principal in dispute cannot be
paid which causes interest to accrue.  Moreover, because the conveyor
system continues to be used, the amount in
dispute grows.  PSE and the other Colstrip 3 & 4 owners
authorized WECO to make a settlement offer to the Montana Department of Revenue
(DOR) and the MMS in connection with these claims.  Discussions with
the DOR and with the MMS continue.  PSE has recorded a $1.7 million
pre-tax loss reserve in this matter.





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,
2007 includes a summary relating to the western power market
proceedings.  The following discussion provides a summary of material
developments during the third quarter 2008.  PSE is vigorously
defending each of these cases.  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/or
adversely affect PSE’s financial condition, results of operations or
liquidity.


Lockyer Case.In
March and April 2008, FERC issued orders establishing procedures for the Lockyer
remand.  The orders commence a seller-by-seller inquiry into the
transaction reports filed by entities that sold power in California during
2000.  The inquiry is to determine if the transaction reports as filed
masked the gathering of more than 20% of the market during the period, by that
seller.  The California parties sought rehearing on a variety of these
issues.  On October 6, 2008, FERC issued a decision on the rehearing
request that reaffirmed its intent to impose seller-specific remedies rather
than the market-wide remedy sought by the California parties.  The
rehearing decision also reconfirms the Commission’s method for determining
market share, limits the scope of the proceeding and declines to defer the
proceeding pending remand from the Ninth Circuit of the California Refund
Proceeding and the Port of Seattle (Pacific Northwest Refund)
case.  PSE does not believe that it will be found to have possessed
20% of any relevant market during any relevant time.  The proceeding
continues, including a settlement process before an Administrative Law Judge
(ALJ).  Settlement talks among various parties continue but PSE cannot
predict the ultimate outcome of any negotiations or subsequent process before
FERC or the ALJ.




Proceedings
Relating to the Bonneville Power Administration


Petitioners
in several actions in the Ninth Circuit against BPA asserted that BPA acted
contrary to law 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 REP.  Petitioners in
several actions in the Ninth Circuit against BPA also asserted that BPA acted
contrary to law in adopting or implementing the rates upon which the benefits
received or to be received from BPA during the October 1, 2001 through September
30, 2006 period were based.  A number of parties 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.


On May 3,
2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA,
No. 01-70003, in which proceeding the actions of BPA in entering into settlement
agreements regarding the REP with PSE and with other investor-owned utilities
were challenged.  In this opinion, the Ninth Circuit granted petitions
for review and held the settlement agreements entered into between BPA and the
investor-owned utilities being challenged in that proceeding to be inconsistent
with statute.  On May 3, 2007, the Ninth Circuit also issued an
opinion in Golden Northwest
Aluminum v. BPA, No. 03-73426, in which proceeding the petitioners sought
review of BPA’s 2002-2006 power rates.  In this opinion, the Ninth
Circuit granted petitions for review and held that BPA unlawfully shifted onto
its preference customers the costs of its settlements with the investor-owned
utilities.  On October 5, 2007, petitions for rehearing of these two
opinions were denied.  On February 1, 2008, PSE and other utilities
filed in the Supreme Court of the United States a petition for a writ of
certiorari to review the decisions of the Ninth Circuit, which petition was
denied in June 2008.


In May
2007, following the Ninth Circuit’s issuance of these two opinions, BPA
suspended payments to PSE under the amended settlement agreement (and the May
2004 agreement).  On October 11, 2007, the Ninth Circuit remanded the
May 2004 agreement to BPA in light of the Portland Gen. Elec. v. BPA
opinion and dismissed the remaining three pending cases regarding settlement
agreements.


In March
2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to
PSE related to the REP benefits for the fiscal year ended September 30, 2008,
which payment is subject to true-up depending upon the amount of any REP
benefits ultimately determined to be payable to PSE.  In March and
April 2008, Clatskanie People’s Utility District filed petitions in the Ninth
Circuit for review of BPA actions in connection with offering or entering into
such agreement with PSE and similar agreements with other investor-owned
utilities.  Clatskanie People’s Utility District asserts that BPA’s
actions in entering into and executing the 2008 REP agreements were contrary to
law or without authority and that such agreements are null and void and result
in overpayments of REP benefits to PSE and other regional investor-owned
utilities.


