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, 2005**
      
      **OR**
 ****
 
 [ 
      ]
    **TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF**
      **THE
      SECURITIES EXCHANGE ACT OF 1934**
 
 
 **For
      the Transition period from ________ to
  _________**
 
 
 Commission
      File
      Number
    Exact
      name of registrant as specified
      in
      its charter, state of incorporation,
      address
      of principal executive offices,
      telephone
      number
    I.R.S.
      Employer
      Identification
      Number
 
 
 1-16305
    **PUGET
      ENERGY, INC.**
      A
      Washington Corporation
      10885
      NE 4thStreet, Suite 1200
      Bellevue,
      Washington 98004-5591
      (425)
      454-6363
    91-1969407
 
 
 1-4393
    **PUGET
      SOUND ENERGY, INC.**
      A
      Washington Corporation
      10885
      NE 4thStreet, Suite 1200
      Bellevue,
      Washington 98004-5591
      (425)
      454-6363
    91-0374630
  Indicate
      by check mark whether the registrants: (1) have filed all reports required
      to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
      during the preceding 12 months (or for such shorter period that the
      registrants were required to file such reports), and (2) have been subject
      to such filing requirements for the past 90
days.
 Yes
    X
    
    No
  Indicate
      by check mark whether Puget Energy, Inc. is an accelerated filer (as
      defined in Rule 12b-2 of the Exchange Act).Yes
    X
    
    NoIndicate
      by check mark whether Puget Sound Energy, Inc. is an accelerated filer (as
      defined in Rule 12b-2 of the Exchange Act).Yes
    
    
    No
    X
  As of
April 22, 2005, (i) the number of shares of Puget Energy, Inc. common stock
outstanding was 100,050,643 ($.01 par value) and (ii) all of the outstanding
shares of Puget Sound Energy, Inc. common stock were held by Puget Energy, Inc.
 **Table of Contents**
 
 **Definitions****Filing Format****Forward Looking
    Statements****Part I.**
    **Financial
      Information****Item 1.**
    **Financial
    Statements****Puget
      Energy, Inc.**Consolidated Statements of Income - Three
      Months Ended
      March 31, 2005 and
    2004Consolidated Statements of
      Comprehensive Income - Three Months Ended
      March
      31, 2005 and 2004Consolidated Balance Sheets - March 31, 2005
      and December 31, 2004Consolidated Statements of Cash Flows -
      Three Months Ended
      March 31, 2005 and 2004**Puget
      Sound Energy, Inc.**Consolidated Statements of Income - Three Months
      Ended
      March 31, 2005 and 2004Consolidated Statements of Comprehensive Income
      - Three Months Ended
      March 31, 2005 and 2004Consolidated Balance Sheets - March 31, 2005 and
      December 31, 2004Consolidated Statements of Cash Flows - Three Months
      Ended
      March 31, 2005 and 2004**Notes**Combined Notes to Consolidated Financial
      Statements**Item 2.**
    **Management’s Discussion and Analysis of Financial Condition**
      **and Results of Operations****Item 3.**
    **Quantitative and Qualitative Disclosure About
      Market Risk****Item 4.**
    **Controls and Procedures****Part II.**
    **Other Information****Item 1.**
    **Legal
    Proceedings****Item 6.**
    **Exhibits****Signatures****Exhibit Index**
  
 Table of Contents
  **DEFINITIONS**
 
 APB
    Accounting
      Principles BoardCAISO
    California
      Independent System OperatorFASB
    Financial
      Accounting Standards BoardFERC
    Federal
      Energy Regulatory CommissionFIN
    Financial
      Accounting Standards Board InterpretationFPA
    Federal
      Power ActInfrastruX
    InfrastruX
      Group, Inc.LIBOR
    London
      Interbank Offered RateMMS
    Mineral
      Management Service of the United States Department of the
      InteriorMW
    Megawatts
      (one MW equals one thousand kW)MWh
    Megawatt
      Hours (one MWh equals one thousand kWh)PCA
    Power
      Cost AdjustmentPCORC
    Power
      Cost Only Rate CasePGA
    Purchased
      Gas AdjustmentPG&E
    Pacific
      Gas & Electric CompanyPSE
    Puget
      Sound Energy, Inc.Puget
      Energy
    Puget
      Energy, Inc.SFAS
    Statement
      of Financial Accounting StandardsWECO
    Western
      Energy CompanyWashington
      Commission
    Washington
      Utilities and Transportation Commission
 
 
 **FILING FORMAT**
 This
Quarterly Report on Form 10-Q is a combined quarterly report being filed
separately by two different registrants, Puget Energy, Inc. (Puget Energy) and
Puget Sound Energy, Inc. (PSE). Any references in this report to the “Company”
are to Puget Energy and PSE collectively. PSE makes no representation as to the
information contained in this report relating to Puget Energy and the
subsidiaries of Puget Energy other than PSE and its subsidiaries.
 
  Table of Contents
  
 **FORWARD-LOOKING STATEMENTS**
 Puget
Energy and Puget Sound Energy (PSE) are including the following cautionary
statements in this Form 10-Q to make applicable and to take advantage of the
safe harbor provisions of the Private Securities Litigation Reform Act of 1995
for any forward-looking statements made by or on behalf of Puget Energy or PSE.
This report includes forward-looking statements, which are statements of
expectations, beliefs, plans, objectives, assumptions of future events or
performance. Words or phrases such as “anticipates,” “believes,” “estimates,”
“expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,”
“will continue” or similar expressions identify forward-looking
statements.
 Forward-looking
statements involve risks and uncertainties that could cause actual results or
outcomes to differ materially from those expressed. Puget Energy’s and PSE’s
expectations, beliefs and projections are expressed in good faith and are
believed by Puget Energy and PSE, as applicable, to have a reasonable basis,
including without limitation management’s examination of historical operating
trends, data contained in records and other data available from third parties;
but there can be no assurance that Puget Energy’s and PSE’s expectations,
beliefs or projections will be achieved or accomplished.
 In
addition to other factors and matters discussed elsewhere in this report, some
important factors that could cause actual results or outcomes for Puget Energy
and PSE to differ materially from those discussed in forward-looking statements
include:
 
 **Risks
relating to the regulated utility business (PSE)**
 ·
    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, financings, industry and rate structures,
      transmission and generation business structures within PSE, acquisition
      and disposal of assets and facilities, operation, maintenance and
      construction of electric generating facilities, operation of distribution
      and transmission facilities (gas and electric), licensing of hydroelectric
      operations and gas storage facilities, recovery of other capital
      investments, recovery of power and gas costs, recovery of regulatory
      assets, and present or prospective wholesale and retail
      competition;
 ·
    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;
 ·
    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, affect wholesale
      energy prices and/or impede PSE’s ability to manage its energy portfolio
      risks and procure energy supply;
 ·
    the
      effect of wholesale market structures (including, but not limited to,
      regional market designs such as Grid West, or federal initiatives such as
      Standard Market Design);
 ·
    PSE
      electric or gas distribution system failure, which may impact PSE’s
      ability to adequately deliver gas supply to its
  customers;
 ·
    weather,
      which can have a potentially serious impact on PSE’s revenues and its
      ability to procure adequate supplies of gas, fuel or purchased power to
      serve its customers and on the cost of procuring such
      supplies;
 ·
    variable
      hydroelectric conditions, which can impact streamflow and PSE’s ability to
      generate electricity from hydroelectric
facilities;
 ·
    plant
      outages, which can have an adverse impact on PSE’s expenses as it procures
      adequate supplies to replace the lost energy or dispatches a more
      expensive resource;
 ·
    the
      ability of gas or electric plant to operate as intended, which if not in
      proper operating condition or design could limit the capacity of the
      operating plant;
 ·
    the
      ability to renew contracts for electric and gas supply and the price of
      renewal;
 ·
    blackouts
      or large curtailments of transmission systems, whether PSE’s or others’,
      which can have an impact on PSE’s ability to deliver load to its
      customers;
 ·
    the
      ability to restart generation following a regional transmission
      disruption;
 ·
    failure
      of the interstate gas pipeline delivering to PSE’s system, which may
      impact PSE’s ability to adequately deliver gas supply to its
      customers;
 ·
    the
      ability to relicense FERC hydroelectric projects at a cost-effective
      level;
 ·
    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;
and
 ·
    the
      loss of significant customers or changes in the business of significant
      customers, which may result in changes in demand for PSE’s
      services.
 
