UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549


FORM
10-Q








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








For
      the quarterly period ended March 31,
      2009
                
                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











1-4393
            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 registrant: (1) has 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 registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.




Yes
              /X/
              No
              /  /





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate website, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files).




Yes
              /   /
              No
              /  /





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting
company.  See the definitions of “large accelerated filer, accelerated
filer and smaller reporting company” in Rule 12b-2 of the Exchange
Act.




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)





Yes
              /  /
              No
              /X/





All of
the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by
its parent company, Puget Energy, Inc.





Table of
Contents


DefinitionsForward Looking StatementsPart I.
                              Financial InformationItem 1.
                              Financial StatementsPuget
      Sound Energy, Inc.Consolidated Statements of Income – Three Months Ended
      March 31, 2009 and 2008Consolidated Statements of Comprehensive Income – Three
      Months Ended
                                March 31, 2009 and 2008Consolidated Balance Sheets – March 31, 2009 and
      December 31, 2008Consolidated Statement of Common Shareholder’s
      Equity – March 31, 2009
                                and December 31, 2008Consolidated Statements of Cash Flows – Three Months
      Ended March 31, 2009 and 2008NotesNotes 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 6.
                              ExhibitsSignaturesExhibit Index







DEFINITIONS




AFUDC
                Allowance
      for Funds Used During ConstructionASC
                Average
      System CostBPA
                Bonneville
      Power AdministrationFASB
                Financial
      Accounting Standards BoardFERC
                Federal
      Energy Regulatory CommissionFIN
                Financial
      Accounting Standards Board InterpretationFSP
                FASB
      Staff PositionGAAP
                Generally
      Accepted Accounting PrinciplesISDA
                International
      Swaps and Derivatives AssociationkW
                KilowattkWh
                Kilowatt
      HourLIBOR
                London
      Interbank Offered RateMMBtus
                One
      Million British Thermal UnitsMW
                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
      Priority Firm Exchange RatePGA
                Purchased
      Gas AdjustmentPSE
                Puget
      Sound Energy, Inc.Puget
      Energy
                Puget
      Energy, Inc.Puget
      Holdings
                Puget
      Holdings LLCPURPA
                Public
      Utility Regulatory Policy ActREP
                Residential
      Exchange ProgramRPSA
                Residential
      Purchase and Sale AgreementSFAS
                Statement
      of Financial Accounting StandardsVIE
                Variable
      Interest EntityWashington
      Commission
                Washington
      Utilities and Transportation CommissionWSPP
                Western
      Systems Power Pool










FORWARD-LOOKING STATEMENTS


Puget
Sound Energy, Inc. (PSE) is 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 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.  PSE’s
expectations, beliefs and projections are expressed in good faith and are
believed by 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 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 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, financing, 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, maintenance, construction
      and operation of natural gas and electric 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;·
                  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 its
      suppliers;·
                  The
      effect of wholesale market structures (including, but not limited to,
      regional market designs or transmission organizations) or other related
      federal initiatives;·
                  PSE
      electric or 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;·
                  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;·
                The
      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;·
                Changes
      in PSE’s credit ratings, which may have an adverse impact on the
      availability and cost of capital for
PSE;  and·
                Deteriorating
      values of the equity, fixed income and other markets which could
      significantly impact the value of investments of PSE’s retirement plan and
      post-retirement medical trusts and the funding of obligations
      thereunder.




Any
forward-looking statement speaks only as of the date on which such statement is
made, and, except as required by law, PSE undertakes 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 SOUND ENERGY, INC.


CONSOLIDATED
STATEMENTS OF INCOME


(Dollars
in thousands)


(Unaudited)





Three
      Months Ended
                          March
      31,2009
                        
                        
                        2008Operating
      revenues:Electric
                        
                        $
                        600,230
                        
                        
                        $
                        606,134Gas
                        
                        
                        506,436
                        
                        
                        
                        443,236Other
                        
                        
                        889
                        
                        
                        
                        1,562Total
      operating revenues
                        
                        
                        1,107,555
                        
                        
                        
                        1,050,932Operating
      expenses:Energy
      costs:Purchased
      electricity
                        
                        
                        260,249
                        
                        
                        
                        272,832Electric
      generation fuel
                        
                        
                        48,127
                        
                        
                        
                        47,014Residential
      exchange
                        
                        
                        (32,404
                        )
                        
                        
                        (7
                        )Purchased
      gas
                        
                        
                        320,063
                        
                        
                        
                        276,195Net
      unrealized gain on derivative instruments
                        
                        
                        2,330
                        
                        
                        
                        88Utility
      operations and maintenance
                        
                        
                        114,893
                        
                        
                        
                        112,163Non-utility
      expense and other
                        
                        
                        1,307
                        
                        
                        
                        55Merger
      and related costs
                        
                        
                        27,563
                        
                        
                        
                        --Depreciation
      and amortization
                        
                        
                        81,361
                        
                        
                        
                        75,367Conservation
      amortization
                        
                        
                        20,829
                        
                        
                        
                        13,366Taxes
      other than income taxes
                        
                        
                        101,343
                        
                        
                        
                        94,273Total
      operating expenses
                        
                        
                        945,661
                        
                        
                        
                        891,346Operating
      income
                        
                        
                        161,894
                        
                        
                        
                        159,586Other
      income (deductions):Other
      income
                        
                        
                        9,932
                        
                        
                        
                        6,814Other
      expense
                        
                        
                        (2,443
                        )
                        
                        
                        (975
                        )Interest
      charges:AFUDC
                        
                        
                        1,681
                        
                        
                        
                        2,429Interest
      expense
                        
                        
                        (52,576
                        )
                        
                        
                        (51,048
                        )Interest
      expense on Puget Energy note
                        
                        
                        (73
                        )
                        
                        
                        (237
                        )Income before
      income taxes
                        
                        
                        118,415
                        
                        
                        
                        116,569Income
      tax expense
                        
                        
                        33,438
                        
                        
                        
                        35,665Net
      income
                        
                        $
                        84,977
                        
                        
                        $
                        80,904





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







PUGET SOUND ENERGY, INC.


CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME


(Dollars
in thousands)


(Unaudited)


Three
      Months Ended
                    March
      31,2009
                  
                  
                  2008Net
      income
                  
                  $
                  84,977
                  
                  
                  $
                  80,904Other
      comprehensive income:Unrealized
      gain from pension and postretirement plans, net of tax of $509 and $95,
      respectively
                  
                  
                  945
                  
                  
                  
                  176Net
      unrealized gain (loss) on energy derivative instruments during the period,
      net of tax of $(36,911) and $25,457, respectively
                  
                  
                  (68,549
                  )
                  
                  
                  47,277Reclassification
      of net unrealized gain on energy derivative instruments settled during the
      period, net of tax of $7,521 and $957, respectively
                  
                  
                  13,967
                  
                  
                  
                  1,778Amortization
      of financing cash flow hedge contracts to earnings, net of tax of $43 and
      $43, respectively
                  
                  
                  80
                  
                  
                  
                  80Other
      comprehensive income (loss)
                  
                  
                  (53,557
                  )
                  
                  
                  49,311Comprehensive
      income
                  
                  $
                  31,420
                  
                  
                  $
                  130,215





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







PUGET SOUND ENERGY, INC.


CONSOLIDATED
BALANCE SHEETS


(Dollars
in thousands)





ASSETS





March
      31,
                          2009
                          (Unaudited)
                        
                        
                        December
      31,
                          2008Utility
      plant: (at original cost, including construction work in progress of
      $282,785 and $255,214, respectively)Electric
      plant
                        
                        $
                        6,702,507
                        
                        
                        $
                        6,596,359Gas
      plant
                        
                        
                        2,546,179
                        
                        
                        
                        2,500,236Common
      plant
                        
                        
                        572,155
                        
                        
                        
                        550,368Less:  Accumulated
      depreciation and amortization
                        
                        
                        (3,445,778
                        )
                        
                        
                        (3,358,816
                        )Net
      utility plant
                        
                        
                        6,375,063
                        
                        
                        
                        6,288,147Other
      property and investments:Investment
      in Bonneville Exchange Power contract
                        
                        
                        29,095
                        
                        
                        
                        29,976Other
      property and investments
                        
                        
                        117,946
                        
                        
                        
                        118,039Total
      other property and investments
                        
                        
                        147,041
                        
                        
                        
                        148,015Current
      assets:Cash
                        
                        
                        101,028
                        
                        
                        
                        38,470Restricted
      cash
                        
                        
                        15,988
                        
                        
                        
                        18,889Accounts
      receivable, net of allowance for doubtful accounts
                        
                        
                        395,871
                        
                        
                        
                        207,776Secured
      pledged accounts receivable
                        
                        
                        --
                        
                        
                        
                        158,000Unbilled
      revenues
                        
                        
                        171,604
                        
                        
                        
                        248,649Materials
      and supplies, at average cost
                        
                        
                        66,718
                        
                        
                        
                        62,024Fuel
      and gas inventory, at average cost
                        
                        
                        73,266
                        
                        
                        
                        120,205Unrealized
      gain on derivative instruments
                        
                        
                        22,186
                        
                        
                        
                        15,618Prepaid
      income taxes
                        
                        
                        10,272
                        
                        
                        
                        17,317Prepaid
      expenses and other
                        
                        
                        24,285
                        
                        
                        
                        14,420Deferred
      income taxes
                        
                        
                        34,508
                        
                        
                        
                        9,439Total
      current assets
                        
                        
                        915,726
                        
                        
                        
                        910,807Other
      long-term and regulatory assets:Regulatory
      asset for deferred income taxes
                        
                        
                        92,202
                        
                        
                        
                        95,417Regulatory
      asset for PURPA buyout costs
                        
                        
                        102,669
                        
                        
                        
                        110,838Power
      cost adjustment mechanism
                        
                        
                        3,147
                        
                        
                        
                        3,126Other
      regulatory assets
                        
                        
                        765,715
                        
                        
                        
                        766,732Unrealized
      gain on derivative instruments
                        
                        
                        10,203
                        
                        
                        
                        6,712Other
                        
                        
                        73,071
                        
                        
                        
                        40,365Total
      other long-term and regulatory assets
                        
                        
                        1,047,007
                        
                        
                        
                        1,023,190Total
      assets
                        
                        $
                        8,484,837
                        
                        
                        $
                        8,370,159





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







PUGET
SOUND ENERGY, INC.


CONSOLIDATED
BALANCE SHEETS


(Dollars
in thousands)





CAPITALIZATION
AND LIABILITIES





March
      31,
                                2009
                                (Unaudited)
                              
                              
                              December
      31,
                                2008Capitalization:Common
      shareholder’s investment:Common
      stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791
      shares outstanding
                              
                              $
                              --
                              
                              
                              $
                              859,038Common
      stock ($0.01 par value) - 150,000,000 shares authorized, 85,903,791
      shares outstanding
                              
                              
                              859
                              
                              
                              
                              --Additional
      paid-in capital
                              
                              
                              2,962,864
                              
                              
                              
                              1,296,005Earnings
      reinvested in the business
                              
                              
                              351,501
                              
                              
                              
                              356,947Accumulated
      other comprehensive loss, net of tax
                              
                              
                              (316,361
                              )
                              
                              
                              (262,804
                              )Total
      shareholder’s equity
                              
                              
                              2,998,863
                              
                              
                              
                              2,249,186Redeemable
      securities and long-term debt:Preferred
      stock subject to mandatory redemption
                              
                              
                              --
                              
                              
                              
                              1,889Junior
      subordinated notes
                              
                              
                              250,000
                              
                              
                              
                              250,000Long-term
      debt
                              
                              
                              2,295,860
                              
                              
                              
                              2,270,860Total
      redeemable securities and long-term debt
                              
                              
                              2,545,860
                              
                              
                              
                              2,522,749Total
      capitalization
                              
                              
                              5,544,723
                              
                              
                              
                              4,771,935Current
      liabilities:Accounts
      payable
                              
                              
                              225,142
                              
                              
                              
                              341,255Short-term
      debt
                              
                              
                              175,000
                              
                              
                              
                              964,700Short-term
      note owed to parent
                              
                              
                              19,443
                              
                              
                              
                              26,053Current
      maturities of long-term debt
                              
                              
                              233,000
                              
                              
                              
                              158,000Accrued
      expenses:Purchased
      gas liability
                              
                              
                              29,725
                              
                              
                              
                              8,892Taxes
                              
                              
                              96,172
                              
                              
                              
                              85,068Salaries
      and wages
                              
                              
                              19,374
                              
                              
                              
                              35,280Interest
                              
                              
                              46,084
                              
                              
                              
                              36,112Unrealized
      loss on derivative instruments
                              
                              
                              324,331
                              
                              
                              
                              236,866Other
                              
                              
                              141,999
                              
                              
                              
                              117,223Total
      current liabilities
                              
                              
                              1,310,270
                              
                              
                              
                              2,009,449Long-term
      liabilities and regulatory liabilities:Deferred
      income taxes
                              
                              
                              769,863
                              
                              
                              
                              750,440Unrealized
      loss on derivative instruments
                              
                              
                              176,665
                              
                              
                              
                              158,423Regulatory
      liabilities
                              
                              
                              222,181
                              
                              
                              
                              219,221Other
      deferred credits
                              
                              
                              461,135
                              
                              
                              
                              460,691Total
      long-term liabilities and regulatory liabilities
                              
                              
                              1,629,844
                              
                              
                              
                              1,588,775Total
      capitalization and liabilities
                              
                              $
                              8,484,837
                              
                              
                              $
                              8,370,159





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







PUGET SOUND ENERGY, INC.