In
September 2008, BPA issued its record of decision in its reopened WP-07 rate
proceeding to respond to the various Ninth Circuit opinions.  In the
record of decision, BPA adjusted its fiscal year 2009 rates, determined the
amounts of REP benefits it considered to have been improperly paid after fiscal
year 2001 to PSE and the other regional investor-owned utilities, and determined
that such amounts are to be recovered through reductions in REP benefit payments
to be made over a number of years.  The amount to be recovered (with
interest) through reductions in REP payments for PSE’s residential and small
farm customers is approximately $207.2 million to the extent that PSE receives
any REP benefits for its customers in the future.  However, this BPA
determination is subject to subsequent administrative and judicial review, which
may alter or reverse such determination.  PSE is also reviewing its
options in determining if it will contest the amounts withheld as improper
payments made after 2001.


In
September 2008, BPA and PSE signed a Residential Purchase and Sale Agreement
(RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending
September 30, 2009–2011.  Generally, REP benefit payments under a RPSA
are based on the amount, if any, by which a utility's average system cost (ASC)
exceeds BPA’s Preference Rate (PF) Exchange rate for such
utility.  The ASC for a utility is determined using an ASC methodology
adopted by BPA.  The ASC methodology adopted by BPA and the ASC
determinations, REP overpayment determinations, and the PF Exchange rate
determinations by BPA are all subject to FERC review or judicial review or both
and are subject to adjustment, which may affect the amount of REP benefits paid
or to be paid by BPA to PSE.  As discussed above, BPA has determined
to reduce such payments based on its determination of REP benefit overpayments
after fiscal year 2001.


It is not
clear what impact, if any, such development or review of such BPA rates, review
of such ASC, ASC Methodology, and BPA determination of REP overpayments, review
of such agreements, and the above described Ninth Circuit litigation may
ultimately have on PSE.




Proceeding
Relating to the Proposed Merger


On
February 6, 2008, the Company entered into a memorandum of understanding
providing for the settlement of the consolidated shareholder lawsuit, subject to
customary conditions including completion of appropriate settlement
documentation, confirmatory discovery and court approval.  Pursuant to
the memorandum of understanding, the Company agreed to include certain
additional disclosures in its proxy statement relating to the
merger.  The Company does not admit, however, that its prior
disclosures were in any way materially misleading or inadequate.  In
addition, the Company and the other defendants in the consolidated lawsuit deny
the plaintiffs’ allegations of wrongdoing and violation of law in connection
with the merger.  The settlement, if completed and approved by the
court, will result in dismissal with prejudice and release of all claims of the
plaintiffs and settlement class of the Company’s shareholders that were or could
have been brought on behalf of the plaintiffs and the settlement
class.  In connection with such settlement, the plaintiffs intend to
seek a court-approved award of attorneys’ fees and expenses in an amount up to
$290,000, which the Company has agreed to pay.  As of September 30,
2008, the Company has a loss reserve of $290,000.




Baker
River Project License


On
October 17, 2008, the FERC issued a new license for the Baker River
hydroelectric project for a 50-year term.  The new license
incorporates the measures proposed in the comprehensive Settlement Agreement
that was filed on November 30, 2004 and signed by PSE and 23 parties (federal,
state and local governmental organizations, Native American Indian tribes,
environmental and other non-governmental entities).  The new license
will require an investment of approximately $360.0 million (capital expenditures
and operations and maintenance cost) over 30 years in order to implement the
license conditions.  The license provides protection and enhancements
for fish and wildlife, water quality, recreation and cultural and historic
resources.  Parties may seek rehearing of the order issuing the new
license within 30 days of license issuance.