 **Risks
relating to the non-regulated utility service business (InfrastruX Group,
Inc.)**
 ·
    the
      ability of Puget Energy to complete a sale of its interests in InfrastruX
      to a third party under reasonable terms;
 ·
    the
      failure of InfrastruX to service its obligations under its credit
      agreement, in which case Puget Energy, as guarantor, may be required to
      satisfy these obligations, which could have a negative impact on Puget
      Energy’s liquidity and access to capital;
 ·
    the
      inability to generate internal growth at InfrastruX, which could be
      affected by, among other factors, InfrastruX’s ability to expand the range
      of services offered to customers, attract new customers, increase the
      number of projects performed for existing customers, hire and retain
      employees and open additional facilities;
 ·
    the
      effect of competition in the industry in which InfrastruX competes,
      including from competitors that may have greater resources than
      InfrastruX, which may enable them to develop expertise, experience and
      resources to provide services that are superior in quality or lower in
      price;
 ·
    the
      extent to which existing electric power and gas companies or prospective
      customers will continue to outsource services in the future, which may be
      impacted by, among other things, regional and general economic conditions
      in the markets InfrastruX serves;
 ·
    delinquencies,
      including those associated with the financial conditions of InfrastruX’s
      customers;
 ·
    the
      impact of any goodwill impairments on the results of operations of
      InfrastruX arising from its acquisitions, which could have a negative
      effect on the results of operations of Puget
Energy;
 ·
    the
      impact of adverse weather conditions that negatively affect operating
      conditions and results;
 ·
    the
      ability to obtain adequate bonding coverage and the cost of such bonding;
      and
 ·
    the
      perception of risk associated with its business due to a challenging
      business environment.
 
 **Risks
relating to both the regulated and non-regulated
businesses**
 ·
    the
      impact of acts of terrorism or similar significant
  events;
 ·
    the
      ability of Puget Energy, PSE and InfrastruX to access the capital markets
      to support requirements for working capital, construction costs and the
      repayment of maturing debt;
 ·
    capital
      market conditions, including changes in the availability of capital or
      interest rate fluctuations;
 ·
    changes
      in Puget Energy’s or PSE’s credit ratings, which may have an adverse
      impact on the availability and cost of capital for Puget Energy, PSE and
      InfrastruX;
 ·
    legal
      and regulatory proceedings;
 ·
    the
      ability to recover changes in enacted federal, state or local tax laws
      through revenue in a timely manner;
 ·
    changes
      in, adoption of and compliance with laws and regulations including
      environmental and endangered species laws, regulations, decisions and
      policies concerning the environment, natural resources, and fish and
      wildlife (including the Endangered Species
Act);
 ·
    employee
      workforce factors, including strikes, work stoppages, availability of
      qualified employees or the loss of a key executive;
 ·
    the
      ability to obtain and keep patent or other intellectual property rights to
      generate revenue;
 ·
    the
      ability to obtain adequate insurance coverage and the cost of such
      insurance;
 ·
    the
      impacts of natural disasters such as earthquakes, hurricanes, floods,
      fires or landslides;
 ·
    the
      impact of adverse weather conditions that negatively affect operating
      conditions and results;
 ·
    the
      ability to maintain effective internal controls over financial reporting;
      and
 ·
    the
      ability to maintain customers and
employees.
 
 Any
forward-looking statement speaks only as of the date on which such statement is
made, and, except as required by law, Puget Energy and PSE undertake no
obligation to update any forward-looking statement to reflect events or
circumstances after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time to time and it
is not possible for management to predict all such factors, nor can it assess
the impact of any such factor on the business or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
 Table of Contents
 **PART
I****FINANCIAL
INFORMATION**
 Item
1.**Financial
Statements**
 
 **PUGET ENERGY, INC.**
 CONSOLIDATED
STATEMENTS OF INCOME
 (Dollars
in thousands except per share amounts)
 (Unaudited)
 
 Three
      Months Ended
      March
      312005
    
    2004Operating
      Revenues:Electric
    $
    420,090
    
    $
    392,495Gas
    
    321,129
    
    
    275,692Other
    
    434
    
    
    527Total
      operating revenues
    
    741,653
    
    
    668,714Operating
      Expenses:Energy
      costs:Purchased
      electricity
    
    208,178
    
    
    196,367Electric
      generation fuel
    
    20,448
    
    
    13,988Residential
      exchange
    
    (55,046
    )
    
    (54,423
    )Purchased
      gas
    
    201,744
    
    
    162,407Unrealized
      (gain) loss on derivative instruments
    
    509
    
    
    (87
    )Utility
      operations and maintenance
    
    75,522
    
    
    73,855Other
      operations and maintenance
    
    741
    
    
    484Depreciation
      and amortization
    
    58,077
    
    
    55,870Conservation
      amortization
    
    5,162
    
    
    8,190Taxes
      other than income taxes
    
    69,700
    
    
    64,224Income
      taxes
    
    46,084
    
    
    39,097Total
      operating expenses
    
    631,119
    
    
    559,972Operating
      Income
    
    110,534
    
    
    108,742Other
      income (deductions):Other
      income
    
    1,164
    
    
    68Interest
      charges:AFUDC
    
    1,462
    
    
    1,078Interest
      expense
    
    (41,044
    )
    
    (43,121
    )Mandatorily
      redeemable securities interest expense
    
    (23
    )
    
    (23
    )Income
      from continuing operations
    
    72,093
    
    
    66,744Loss
      from discontinued operations, net of tax
    
    (1,018
    )
    
    (379
    )Net
      income
    $
    71,075
    
    $
    66,365Common
      shares outstanding weighted average (in thousands)
    
    99,953
    
    
    99,169Diluted
      common shares outstanding weighted average (in thousands)
    
    100,446
    
    
    99,637Basic
      and diluted earnings per common share from continuing
      operations
    $
    0.72
    
    $
    0.67Basic
      and diluted earnings per common share from discontinued
      operations
    
    (0.01
    )
    
    --Basic
      and diluted earnings per common share
    $
    0.71
    
    $
    0.67
 
 *The
accompanying notes are an integral part of the financial
statements.*
 Table of Contents
  
 **PUGET ENERGY, INC.**
 CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
 (Dollars
in thousands)
 (Unaudited)
 
 Three
      Months Ended
      March
      312005
    
    2004Net
      income
    $
    71,075
    
    $
    66,365Other
      comprehensive income, net of tax:Foreign
      currency translation adjustment
    
    3
    
    
    265Unrealized
      gains on derivative instruments during the period
    
    15,658
    
    
    7,305Reversal
      of unrealized gains on derivative instruments settled
      during
      the period
    
    (1,817
    )
    
    (2,570
    )Deferral
      related to power cost adjustment mechanism
    
    (5,563
    )
    
    (4,687
    )Other
      comprehensive income
    
    8,281
    
    
    313Comprehensive
      income
    $
    79,356
    
    $
    66,678
 
 *The
accompanying notes are an integral part of the financial
statements.* ****
  Table of Contents
   **PUGET ENERGY, INC.**
 CONSOLIDATED
BALANCE SHEETS
 (Dollars
in thousands)
 (Unaudited)
 
 **ASSETS**
 
 March
      31,
      2005
    
    March
      31,
      2004Utility
      Plant: (at original cost, including construction work in progress of
      $179,518and
      $129,966, respectively)Electric
    $
    4,441,017
    