CONSOLIDATED
STATEMENTS OF COMMON SHAREHOLDER’S EQUITY


(Dollars
in thousands)


(Unaudited)








Common
      Stock
              
              
              Additional
              
              
              
              
              
              Accumulated
                OtherFor
      Quarter Ended
                March
      31, 2009
              
              Shares
              
              
              Amount
              
              
              Paid-in
                Capital
              
              
              Retained
                Earnings
              
              
              Comprehensive
                Loss
              
              
              Total
      AmountBalance
      at December 31, 2008
              
              
              85,903,791
              
              
              $
              859,038
              
              
              $
              1,296,005
              
              
              $
              356,947
              
              
              $
              (262,804
              )
              
              $
              2,249,186Net
      income
              
              
              --
              
              
              
              --
              
              
              
              --
              
              
              
              84,977
              
              
              
              --
              
              
              
              84,977Common
      stock dividend declared
              
              
              --
              
              
              
              --
              
              
              
              --
              
              
              
              (90,423
              )
              
              
              --
              
              
              
              (90,420
              )Change
      in par value
              
              
              --
              
              
              
              (858,179
              )
              
              
              858,179
              
              
              
              --
              
              
              
              --
              
              
              
              --Investment
      from Puget Energy
              
              
              --
              
              
              
              --
              
              
              
              808,680
              
              
              
              --
              
              
              
              --
              
              
              
              808,677Other
      comprehensive loss
              
              
              --
              
              
              
              --
              
              
              
              --
              
              
              
              --
              
              
              
              (53,557
              )
              
              
              (53,557
              )Balance
      at March 31, 2009
              
              
              85,903,791
              
              
              $
              859
              
              
              $
              2,962,864
              
              
              $
              351,501
              
              
              $
              (316,361
              )
              
              $
              2,998,863





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







PUGET SOUND ENERGY, INC.


CONSOLIDATED
STATEMENTS OF CASH FLOWS


(Dollars
in thousands)


(Unaudited)


Three
      Months Ended
                      March
      31,2009
                    
                    
                    2008Operating
      activities:Net
      income
                    
                    $
                    84,977
                    
                    
                    $
                    80,904Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depreciation
      and amortization
                    
                    
                    81,361
                    
                    
                    
                    75,367Conservation
      amortization
                    
                    
                    20,829
                    
                    
                    
                    13,366Deferred
      income taxes and tax credits, net
                    
                    
                    26,408
                    
                    
                    
                    22,327Amortization
      of gas pipeline capacity assignment
                    
                    
                    (2,308
                    )
                    
                    
                    (2,614
                    )Non
      cash return on regulatory assets
                    
                    
                    (2,397
                    )
                    
                    
                    (3,363
                    )Net
      unrealized loss on derivative instruments
                    
                    
                    2,330
                    
                    
                    
                    88Mint
      Farm deferred costs
                    
                    
                    (5,449
                    )
                    
                    
                    --Non
      cash Colstrip settlement
                    
                    
                    --
                    
                    
                    
                    10,487Change
      in residential exchange program
                    
                    
                    6,330
                    
                    
                    
                    (921
                    )Other
                    
                    
                    (16,630
                    )
                    
                    
                    (251
                    )Counterparty
      collateral deposit
                    
                    
                    (5,268
                    )
                    
                    
                    --Change
      in certain current assets and liabilities:Accounts
      receivable and unbilled revenue
                    
                    
                    46,949
                    
                    
                    
                    25,456Materials
      and supplies
                    
                    
                    (4,693
                    )
                    
                    
                    930Fuel
      and gas inventory
                    
                    
                    46,938
                    
                    
                    
                    59,482Prepaid
      income taxes
                    
                    
                    7,046
                    
                    
                    
                    41,271Prepayments
      and other
                    
                    
                    (9,865
                    )
                    
                    
                    3,146Purchased
      gas receivable/payable
                    
                    
                    20,833
                    
                    
                    
                    (9,436
                    )Accounts
      payable
                    
                    
                    (101,670
                    )
                    
                    
                    (17,884
                    )Taxes
      payable
                    
                    
                    11,530
                    
                    
                    
                    22,900Accrued
      expenses and other
                    
                    
                    6,654
                    
                    
                    
                    11,397Net
      cash provided by operating activities
                    
                    
                    213,905
                    
                    
                    
                    332,652Investing
      activities:Construction
      expenditures - excluding equity AFUDC
                    
                    
                    (179,308
                    )
                    
                    
                    (126,646
                    )Energy
      efficiency expenditures
                    
                    
                    (16,570
                    )
                    
                    
                    (14,010
                    )Restricted
      cash
                    
                    
                    2,901
                    
                    
                    
                    (1
                    )Other
                    
                    
                    4,960
                    
                    
                    
                    1,884Net
      cash used by investing activities
                    
                    
                    (188,017
                    )
                    
                    
                    (138,773
                    )Financing
      activities:Change
      in short-term debt, net
                    
                    
                    (10,376
                    )
                    
                    
                    (158,882
                    )Dividends
      paid
                    
                    
                    (67,871
                    )
                    
                    
                    (48,581
                    )Loan
      from (payment to) parent
                    
                    
                    (6,610
                    )
                    
                    
                    14,234Long
      term bond issued
                    
                    
                    250,000
                    
                    
                    
                    --Redemption
      of trust preferred stock
                    
                    
                    (1,889
                    )
                    
                    
                    --Redemption
      of bonds and notes
                    
                    
                    (150,000
                    )
                    
                    
                    --Investment
      from parent
                    
                    
                    29,616
                    
                    
                    
                    --Issuance
      cost of bonds and other
                    
                    
                    (6,199
                    )
                    
                    
                    3,979Net
      cash provided (used) by financing activities
                    
                    
                    36,671
                    
                    
                    
                    (189,250
                    )Net
      increase in cash
                    
                    
                    62,559
                    
                    
                    
                    4,629Cash
      at beginning of year
                    
                    
                    38,470
                    
                    
                    
                    40,773Cash
      at end of period
                    
                    $
                    101,029
                    
                    
                    $
                    45,402Supplemental
      cash flow information:Cash
      payments for interest (net of capitalized interest)
                    
                    $
                    39,709
                    
                    
                    $
                    38,642Cash
      refunds from income taxes
                    
                    
                    (271
                    )
                    
                    
                    (39,730
                    )





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







NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)
              Summary
      of Consolidation Policy


Basis
of Presentation


Puget
Sound Energy, Inc. (PSE) is a subsidiary of Puget Energy, Inc. (Puget Energy),
an energy services holding company incorporated in the state of Washington in
1999.  On February 6, 2009, Puget Holdings LLC (Puget Holdings)
completed its merger with Puget Energy.  PSE’s basis of accounting
will continue to be on a historical basis and PSE’s financial statements will
not include any Statement of Financial Accounting Standards (SFAS) No. 141R,
“Business Combinations” purchase accounting adjustments.


PSE’s
consolidated financial statements include the accounts of PSE and its
subsidiaries.  PSE is 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 opinion of PSE’s management, 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 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, 2008.


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 $85.9 million for the three months ended March 31,
2009 and $76.6 million for the three months ended March 31, 2008.  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)
              Merger




In
conjunction with the merger on February 6, 2009, Puget Energy contributed $808.9
million in capital to PSE, of which $779.3 million was used to pay off
short-term debt owed by PSE, including $188.0 million in short-term debt
outstanding through the PSE Funding accounts receivable securitization program
that was terminated upon closing of the merger.  The $779.3 million is
excluded as cash provided by financing activities in the statement of cash
flows.  An additional $29.6 million of the capital contribution was
used to pay for change in control costs associated with the merger and is
included as cash provided by financing activities in the statement of cash
flows.  The stated value of the outstanding common stock was changed
from $10.00 to a par value of $0.01 per share.  The remaining $9.99 of
the original stated value was transferred to additional paid in
capital.


During
the first quarter 2009, PSE incurred $27.6 million pre-tax in merger
costs.  These costs include compensation costs as a result of the
change in control, write-off of deferred debt costs associated with the
termination of the pre-merger credit facilities, expenses associated with new
credit facilities and the impact of deferred compensation liabilities as a
result of the merger.  Pursuant
to the Washington Commission merger order commitments, PSE will not seek
recovery of these costs.In addition, a requirement of the merger
was that Puget Energy be the sole shareholder of PSE.  Accordingly, on
February 5, 2009, prior to the close of the merger, PSE defeased and called for
the redemption of its two outstanding series of preferred stock. The redemption
was completed on March 13, 2009.


The
merger order issued by the Washington Utilities and Transportation Commission
(Washington Commission) was subject to a Settlement Stipulation which included
78 conditions.  The conditions provided for, among other matters,
minimum equity to capitalization ratio, dividend restrictions, financial
reporting and rate credits of $10.0 million per year for ten years.




(3)
            Accounting
      for Derivative Instruments and Hedging
  Activities




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 the Company’s physical contracts qualify
for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting
rules, provided they meet certain criteria.  Generally, NPNS applies
to contracts with creditworthy counterparties, for which physical delivery is
probable and in quantities that will be used in the normal course of
business.  Power purchases designated as NPNS must meet additional
criteria 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 the Company’s forecasted load requirements.  The
Company may enter into financial fixed contracts to hedge the variability of
certain NPNS contracts.  Those contracts that do not meet NPNS
exception or cash flow hedge criteria are marked-to-market to current earnings
in the income statement, subject to deferral under SFAS No. 71, “Accounting for
the Effects of Certain Types of Regulation” (SFAS No. 71), for energy related
derivatives due to the Power Cost Adjustment (PCA) mechanism and Purchased Gas
Adjustment (PGA) mechanism.


The
Company pursues various portfolio optimization strategies, but is not in the
business of assuming risk for the purpose of realizing speculative trading
revenues.  The nature of serving regulated electric customers with its
wholesale portfolio of owned and contracted electric generation resources
exposes the Company and its customers to some volumetric and commodity price
risks within the sharing mechanism of the PCA.  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.  The Company’s energy risk
portfolio management function monitors and manages these risks using analytical
models and tools.    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 electric derivatives that do not meet the NPNS
exception at March 31, 2009 and December 31, 2008, including contracts
designated as cash flow hedges:


Electric
                      Derivatives(Dollars
      in Millions)
                    
                    March
      31,
                      2009
                    
                    
                    December
      31,
                      2008Current
      asset
                    
                    $
                    1.3
                    
                    
                    $
                    0.4Long-term
      asset
                    
                    
                    0.9
                    
                    
                    
                    0.5Total
      assets
                    
                    $
                    2.2
                    
                    
                    $
                    0.9Current
      liability
                    
                    $
                    151.9
                    
                    
                    $
                    90.6Long-term
      liability
                    
                    
                    122.3
                    
                    
                    
                    96.1Total
      liabilities
                    
                    $
                    274.2
                    
                    
                    $
                    186.7





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
recognition of future changes in value in the income statements.  As
these contracts are settled, amounts previously deferred in other comprehensive
income (OCI) are recognized as energy costs and are included as part of the PCA
mechanism.


The
following table presents the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria to the Company’s
earnings during the three months ended March 31, 2009 and March 31,
2008:





(Dollars
      in Millions)
            March
      31,
              2009
            March
      31,
              2008
            ChangeDecrease
      in earnings
            $  (2.3)
            $  (0.1)
            $  (2.2)





The
decrease in earnings in 2009 primarily relates to a $3.2 million unrealized loss
associated with the ineffective portion of cash flow hedges for two long-term
power supply agreements.