Proceeding Relating toSnoqualmie Falls Project


The
Snoqualmie Falls project was granted a new 40-year operating license by FERC on
June 29, 2004.  The Snoqualmie Tribe asked for rehearing of the order
and requested a stay of the new license.  On March 1, 2005, FERC
issued an Order on Rehearing and Dismissing Stay Request.  The order
required additional flows at Snoqualmie Falls during certain times of the year,
but otherwise denied the Snoqualmie Tribe’s request.  The Snoqualmie
Tribe sought further review by the U.S. Court of Appeals arguing, among other
issues, that FERC violated the Religious Freedom Restoration Act (RFRA) and that
the license decision substantially burdened the Snoqualmie Tribe’s free exercise
of religion.  PSE also sought review of FERC’s decision to require
additional flows during certain times of the year because the action appeared to
interfere with the Washington State Department of Ecology’s jurisdiction to
determine water quality issues.  On October 7, 2008, the court issued
a decision denying the appeals and determined that FERC did not violate RFRA and
that FERC’s adoption of water flows greater than those prescribed in the water
quality certification did not contradict or weaken the water quality
certification’s minimum flow requirements.  Parties may seek review of
the decision by the United States Supreme Court.  Such review is
discretionary and PSE is unable to determine whether the Supreme Court will
elect to review the matter if further review is sought.  In addition,
on December 6, 2007, PSE filed an application for a non-capacity amendment to
the 2004 license.  The application seeks to amend the license to
account for technology improvements and hydrologic and other changes that
occurred post-license.  The license amendment application remains
pending and its ultimate outcome remains uncertain.




New
Accounting Pronouncements


On
September 15, 2006, Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements”
(SFAS No. 157), which clarifies how companies should use fair value measurements
in accordance with GAAP for recognition and disclosure purposes.  SFAS
No. 157 establishes a common definition of fair value and a framework for
measuring fair value under GAAP, along with expanding disclosures about fair
value to eliminate differences in current practice that exist in measuring fair
value under the existing accounting standards.  The definition of fair
value in SFAS No. 157 retains the notion of exchange price; however, it focuses
on the price that would be received to sell the asset or paid to transfer a
liability (i.e. an exit price), rather than the price that would be paid to
acquire the asset or received to assume the liability (i.e. an entrance
price).  Under SFAS No. 157, a fair value measure should reflect all
of the assumptions that market participants would use in pricing the asset or
liability, including assumptions about the risk inherent in a particular
valuation technique, the effect of a restriction on the sale or use of an asset,
and the risk of nonperformance.  To increase consistency and
comparability in fair value measures, SFAS No. 157 establishes a three-level
fair value hierarchy to prioritize the inputs used in valuation techniques
between observable inputs that reflect quoted market prices in active markets,
inputs other than quoted prices with observable market data, and unobservable
data (e.g. a company’s own data).


SFAS No.
157 is effective for fiscal years beginning after November 15, 2007, which was
January 1, 2008, for the Company.  On February 28, 2008, the FASB
issued a final FASB Staff Position (FSP) that partially deferred the effective
date of SFAS No. 157 for one year for non-financial assets and non-financial
liabilities that are recognized or disclosed at fair value, except for those
that are recognized or disclosed at fair value on an annual or more frequent
basis.  The Company adopted SFAS No. 157 on January 1, 2008,
prospectively, as required by the Statement, with certain
exceptions,  including the initial impact of changes in fair value
measurements of existing derivative financial instruments measured initially
using the transaction price under Emerging Issues Task Force (EITF) No.
02-3.  On January 1, 2008, the difference between the carrying amounts
and the fair values of those instruments originally recorded under guidance in
EITF No. 02-3 was recognized as a cumulative-effect adjustment to the opening
balance of retained earnings.  SFAS No. 157 nullified a portion of
EITF No. 02-3.  Under EITF No. 02-3, the transaction price presumption
prohibited recognition of a trading profit at inception of a derivative unless
the positive fair value of that derivative was substantially based on quoted
prices or a valuation process incorporating observable inputs.  For
transactions that did not meet this criterion at inception, trading profits that
had been deferred were recognized in the period that inputs to value the
derivative became observable or when the contract performed.