    $
    4,389,882Gas
    
    1,911,542
    
    
    1,881,768Common
    
    417,343
    
    
    409,677Less:
      Accumulated depreciation and amortization
    
    (2,480,458
    )
    
    (2,452,969
    )Net
      utility plant
    
    4,289,444
    
    
    4,228,358Other
      property and investments
    
    160,830
    
    
    157,670Current
      assets:Cash
    
    13,984
    
    
    12,955Restricted
      cash
    
    1,146
    
    
    1,633Accounts
      receivable, net of allowance for doubtful accounts
    
    268,977
    
    
    137,659Unbilled
      revenue
    
    111,992
    
    
    140,391Purchased
      gas adjustment receivable
    
    22,331
    
    
    19,088Materials
      and supplies, at average cost
    
    87,231
    
    
    97,578Unrealized
      gain on derivative instruments
    
    65,431
    
    
    14,791Prepayments
      and other
    
    11,819
    
    
    6,858Deferred
      income taxes
    
    --
    
    
    1,415Current
      assets of discontinued operations
    
    107,487
    
    
    110,922Total
      current assets
    
    690,398
    
    
    543,290Other
      long-term assets:Regulatory
      asset for deferred income taxes
    
    136,122
    
    
    127,252Regulatory
      asset for PURPA contract buyout costs
    
    206,223
    
    
    211,241Unrealized
      gain on derivative instruments
    
    22,223
    
    
    21,315Power
      cost adjustment mechanism
    
    15,020
    
    
    --Other
    
    339,505
    
    
    401,795Long-term
      assets of discontinued operations
    
    165,335
    
    
    160,298Total
      other long-term assets
    
    884,428
    
    
    921,901Total
      assets
    $
    6,025,100
    
    $
    5,851,219
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET
ENERGY, INC.**
 CONSOLIDATED
BALANCE SHEETS
 (Dollars
in thousands)
 (Unaudited)
 
 **CAPITALIZATION
AND LIABILITIES**
 
 March
      31,
      2005
    
    December
      31,
      2004Capitalization:Common
      shareholders’ investment:Common
      stock $0.01 par value, 250,000,000 shares authorized, 100,039,422 and
      99,868,368
      shares outstanding, respectively
    $
    1,000
    
    $
    999Additional
      paid-in capital
    
    1,625,844
    
    
    1,621,756Earnings
      reinvested in the business
    
    59,960
    
    
    13,853Accumulated
      other comprehensive loss, net of tax
    
    (6,051
    )
    
    (14,332
    )Total
      shareholders’ equity
    
    1,680,753
    
    
    1,622,276Redeemable
      securities and long-term debt:Preferred
      stock subject to mandatory redemption
    
    1,889
    
    
    1,889Junior
      subordinated debentures of the corporation payable to a subsidiary trust
      holding
      mandatorily redeemable preferred securities
    
    280,250
    
    
    280,250Long-term
      debt
    
    2,069,360
    
    
    2,069,360Total
      redeemable securities and long-term debt
    
    2,351,499
    
    
    2,351,499Total
      capitalization
    
    4,032,252
    
    
    3,973,775Minority
      interest in discontinued operations
    
    4,651
    
    
    4,648Current
      liabilities:Accounts
      payable
    
    202,613
    
    
    226,478Short-term
      debt
    
    97,051
    
    
    --Current
      maturities of long-term debt
    
    31,000
    
    
    31,000Accrued
      expenses:Taxes
    
    113,136
    
    
    81,315Salaries
      and wages
    
    13,341
    
    
    13,829Interest
    
    40,335
    
    
    29,005Unrealized
      loss on derivative instruments
    
    17,185
    
    
    26,581Deferred
      income taxes
    
    5,109
    
    
    --Tenaska
      disallowance reserve
    
    --
    
    
    3,156Other
    
    36,060
    
    
    34,918Current
      liabilities of discontinued operations
    
    54,847
    
    
    51,892Total
      current liabilities
    
    610,677
    
    
    498,174Long-term
      liabilities:Deferred
      income taxes
    
    807,786
    
    
    795,291Long-term
      portion of unrealized loss on derivative instruments
    
    --
    
    
    385Other
      deferred credits
    
    387,419
    
    
    395,236Long-term
      liabilities of discontinued operations
    
    182,315
    
    
    183,710Total
      long-term liabilities
    
    1,377,520
    
    
    1,374,622Total
      capitalization and liabilities
    $
    6,025,100
    
    $
    5,851,219
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET ENERGY, INC.**
 CONSOLIDATED
STATEMENTS OF CASH FLOWS
 (Dollars
in thousands)
 (Unaudited)
 
 Three
      Months Ended
      March
      312005
    
    2004Operating
      activities:Net
      income
    $
    71,075
    
    $
    66,365Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depreciation
      and amortization
    
    60,074
    
    
    60,288Deferred
      income taxes and tax credits - net
    
    6,075
    
    
    21,112Net
      unrealized (gain) loss on derivative instruments
    
    509
    
    
    (87
    )Cash
      collateral received from energy suppliers
    
    3,100
    
    
    --Decrease
      in residential exchange program
    
    (11,159
    )
    
    (10,296
    )Other
    
    (2,929
    )
    
    (2,798
    )Change
      in certain current assets and liabilities:Accounts
      receivable and unbilled revenue
    
    (97,786
    )
    
    (26,122
    )Materials
      and supplies
    
    10,702
    
    
    11,188Prepayments
      and other
    
    (8,656
    )
    
    (2,994
    )Purchased
      gas receivable
    
    (3,242
    )
    
    (11,083
    )Accounts
      payable
    
    (23,352
    )
    
    (29,958
    )Taxes
      payable
    
    31,720
    
    
    15,703Tenaska
      disallowance reserve
    
    (3,156
    )
    
    --Accrued
      expenses and other
    
    12,679
    
    
    15,621Net
      cash provided by operating activities
    
    45,654
    
    
    106,939Investing
      activities:Construction
      and capital expenditures-excluding equity AFUDC
    
    (124,376
    )
    
    (71,489
    )Energy
      efficiency expenditures
    
    (4,738
    )
    
    (4,440
    )Refundable
      cash received for customer construction projects
    
    3,582
    
    
    2,199Restricted
      cash
    
    486
    
    
    1,365Other
    
    5,515
    
    
    (1,924
    )Net
      cash used by investing activities
    
    (119,531
    )
    
    (74,289
    )Financing
      activities:Change
      in short-term debt - net
    
    100,035
    
    
    (155
    )Dividends
      paid
    
    (21,924
    )
    
    (21,604
    )Issuance
      of common stock
    
    1,017
    
    
    1,208Issuance
      of bonds and notes
    
    --
    
    
    625Redemption
      of bonds and notes
    
    (2,946
    )
    
    (23,356
    )Issuance
      costs of bonds and other
    
    (737
    )
    
    1,434Net
      cash provided (used) by financing activities
    
    75,445
    
    
    (41,848
    )Net
      increase (decrease) in cash
    
    1,568
    
    
    (9,198
    )Change
      in cash from discontinued operations
    
    (539
    )
    
    7,687Cash
      at beginning of year
    
    12,955
    
    
    14,778Cash
      at end of period
    $
    13,984
    
    $
    13,267Supplemental
      cash flow information:Cash
      payments for:Interest
      (net of capitalized interest)
    $
    32,511
    
    $
    35,982Income
      taxes
    
    22,000
    
    
    16,174
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET SOUND ENERGY, INC.**
 CONSOLIDATED
STATEMENTS OF INCOME
 (Dollars
in thousands)
 (Unaudited)
 