The
amount of unrealized loss, net of tax, related to the Company’s energy-related
cash flow hedges under SFAS No. 133 deferred in accumulated other comprehensive
income consisted of the following at March 31, 2009 and December 31,
2008:


(Dollars
      in Millions, net of tax)
            March
      31,
              2009
            December
      31,
              2008Other
      comprehensive income – unrealized loss
            $
      (166.3)
            $
      (111.7)





The
following table presents natural gas derivative contracts at March 31, 2009 and
December 31, 2008:





Gas
                      Derivatives(Dollars
      in Millions)
                    
                    March
      31,
                      2009
                    
                    
                    December
      31,
                      2008Current
      asset
                    
                    $
                    20.9
                    
                    
                    $
                    15.2Long-term
      asset
                    
                    
                    9.3
                    
                    
                    
                    6.2Total
      assets
                    
                    $
                    30.2
                    
                    
                    $
                    21.4Current
      liability
                    
                    $
                    172.4
                    
                    
                    $
                    146.3Long-term
      liability
                    
                    
                    54.4
                    
                    
                    
                    62.3Total
      liabilities
                    
                    $
                    226.8
                    
                    
                    $
                    208.6





At March
31, 2009, the Company had total assets of $30.2 million and total liabilities of
$226.8 million related to financial contracts used to economically hedge the
cost of physical gas purchased to serve natural gas customers.  All
fair value adjustments on derivatives relating to natural gas 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 gas costs under the PGA mechanism.


The
ending balance in OCI related to the forward starting swaps and previously
settled treasury lock contracts at March 31, 2009 is a net loss of $7.8 million
after tax and accumulated amortization.  This compares to a loss of
$7.9 million in OCI after tax and accumulated amortization at December 31,
2008.


SFAS No.
161, “Disclosures about Derivative Instruments and Hedging Activities – An
Amendment of Financial Accounting Standards Board (FASB) Statement No. 133”
(SFAS No. 161), requires enhanced disclosures about a company’s derivative
activities and how the related hedged items affect a company’s financial
position, financial performance and cash flows.   To meet the
objectives, SFAS No. 161 requires qualitative disclosures about the Company’s
fair value amounts of gains and losses associated with derivative instruments,
as well as disclosures about credit-risk-related contingent features in
derivative agreements.


The
following table presents the fair values and locations of derivative instruments
recorded in the balance sheet at March 31, 2009:




Derivatives
      Designated as Hedging InstrumentsAsset
      Derivatives
                    
                    Liability
      Derivatives(Dollars
      in Millions)
                      At  March
      31, 2009
                    Balance
      Sheet
                      Location
                    
                    Fair
      Value
                    
                    Balance
      Sheet
                      Location
                    
                    Fair
      ValueCommodity
      contracts:
                      Electric
      derivatives:
                      Current
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    $
                    --
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    $
                    145.6Long
      term
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    
                    0.3
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    
                    120.0Gas
      derivatives:
                      Current
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    
                    --
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    
                    --Long
      term
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    
                    --
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    
                    --Total
      derivatives designated as hedging instruments
                    
                    $
                    0.3
                    
                    
                    
                    $
                    265.6








Derivatives
      Not Designated as Hedging InstrumentsCommodity
      contracts:
                      Electric
      derivatives:
                      Current
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    $
                    1.2
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    $
                    6.3Long
      term
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    
                    0.6
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    
                    2.2Gas
      derivatives:
                      Current
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    
                    20.9
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    
                    172.4Long
      term
                    Unrealized
      gain on
                      derivative
      instruments
                    
                    
                    9.3
                    
                    Unrealized
      loss on
                      derivative
      instruments
                    
                    
                    54.4Total
      derivatives not designated as hedging instruments
                    
                    $
                    32.0
                    
                    
                    
                    $
                    235.3Combined
      total
                    
                    
                    $
                    32.3
                    
                    
                    
                    $
                    500.9








The
following table presents the effect of energy related derivatives on the PGA
mechanism in the balance sheet as of March 31, 2009:





(Dollars
      in Millions)
                        At  March  31,
      2009
                      Balance
      Sheet
                        Location
      1
                      
                      Fair
      Value
                      
                      Balance
      Sheet
                        Location
      1
                      
                      Fair
      ValueCommodity
      contracts:
                        Gas
      derivatives:
                        Current
                      Other
      regulatory assets
                      
                      $
                      196.6
                      
                      Regulatory
      liabilities
                      
                      $
                      --Total
                      
                      
                      $
                      196.6
                      
                      
                      
                      $
                      --
 ______________


1
            Natural
      gas derivatives are deferred, in accordance with SFAS No. 71 and all
      increases and decreases in the cost of natural gas supply are passed on to
      customers with the PGA mechanism.  As gains and losses are
      realized in future periods, they will be recorded as purchased gas costs
      in the income statement.








The
following table presents the effect of hedging instruments on OCI and income for
the three months ended March 31, 2009:


(Dollars
      in Millions)
                  Amount
      of Loss Recognized in OCI on Derivatives
                  Location
      of Loss Reclassified from Accumulated OCI into Income
                  Amount
      of Loss Reclassified from Accumulated OCI into Income
                  Location
      of Loss Recognized in Income on Derivatives
                  Amount
      of Loss Recognized in Income on DerivativesDerivatives
      in SFAS No. 133 Cash Flow Hedging  Relationships
                  Effective
      Portion 1
                  Effective
      Portion 2
                  Ineffective
      Portion and Amount Excluded from Effectiveness Testing 2,
      3Interest
      rate contracts:
                  $        --
                  Interest
      expense
                  $      (0.1)
                  
                  $      --Commodity
      contracts:
                    Electric
      derivatives
                  (48.5)
                  Electric
      generation fuel
                  (21.5)
                  Net
      unrealized loss on derivative instruments
                  --Electric
      derivatives
                  (19.4)
                  Purchased
      electricity
                  --
                  Net
      unrealized loss on derivative instruments
                  (3.2)Gas
      derivatives
                  --
                  Purchased
      gas
                  --
                  Net
      unrealized loss on derivative instruments
                  --Total
                  $  (67.9)
                  
                  $    (21.6)
                  
                  $  (3.2)


____________


1
            Changes
      in OCI are reported in after tax dollars.2
            Losses
      are reported in pre-tax dollars.3
            Ineffective
      portion of long-term power supply contracts that are designated as cash
      flow hedges.





For derivative instruments that meet
cash flow hedge criteria, the effective portion of the gain or loss on the
derivative is reported as a component of OCI and reclassified into earnings in
the same period or periods during which the hedged transaction affects earnings.
Gains and losses on the derivatives representing hedge ineffectiveness are
recognized in current earnings.  The Company expects that in the
future it may be extremely difficult to qualify for cash flow hedge treatment
due to market conditions.  The Company expects that $88.6 million of
losses in OCI will be reclassified into earnings within the next 12
months.  The maximum length of time over which the Company is hedging
its exposure to the variability in future cash flows extends to February 2015
for the physical electric contracts and to January 2012 for electric generation
fuel financial contracts.


The
following table presents the effect of derivatives not designated as hedging
instruments on income for the three months ended March 31,
2009:


(Dollars
      in Millions)
                        Three
      Months Ended March 31, 2009
                      Location
      of Gain
                        in
      Income on
                        Derivatives
                      Amount
      of Gain Recognized in Income on DerivativesInterest
      rate contracts:
                      
                      $
                      --Commodity
      contracts:
                        Electric
      derivatives
                      Net
      unrealized gain on derivative instruments
                      
                      0.9Gas
      derivatives
                      Net
      unrealized gain on derivative instruments
                      
                      --Total
                      
                      $
                      0.9





For the
quarter ended March 31, 2009, the Company reported $4.8 million in losses that
were reclassified into earnings as a result of the discontinuance of cash flow
hedges because the original forecasted transactions have a remote chance of
occurring.  The Company also reported year-to-date gains of $5.7
million related to transactions that did not meet NPNS or cash flow hedge
criteria.





The
Company had the following outstanding commodity contracts that were entered into
as of March 31, 2009:




Number
      of UnitsThree
      Months Ended March 31, 2009Derivatives
      designated as hedging instruments:Electric
      generation fuel
                  61,660,000
      MMBtusPurchased
      electricity
                  4,812,300
      MWhDerivatives
      not designated as hedging instruments:Gas
      derivatives1
                  86,021,684
      MMBtusElectric
      generation fuel
                  5,228,960
      MMBtusPurchased
      electricity
                  2,635,400
      MWh


________________1
                            Gas
      derivatives are deferred in accordance with SFAS No.
  71.





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.


Where
deemed appropriate, the Company may request collateral or other security from
its counterparties to mitigate the potential credit default losses. 
Criteria employed in this decision includes, among other things, the perceived
creditworthiness of the counterparty and the expected credit
exposure.


The
Company monitors counterparties’ credit standing, including those 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.


It is
possible that volatility in energy commodity prices could cause the Company to
have material credit risk exposures with one or more
counterparties.  If such counterparties fail to perform their
obligations under one or more agreements, the Company could suffer a material
financial loss.  However, as of March 31, 2009, approximately
99.6% of the counterparties with transaction amounts outstanding in the
Company’s energy portfolio, including NPNS transactions, are rated at least
investment grade by the major rating agencies and 0.4% are either rated below
investment grade or are not rated by rating agencies.  The Company
assesses credit risk internally for counterparties that are not
rated.


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.  The Company believes that entering into such
agreements reduces the risk of default by allowing a counterparty the ability to
make only one net payment.


The
Company computes credit reserves at a master agreement level (i.e. WSPP, ISDA or
NAESB) by counterparty. The Company considers external credit ratings and market
factors, such as credit default swaps and bond spreads, in determination of
reserves.  The Company recognizes that external ratings may not always
reflect how a market participant perceives counterparty’s risk of
default.  The Company uses both default factors published by Standard
& Poor’s (S&P) and factors derived through analysis of market risk,
which reflect the application of an industry standard recovery
rate.  The Company selects a default factor by counterparty at an
aggregate master agreement level based on a weighted average default tenor for
that counterparty’s deals.  The default tenor is used by weighting
fair values and contract tenors for all deals for each counterparty and coming
up with an average value.  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 to compute credit reserves for
counterparties in a net liability position. The Company’s S&P rating at
March 31, 2009 was BBB.  Credit reserves are booked as contra accounts
to unrealized gain (loss) positions. As of March 31, 2009, 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 the
year.  The majority of the Company’s derivative contracts are
with financial institutions and other utilities operating within
the Western Electric Coordinating Council.


The
Company enters into energy contracts with various credit-risk-related contingent
features, which could result in a counterparty requesting immediate payment or
demand immediate and ongoing full overnight collateralization on derivative
instruments in a net liability position.





The table
below presents the fair value of the overall contractual contingent liability
positions for the Company’s derivative activity at March 31, 2009:





(Dollars
      in Millions)
                    At
      March 31, 2009
                    Contingent
      Feature
                  
                  Fair
      Value 4
                    Liability
                  
                  
                  Posted
                    Collateral
                  
                  
                  Contingent
      CollateralCredit
      rating1
                  
                  $
                  (4.0
                  )
                  
                  $
                  --
                  
                  
                  $
                  4.0Reasonable
      grounds for adequate assurance 2
                  
                  
                  (143.4
                  )
                  
                  
                  --
                  
                  
                  
                  --Forward
      value of contract 3
                  
                  
                  (60.2
                  )
                  
                  
                  35.0
                  
                  
                  
                  N/ATotal
                  
                  $
                  (207.6
                  )
                  
                  $
                  35.0
                  
                  
                  $
                  4.0
 _________________


1
              The
      Company is required to maintain an investment grade credit rating from
      each of the major credit rating agencies.2
              A
      counterparty with reasonable grounds for insecurity regarding performance
      of an obligation may request adequate assurance of
      performance.3
              Collateral
      requirements may vary, based on changes in forward value of underlying
      transactions.4
              Represents
      derivative fair values of contracts with contingent features for
      counterparties in net derivative liability positions at March 31,
      2009.  Excludes NPNS and accounts payable and accounts
      receivable activity.




(4)
            Fair
      Value Measurements





SFAS No.
157, “Fair Value Measurements” (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.





Financial
assets and liabilities are classified in their entirety based on the lowest
level of input that is significant to the fair value measurement.  If
a fair value measurement relies on inputs from different levels of the
hierarchy, the entire measurement must be placed into the same level based on
the lowest level 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 that not only include 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.