As a
result of the recent credit crisis, on October 10, 2008, the FASB issued FSP FAS
No. 157-3, “Determining the Fair Value of a Financial Asset in a Market That is
Not Active.”  This FSP clarifies the application of SFAS No. 157 in a
market that is not active.  The FSP addresses how management should
consider measuring fair value when relevant observable data does not
exist.  The FSP also provides guidance on how observable market
information in a market that is not active should be considered when measuring
fair value, as well as how the use of market quotes should be considered when
assessing the relevance of observable and unobservable data available to measure
fair value. This FSP was effective upon issuance, including prior periods for
which financial statement have not been issued.  Revisions resulting
from a change in the valuation technique or its application shall be accounting
for as a change in accounting estimate (FASB Statement No. 154, “Accounting
Changes and Error Corrections,” (SFAS No. 154) paragraph 19).  The
disclosure provisions on SFAS No. 154 for a change in accounting estimate are
not required for revisions resulting from a change in valuation technique or its
application.  The Company has reviewed the statement and has assessed
there will be no significant impact to the financial statements.


In
December 2007, the FASB issued SFAS No. 141(R), “Business Combinations”
(SFAS No. 141(R)).  This Statement replaces FASB Statement No. 141,
“Business Combinations” and addresses the accounting for all transactions or
other events in which an entity obtains control of one or more
businesses.  The objective of this Statement is to improve the
relevance, representational faithfulness and comparability of the information
that a reporting entity provides in its financial reports about a business
combination and its effects. To accomplish that, this Statement establishes
principles and requirements for how the acquirer: 1) Recognizes and measures in
its financial statements the identifiable assets acquired, the liabilities
assumed and any noncontrolling interest in the acquiree; 2) Recognizes and
measures the goodwill acquired in the business combination or a gain from a
bargain purchase; and 3) Determines what information to disclose to enable users
of the financial statements to evaluate the nature and financial effects of the
business combination.  This Statement shall be applied prospectively
to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008.  The Company is currently assessing the impact of SFAS No.
141(R).


On March
19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No.
161).  SFAS No. 161 is effective for the fiscal years and interim
years beginning after November 15, 2008, which will be the quarter ending March
31, 2009 for the Company.  SFAS No. 161 requires companies with
derivative instruments to disclose information that should enable financial
statement users to understand how and why a company uses derivative instruments,
how derivative instruments and related hedged items are accounted for under SFAS
No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS
No. 133) and how derivative instruments and related hedged items affect a
company’s financial position, financial performance and cash
flows.  SFAS No. 161 requirements will impact the following derivative
and hedging disclosures: objectives and strategies, balance sheet, financial
performance, contingent features and counterparty credit risk.  The
Company is currently assessing the impact of SFAS No. 161.


In May
2008, FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting
Principles” (SFAS No. 162), which identifies the sources of accounting
principles and the framework for selecting the principles to be used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting
principles.  The FASB Board is responsible for identifying the sources
of accounting principles and providing entities with a framework for selecting
the principles used in the preparation of financial statements.  The
Company has reviewed the statement and has assessed there will be no significant
impact to the financial statements.


On June
16, 2008, FSP EITF No. 03-6-1, “Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities,” (EITF No.
03-6-1) was issued.  This FSP addresses whether instruments granted in
share-based payment transactions are participating securities prior to vesting
and, therefore, need to be included in the earnings allocation in computing
earnings per share under the two-class method.  Unvested share-based
payment awards that contain nonforfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are participating securities and shall be
included in the computation of earnings per share pursuant to the two-class
method.  This FSP will be effective for financial statements issued
for fiscal years beginning after December 15, 2008, which will be the year ended
December 31, 2009 for the Company.  The Company is currently assessing
the financial statement presentation impact of FSP EITF No. 03-6-1.




Item
      3.             
      Quantitative
      and Qualitative Disclosure About Market
  Risk




Energy
Portfolio Management


The
Company has energy risk policies and procedures to manage commodity and
volatility risks.  The Company’s Energy Management Committee
establishes the Company’s energy risk management policies and procedures and
monitors compliance.  The Energy Management Committee is comprised of
certain Company officers and is overseen by the Audit Committee of the Company’s
Board of Directors.