 Three
      Months Ended
      March
      312005
    
    2004Operating
      revenues:Electric
    $
    420,090
    
    $
    392,495Gas
    
    321,129
    
    
    275,692Other
    
    434
    
    
    527Total
      operating revenues
    
    741,653
    
    
    668,714Operating
      expenses:Energy
      costs:Purchased
      electricity
    
    208,178
    
    
    196,367Electric
      generation fuel
    
    20,448
    
    
    13,988Residential
      exchange
    
    (55,046
    )
    
    (54,423
    )Purchased
      gas
    
    201,744
    
    
    162,407Unrealized
      (gain) loss on derivative instruments
    
    509
    
    
    (87
    )Utility
      operations and maintenance
    
    75,522
    
    
    73,855Other
      operations and maintenance
    
    259
    
    
    300Depreciation
      and amortization
    
    58,077
    
    
    55,870Conservation
      amortization
    
    5,162
    
    
    8,190Taxes
      other than income taxes
    
    69,700
    
    
    64,224Income
      taxes
    
    46,545
    
    
    39,178Total
      operating expenses
    
    631,098
    
    
    559,869Operating
      income
    
    110,555
    
    
    108,845Other
      income (deductions):Other
      income, net of tax
    
    1,164
    
    
    68Interest
      charges:AFUDC
    
    1,462
    
    
    1,078Interest
      expense
    
    (40,976
    )
    
    (43,070
    )Mandatorily
      redeemable securities interest expense
    
    (23
    )
    
    (23
    )Net
      income
    $
    72,182
    
    $
    66,898
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET SOUND ENERGY, INC.**
 CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
 (Dollars
in thousands)
 (Unaudited)
 
 Three
      Months Ended
      March
      312005
    
    2004Net
      income
    $
    72,182
    
    $
    66,898Other
      comprehensive income, net of tax:Unrealized
      gains on derivative instruments during the period
    
    15,658
    
    
    7,305Reversal
      of unrealized gains on derivative instruments settled
      during
      the period
    
    (1,817
    )
    
    (2,570
    )Deferral
      related to power cost adjustment mechanism
    
    (5,563
    )
    
    (4,687
    )Other
      comprehensive income
    
    8,278
    
    
    48Comprehensive
      income
    $
    80,460
    
    $
    66,946
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET SOUND ENERGY, INC.**
 CONSOLIDATED
BALANCE SHEETS
 (Dollars
in thousands)
 (Unaudited)
 
 **ASSETS**
 
 March
      31,
      2005
    
    December
      31,
      2004Utility
      plant: (at original cost, including construction work in progress of
      $179,518
      and $129,966, respectively)Electric
    $
    4,441,017
    
    $
    4,389,882Gas
    
    1,911,542
    
    
    1,881,768Common
    
    417,343
    
    
    409,677Less:
      Accumulated depreciation and amortization
    
    (2,480,458
    )
    
    (2,452,969
    )Net
      utility plant
    
    4,289,444
    
    
    4,228,358Other
      property and investments
    
    160,830
    
    
    157,670Current
      assets:Cash
    
    13,984
    
    
    12,955Restricted
      cash
    
    1,146
    
    
    1,633Accounts
      receivable, net of allowance for doubtful accounts
    
    269,251
    
    
    138,792Unbilled
      revenues
    
    111,992
    
    
    140,391Purchased
      gas receivable
    
    22,331
    
    
    19,088Materials
      and supplies, at average cost
    
    87,231
    
    
    97,578Unrealized
      gain on derivative instruments
    
    65,431
    
    
    14,791Prepayments
      and other
    
    11,209
    
    
    6,247Deferred
      income taxes
    
    --
    
    
    1,415Total
      current assets
    
    582,575
    
    
    432,890Other
      long-term assets:Regulatory
      asset for deferred income taxes
    
    136,122
    
    
    127,252Regulatory
      asset for PURPA contract buyout costs
    
    206,223
    
    
    211,241Unrealized
      gain on derivative instruments
    
    22,223
    
    
    21,315Power
      cost adjustment mechanism
    
    15,020
    
    
    --Other
    
    338,806
    
    
    401,030Total
      other long-term assets
    
    718,394
    
    
    760,838Total
      assets
    $
    5,751,243
    
    $
    5,579,756
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET
SOUND ENERGY, INC.**
 CONSOLIDATED
BALANCE SHEETS
 (Dollars
in thousands)
 (Unaudited)
 
 **CAPITALIZATION
AND LIABILITIES**
 
 March
      31,
      2005
    
    December
      31,
      2005Capitalization:Common
      shareholder’s investment:Common
      stock ($10 stated value) - 150,000,000 shares authorized,
      85,903,791
      shares outstanding
    $
    859,038
    
    $
    859,038Additional
      paid-in capital
    
    610,368
    
    
    609,467Earnings
      reinvested in the business
    
    187,807
    
    
    138,678Accumulated
      other comprehensive loss, net of tax
    
    (6,472
    )
    
    (14,750
    )Total
      shareholder’s equity
    
    1,650,741
    
    
    1,592,433Redeemable
      securities and long-term debt:Preferred
      stock subject to mandatory redemption
    
    1,889
    
    
    1,889Junior
      subordinated debentures of the corporation payable to a subsidiary
      trust
      holding mandatorily redeemable preferred securities
    
    280,250
    
    
    280,250Long-term
      debt
    
    2,064,360
    
    
    2,064,360Total
      redeemable securities and long-term debt
    
    2,346,499
    
    
    2,346,499Total
      capitalization
    
    3,997,240
    
    
    3,938,932Current
      liabilities:Accounts
      payable
    
    205,882
    
    
    229,747Short-term
      debt
    
    97,051
    
    
    --Current
      maturities of long-term debt
    
    31,000
    
    
    31,000Accrued
      expenses:Taxes
    
    114,477
    
    
    81,634Salaries
      and wages
    
    13,341
    
    
    13,829Interest
    
    40,335
    
    
    29,005Unrealized
      loss on derivative instruments
    
    17,185
    
    
    26,581Tenaska
      disallowance reserve
    
    --
    
    
    3,156Deferred
      income taxes
    
    5,109
    
    
    --Other
    
    34,342
    
    
    34,918Total
      current liabilities
    
    558,722
    
    
    449,870Long-term
      liabilities:Deferred
      income taxes
    
    807,929
    
    
    795,392Unrealized
      loss on derivative instruments
    
    --
    
    
    385Other
      deferred credits
    
    387,352
    
    
    395,177Total
      long-term liabilities
    
    1,195,281
    
    
    1,190,954Total
      capitalization and liabilities
    $
    5,751,243
    
    $
    5,579,756
 
 *The
accompanying notes are an integral part of the financial
statements.*
  Table of Contents
  
 **PUGET SOUND ENERGY, INC.**
 CONSOLIDATED
STATEMENTS OF CASH FLOWS
 (Dollars
in thousands)
 (Unaudited)
 
 Three
      Months Ended
      March
      312005
    
    2004Operating
      activities:Net
      income
    $
    72,182
    
    $
    66,898Adjustments
      to reconcile net income to net cash
      provided
      by operating activities:Depreciation
      and amortization
    
    58,077
    
    
    55,870Deferred
      income taxes and tax credits, net
    
    5,735
    
    
    21,255Net
      unrealized (gain) loss on derivative instruments
    
    509
    
    
    (87
    )Cash
      collateral received from energy suppliers
    
    3,100
    
    
    --Decrease
      in residential exchange program
    
    (11,159
    )
    
    (10,296
    )Other
    
    (4,626
    )
    
    (1,856
    )Change
      in certain current assets and liabilities:Accounts
      receivable and unbilled revenue
    
    (102,060
    )
    
    (24,856
    )Materials
      and supplies
    
    10,347
    
    
    11,578Prepayments
      and other
    
    (4,962
    )
    
    448Purchased
      gas receivable
    
    (3,243
    )
    
    (11,083
    )Accounts
      payable
    
    (23,865
    )
    