As of
March 31, 2009, the Company considers the markets for its electric and natural
gas Level 2 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 pricing service 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
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 March 31, 2009:





Recurring
      Fair Value Measures
                  
                  At
      Fair Value as of March 31, 2009
                  
                  
                  At
      Fair Value as of March 31, 2008(Dollars
      in Millions)
                  
                  Level
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  Total
                  
                  
                  Level
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  TotalAssets:Energy
      derivative instruments
                  
                  $
                  --
                  
                  
                  $
                  31.5
                  
                  
                  $
                  0.9
                  
                  
                  $
                  32.4
                  
                  
                  $
                  --
                  
                  
                  $
                  107.8
                  
                  
                  $
                  34.6
                  
                  
                  $
                  142.4Money
      market accounts
                  
                  
                  63.9
                  
                  
                  
                  --
                  
                  
                  
                  1.4
                  
                  
                  
                  65.3
                  
                  
                  
                  13.8
                  
                  
                  
                  --
                  
                  
                  
                  1.4
                  
                  
                  
                  15.2Total
      assets
                  
                  $
                  63.9
                  
                  
                  $
                  31.5
                  
                  
                  $
                  2.3
                  
                  
                  $
                  97.7
                  
                  
                  $
                  13.8
                  
                  
                  $
                  107.8
                  
                  
                  $
                  36.0
                  
                  
                  $
                  157.6Liabilities:Energy
      derivative instruments
                  
                  $
                  --
                  
                  
                  $
                  322.5
                  
                  
                  $
                  178.5
                  
                  
                  $
                  501.0
                  
                  
                  $
                  --
                  
                  
                  $
                  1.4
                  
                  
                  $
                  10.2
                  
                  
                  $
                  11.6Other
      financial items
                  
                  
                  --
                  
                  
                  
                  --
                  
                  
                  
                  --
                  
                  
                  
                  --
                  
                  
                  
                  --
                  
                  
                  
                  --
                  
                  
                  
                  7.2
                  
                  
                  
                  7.2Total
      liabilities
                  
                  $
                  --
                  
                  
                  $
                  322.5
                  
                  
                  $
                  178.5
                  
                  
                  $
                  501.0
                  
                  
                  $
                  --
                  
                  
                  $
                  1.4
                  
                  
                  $
                  17.4
                  
                  
                  $
                  18.8





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)
                  
                  2009
                  
                  
                  2008Balance
      at beginning of period  (net credit reserve on energy
      derivatives)
                  
                  $
                  (132.2
                  )
                  
                  $
                  (7.3
                  )Changes
      during period :Realized
      and unrealized energy derivatives-
      included in earnings
                  
                  
                  (2.4
                  )
                  
                  
                  (0.1
                  )-
      included in other comprehensive income
                  
                  
                  (53.1
                  )
                  
                  
                  28.7-
      included in regulatory assets/liabilities
                  
                  
                  (7.4
                  )
                  
                  
                  0.3Purchases,
      issuances, and settlements
                  
                  
                  8.1
                  
                  
                  
                  (1.9
                  )Energy
      derivatives transferred in/out of Level 3
                  
                  
                  10.8
                  
                  
                  
                  (1.1
                  )Balance
      as of March 31, 2009 (net credit reserve on energy
      derivatives)
                  
                  $
                  (176.2
                  )
                  
                  $
                  18.6





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 inputs on energy derivatives recurring items are
included in the net unrealized (gain) loss on derivative instruments section in
the Company’s income statement and as net unrealized (gain) loss on derivative
instruments in OCI.  The Company does not believe that the fair values
diverge materially from the amounts the Company currently anticipates realizing
on settlement or maturity.


Energy
derivative instruments are classified as Level 3 in the fair value hierarchy
because Level 3 inputs are significant to their fair value
measurement.  Energy derivatives transferred out of Level 3 represent
existing assets or liabilities that were classified as Level 3 at end of the
prior reporting period for which the lowest significant input became observable
during the current reporting period. The net unrealized loss recognized during
the reporting period is primarily due to a significant decrease in market
prices.







(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.  The Company also maintains a non-qualified supplemental
retirement plan for officers and certain director-level
employees.


The
following table summarizes the estimate of net periodic benefit cost for the
three months ended March 31:





Qualified
                  Pension
      Benefits
                
                
                SERP
                  Pension
      Benefits
                
                
                Other
                  Benefits(Dollars
      in Thousands)
                
                2009
                
                
                2008
                
                
                2009
                
                
                2008
                
                
                2009
                
                
                2008Components
      of net periodic benefit cost:Service
      cost
                
                $
                3,271
                
                
                $
                3,054
                
                
                $
                267
                
                
                $
                234
                
                
                $
                32
                
                
                $
                43Interest
      cost
                
                
                6,905
                
                
                
                6,498
                
                
                
                579
                
                
                
                553
                
                
                
                266
                
                
                
                283Expected
      return on plan assets
                
                
                (10,755
                )
                
                
                (10,455
                )
                
                
                --
                
                
                
                --
                
                
                
                (111
                )
                
                
                (197
                )Amortization
      of prior service cost
                
                
                283
                
                
                
                161
                
                
                
                154
                
                
                
                154
                
                
                
                21
                
                
                
                21Amortization
      of net loss (gain)
                
                
                808
                
                
                
                --
                
                
                
                221
                
                
                
                183
                
                
                
                (46
                )
                
                
                (199
                )Amortization
      of transition obligation
                
                
                --
                
                
                
                --
                
                
                
                --
                
                
                
                --
                
                
                
                13
                
                
                
                13Net
      periodic benefit cost (income)
                
                $
                512
                
                
                $
                (742
                )
                
                $
                1,221
                
                
                $
                1,124
                
                
                $
                175
                
                
                $
                (36
                )





The
Company previously disclosed in its financial statements for the year ended
December 31, 2008 that it expected contributions by the Company to fund the
Supplemental Executive Retirement Plan (SERP) and the other postretirement plans
for the year ending December 31, 2009 to be $4.0 million and $0.1 million,
respectively.  The full amount of the pension funding for 2009 is for
the Company’s non-qualified supplemental retirement plan.


During
the three months ended March 31, 2009, payments of benefits related to the
Company’s non-qualified pension plans were $0.4 million.  Based on
this activity, the Company anticipates paying additional benefits of $3.6
million for the Company’s non-qualified pension plan during
2009.  During the three months ended March 31, 2009, actual other
post-retirement medical benefit plan contributions were $0.2
million.  The Company expects to make additional contributions of
approximately $18.0 million during the remaining periods of 2009.




(6)
            Regulation
      and Rates




On April
17, 2009, the Washington Commission issued a final order approving and adopting
a settlement agreement that authorized PSE to defer certain ownership and
operating costs related to its purchase of the Mint Farm Generation Station
(Mint Farm) that will be incurred prior to PSE recovering such costs in electric
customer rates.  Under Washington State law, a company may defer the
costs associated with purchasing and operating a gas plant that complies with
the greenhouse gases (GHG) emissions performance standard until the plant is
included in rates or for two years from the date of purchase, whichever is
sooner.  As of March 31, 2009, PSE had established a regulatory asset
of $7.7 million.  The prudence of the Mint Farm acquisition, recovery
of costs of Mint Farm and compliance with the GHG emissions performance standard
will be addressed in the Company’s next rate proceeding.


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
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
issued a separate orderon January 15, 2009, that authorized the
continuation of the Power Cost Only Rate Case (PCORC) with certain modifications
to which the Washington Commission staff and the Company had
agreed.  The five procedural modifications to the PCORC include
extending the expected procedural schedule from five to six months, limiting the
power cost updates to one per PCORC unless an additional update is allowed by
the Washington Commission as part of the compliance filing, prohibiting the
overlap of PCORC and general rate cases (except for requests for interim rate
relief), shortening data request time from ten to five business days and
requiring the Company to provide its future energy resource model projections at
the outset of a case.


On
September 25, 2008, the Washington Commission approved PSE’s requested revisions
to its 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.







(7)
            Litigation




Residential
Exchange.  Petitioners in several actions in the U. S. Court of
Appeals for the Ninth Circuit (Ninth Circuit) against the Bonneville Power
Administration (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 Residential Exchange Program (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 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,
CaseNo. 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, CaseNo. 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
thisrecord 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 determined by BPAto be recovered through
reductions commencing October 2007 in REP payments for PSE’s residential and
small farm customers was approximately $207.2 million plus interest on
unrecovered amounts.  However, these BPA determinations are subject to
subsequent administrative and judicial review, which may alter or reverse such
determinations.PSE
and others, including a number of preference agency and investor-owned utility
customers of BPA, in December 2008 filed petitions for review in the Ninth
Circuit of various of these BPA determinations.  PSE is reviewing its
options in determining if it will contest the amounts withheld as improper
payments made since 2001.


In
September 2008, BPA and PSE signed a short-termResidential Purchase and
Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal
years ending September 30, 2009–2011.In December 2008, BPA
and PSE signed another long-term RPSA under which BPA is to pay REP benefits to
PSE for the period October 2011 through September 2028.  PSE and other
customers of BPA in December 2008 filed petitions for review in the Ninth
Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs
signed by other investor-owned utility customers of BPA) and BPA’s record of
decision regarding such RPSAs.  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 Priority Firm (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 Federal Energy Regulatory Commission
(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.  Any changes to the REP payments passes
through to customers with no impact to PSE’s net income.


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, 2008 includes a summary relating to the western
power market proceedings.  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.


CPUC v. FERC.  On August 2, 2006, the
Ninth Circuit decided that FERC erred in excluding potential relief for tariff
violations for periods that pre-dated October 2, 2000 and additionally ruled
that FERC should consider remedies for transactions previously considered
outside the scope of the proceedings.  The August 2, 2006 decision may
adversely impact PSE’s ability to recover the full amount of its California
Independent System Operator (CAISO) receivable.  The decision may also
expose PSE to claims or liabilities for transactions outside the previously
defined “refund period.”  At this time the ultimate financial outcome
for PSE is unclear.  Rehearing by the Ninth Circuit was denied on
April 6, 2009.  Parties have been engaged in court-sponsored
settlement discussions, and those discussions may result in some
settlements.  PSE is unable to predict either the outcome of the
proceedings or the ultimate financial effect on PSE.




(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 or (b) PSE’s senior
unsecured revolving credit facility.  At March 31, 2009 and December
31, 2008, the outstanding balance of the Note was $19.4 million and $26.1
million, respectively and the interest rate was 1.4% and 1.7%
respectively.  This Note is unaffected by the February 6, 2009
merger.


The
Company has a general liability claim from AEGIS Insurance Services Inc. (AEGIS)
for $3.3 million as of March 31, 2009 which was recovered by the Company in
April 2009.  A PSE management employee serves on one of AEGIS’ risk
management advisory committees for which no compensation is
received.


PSE has
property insurance with various companies and approximately 35.0% of the
property insurance coverage is with American International Group, Inc
(AIG).  On October 23, 2008, AIG named the wife of PSE’s President and
Chief Executive as its Vice Chairman and Chief Restructuring
Officer.




(9)
            Other




In
January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable
Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R,
which clarifies the application of Accounting Research Bulletin No. 51,
“Consolidated Financial Statements,” to certain entities in which equity
investors do not have a controlling interest or sufficient equity at risk for
the entity to finance its activities without additional financial
support.


A
variable interest entity (VIE) is an entity in which the equity of the investors
as a group do not have: (1) the characteristics of a controlling financial
interest; (2) sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support; or (3) symmetry between
voting rights and economic interests and where substantially all of the entity’s
activities either involve or are conducted on behalf of an investor with
disproportionally few voting rights. Variable interests in a VIE are
contractual, ownership or other pecuniary interests in an entity that change
with changes in the fair value of the entity’s net assets exclusive of variable
interest.


FIN 46R
requires that if a business entity has a controlling financial interest in a
VIE, the financial statements must be included in the consolidated financial
statements of the business entity. The adoption of FIN 46R for all interests in
VIEs created after January 31, 2003 was effective immediately.  For
VIEs created before February 1, 2003, it was effective July 1, 2003. The
adoption of FIN 46R was effective March 31, 2004 for the Company.


The
Company evaluated its power purchase agreements and determined that two power
purchase agreements may be considered significant VIEs under FIN
46R.  The Company is required to buy all the generation from the two
plants, subject to displacement by the Company, at rates set forth in the
relevant power purchase agreements.  As a result, the Company
submitted requests for information to those parties; however, the parties have
refused to submit to the Company the necessary information for the Company to
determine whether they meet the requirements of a VIE that requires
consolidation. The Company will continue to submit requests for information to
the counterparties annually to determine if FIN 46R is
applicable.  PSE’s purchased electricity expense for the three months
ended March 31, 2009 and 2008 for these entities was $47.4 million and $54.9
million, respectively.