The
Company is focused on commodity price exposure and risks associated with
volumetric variability in the natural gas and electric portfolios.  It
is not engaged in the business of assuming risk for the purpose of speculative
trading.  The Company hedges open natural gas and electric positions
to reduce both the portfolio risk and the volatility risk in
prices.  The exposure position is determined by using a probabilistic
risk system that models 100 scenarios of how the Company’s natural gas and power
portfolios will perform under various weather, hydro and unit performance
conditions.  The objectives of the hedging strategy are
to:





·
            Ensure
      physical energy supplies are available to reliably and cost-effectively
      serve retail load;·
            Manage
      energy portfolio risks prudently to serve retail load at overall least
      cost and limit undesired impacts on the Company’s customers and
      shareholders; and·
            Reduce
      power costs by extracting the value of the Company’s
    assets.





The
Company enters into derivative contracts to reduce commodity price risk and
volumetric variability.  As a result, the Company’s financial
statements will be subject to volatility due to changes in forward market prices
of natural gas and electricity.  The Company’s intent when entering
into these contracts is to hold the contracts until settlement to serve
customers; thus the Company will be exposed to unrealized gains and
losses associated with derivative contracts in its financial
statements.  When forward market prices are higher than the Company’s
contract price of derivative contracts, an unrealized gain is
recorded.  When forward market prices are lower than the Company’s
contract price of derivative contracts, an unrealized loss is
recorded.


The
following table presents electric derivatives that are designated as cash flow
hedges or contracts that do not meet Normal Purchase Normal Sale (NPNS) at
September 30, 2008 and December 31, 2007:


Electric
              Derivatives(Dollars
      in Millions)
            
            September
      30,
              2008
            
            
            December
      31,
              2007Short-term
      asset
            
            $
            2.9
            
            
            $
            11.1Long-term
      asset
            
            
            2.6
            
            
            
            6.6Total
      assets
            
            $
            5.5
            
            
            $
            17.7Short-term
      liability
            
            $
            34.6
            
            
            $
            9.8Long-term
      liability
            
            
            26.9
            
            
            
            --Total
      liabilities
            
            $
            61.5
            
            
            $
            9.8





If it is
determined that it is uneconomical to operate the Company’s controlled electric
generating facilities in the future period, the fuel supply cash flow hedge
relationship is terminated and the hedge is de-designated which results in the
unrealized gains and losses associated with the contracts being recorded in the
income statement.  As these contracts are settled, the costs are
recognized as energy costs and are included as part of the Power Cost Adjustment
(PCA) mechanism.


At
December 31, 2007, the Company had an unrealized day one loss deferral of $9.0
million related to a three-year locational power exchange contract which was
modeled and therefore the day one loss was deferred under EITF No.
02-3.  The contract has economic benefit to the Company over its
terms.  The locational exchange will help ease electric transmission
congestion across the Cascade Mountains during the winter months as the Company
will take delivery of energy at a location that interconnects with the Company’s
transmission system in western Washington.  At the same time, the
Company will make available the quantities of power at the Mid-Columbia trading
hub location.  The day one loss deferral was transferred to retained
earnings on January 1, 2008 as required by SFAS No. 157 and any future day one
loss on contracts will be recorded in the income statement beginning January 1,
2008 in accordance with the statement.


The
following tables present the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria, and ineffectiveness
related to highly effective cash flow hedges, to the Company’s earnings during
the three and nine months ended September 30, 2008 and September 30,
2007:





(Dollars in
      Millions)
              Three
      Months Ended September 30,
            2008
            2007
            ChangeDecrease
      in earnings
            $
      (3.5)
            $
      (5.3)
            $  1.8








(Dollars in
      Millions)
              Nine
      Months Ended September 30,
            2008
            2007
            ChangeDecrease
      in earnings
            $
      (1.2)
            $  (1.0)
            $
      (0.2)





The
amount of net unrealized gain (loss), net of tax, related to the Company’s cash
flow hedges under SFAS No. 133 consisted of the following at September 30, 2008
and December 31, 2007:





(Dollars
      in Millions, net of tax)
            September
      30,
              2008
            December
      31,
              2007Other
      comprehensive income – unrealized gain (loss)
            $
      (31.5)
            $  3.4