    (29,962
    )Taxes
      payable
    
    32,843
    
    
    14,361Tenaska
      disallowance reserve
    
    (3,156
    )
    
    --Accrued
      expenses and other
    
    10,263
    
    
    15,431Net
      cash provided by operating activities
    
    39,985
    
    
    107,701Investing
      activities:Construction
      expenditures - excluding equity AFUDC
    
    (117,931
    )
    
    (65,786
    )Energy
      efficiency expenditures
    
    (4,738
    )
    
    (4,440
    )Restricted
      cash
    
    487
    
    
    1,365Refundable
      cash received for customer construction projects
    
    3,582
    
    
    2,199Other
    
    5,514
    
    
    (2,501
    )Net
      cash used by investing activities
    
    (113,086
    )
    
    (69,163
    )Financing
      activities:Change
      in short-term debt, net
    
    97,051
    
    
    --Dividends
      paid
    
    (23,053
    )
    
    (22,431
    )Redemption
      of bonds and notes
    
    --
    
    
    (20,145
    )Issuance
      cost of bonds and other
    
    132
    
    
    2,527Net
      cash provided (used) by financing activities
    
    74,130
    
    
    (40,049
    )Net
      increase (decrease) in cash
    
    1,029
    
    
    (1,511
    )Cash
      at beginning of year
    
    12,955
    
    
    14,778Cash
      at end of period
    $
    13,984
    
    $
    13,267Supplemental
      cash flow information:Cash
      payments for:Interest
      (net of capitalized interest)
    $
    30,549
    
    $
    34,583Income
      taxes
    
    22,000
    
    
    16,174
 
 *The
accompanying notes are an integral part of the financial
statements* *.*
 
 Table of Contents
  **COMBINED NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS**
 
 
 **(1)**
    **Summary
      of Consolidation Policy**
 
 BASIS OF
PRESENTATION
 Puget
Energy is an exempt public utility holding company under the Public Utility
Holding Company Act of 1935. Puget Energy owns Puget Sound Energy (PSE) and has
a 90.9% ownership interest in InfrastruX Group, Inc. (InfrastruX). PSE is a
public utility incorporated in the State of Washington and furnishes electric
and gas services in a territory covering 6,000 square miles, primarily in the
Puget Sound region. InfrastruX is a non-regulated utility construction services
company incorporated in the State of Washington, which provides construction
services to the electric and gas utility industries primarily in the Midwest,
Texas, south-central and eastern United States regions.
 The
consolidated financial statements of Puget Energy include the accounts of Puget
Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the
common shares of PSE and holds a 90.9% interest in InfrastruX. The results of
PSE and InfrastruX are presented on a consolidated basis. The financial position
and results of operations for InfrastruX have been presented as a discontinued
operation (see Note 2). PSE’s consolidated financial statements include the
accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively
referred to herein as “the Company.” The consolidated financial statements are
presented after elimination of all significant intercompany items and
transactions. Certain amounts previously reported have been reclassified to
conform with current year presentations with no effect on total equity or net
income.
 The
consolidated financial statements contained in this Form 10-Q are unaudited. In
the respective opinions of the management of Puget Energy and PSE, all
adjustments necessary for a fair presentation of the results for the interim
periods have been reflected and were of a normal recurring nature. These
condensed financial statements should be read in conjunction with the audited
financial statements (and the Combined Notes thereto) included in the combined
Puget Energy and PSE annual report on Form 10-K for the year ended December 31,
2004. Puget Energy previously had two reportable segments which included
regulated utility operations (PSE) and utility construction services
(InfrastruX). With the treatment of InfrastruX as a discontinued operation,
Puget Energy now only has one reportable segment.
 The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, and disclosure of
contingent assets and liabilities at the date of the financial statements, and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
 
 
 **(2)
Discontinued Operations** (Puget
Energy Only)
 
 Following
a strategic review of Puget Energy’s unregulated subsidiary, InfrastruX Group,
Inc., on February 8, 2005 Puget Energy’s Board of Directors decided to exit the
utility construction services sector. Puget Energy intends to monetize its
interest in InfrastruX through a sale and to invest the proceeds of such
monetization in its regulated utility subsidiary, PSE. This planned disposal
meets the criteria established for recognition as a discontinued operation under
Statement of Financial Accounting Standard (SFAS) No. 144, “Accounting for the
Impairment or Disposal of Long-Lived Assets,” and is expected to be completed
during 2005.
 The
following amounts related to InfrastruX have been segregated from continuing
operations and reflected as discontinued operations:
 
 (DOLLARS
      IN THOUSANDS)
      THREE
      MONTHS ENDED MARCH 31
    
    2005
    
    
    2004Revenues
    $
    77,692
    
    $
    74,756Operating
      expenses (including interest expense)
    
    79,433
    
    
    75,564Pre-tax
      loss
    
    (1,741
    )
    
    (808
    )Income
      tax benefit
    
    726
    
    
    386Minority
      interest in (income) loss of discontinued operations
    
    (3
    )
    
    43Loss
      from discontinued operations
    $
    (1,018
    )
    $
    (379
    )
 
 Loss from
discontinued operations for the three months ended March 31, 2005 includes a
charge of $1.1 million after-tax related to the estimated loss upon disposal of
InfrastruX. In accordance with SFAS No. 144, InfrastruX discontinued
depreciation and amortization of its assets effective February 8, 2005. This
discontinuation of depreciation and amoritization resulted in $2.6 million ($1.6
million after-tax) lower depreciation and amortization expense than otherwise
would have been recorded as continuing operations.
 InfrastruX’s
summarized balance sheets, excluding intercompany balances eliminated in
consolidation, are as follows:
 (DOLLARS
      IN THOUSANDS)
    
    March
      31,
      2005
    
    
    December
      31,
      2004Assets:Cash
    $
    7,356
    
    $
    6,817Accounts
      receivable
    
    73,512
    
    
    78,646Other
      current assets
    
    26,619
    
    
    25,459Total
      current assets
    
    107,487
    
    
    110,922Goodwill
    
    43,886
    
    
    43,503Intangibles
    
    16,189
    
    
    16,680Non-utility
      property and other
    
    105,260
    
    
    100,115Total
      long-term assets
    
    165,335
    
    
    160,298Total
      assets
    $
    272,822
    
    $
    271,220Liabilities:Accounts
      payable
    $
    10,287
    
    $
    9,773Short-term
      debt
    
    11,281
    
    
    8,297Current
      maturities of long-term debt
    
    6,796
    
    
    7,933Other
      current liabilities
    
    26,483
    
    
    25,889Total
      current liabilities
    
    54,847
    
    
    51,892Deferred
      income taxes
    
    24,031
    
    
    25,828Long-term
      debt
    
    141,363
    
    
    143,172Other
      deferred credits
    
    16,921
    
    
    14,710Total
      long-term liabilities
    
    182,315
    
    
    183,710Total
      liabilities
    $
    237,162
    
    $
    235,602
 
 
 **(3)
Earnings per Common Share** (Puget
Energy Only)
 
 Puget
Energy’s basic earnings per common share have been computed based on weighted
average common shares outstanding of 99,953,000 for the three months ended March
31, 2005 and 99,169,000 for the three months ended March 31, 2004.
 Puget
Energy’s diluted earnings per common share have been computed based on weighted
average common shares outstanding of 100,446,000 for the three months ended
March 31, 2005 and 99,637,000 for the three months ended March 31, 2004. These
shares include the dilutive effect of securities related to employee and
director equity plans.
 