In
December 2008, FASB issued FIN 46R-8, “Disclosures by Public Entities
(Enterprises) about Transfers of Financial Assets and Interests in Variable
Interest Entities” (FIN 46R-8), which requires new expanded disclosures in the
quarterly financial statements for periods ending after December 15, 2008 for
VIEs.  The disclosures required by FIN 46R-8 are intended to provide
users of the financial statements with greater transparency about a transferor’s
continuing involvement with transferred financial assets and an enterprise’s
involvement with VIEs.


A primary
beneficiary of a VIE is the variable interest holder (e.g. a contractual
counterparty or capital provider) deemed to have the controlling financial
interest(s) and is considered to be exposed to the majority of the risks and
rewards associated with the VIE and therefore must consolidate
it.  The Company enters into a variety of contracts for energy with
other counterparties and evaluates all contracts for variable
interests.  The Company’s variable interests primarily arise through
power purchase agreements where the Company obtains control other than through
voting rights and is required to buy all or a majority of generation from a
plant at rates set forth in a power purchase agreement, subject to displacement.
If a counterparty does not deliver energy to the Company, the Company may have
to replace the energy at prices which could be higher or lower than agreed to
prices.  Therefore, the Company may be exposed to risk associated with
replacement costs of a contract.


The
Company evaluates variable interest relationships based on
significance.  If the Company did not participate significantly in the
design or redesign of an entity and the variable interest is not considered
significant to the Company’s financial statements, the variable interest is not
considered significant.  Purchase power contracts with governmental
organizations do not require disclosure.  When the Company determines
a significant variable interest may exist with another party, the Company
requests for information to determine if it is required to be
consolidated.


The
following table presents the Company’s VIE relationships, irrespective of
significance, related to power purchase agreements as of March 31,
2009:




(Dollars
      in Millions)
                  Variable
      Interests in Power Purchase Agreements
                    for
      the Month Ended March 31, 2009Nature
      of Variable Interest
                  Longest
      Contract
                    Tenor
                  
                  Number
      of Counterparties
                  
                  
                  Aggregate
      Carrying Value
                    Liability
      2
                  
                  
                  Level
      of Activity - 2009 Expenses 2Electric-combustion
      turbine co-generation plant 1
                  2011
                  
                  
                  2
                  
                  
                  $
                  (12.4
                  )
                  
                  $
                  47.4Electric-hydro
                  2037
                  
                  
                  8
                  
                  
                  
                  (0.6
                  )
                  
                  
                  2.2Other
                  2011
                  
                  
                  3
                  
                  
                  
                  --
                  
                  
                  
                  0.1Total
                  
                  
                  
                  13
                  
                  
                  $
                  (13.0
                  )
                  
                  $
                  49.7


_____________


1
              Variable
      interests may be significant.2
              Carrying
      values are classified in the balance sheet in accounts payable and
      expenses are classified on the income statement in purchased
      electricity.




(10)
            New
      Accounting Pronouncements




On April
9, 2009, FASB issued FASB Staff Position (FSP) No. 157-4, “Determining Fair
Value When the Volume and Level of Activity for the Asset or Liability Have
Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP
No. 157-4).  FSP No. 157-4 provides additional guidance for estimating
fair value in accordance with SFAS No. 157, when the volume and level of
activity for the asset or liability have significantly decreased. FSP No. 157-4
also includes guidance on identifying circumstances that indicate a transaction
is not orderly.  FSP No. 157-4 will be effective for the Company as of
June 30, 2009.  The Company is currently assessing the impact of the
FSP on its SFAS No. 157 calculations and disclosures.


On April
9, 2009, FASB issued FSP No. 107-1, “Interim Disclosures about Fair Value of
Financial Instruments” (FSP No. 107-1).  This FSP amends SFAS No. 107,
“Disclosures about Fair Value of Financial Instruments,” to require disclosures
about fair value of financial instruments for interim reporting periods of
publicly traded companies as well as in annual financial
statements.  FSP No. 107-1 also amends APB Opinion No. 28, “Interim
Financial Reporting,” to require those disclosures in summarized financial
information at interim reporting periods.  FSP No. 107-1 will be
effective for the Company as of June 30, 2009.







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
Sound Energy, Inc. (PSE) is a subsidiary of Puget Energy, Inc. (Puget Energy),
an energy services holding company incorporated in the state of Washington in
1999.  On February 6, 2009, Puget Holdings LLC (Puget Holdings)
completed its merger with Puget Energy.  PSE’s basis of accounting
will continue to be on a historical basis and PSE’s financial statements will
not include any Statement of Financial Accounting Standards (SFAS) No. 141R,
“Business Combinations” purchase accounting adjustments.


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.  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 Federal Energy Regulatory
Commission (FERC) regulations, North American Electric Reliability Corporation
(NERC) standards and Washington Utilities and Transportation Commission
(Washington Commission) regulations which affects a wide array of business
activities, including regulating 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 attainment of PSE’s business objectives.  In addition, PSE
is subject to risks inherent to the utility industry as a whole, including
weather changes affecting purchases and sales of energy; outages at owned and
non-owned generation plants where energy is obtained; storms or other events
which can damage natural gas and electric distribution and transmission lines;
increasing regulatory standards for system reliability and 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.  PSE filed its most recent Integrated Resource Plan
(IRP) on May 31, 2007 with the Washington Commission.  The 2007 IRP
demonstrated PSE’s need to acquire significant amounts of new generating
resources, driven primarily by expiration of existing purchase power
contracts.  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.  The next IRP will be filed in July
2009.


On
January 16, 2009, Standard & Poor’s (S&P) Rating Services raised its
corporate credit rating on PSE and removed PSE from its watch list for negative
implications citing a stable outlook.  The rating actions reflected
the completion of the acquisition of Puget Energy and PSE by Puget
Holdings.  On February 2, 2009, Moody’s Investors Service (Moody’s)
affirmed the long-term ratings of PSE.  The ratings outlook for PSE is
stable.   PSE’s equity ratio increased from 38.0% at December 31,
2008 to 50.2% at March 31, 2009.





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





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.


Net
income for the three months ended March 31, 2009 was $85.0 million on operating
revenues of $1.1 billion as compared to net income of $80.9 million on operating
revenues of $1.0 billion for the same period in 2008.


Net
income for the three months ended March 31, 2009 as compared to the same period
in 2008 was positively impacted by a $26.3 million pre-tax increase in electric
margin and a $12.1 million pre-tax increase in gas margin.  Electric
and natural gas margins were favorably impacted by general tariff rate increases
of 7.1% and 4.6%, respectively, that were approved by the Washington Commission
and were effective November 1, 2008.  The favorable impact of lower
natural gas prices and wholesale power costs was offset by below normal
hydroelectric energy production during the first quarter of 2009.  Net
income was negatively impacted by one-time merger costs of $27.6 million related
to the merger of Puget Energy with Puget Holdings.  These costs were
primarily related to PSE employee compensation triggered by the Puget Energy’s
change of control, credit agreement related expenses and the income statement
impact of deferred compensation related liability increases triggered by the
merger. In addition, net income was negatively impacted due to an increase in
depreciation and amortization of $6.0 million.





Energy
Margins


The
following table displays the details of electric margin changes for the three
months ended March 31, 2009 as compared to the same period in
2008.  Electric margin is electric sales to retail and transportation
customers less pass-through tariff items, revenue-sensitive taxes, and the cost
of generating and purchasing electric energy sold to customers, including
transmission costs to bring electric energy to PSE’s service
territory.





Electric
      Margin(Dollars
      in Millions)
                        Three
      Months Ended March 31,
                      
                      2009
                      
                      
                      2008
                      
                      
                      Change
                      
                      
                      Percent
                        ChangeElectric
      operating revenue1
                      
                      $
                      600.2
                      
                      
                      $
                      606.1
                      
                      
                      $
                      (5.9
                      )
                      
                      
                      (1.0
                      )
      %Less:
      Other electric operating revenue
                      
                      
                      (0.8
                      )
                      
                      
                      (12.2
                      )
                      
                      
                      11.4
                      
                      
                      
                      93.4Add:
      Other electric operating revenue-gas supply resale
                      
                      
                      (8.9
                      )
                      
                      
                      2.6
                      
                      
                      
                      (11.5
                      )
                      
                      
                      *Total
      electric revenue for margin
                      
                      
                      590.5
                      
                      
                      
                      596.5
                      
                      
                      
                      (6.0
                      )
                      
                      
                      (1.0
                      )Adjustments
      for amounts included in revenue:Pass-through
      tariff items
                      
                      
                      (21.7
                      )
                      
                      
                      (12.9
                      )
                      
                      
                      (8.8
                      )
                      
                      
                      (68.2
                      )Pass-through
      revenue-sensitive taxes
                      
                      
                      (44.4
                      )
                      
                      
                      (41.6
                      )
                      
                      
                      (2.8
                      )
                      
                      
                      (6.7
                      )Net
      electric revenue for margin
                      
                      
                      524.4
                      
                      
                      
                      542.0
                      
                      
                      
                      (17.6
                      )
                      
                      
                      (3.2
                      )Minus
      power costs:Purchased
      electricity1
                      
                      
                      (260.2
                      )
                      
                      
                      (272.8
                      )
                      
                      
                      12.6
                      
                      
                      
                      4.6Electric
      generation fuel1
                      
                      
                      (48.1
                      )
                      
                      
                      (47.0
                      )
                      
                      
                      (1.1
                      )
                      
                      
                      (2.3
                      )Residential
      exchange1
                      
                      
                      32.4
                      
                      
                      
                      --
                      
                      
                      
                      32.4
                      
                      
                      
                      *Total
      electric power costs
                      
                      
                      (275.9
                      )
                      
                      
                      (319.8
                      )
                      
                      
                      43.9
                      
                      
                      
                      13.7Electric
      margin2
                      
                      $
                      248.5
                      
                      
                      $
                      222.2
                      
                      
                      $
                      26.3
                      
                      
                      
                      11.8
                      %
 ____________________________


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 $26.3 million for the three months ended March 31, 2009 as
compared to the same period in 2008.  The increase in electric margin
was primarily due to a general rate case increase of 7.1% effective November 1,
2008 and favorable impact of lower natural gas and wholesale power prices offset
by below normal hydroelectric energy production during the first quarter 2009
which increased margin by $28.3 million.  With lower natural gas
prices, PSE increased its generation from its gas-fired generating
facilities.  This increase was partially offset by a 0.5% decrease in
retail kilowatt hour (kWH) sales and other items which decreased margin by $1.9
million.


The
following table displays the details of gas margin changes for the three months
ended March 31, 2009 as compared to the same period in 2008.  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 March 31,
                    
                    2009
                    
                    
                    2008
                    
                    
                    Change
                    
                    
                    Percent
                      ChangeGas
      operating revenue1
                    
                    $
                    506.4
                    
                    
                    $
                    443.2
                    
                    
                    $
                    63.2
                    
                    
                    
                    14.3
                    %Less:
      Other gas operating revenue
                    
                    
                    (4.9
                    )
                    
                    
                    (4.6
                    )
                    
                    
                    (0.3
                    )
                    
                    
                    (6.5
                    )Total
      gas revenue for margin
                    
                    
                    501.5
                    
                    
                    
                    438.6
                    
                    
                    
                    62.9
                    
                    
                    
                    14.3Adjustments
      for amounts included in revenue:Pass-through
      tariff items
                    
                    
                    (4.7
                    )
                    
                    
                    (4.4
                    )
                    
                    
                    (0.3
                    )
                    
                    
                    (6.8
                    )Pass-through
      revenue-sensitive taxes
                    
                    
                    (41.6
                    )
                    
                    
                    (35.0
                    )
                    
                    
                    (6.6
                    )
                    
                    
                    (18.9
                    )Net
      gas revenue for margin
                    
                    
                    455.2
                    
                    
                    
                    399.2
                    
                    
                    
                    56.0
                    
                    
                    
                    14.0Minus
      purchased gas costs1
                    
                    
                    (320.1
                    )
                    
                    
                    (276.2
                    )
                    
                    
                    (43.9
                    )
                    
                    
                    (15.9
                    )Gas
      margin2
                    
                    $
                    135.1
                    
                    
                    $
                    123.0
                    
                    
                    $
                    12.1
                    
                    
                    
                    9.8
                    %





____________________________


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 $12.1 million for the three months ended March 31, 2009 as
compared to the same period in 2008 primarily due to the general rate case
increase of 4.6% effective November 1, 2008 which increased margin by $20.4
million.  This increase was partially offset by a decrease in margin
of $6.4 million due to customer mix and other pricing variances and a decrease
of $1.9 million due to a 1.6% decrease in gas therm volume.