The
following table presents derivative hedges of natural gas contracts to serve
natural gas customers at September 30, 2008 and December 31, 2007:


Gas
              Derivatives(Dollars
      in Millions)
            
            September
      30,
              2008
            
            
            December
      31,
              2007Short-term
      asset
            
            $
            12.9
            
            
            $
            6.0Long-term
      asset
            
            
            3.8
            
            
            
            5.3Total
      assets
            
            $
            16.7
            
            
            $
            11.3Short-term
      liability
            
            $
            112.1
            
            
            $
            17.3Long-term
      liability
            
            
            37.3
            
            
            
            --Total
      liabilities
            
            $
            149.4
            
            
            $
            17.3





At
September 30, 2008, the Company had total assets of $16.7 million and total
liabilities of $149.4 million related to hedges of natural 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, “Accounting for the Effects of Certain Types of
Regulation” (SFAS No. 71) due to the PGA mechanism.  All increases and
decreases in the cost of natural gas supply are passed on to customers with the
PGA mechanism.  As the gains and losses on the hedges are realized in
future periods, they will be recorded as natural gas costs under the PGA
mechanism.


A
hypothetical 10.0% decrease in the market prices of natural gas and electricity
would decrease the fair value of qualifying cash flow hedges by $40.7 million
after-tax, with a corresponding after-tax impact in comprehensive income and
earnings (due to ineffectiveness) of $39.6 million and $1.1 million,
respectively.




Credit
Risk


The
Company is exposed to credit risk primarily through buying and selling
electricity and natural gas to serve 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.  The Company may require
collateral, a letter of credit or a parental guarantee in order to minimize the
Company’s exposure related to counterparty default.  The Company
monitors counterparties that are experiencing financial problems, have
significant swings in credit default swap rates, have credit rating changes by
external rating agencies, or have changes in ownership.  The Company
monitors its trading limit exposures and may assign an internal credit rating
lower than what is issued by external rating agencies.


The
Company has entered into commodity master arrangements with its counterparties
to mitigate credit exposure to those counterparties.  The Company
generally enters into the following master arrangements:  1) Western
Systems Power Pool Agreements (WSPP) - standardized power sales contract in the
electric industry; 2) International Swaps and Derivatives Association Agreements
(ISDA) - standardized financial gas and electric contracts; and 3) North
American Energy Standards Board Agreements (NAESB) - standardized physical gas
contracts.


It is
possible that extreme volatility in energy commodity prices could cause the
Company to have 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, 2008, approximately
99.96% of the counterparties with transaction amounts outstanding in the
Company’s energy portfolio are rated at least investment grade by the major
rating agencies.  The Company assesses credit risk internally for
counterparties that are not rated and also takes credit default swaps into
consideration in valuing counterparty credit reserves.


Counterparty
credit impacts the Company’s decisions on derivative accounting
treatment.  A counterparty may have a deterioration of credit below
investment grade, potentially indicating that it is no longer probable that it
will fulfill its obligations under a contract (e.g., make a physical delivery
upon the contract’s maturity).  SFAS No. 133 specifies the
requirements for derivative contracts to qualify for the NPNS scope exception.
When performance is no longer probable, based on the deterioration of a
counterparty’s credit, the Company records the fair value of the contract on the
balance sheet, with the corresponding debit or credit recorded in the income
statement.


Cash flow
hedge derivative treatment is also impacted by a counterparty’s deterioration of
credit under SFAS No. 133 guidelines. If a forecasted transaction associated
with a cash flow hedge is no longer probable of occurring, based on
deterioration of credit, the Company would discontinue hedge accounting, record
in earnings subsequent changes in the derivative’s fair value and freeze amounts
previously accounted for in Accumulated Other Comprehensive
Income.  If the transaction is remote of occurring, any amounts
previously accounted for in Accumulated Other Comprehensive Income would be
reclassified into earnings.


Should
a counterparty file for bankruptcy, which could be considered a default under
master arrangements, the Company may terminate related
contracts.  Derivative accounting entries previously recorded would be
reversed in financial statements.  The Company would compute any
termination receivable or payables, based on the terms of existing master
arrangements.