 
 **(4)
Accounting for Derivative Instruments and Hedging
Activities**
 
 SFAS No.
133, “Accounting for Derivative Instruments and Hedging Activities,” as amended
by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be
derivative instruments be recorded on the balance sheet at their fair value. The
Company enters into both physical and financial contracts to manage its energy
resource portfolio and interest rate exposure including forward physical and
financial contracts, option contracts and swaps. The majority of these contracts
qualify for the normal purchase normal sale exception. Those contracts that do
not meet normal purchase normal sale exception or cash flow hedge criteria are
marked-to-market to current earnings in the income statement, subject to
deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation,” for energy related derivatives due to the Power Cost Adjustment
(PCA) mechanism.
 The
nature of serving regulated electric customers with its wholesale portfolio of
owned and contracted resources exposes the Company and its customers to some
volumetric and commodity price risks within the sharing mechanism of the PCA.
The Company’s energy risk management function monitors and manages these risks
using analytical models and tools.
 The
Company is not engaged in the business of assuming risk for the purpose of
speculative trading revenues. Therefore, wholesale market transactions are
focused on balancing the Company’s energy portfolio, reducing costs and risks
where feasible, and reducing volatility in wholesale costs and margin in the
portfolio. In order to manage risks effectively, the Company enters into
physical and financial transactions, which are appropriate for the service
territory of the Company and are relevant to its regulated electric and gas
portfolios.
 The
Company’s energy risk management staff develops hedging strategies for the
Company’s energy supply portfolio. The first priority is to obtain reliable
supply for delivery to the Company’s retail customers. The second priority is to
protect against unwanted risk exposure. The third priority is to optimize excess
capacity or flexibility within the energy portfolio.
 The
Company has entered into master netting agreements with counterparties when
available to mitigate credit exposure to those counterparties. The Company
believes that entering into such agreements reduces risk of settlement default
with the ability to make only one net payment. In addition, the Company believes
risk is mitigated with an improved position in potential counterparty bankruptcy
situations due to a consistent netting approach. The Company was subject to a
range of netting provisions, including both stand alone agreements and the
provisions associated with the Western Systems Power Pool agreement of which
many energy suppliers in the western United States are a part.
 During
the three months ended March 31, 2005, the Company recorded a decrease in
earnings for the change in the market value of derivative instruments not
meeting cash flow hedge criteria of approximately $0.5 million compared to an
increase in earnings of approximately $0.1 million for the three months ended
March 31, 2004. At March 31, 2005, the Company had a net unrealized gain
recorded in other comprehensive income of $1.7 million after-tax related to
energy and financial contracts which meet the criteria for designation as cash
flow hedges under SFAS No. 133. In 2005, a portion of the total unrealized gain
on cash flow hedge transactions in other comprehensive income and the
marked-to-market loss in the income statement were deferred in accordance with
SFAS No. 71 due to the Company exceeding the $40 million cap under the PCA
mechanism. When these transactions are realized, they will be reflected in the
PCA calculation.
 In the
third quarter 2004, the Company entered into two treasury lock contracts to
hedge against potential rising interest rate exposure for a debt offering
anticipated to be performed in the first half of 2005. A treasury lock is a
financial arrangement between the Company and a counterparty whereby one of the
parties will be required to make a payment to the other party on a specific
valuation date based upon the change in value of a 30 year treasury bond. If
interest rates rise related to the hedged debt from the date of issuance of the
treasury lock instruments, the Company would receive a payment from the
counterparty for the change in the bond value. Alternatively, if interest rates
decrease related to the hedged debt from the date of issuance of the treasury
lock instruments, the Company would pay the counterparty for the change in the
bond value. These treasury lock contracts were designated under SFAS No. 133
criteria as cash flow hedges, with all changes in market value for each
reporting period being presented net of tax in other comprehensive income. When
these treasury lock contracts are settled upon issuance of debt, any gain or
loss will be amortized from other comprehensive income to interest expense over
the 30 year life of the issued debt. At March 31, 2005 the Company recorded a
liability associated with these two contracts in the amount of $16.3 million and
an unrealized loss in the amount of $10.6 million, after-tax, which is included
in other comprehensive income.
 
 
 **(5)
Asset Retirement Obligations**
 
 SFAS No.
143, “Accounting for Asset Retirement Obligations,” requires legal obligations
associated with the retirement of long-lived assets to be recognized at their
fair value at the time the obligations are incurred. Upon initial recognition of
a liability, that cost is capitalized as part of the related long-lived asset
and allocated to expense over the useful life of the asset.
 The
Company identified various asset retirement obligations upon initial adoption of
SFAS No. 143 on January 1, 2003, and identified an additional asset retirement
obligation related to unprotected bare steel gas pipe in January 2005.
Currently, the Company has an obligation (1) to dismantle two leased electric
generation turbine units and deliver the turbines to the nearest railhead at the
termination of the lease in 2009; (2) to remove certain structures as a result
of re-negotiations with the Department of Natural Resources of a now expired
lease; (3) to replace or line all cast iron pipes in its service territory by
2007 as a result of a 1992 Washington Commission order; (4) to restore ash
holding ponds at a jointly-owned coal-fired electric generating facility in
Montana; and (5) to replace all unprotected bare steel gas pipe in its service
territory by 2015 as a result of a January 31, 2005 Washington Commission order.
 The
following table describes all changes to the Company’s asset retirement
obligation liability during the three months ended March 31:
 
 (DOLLARS
      IN THOUSANDS)AT
      MARCH  31
    
    2005
    
    
    2004Asset
      retirement obligation at beginning of year
    $
    3,516
    
    $
    3,421Liability
      recognized in the period
    
    2,202
    
    
    --Liability
      settled in the period
    
    (254
    )
    
    --Accretion
      expense
    
    47
    
    
    22Asset
      retirement obligation at March 31
    $
    5,511
    
    $
    3,443
 
 
 **(6)**
    **Stock
      Compensation**(Puget
      Energy Only)
 
 The
Company has various stock-based compensation plans which, prior to 2003, were
accounted for according to Accounting Principles Board (APB) No. 25, “Accounting
for Stock Issued to Employees,” and related interpretations as allowed by SFAS
No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted
the fair value based accounting of SFAS No. 123 using the prospective method
under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company is applying SFAS No. 123 accounting
prospectively to stock compensation awards granted from 2003 on, while grants
that were made in years prior to 2003 continue to be accounted for using the
intrinsic value method of APB No. 25. Had the Company used the fair value method
of accounting specified by SFAS No. 123 for all grants at their grant date
rather than prospectively implementing SFAS No. 123, net income and earnings per
share would have been as follows:
 
 Three
      Months Ended
      March
      31(DOLLARS
      IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
    2005
    
    2004Net
      income , as reported
    $
    71,075
    
    $
    66,365Add:
      Total stock-based employee compensation expense
      included
      in net income, net of tax
    
    636
    
    
    616Less:
      Total stock-based employee compensation expense per
      the
      fair value method of SFAS No. 123, net of tax
    
    (810
    )
    
    (528
    )Pro
      forma net income
    $
    70,901
    
    $
    66,453Earnings
      per share:Basic
      and diluted per common share as reported
    $
    0.71
    
    $
    0.67Basic
      and diluted per common share pro forma
    $
    0.71
    
    $
    0.67
 **(7)
Retirement Benefits**
 
 The
following summarizes the net periodic benefit cost for the three months ended
March 31:
 
 Pension
      Benefits
    Other
      Benefits(DOLLARS
      IN THOUSANDS)
    2005
    2004
    2005
    2004Service
      cost
    $
    3,041
    
    $
    2,508
    
    $
    56
    
    $
    50Interest
      cost
    
    5,964
    
    
    5,966
    
    
    404
    
    
    438Expected
      return on plan assets
    
    (9,513
    )
    
    (9,800
    )
    
    (219
    )
    
    (222
    )Amortization
      of prior service cost
    
    756
    
    
    805
    
    
    77
    
    
    77Recognized
      net actuarial loss
    
    743
    
    
    282
    
    
    --
    
    
    --Amortization
      of transition (asset) obligation
    
    (41
    )
    
    (275
    )
    
    105
    
    
    105Net
      periodic benefit cost (income)
    $
    950
    
    $
    (514
    )
    $
    423
    
    $
    448
 
 The
Company previously disclosed in its financial statements for the year ended
December 31, 2004 that it expected contributions by the Company to fund the
pension and other benefits plans for the year ended December 31, 2005 to be $2.0
million and $1.4 million, respectively. During the first quarter 2005, the
actual cash contributions to the pension plans were $0.5 million. In addition,
some plan participants chose lump sum pension payments totaling $0.6 million and
deferred them under the Company’s deferred compensation plan in the first
quarter 2005. Based on this activity, the Company anticipates contributing an
additional $0.9 million to the Company’s pension plan in 2005. The full amount
of the pension plan funding for 2005 is for the Company’s non-qualified
supplemental retirement plan.
 During
the three months ended March 31, 2005, actual other post-retirement medical
benefit plan contributions were $0.4 million, and the Company expects to make
additional contributions of $1.0 million for a total of $1.4 million in
2005.
 