Electric
Operating Revenues


The table
below sets forth changes in electric operating revenues for PSE for the three
months ended March 31, 2009 as compared to the same period in 2008.





(Dollars
      in Millions)
                  Three
      Months Ended March 31,
                
                2009
                
                
                2008
                
                
                Change
                
                
                Percent
                  ChangeElectric
      operating revenues:Residential
      sales
                
                $
                358.8
                
                
                $
                346.6
                
                
                $
                12.2
                
                
                
                3.5
                %Commercial
      sales
                
                
                231.6
                
                
                
                212.0
                
                
                
                19.6
                
                
                
                9.2Industrial
      sales
                
                
                26.5
                
                
                
                27.5
                
                
                
                (1.0
                )
                
                
                (3.6
                )Other
      retail sales, including unbilled revenue
                
                
                (29.4
                )
                
                
                (11.6
                )
                
                
                (17.8
                )
                
                
                *Total
      retail sales
                
                
                587.5
                
                
                
                574.5
                
                
                
                13.0
                
                
                
                2.3Transportation
      sales
                
                
                2.5
                
                
                
                1.5
                
                
                
                1.0
                
                
                
                66.7Sales
      to other utilities and marketers
                
                
                9.3
                
                
                
                18.0
                
                
                
                (8.7
                )
                
                
                (48.3
                )Other
                
                
                0.9
                
                
                
                12.1
                
                
                
                (11.2
                )
                
                
                (92.6
                )Total
      electric operating revenues
                
                $
                600.2
                
                
                $
                606.1
                
                
                $
                (5.9
                )
                
                
                (1.0
                )
      % ____________________


*
              Percent
      change not applicable or
meaningful.





Electric
retail sales increased $13.0 million for the three months ended March 31, 2009
as compared to the same period in 2008.  The increase was due in part
to the electric general rate increase of November 1, 2008 partially offset by a
merger rate credit effective February 13, 2009, which combined, contributed to
an increase in electric retail sales of $41.4 million for 2009 as compared to
2008.  Electric retail sales also increased by $7.5 million as a
result of an increase in the conservation rider charged to customers due to an
increase in the Company’s energy efficiency programs, which has no impact on net
income as the amount is offset in conservation amortization.  These
increases were partially offset by a decrease in retail electricity usage of
30,346 megawatt hours (MWh) or 0.5% for 2009 as compared to the same period in
2008, which resulted in a decrease of approximately $2.9 million to electric
operating revenue.  The benefits of the Residential and Farm Energy
Exchange Benefit credited to customers reduced electric operating revenues by
$33.9 million in 2009.  This credit also reduced power costs and
revenue sensitive taxes by a corresponding amount with no impact on
earnings.


Sales to
other utilities and marketers decreased $8.7 million for the three months ended
March 31, 2009 as compared to the same period in 2008 primarily due to a
decrease in wholesale electric energy prices which decreased revenue by of $9.1
million.  This decrease was partially offset by an increase in other
items.


Other
electric operating revenues decreased $11.2 million for the three months ended
March 31, 2009 as compared to the same period in 2007 primarily due to a
decrease of $11.5 million in noncore gas sales and related losses from hedging
contracts entered into to manage those noncore gas sales.


The
following electric rate changes were approved by the Washington Commission in
2008 and 2009:





Type
      of Rate
                Adjustment
              Effective
      Date
              Average
                Percentage
                Increase
      (Decrease)
                in
      Rates
              Annual
                Increase
      (Decrease)
                in
      Revenues
                (Dollars
      in Millions)Electric
      General Rate Case
              November
      1, 2008
              7.1
      %
              $130.2Merger
      Rate Credit
              February
      13, 2009
              (0.4)%
              $   (6.7)





Gas
Operating Revenues


The table
below sets forth changes in gas operating revenues for PSE for the three months
ended March 31, 2009 as compared to the same period in 2008.





(Dollars
      in Millions)
                  Three
      Months Ended March 31,
                
                2009
                
                
                2008
                
                
                Change
                
                
                Percent
                  ChangeGas
      operating revenues:Residential
      sales
                
                $
                344.2
                
                
                $
                294.2
                
                
                $
                50.0
                
                
                
                17.0
                %Commercial
      sales
                
                
                139.4
                
                
                
                127.8
                
                
                
                11.6
                
                
                
                9.1Industrial
      sales
                
                
                14.8
                
                
                
                12.8
                
                
                
                2.0
                
                
                
                15.6Total
      retail sales
                
                
                498.4
                
                
                
                434.8
                
                
                
                63.6
                
                
                
                14.6Transportation
      sales
                
                
                3.1
                
                
                
                3.8
                
                
                
                (0.7
                )
                
                
                (18.4
                )Other
                
                
                4.9
                
                
                
                4.6
                
                
                
                0.3
                
                
                
                6.5Total
      gas operating revenues
                
                $
                506.4
                
                
                $
                443.2
                
                
                $
                63.2
                
                
                
                14.3
                %





Gas
retail sales increased $63.6 million for the three months ended March 31, 2009
as compared to the same period in 2008 due to a $64.8 million increase in gas
operating revenues as a result of a 11.1% Purchased Gas Adjustment (PGA)
mechanism rate increase for retail customers effective October 1, 2008 and a
general rate increase effective November 1, 2008.  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.  Partially
offsetting the increase was a 1.0 million decrease in gas therm sales which
decreased margin $1.3 million.


The
following natural gas rate adjustments were approved by the Washington
Commission in 2008 and 2009:





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
      %
              $
      108.8General
      Rate Case
              November
      1, 2008
              4.3
      %
              $   49.2Merger
      Rate Credit
              February
      13, 2009
              (0.4)%
              $   (3.6)





Operating
Expenses


The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the three months ended March 31, 2009 as compared to the same
period in 2008.





(Dollars
      in Millions)
                  Three
      Months Ended March  31,
                
                2009
                
                
                2008
                
                
                Change
                
                
                Percent
                  ChangePurchased
      electricity
                
                $
                260.3
                
                
                $
                272.8
                
                
                $
                (12.5
                )
                
                
                (4.6
                )
      %Residential
      exchange
                
                
                (32.4
                )
                
                
                --
                
                
                
                (32.4
                )
                
                
                *Purchased
      gas
                
                
                320.1
                
                
                
                276.2
                
                
                
                43.9
                
                
                
                15.9Utility
      operations and maintenance
                
                
                114.9
                
                
                
                112.2
                
                
                
                2.7
                
                
                
                2.4Merger
      and related costs
                
                
                27.6
                
                
                
                --
                
                
                
                27.6
                
                
                
                *Depreciation
      and amortization
                
                
                81.4
                
                
                
                75.4
                
                
                
                6.0
                
                
                
                8.0Conservation
      amortization
                
                
                20.8
                
                
                
                13.4
                
                
                
                7.4
                
                
                
                55.2Taxes
      other than income taxes
                
                
                101.3
                
                
                
                94.3
                
                
                
                7.0
                
                
                
                7.4 ___________________


*
              Percent
      change not applicable or
meaningful.





Purchased electricityexpenses
decreased $12.5 million for the three months ended March 31, 2009 as compared to
the same period in 2008.  The decrease is related to lower wholesale
power prices and increased generation at PSE’s gas-fired generating facilities
due to lower cost of natural gas in the three months ended March 31, 2009 as
compared to the same period in 2008, which resulted in a decrease of $13.1
million.  PSE utilizes less purchased power when the cost of natural
gas is lower than the cost of wholesale purchased power due to its recent
acquisitions of the Goldendale and Mint Farm gas-fired generating facilities,
which have low heat rates. This decrease was partially offset by an increase of
$0.6 million in transmission and other expenses.


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.


Residential exchange credits
associated with the Bonneville Power Administration (BPA) Residential Exchange
Program (REP) increased to $32.4 million for the three months ended March 31,
2009 as a result of an agreement with BPA to continue to pass on REP benefits to
PSE’s customers.  REP does not have an impact on net
income.


Purchased gas expenses
increased $43.9 million for the three months ended March 31, 2009 as compared to
the same period in 2008 primarily due to an increase of 11.1% in PGA rates which
provides the rates used to determine gas costs based on customer
usage.  The rate increase was the result of higher costs of natural
gas in the forward market and a reduction of the credit for accumulated PGA
payable balance.  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 March 31, 2009 was
$29.7 million as compared to $8.9 million at December 31, 2008.  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 $2.7 million for the three months ended March 31, 2009
as compared to the same period in 2008.  The increase for the three
months ended March 31, 2009 was primarily due to an increase in administrative
and general expenses of $3.1 million which included increases in salary and
employee benefits expense, an increase in rent expense and an increase in
property insurance costs, customer service costs of $3.0 million, electric
transmission and distribution costs of $1.9 million and a $1.6 million increase
in gas operations and distribution expenses.  These increases were
partially offset by a $7.8 million decrease in production operations and
maintenance costs related to settlement of a lawsuit at the Colstrip generating
facilities.


Merger and related costs
associated with the merger with Puget Holdings incurred for the three months
ended March 31, 2009 were $27.6 million.  These costs include
compensation costs as a result of the change in control, write-off of deferred
debt costs associated with the termination of the pre-merger credit facilities,
expenses associated with new credit facilities and the impact of deferred
compensation liabilities as a result of the merger.  Pursuant
to the Washington Commission merger order commitments, PSE will not seek
recovery of these costs.


Depreciation and amortization
expense increased $6.0 million for the three months ended March 31, 2009 as
compared to the same period in 2008.  Excluding the regulatory credit
for the deferral of Mint Farm Generation Station (Mint Farm) fixed costs of $3.8
million, depreciation and amortization expense increased $9.8 million for the
three months ended March 31, 2009 as compared to the same period in 2008. This
increase is due to additional depreciable property placed into service and an
increase in storm amortization costs as approved in PSE’s general rate case
effective November 1, 2008.


Conservation amortization
increased $7.4 million for the three months ended March 31, 2009 as compared to
the same period in 2008 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 $7.0 million for the three months ended March 31, 2009 as compared to
the same period in 2008.  Revenue sensitive taxes increased $9.3
million due to an increase in revenue offset by a decrease of $2.7 million in
property taxes from a true-up of accrued property taxes recorded for
2008.







Capital
Requirements


Contractual
Obligations and Commercial Commitments


The
following are PSE’s aggregate consolidated commercial commitments as of March
31, 2009:





Amount
      of Commitment
                      Expiration
      Per PeriodCommercial
      Commitments
                      (Dollars
      in Millions)
                    
                    Total
                    
                    
                    2009
                    
                    
                    
                    2010-
                      2011
                    
                    
                    
                    2012-
                      2013
                    
                    
                    2014
      &
                      ThereafterWorking
      capital facility
                    
                    $
                    225.0
                    
                    
                    $
                    --
                    
                    
                    $
                    --
                    
                    
                    $
                    --
                    
                    
                    $
                    225.0Capital
      expenditure facility
                    
                    
                    400.0
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    400.0Energy
      hedging facility
                    
                    
                    315.0
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    315.0Energy
      operations letter of credit
                    
                    
                    6.6
                    
                    
                    
                    6.6
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    --Energy
      hedging letter of credit
                    
                    
                    35.0
                    
                    
                    
                    35.0
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    --Total
      commercial commitments
                    
                    $
                    981.6
                    
                    
                    $
                    41.6
                    
                    
                    $
                    --
                    
                    
                    $
                    --
                    
                    
                    $
                    940.0





The
following are PSE’s aggregate contractual obligations and commercial commitments
as of March 31, 2009:





Payments
      Due Per PeriodContractual
      Obligations
                      (Dollars
      in Millions)
                    
                    Total
                    
                    
                    2009
                    
                    
                    
                    2010-
                      2011
                    
                    
                    
                    2012-
                      2013
                    
                    
                    2014
      &
                      ThereafterLong-term
      debt including interest
                    
                    $
                    6,243.9
                    
                    
                    $
                    146.3
                    
                    
                    $
                    809.6
                    
                    
                    $
                    305.7
                    
                    
                    $
                    4,982.3Short-term
      debt including interest
                    
                    
                    194.5
                    
                    
                    
                    194.5
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    --Service
      contract obligations
                    