In
conjunction with SFAS No. 157 requirements, the Company calculates credit
reserves in order to reflect credit risk in the financial statements. The
Company’s assessment of a counterparty’s credit exposure impacts the
calculations of credit reserves. The Company considers counterparty internal and
external credit ratings, as well as annual study default factors published by
Standard and Poor’s (S&P).  Furthermore, the Company computes
credits reserves at a master agreement level (i.e. WSPP, ISDA, or NAESB) by
counterparty, utilizing default factors applicable to the lower rating of either
the S&P or the Company’s assigned internal credit rating.  The
default factor used is dependent upon whether the counterparty is in a net asset
or a net liability position after applying the master agreement
levels.  The Company applies the counterparty’s default factor to
compute credit reserves for counterparties that are in a net asset
position.  Moreover, the Company applies its own default factor based
on the S&P credit rating to compute credit reserves for counterparties in a
net liability position. The Company’s S&P rating at September 30, 2008 was
BBB-.  The Company applies the default factor for each counterparty at
an aggregate master agreement level based on the default factor calculated for
the contract with the longest tenor. Credit reserves are booked as contra
accounts to unrealized gain/(loss) positions. As of September 30, 2008, the
Company was in a net liability position with the majority of counterparties, so
the default factors of counterparties did not have a significant impact on
reserves for this quarter.





Interest
Rate Risk


The
Company believes its interest rate risk primarily relates to the use of
short-term debt instruments, leases and anticipated 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 commercial paper, borrowing from its
line of credit facilities and accounts receivable securitization facility 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.


The
ending balance in other comprehensive income related to the forward starting
swaps and previously settled treasury lock contracts at September 30, 2008 was a
net loss of $8.0 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 Executive Vice
President 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, 2008,
the end of the period covered by this report.  Based upon that
evaluation, the Chairman, President and Chief Executive Officer and the
Executive Vice President 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, 2008 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 Executive Vice President
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, 2008, the end of the period
covered by this report.  Based upon that evaluation, the Chairman,
President and Chief Executive Officer and the Executive Vice President 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, 2008, 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 Report on Form 10-Q.  Contingencies arising out of
the normal course of the Company’s business exist at September 30,
2008.  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,
2007.




Item
5.              Other
Information




On
August 29, 2008, PSE, as borrower, entered into a Credit Agreement with The
Bank of Nova Scotia, as Administrative Agent, Wells Fargo Bank, N.A., as
Documentation Agent, JPMorgan Chase Bank, N.A. and Barclays Bank PLC as
Co-Agents and the lenders party thereto (the Credit Agreement).
 The
Credit Agreement provides for a $375.0 million unsecured term loan facility (the
Credit Facility), to be funded in up to three advances at the request of PSE
until May 29, 2009, when the commitment of the lenders to make advances
under the Credit Facility terminates.  The Credit Facility is not a
revolving credit facility.  The Credit Facility matures on the earlier
of May 29, 2009 or the date of the merger of Puget Merger Sub Inc. into
Puget Energy, Inc., at which time all outstanding borrowings must be
repaid.
 The Credit
Agreement also contains customary events of default.  The occurrence
of an event of default could result in an increase the applicable rate of
interest and could result in the acceleration of PSE’s obligations under the
Credit Facility.


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. EldredgeJames
      W. EldredgeVice
      President, Controller and Chief Accounting OfficerDate:  November
      5, 2008Chief
      accounting officer and officer duly authorized to sign this report on
      behalf of each registrant





EXHIBIT
INDEX





The following exhibits are filed
herewith:





10.1
            Credit
      Agreement dated as of August 29, 2008 among Puget Sound Energy, Inc., the
      various financial institutions named therein and The Bank of Nova Scotia,
      Administrative Agent.12.1
            Statement
      setting forth computation of ratios of earnings to fixed charges (2003
      through 2007 and 12 months ended September 30, 2008) for Puget
      Energy.12.2
            Statement
      setting forth computation of ratios of earnings to fixed charges (2003
      through 2007 and 12 months ended September 30, 2008) 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.