 
 **(8)
Other**
 
 On
February 18, 2005, the Washington Commission approved a 3.5% general tariff gas
rate case increase and a 4.1% general tariff electric rate case increase which
was clarified in an order of March 1, 2005. The increases of $26.3 million
annually for gas customers and $57.7 million annually for electric customers
were effective March 4, 2005. In the order, the Washington Commission also
approved a capital structure of 43% common equity with a return on common equity
of 10.3%.
 On
February 23, 2005, the Washington Commission issued an order concerning PSE’s
compliance filing related to the PCA 2 period of July 1, 2003 through June 30,
2004. In its order, the Washington Commission determined that PSE was allowed to
reflect additional power costs totaling $6.0 million during the PCA 2 period for
the period July 1, 2003 through December 31, 2003. These costs represent an
additional return on PSE’s regulatory assets for the Tenaska generating
facility. These costs were deferred under the PCA mechanism, which resulted in a
reduction in purchased electricity expense for the three month period ended
March 31, 2005.
 On
November 1, 1999, PSE acquired Encogen Northwest, LP (Encogen) whose sole asset
is a natural gas-fired cogeneration facility located in Washington State. With
the approval of the Washington Commission, the Encogen facility has been
operated as part of PSE’s least cost generation dispatch portfolio to serve its
native load obligations since it was acquired in 1999. Two wholly-owned
subsidiaries of PSE, GP Acquisition Corporation and LP Acquisition Corporation,
are the general and limited partners of Encogen, respectively. On December 29,
2004, PSE filed an application with FERC pursuant to Section 203 of the Federal
Power Act to transfer the Encogen facility to PSE and eliminate the various
subsidiaries via an Agreement and Plan of Merger (Merger). On February 15, 2005,
FERC issued an order authorizing the Encogen plant to be transferred to PSE. PSE
anticipates completing the Merger in the second quarter of 2005.
 On April
7, 2004 the Washington Commission approved PSE’s recovery on the amortized White
River plant investment. At March 31, 2005, the White River project net book
value totaled $65.0 million, which included $46.0 million of net utility plant,
$14.7 million of capitalized FERC licensing costs, $3.2 million of costs related
to construction work in progress and $1.1 million related to dam operation and
safety. In its February 18, 2005 general rate case order, the Washington
Commission approved a Washington Commission staff recommendation that PSE be
allowed recovery of the White River net utility plant costs noted above, but
defer recovery of other costs until all costs and any sales proceeds are known.
 In
January 2003, the Financial Accounting Standards Board (FASB) issued
Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R).
FIN 46R requires that if a business entity has a controlling financial interest
in a variable interest entity, the financial statements must be included in the
consolidated financial statements of the business entity. The Company has
evaluated its purchase power agreements and determined that three counterparties
may be considered variable interest entities. As a result, PSE submitted
requests for information to those parties; however, the parties have refused to
submit to PSE the necessary information for PSE to determine whether they meet
the requirements of a variable interest entity. PSE also determined that it does
not have a contractual right to such information. PSE will continue to submit
requests for information to the counterparties on a quarterly basis to determine
if FIN 46R is applicable.
 For the
three purchase power agreements that may be considered variable interest
entities under FIN 46R, PSE is required to buy all the generation from these
plants, subject to displacement by PSE, at rates set forth in the purchase power
agreements. If at any time the counterparties cannot deliver energy to PSE, PSE
would have to buy energy in the wholesale market at prices which could be higher
or lower than the purchase power agreement prices. PSE’s Purchased Electricity
expense for the three months ended March 31, 2005 and 2004 for these three
entities was $71.8 million and $67.5 million, respectively.
 
 
 **(9)**  **New
Accounting Pronouncements**
 
 In
December 2004, FASB issued SFAS No. 123R, “Share-Based Payment”, which revises
SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No. 123R requires
companies that issue share-based payment awards to employees for goods or
services to recognize as compensation expense, the fair value of the expected
vested portion of the award as of the grant date over the vesting period of the
award. Forfeitures that occur before the award vesting date will be adjusted
from the total compensation expense, but once the award vests, no adjustment to
compensation expense will be allowed for forfeitures or unexercised awards. In
addition, SFAS No. 123R would require recognition of compensation expense of all
existing outstanding awards that are not fully vested for their remaining
vesting period as of the effective date that were not accounted for under a fair
value method of accounting at the time of their award. SFAS No. 123R was
originally effective for interim reporting periods beginning after June 15,
2005. However, on April 14, 2005, the Securities and Exchange Commission delayed
implementation of SFAS No. 123R to annual reporting periods beginning after June
15, 2005. The Company is currently evaluating what impact the application of
SFAS No. 123R will have on its operations. The Company had adopted the fair
value provisions of SFAS No. 123 “Accounting for Stock Based Compensation” in
January 2003.
 In March
2005, FASB issued FIN 47, which finalized a proposed interpretation of SFAS No.
143 titled “Accounting for Conditional Asset Retirement Obligations.” The
interpretation addresses the issue of whether SFAS No. 143 requires an entity to
recognize a liability for a legal obligation to perform asset retirement when
the asset retirement activities are conditional on a future event, and if so,
the timing and valuation of the recognition. The decision reached by FASB was
that there are no instances where a law or regulation obligates an entity to
perform retirement activities but then allows the entity to permanently avoid
settling the obligation. The Company is currently evaluating what impact FIN 47
will have on potential asset retirement obligations. The adoption of FIN 47 is
effective for fiscal years ending after December 15, 2005, and is required to be
accounted for as a cumulative effect of an accounting change.
 In
December 2004, FASB issued FASB Staff Position No. 109-1, “Application of FASB
Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs Creation Act of
2004” (FSP No. 109-1). FSP No. 109-1 states that the staff position related to
deductions as a result of the American Jobs Creation Act (the Act) should be
treated as a “special deduction,” as described in SFAS No. 109, “Accounting For
Income Taxes” and therefore has no effect on deferred tax assets or liabilities
existing at the enactment date.
 
 
 Item
2.**Management’s
Discussion and Analysis of Financial Condition and Results of
Operations**
 
 *The
following discussion of the Company’s financial condition and results of
operations contains forward-looking statements that involve risks and
uncertainties, such as statements of the Company’s plans, objectives,
expectations and intentions. Words such as "anticipate," "believe," "expect,"
"future" and "intend" and similar expressions are used to identify
forward-looking statements. However, these words are not the exclusive means of
identifying such statements. In addition, any statements that refer to
expectations, projections or other characterizations of future events or
circumstances are forward-looking statements. The Company’s actual results could
differ materially from those anticipated in these forward-looking statements for
many reasons, including the factors described below and under the caption
“Forward-Looking Statements” at the beginning of this report. You should not
place undue reliance on these forward-looking statements, which apply only as of
the date of this Form 10-Q.*
 
 
 **Overview**
 
 Puget
Energy is an energy services holding company and all of its operations are
conducted through its two subsidiaries. These subsidiaries are PSE, a regulated
electric and gas utility company, and InfrastruX, a utility construction and
services company. Following a strategic review of Puget Energy’s unregulated
subsidiary, InfrastruX, on February 8, 2005 Puget Energy’s Board of Directors
decided to exit the utility construction services sector. Puget Energy intends
to monetize its interest in InfrastruX through a sale and to invest the proceeds
of such monetization in its regulated utility subsidiary, PSE. See section
titled “InfrastruX” for further discussion.
 