                    
                    398.3
                    
                    
                    
                    51.9
                    
                    
                    
                    129.2
                    
                    
                    
                    82.3
                    
                    
                    
                    134.9Non-cancelable
      operating leases
                    
                    
                    193.6
                    
                    
                    
                    47.4
                    
                    
                    
                    28.9
                    
                    
                    
                    27.7
                    
                    
                    
                    89.6Fredonia gas-fired generating facility lease 1
                    
                    
                    46.3
                    
                    
                    
                    46.3
                    
                    
                    
                    --
                    
                    
                    
                    --
                    
                    
                    
                    --Energy
      purchase obligations
                    
                    
                    4,796.2
                    
                    
                    
                    645.5
                    
                    
                    
                    1,635.2
                    
                    
                    
                    772.0
                    
                    
                    
                    1,743.5Contract initiation payment/collateral requirement
                    
                    
                    18.5
                    
                    
                    
                    --
                    
                    
                    
                    18.5
                    
                    
                    
                    --
                    
                    
                    
                    --Financial
      hedge obligations
                    
                    
                    112.6
                    
                    
                    
                    59.7
                    
                    
                    
                    52.9
                    
                    
                    
                    --
                    
                    
                    
                    --Purchase
      obligations
                    
                    
                    130.1
                    
                    
                    
                    73.1
                    
                    
                    
                    6.6
                    
                    
                    
                    6.8
                    
                    
                    
                    43.6Non-qualified pension and other benefits funding and
    payments
                    
                    
                    67.8
                    
                    
                    
                    21.5
                    
                    
                    
                    8.8
                    
                    
                    
                    9.9
                    
                    
                    
                    27.6Total
      contractual cash obligations
                    
                    $
                    12,201.8
                    
                    
                    $
                    1,286.2
                    
                    
                    $
                    2,689.7
                    
                    
                    $
                    1,204.4
                    
                    
                    $
                    7,021.5


______________


1
              See
      “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
      below.





Off-Balance
Sheet Arrangements


Fredonia 3 and 4 Operating
Lease.PSE
leases two gas-fired turbines for its Fredonia 3 and 4 generating facility
pursuant to a master operating lease that was amended for this purpose in April
2001.  On November 14, 2008, GE Capital Commercial Inc. notified PSE
of its intentions to cancel the lease effective January 14, 2009.  PSE
intends to purchase the gas-fired turbines by January 2010.  Payments
under the lease vary with changes in the London Interbank Offered Rate
(LIBOR).  At March 31, 2009, PSE’s outstanding balance under the lease
was $44.7 million.  The expected residual value under the lease is the
lesser of $42.3 million or 60.0% of the cost 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
Allowance for Funds Used During Construction (AFUDC) and customer refundable
contributions, was $177.7 million for the three months ended March 31,
2009.  The anticipated utility construction expenditures, excluding
AFUDC, for 2009, 2010 and 2011 are:





Capital
      Expenditure Estimates
                    (Dollars
      in Millions)
                  
                  2009
                  
                  
                  2010
                  
                  
                  2011Energy
      delivery, technology and facilities
                  
                  $
                  687
                  
                  
                  $
                  840
                  
                  
                  $
                  786New
      supply resources
                  
                  
                  234
                  
                  
                  
                  621
                  
                  
                  
                  346Total
      expenditures
                  
                  $
                  921
                  
                  
                  $
                  1,461
                  
                  
                  $
                  1,132





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





Capital
Resources


Cash
From Operations


Cash
generated from operations for the three months ended March 31, 2009 was $213.9
million, a decrease of $118.8 million from the $332.7 million generated during
the first quarter of 2008.  The decrease was primarily the result of
an increase of $118.7 million in natural gas payments and payment of gas
financial hedge contracts, power cost and other payable balances as compared to
the same period in 2008.  Further, PSE received a refund of $39.7
million in income taxes in the first quarter 2008 compared to a refund of $0.2
million in 2009 which resulted in a decrease of $39.5 million in the current
quarter.  Also contributing to the decrease in operating activities
was a Colstrip legal settlement accrual of $10.5 million in the first quarter
2008 and an increase in fuel and gas inventories and materials and supplies of
$18.2 million over the same period in 2008.  PSE increased first
quarter 2009 prepayments by $13.0 million compared to the same period in
2008.


The
decrease in cash generated from operating activities for the first quarter 2009
as compared to 2008 was partially offset by overrecovery of natural gas costs
through the PGA mechanism during the first quarter 2009 of $20.8 million
compared to an underrecovery of $9.4 million during the same period in 2008
which increased operating activities by $30.2 million.  Further, PSE
collected $21.5 million in accounts receivable in 2009 over 2008.





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
capital markets.  PSE anticipates refinancing the redemption of bonds
with its liquidity facilities and/or the issuance of new
bonds.  Access to funds depends upon factors such as general economic
conditions, regulatory climate and policies and PSE’s credit
ratings.


On
January 23, 2009, PSE issued $250.0 million of first mortgage
bonds.  The bonds were placed with approximately 35 institutional
investors, have a term of seven years and carry a 6.75% coupon.





Liquidity
Facilities and Commercial Paper


PSE’s
short-term borrowings and sales of commercial paper are used to provide working
capital and funding of utility construction programs.  PSE has not
been significantly impacted by the recent disruption in the credit
environment.





PSE
Credit Facilities


Credit
Agreements.  Effective immediately after the merger on February
6, 2009, PSE has three committed unsecured revolving credit facilities that
provide, in aggregate, $1.15 billion in short-term borrowing
capability.  These new facilities include a $400.0 million credit
agreement for working capital needs, a $400.0 million credit facility for
funding capital expenditures and a $350.0 million facility to support other
working capital and energy hedging activities.


These
facilities mature in February 2014 and each contain similar terms and conditions
and are syndicated among numerous banks.  The agreements provide PSE
with the ability to borrow at either a base rate (which is based on the Prime
Rate) or the Eurodollar rate (which is based on the LIBOR), plus a
spread.  The Company must also pay a commitment fee on the unused
portion of the facilities. The spread and the commitment fee depend on PSE’s
credit ratings as determined by S&P and Moody’s.  At the Company’s
current credit ratings, the spread is 85 basis points and the commitment fee is
26 basis points.  The $400.0 million working capital facility and
$350.0 million credit agreement to support energy hedging permit the issuance of
standby letters of credit up to the entire amount of the credit
agreements.  The $400.0 million working capital facility also serves
as a backstop for PSE’s commercial paper program.


As of
March 31, 2009, PSE had borrowed $175.0 million on the $400.0 million working
capital facility and had a $35.0 million letter of credit outstanding under the
$350.0 million facility.  There were no borrowings under the $400.0
million capital expenditure facility as of March 31, 2009.  In
addition to the credit agreements, PSE had a $6.6 million letter of credit
through a bank in support of a long-term transmission contract.





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 or (b) PSE’s senior unsecured revolving credit
facility.  At March 31, 2009, the outstanding balance of the Note was
$19.4 million.  This Note is unaffected by the February 6, 2009
merger.





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 March 31, 2009, PSE could issue:


·
            approximately
      $1.0 billion of additional first mortgage bonds under PSE’s electric
      mortgage indenture based on approximately $1.7 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 March 31,
      2009;


·
            approximately
      $560.0 million of additional first mortgage bonds under PSE’s natural gas
      mortgage indenture based on approximately $930.0 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 March 31, 2009;


At March
31, 2009, PSE had approximately $5.1 billion in electric and natural gas
ratebase to support the interest coverage ratio limitation test for net earnings
available for interest.





Credit
Ratings


PSE has
no 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-2/P-3 ratings by S&P’s and Moody’s.  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.


On
January 16, 2009, S&P’s Rating Services raised its corporate credit rating
on PSE and removed it from its watch list for negative implications citing a
stable outlook.  The rating actions reflected the anticipated
completion of the acquisition of Puget Energy and PSE by Puget Holdings, which
occurred on February 6, 2009.


On
February 2, 2009, Moody’s affirmed the long-term ratings of PSE.  The
ratings outlook for PSE is stable.


The
ratings of PSE, as of April 27, 2009, were as follows:





RatingsS&P1
              Moody’s2Puget
      Sound EnergyCorporate
      credit/issuer rating
              BBB
              Baa3Senior
      secured debt
              A-
              Baa2Junior
      subordinated notes
              BB+
              Ba1Preferred
      stock
              BB+
              Ba2Commercial
      paper
              A-2
              P-3Bank
      facilities
              BBB
              Baa3Ratings
      outlook
              Stable
              Stable _______________


1
              On
      January 16, 2009, S&P’s upgraded PSE’s corporate and other credit
      ratings.  It also removed all the ratings from negative watch,
      citing a stable outlook.2
              On
      February 2, 2009, Moody’s affirmed the long-term ratings of
      PSE.








Other





Regulation
and Rates


On April
17, 2009, the Washington Commission issued a final order approving and adopting
a settlement agreement that authorized PSE to defer certain ownership and
operating costs related to its purchase of the Mint Farm that will be incurred
prior to PSE recovering such costs in electric customer rates.  Under
Washington state law, a company may defer the costs associated with purchasing
and operating a gas plant that complies with the greenhouse gases (GHG)
emissions performance standard until the plant is included in rates or for two
years from the date of purchase, whichever is sooner.  As of March 31,
2009, PSE had established a regulatory asset of $7.7 million.  The
prudence of the Mint Farm acquisition, recovery of costs of Mint Farm and
compliance with the GHG emissions performance standard will be addressed in the
Company’s next rate proceeding.


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
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
issued a separate orderon January 15, 2009, that authorized the
continuation of the Power Cost Only Rate Case (PCORC) with certain modifications
to which the Washington Commission staff and the Company had
agreed.  The five procedural modifications to the PCORC include
extending the expected procedural schedule from five to six months, limiting the
power cost updates to one per PCORC unless an additional update is allowed by
the Washington Commission as part of the compliance filing, prohibiting the
overlap of PCORC and general rate cases (except for requests for interim rate
relief), shortening data request time from ten to five business days and
requiring the Company to provide its future energy resource model projections at
the outset of a case.


On
September 25, 2008, the Washington Commission approved PSE’s requested revisions
to its 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.





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,
2008 includes a summary relating to the western power market
proceedings.  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.


CPUC v.
FERC.  On August 2, 2006, the U.S. Court of Appeals for the
Ninth Circuit (Ninth Circuit) decided that FERC erred in excluding potential
relief for tariff violations for periods that pre-dated October 2, 2000 and
additionally ruled that FERC should consider remedies for transactions
previously considered outside the scope of the proceedings.  The
August 2, 2006 decision may adversely impact PSE’s ability to recover the full
amount of its California Independent System Operator (CAISO)
receivable.  The decision may also expose PSE to claims or liabilities
for transactions outside the previously defined “refund period.”  At
this time, the ultimate financial outcome for PSE is
unclear.  Rehearing by the Ninth Circuit was denied on April 6,
2009.  Parties have been engaged in court-sponsored settlement
discussions, and those discussions may result in some
settlements.  PSE is unable to predict either the outcome of the
proceedings or the ultimate financial effect on PSE.




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,
CaseNo. 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, CaseNo. 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
thisrecord 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 determined by BPAto be recovered through
reductions commencing October 2007 in REP payments for PSE’s residential and
small farm customers was approximately $207.2 million plus interest on
unrecovered amounts.  However, these BPA determinations are subject to
subsequent administrative and judicial review, which may alter or reverse such
determinations.PSE
and others, including a number of preference agency and investor-owned utility
customers of BPA, in December 2008 filed petitions for review in the Ninth
Circuit of various of these BPA determinations.  PSE is reviewing its
options in determining if it will contest the amounts withheld as improper
payments made since 2001.


In
September 2008, BPA and PSE signed a short-termResidential Purchase and
Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal
years ending September 30, 2009–2011.In December 2008, BPA
and PSE signed another long-term RPSA under which BPA is to pay REP benefits to
PSE for the period October 2011 through September 2028.  PSE and other
customers of BPA in December 2008 filed petitions for review in the Ninth
Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs
signed by other investor-owned utility customers of BPA) and BPA’s record of
decision regarding such RPSAs.  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 Priority Firm (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.




New
Accounting Pronouncements


On April
9, 2009, the Financial Standards Accounting Board (FASB) issued Staff Position
(FSP) No. 157-4, “Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly” (FSP No. 157-4).  FSP No. 157-4
provides additional guidance for estimating fair value in accordance with
Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”
(SFAS No. 157), when the volume and level of activity for the asset or liability
have significantly decreased.  FSP No. 157-4 also includes guidance on
identifying circumstances that indicate a transaction is not
orderly.  FSP No. 157-4 will be effective for the Company as of June
30, 2009.  The Company is currently assessing the impact of the FSP on
its SFAS No. 157 calculations and disclosures.


On April
9, 2009, FASB issued FSP No. 107-1, “Interim Disclosures about Fair Value of
Financial Instruments” (FSP No. 107-1).  FSP No. 107-1 amends SFAS No.
107, Disclosures about Fair Value of Financial Instruments, to require
disclosures about fair value of financial instruments for interim reporting
periods of publicly traded companies as well as in annual financial statements.
FSP No. 107-1 also amends APB Opinion No. 28, “Interim Financial Reporting,” to
require those disclosures in summarized financial information at interim
reporting periods.  FSP No. 107-1 will be effective for the Company as
of June 30, 2009.




Item 3.
            Quantitative
      and Qualitative Disclosure About Market
  Risk




Energy
Portfolio Management


The
Company maintains energy risk policies and procedures to manage commodity and
volatility risks and the related effects on credit, tax, accounting, financing
and liquidity. The Company’s Energy Management Committee establishes the
Company’s risk management policies and procedures, and monitors compliance. The
Energy Management Committee is comprised of certain Company officers and is
overseen by the Board of Directors.


The
Company is focused on commodity price exposure and risks associated with
volumetric variability in the gas and electric portfolios and the related
effects noted above.  It is not engaged in the business of assuming
risk for the purpose of speculative trading.  The Company hedges open
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 250 simulations of how the Company’s 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
      the energy portfolio prudently to serve retail load at overall least cost
      and limit undesired impacts on PSE’s customers and
      shareholders;·
            reduce
      power costs by extracting the value of the Company’s assets;
      and·
            meet
      the credit, liquidity, financing, tax and accounting requirements of the
      Company.





The
following table presents electric derivatives that do not meet the Normal
Purchase Normal Sale (NPNS) exception at March 31, 2009 and December 31, 2008
including contracts designated as cash flow hedges:





Electric
                            Derivatives(Dollars
      in Millions)
                          
                          March
      31,
                            2009
                          
                          December
      31,
                            2008Current
      asset
                          
                          $
                          1.3
                          
                          $
                          0.4Long-term
      asset
                          
                          
                          0.9
                          
                          
                          0.5Total
      assets
                          
                          $
                          2.2
                          
                          $
                          0.9Current
      liability
                          
                          $
                          151.9
                          
                          $
                          90.6Long-term
      liability
                          
                          
                          122.3
                          
                          
                          96.1Total
      liabilities
                          
                          $
                          274.2
                          
                          $
                          186.7





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
recognition of future changes in value in the income statements.  As
these contracts are settled, amounts previously deferred in other comprehensive
income (OCI) are recognized as energy costs and are included as part of the
Power Cost Adjustment (PCA) mechanism.


The
following table presents the impact of changes in the market value of derivative
instruments not meeting NPNS or cash flow hedge criteria to the Company’s
earnings for the three months ended March 31, 2009 and March 31,
2008:





(Dollars
      in millions)
            March
      31,
              2009
            March
      31,
              2008
            ChangeDecrease
      in earnings
            $  (2.3)
            $  (0.1)
            $  (2.2)





The
decrease in earnings in 2009 primarily relates to a $3.2 million unrealized loss
associated with the ineffective portion of cash flow hedges for two long-term
power supply agreements.


The
amount of unrealized gain (loss), net of tax, related to the Company’s
energy-related cash flow hedges under SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (SFAS No. 133), deferred in accumulated OCI
consisted of the following at March 31, 2009 and December 31, 2008:





(Dollars
      in Millions, net of tax)
            March
      31,
              2009
            December
      31,
              2008Other
      comprehensive income – unrealized loss
            $
      (166.3)
            $
      (111.7)





The
following table presents natural gas derivative contracts at March 31, 2009 and
December 31, 2008:





Gas
                          Derivatives(Dollars
      in millions)
                        
                        March
      31,
                          2009
                        
                        December
      31,
                          2008Current
      asset
                        
                        $
                        20.9
                        
                        $
                        15.2Long-term
      asset
                        
                        
                        9.3
                        
                        
                        6.2Total
      assets
                        
                        $
                        30.2
                        
                        $
                        21.4Current
      liability
                        
                        $
                        172.4
                        
                        $
                        146.3Long-term
      liability
                        
                        
                        54.4
                        
                        
                        62.3Total
      liabilities
                        
                        $
                        226.8
                        
                        $
                        208.6





At March
31, 2009, the Company had total assets of $30.2 million and total liabilities of
$226.8 million related to financial contracts used to economically hedge the
cost of physical gas purchased to serve natural gas customers.  All
fair value adjustments on derivatives 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 gas costs under the PGA
mechanism.


A
hypothetical 10.0% decrease in market prices of natural gas and electricity
would decrease the fair value of derivative contracts by $93.6 million, with a
corresponding after-tax decrease in OCI and earnings of $33.3 million and $2.3
million, respectively, after-tax, and would decrease the fair value of those
contracts marked-to-market in earnings by $1.6 million after-tax.  A
discussion of the Level 3 valuation is included in Note 4, “Fair Value
Measurements.”





Contingent
Features and Counterparty 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
and exposure monitoring and exposure mitigation.


Where
deemed appropriate, the Company may request collateral or other security from
its counterparties to mitigate the potential credit default losses. 
Criteria employed in this decision includes, among other things, the perceived
creditworthiness of the counterparty and the expected credit
exposure.  As of March 31, 2009, the Company held approximately $1.1
million worth of standby letters of credit in support of various
electricity and renewable energy credit transactions.


It is
possible that volatility in energy commodity prices could cause the Company to
have material credit risk exposures with one or more
counterparties.  If such counterparties fail to perform their
obligations under one or more agreements, the Company could suffer a material
financial loss.  However, as of March 31, 2009, approximately 99.6% of
the counterparties with transaction amounts outstanding in the Company’s energy
portfolio, including NPNS transactions, are rated at least investment grade by
the major rating agencies and 0.4% are either rated below investment grade or
are not rated by rating agencies.  The Company assesses credit risk
internally for counterparties that are not rated.


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.  The Company believes that entering into such
agreements reduces the risk of default by allowing a counterparty the ability to
make only one net payment.


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. Counterparty credit
risk 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 amount 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.


The
Company computes credit reserves at a master agreement level (i.e. WSPP, ISDA or
NAESB) by counterparty. The Company considers external credit ratings and market
factors, such as credit default swaps and bond spreads in determination of
reserves.  The Company recognizes that external ratings may not always
reflect how a market participant perceives a counterparty’s risk of
default.  The Company uses both default factors published by S&P
and factors derived through analysis of market risk, which reflect the
application of an industry standard recovery rate.   The Company
selects a default factor by counterparty at an aggregate master agreement level
based on a weighted average default tenor for that counterparty’s
deals.  The default tenor is used by weighting fair values and
contract tenors for all deals for each counterparty and coming up with an
average value.   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 to compute credit reserves for
counterparties in a net liability position. The Company’s S&P rating at
March 31, 2009 was BBB.  Credit reserves are booked as contra accounts
to unrealized gain (loss) positions. As of March 31, 2009, 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 the
year.





Interest
Rate Risk


The
Company believes its interest rate risk primarily relates to the use of
short-term debt instruments, variable-rate notes and leases and 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 bank borrowings,
commercial paper and line of credit facilities 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 Company did not have any swap instruments
outstanding as of March 31, 2009; however from time to time the Company may
enter into treasury lock or forward starting swap contracts to hedge interest
rate exposure related to an anticipated debt issuance.  The ending
balance in other comprehensive income related to the forward starting swaps and
previously settled treasury lock contracts at March 31, 2009 is a net loss of
$7.8 million after tax and accumulated amortization.  This compares to
a loss of $7.9 million in other comprehensive income after-tax and accumulated
amortization at December 31, 2008.  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
Sound Energy


Evaluation
of Disclosure Controls and Procedures


Under the
supervision and with the participation of PSE’s management, including the
President and Chief Executive Officer and 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 March 31, 2009, the end of the period covered by
this report.  Based upon that evaluation, the 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 March 31, 2009, 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 “Other”
of 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 March 31,
2009.  Litigation is subject to numerous uncertainties and PSE is
unable to predict the ultimate outcome of these matters.




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,
2008.




Item
6.              Exhibits




See
Exhibit Index for list of exhibits.


SIGNATURES


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





PUGET
      SOUND ENERGY, INC./s/
      James W. EldredgeJames
      W. EldredgeVice
      President, Controller and Chief Accounting OfficerDate:  May
      5,2009Chief
      accounting officer and officer duly authorized to sign this report on
      behalf of registrant








EXHIBIT
INDEX








4.1**
                Fortieth
      through Sixtieth Supplemental Indentures defining the rights of the
      holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds
      (incorporated herein by reference to Exhibits 4.3 through 4.23 to PSE’s
      Registration Statement on Form S-3, dated March 13, 2009, Commission File
      No. 333-157960).4.2**
                Indenture
      of First Mortgage, dated as of April 1, 1957, defining the rights of the
      holders of Puget Sound Energy’s Gas Utility First Mortgage Bonds
      (incorporated herein by reference to Exhibit 4.25 to PSE's Registration
      Statement on Form S-3, dated March 13, 2009, Commission File No.
      333-157960).4.3**
                First,
      Sixth, Seventh, Sixteenth and Seventeenth Supplemental Indenture to the
      Gas Utility First Mortgage (incorporated herein by reference to Exhibits
      4.26 through 4.30 to PSE’s Registration Statement on Form S-3, dated March
      13, 2009, Commission File No. 333-157960).10.1*
                First
      Amendment dated as of October 4, 1961 to Power Sales Contract between
      Public Utility District No. 1 of Chelan County, Washington and Puget Sound
      Energy, Inc., relating to the Rocky Reach Project.10.2*
                First
      Amendment dated February 9, 1965 to Power Sales Contract between Public
      Utility District No. 1 of Douglas County, Washington and Puget Sound
      Energy, Inc., relating to the Wells Development.10.3*
                Contract
      dated November 14, 1957 between Public Utility District No. 1 of Chelan
      County, Washington and Puget Sound Energy, Inc., relating to the Rocky
      Reach Project.10.4*
                Power
      Sales Contract dated as of November 14, 1957 between Public Utility
      District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc.,
      relating to the Rocky Reach Project.10.5*
                Power
      Sales Contract dated May 21, 1956 between Public Utility District No. 2 of
      Grant County, Washington and Puget Sound Energy, Inc., relating to the
      Priest Rapids Project.10.6*
                First
      Amendment to Power Sales Contract dated as of August 5, 1958 between Puget
      Sound Energy, Inc. and Public Utility District No. 2 of Grant County,
      Washington, relating to the Priest Rapids Development.10.7*
                Power
      Sales Contract dated June 22, 1959 between Public Utility District No. 2
      of Grant County, Washington and Puget Sound Energy, Inc., relating to the
      Wanapum Development.10.8*
                Agreement
      to Amend Power Sales Contracts dated July 30, 1963 between Public Utility
      District No. 2 of Grant County, Washington and Puget Sound Energy, Inc.,
      relating to the Wanapum Development.10.9*
                Power
      Sales Contract executed as of September 18, 1963 between Public Utility
      District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc.,
      relating to the Wells Development.10.10*
                Construction
      and Ownership Agreement dated as of July 30, 1971 between The Montana
      Power Company and Puget Sound Energy, Inc.10.11*
                Operation
      and Maintenance Agreement dated as of July 30, 1971 between The Montana
      Power Company and Puget Sound Energy, Inc.10.12*
                Contract
      dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of
      Chelan County.10.13+
                Form
      of Executive Employment Agreement between Puget Sound Energy, Inc. and
      each of Eric M. Markell, Kimberly J. Harris, Jennifer L. O’Connor, James
      W. Eldredge, Donald E. Gaines and Bertrand A. Valdman (incorporated herein
      by reference to Exhibit 10.1 to Current Report on Form 8-K dated April 3,
      2009).12.1*
                Statement
      setting forth computation of ratios of earnings to fixed charges (2004
      through 2008 and 12 months ended March 31, 2009) for
  PSE.31.1*
                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 2002.31.2*
                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.





* Filed
herewith.


**
Previously filed with a report or registration statement that is more than 30
years old and therefore refiled with, orincorporated by reference into, this
report.


+
Management contract or compensating plan or arrangement.