 **PUGET
SOUND ENERGY**
 PSE
generates revenues from the sale of electric and gas services, mainly to
residential and commercial customers within Washington State. A majority of
PSE’s revenues are generated in the first and fourth quarters during the winter
heating season in Washington State.
 As a
regulated utility company, PSE is subject to Federal Energy Regulatory
Commission (FERC) and Washington Utility and Transportation Commission
(Washington Commission) regulation which may impact a large array of business
activities, including limitation of future rate increases; directed accounting
requirements that may negatively impact earnings; licensing of PSE-owned
generation facilities; and other FERC and Washington Commission directives that
may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent
to the utility industry as a whole, including weather changes affecting
purchases and sales of energy; outages at owned and non-owned generation plants
where energy is obtained; storms or other events which can damage electric
distribution and transmission lines; and energy trading and wholesale market
stability over time.
 PSE’s
main operational goal has been to provide reliable, safe and cost-effective
energy to its customers. To help accomplish this goal, PSE is attempting to be
more self-sufficient in energy generation resources. Owning more generation
resources rather than purchasing power through contracts and on the wholesale
market is intended to allow customers’ rates to remain stable. PSE is
continually exploring new electric-power resource generation and long-term
purchase power agreements to meet this goal. During the three months ended March
31, 2005, PSE made progress in reaching this goal by completing its acquisition
of the Hopkins Ridge wind project and issued a notice to proceed with
construction of the project. The project is expected to provide up to 150 MW of
capacity (52 average MW) and be completed by the end of 2005. In addition, PSE
continues negotiations from its September 2004 non-binding letter of intent to
acquire the Wild Horse wind project, which is anticipated to provide between 150
to 230 MW of capacity, and if acquired, be completed by the end of
2006.
 The
Hopkins Ridge wind project and proposed Wild Horse wind project are part of
PSE’s long-term electric Least Cost Plan that was filed August 29, 2003 with the
Washington Commission. The plan supports a strategy of diverse resource
acquisitions including resources fueled by natural gas and coal, renewable
resources and shared resources. PSE is in
the process of updating its Least Cost Plan and expects to file the updated plan
with the Washington Commission in the first half of 2005.
 
 
 **Results
of Operations**
 
 **PUGET
ENERGY**
 All the
operations of Puget Energy are conducted through its subsidiaries, PSE and
InfrastruX. Net income for the three months ended March 31, 2005 was $71.1
million on operating revenues of $741.7 million compared to $66.4 million on
operating revenues of $668.7 million for the same period in 2004. Net income for
both periods includes the results of discontinued operations for InfrastruX.
 Basic and
diluted earnings per share for the three months ended March 31, 2005 were $0.71
on 100.0 million weighted average common shares outstanding and 100.4 million
weighted average diluted shares outstanding, respectively. Basic and diluted
earnings per share for the three months ended March 31, 2004 were $0.67 on 99.2
million weighted average common shares outstanding and 99.6 million weighted
average diluted shares outstanding, respectively. Included in the basic and
diluted earnings per share for the three months ended March 31, 2005 was a $0.01
per share loss related to discontinued operations and estimated loss on disposal
of InfrastruX. Discontinued operations did not have an earnings per share impact
for the three months ended March 31, 2004.
 Net
income for the three months ended March 31, 2005 was positively impacted by an
increased electric margin of $7.4 million compared to the same period in 2004
and lower interest expense at PSE of $2.5 million. Net income was negatively
impacted by higher depreciation and amortization expense of $2.2 million for the
three months ended March 31, 2005, primarily due to the acquisition of
Frederickson 1 in April 2004 and other PSE transmission and distribution system
infrastructure projects.
 
 **PUGET
SOUND ENERGY**
 PSE’s
operating revenues and associated expenses are not generated evenly during the
year. Variations in energy usage by consumers occur from season to season and
from month to month within a season, primarily as a result of weather
conditions. PSE normally experiences its highest retail energy sales during the
heating season in the first and fourth quarters of the year. Varying wholesale
electric prices and the amount of hydroelectric energy supplies available to PSE
also make quarter-to-quarter comparisons difficult.
 
 **ENERGY
MARGINS**
 The
following table displays the details of electric margin changes for the three
months ended March 31, 2005 compared to the same period in 2004.
 
 ELECTRIC
      MARGIN(DOLLARS
      IN MILLIONS)
      THREE
      MONTHS ENDED MARCH 31
    2005
    2004
    CHANGE
    PERCENT
      CHANGEElectric
      retail sales revenue
    $
    387.0
    
    $
    367.5
    
    $
    19.5
    
    
    5.3
    %Electric
      transportation revenue
    
    2.7
    
    
    2.3
    
    
    0.4
    
    
    17.4
    %Other
      electric revenue-gas supply resale
    
    4.2
    
    
    3.3
    
    
    0.9
    
    
    27.3
    %Total
      electric revenue for margin
    
    393.9
    
    
    373.1
    
    
    20.8
    
    
    5.6
    %Adjustments
      for amounts included in revenue:Pass-through
      tariff items
    
    (6.5
    )
    
    (8.4
    )
    
    1.9
    
    
    22.6
    %Pass-through
      revenue-sensitive taxes
    
    (28.6
    )
    
    (26.1
    )
    
    (2.5
    )
    
    (9.6
    )%Residential
      exchange credit
    
    55.0
    
    
    54.4
    
    
    0.6
    
    
    1.1
    %Net
      electric revenue for margin
    
    413.8
    
    
    393.0
    
    
    20.8
    
    
    5.3
    %Minus
      power costs:Fuel
    
    (20.4
    )
    
    (14.0
    )
    
    (6.4
    )
    
    (45.7
    )%Purchased
      electricity, net of sales to other utilities and marketers
    
    (209.8
    )
    
    (198.8
    )
    
    (11.0
    )
    
    (5.5
    )%Total
      electric power costs
    
    (230.2
    )
    
    (212.8
    )
    
    (17.4
    )
    
    (8.2
    )%Electric
      margin before PCA
    
    183.6
    
    
    180.2
    
    
    3.4
    
    
    1.9
    %Tenaska
      reserve turnaround
    
    5.3
    
    
    --
    
    
    5.3
    
    
    *Power
      cost deferred under the PCA mechanism
    
    12.6
    
    
    13.9
    
    
    (1.3
    )
    
    (9.4
    )%Electric
      margin
    $
    201.5
    
    $
    194.1
    
    $
    7.4
    
    
    3.8
    %
 _________________________________
 * *Percent
change not applicable* *.*
 
 Electric
margin increased $7.4 million for the three months ended March 31, 2005 compared
to the same period in 2004, primarily due to final resolution and recovery of a
$6.0 million return on the Tenaska Regulatory asset for the PCA 2 period, the
effects of the Power Cost Only Rate Case (PCORC) for the Frederickson 1
generating facility that became effective May 24, 2004, and the effects of the
electric general rate tariff case approved February 18, 2005 with an effective
date of March 4, 2005. The PCORC and the electric general rate case contributed
to electric margin $3.8 million and $2.7 million, respectively, for the three
months ended March 31, 2005 compared to the same period in 2004, offset by a
$2.8 million Tenaska disallowance for the three months ended March 31, 2005. In
addition, retail customer kWh sales (residential, commercial and industrial
customers) increased 0.5% in 2005 compared to 2004. These increases were
partially offset by changes in customer class usage (residential, commercial and
industrial). Electric margin is electric sales to retail and transportation
customers less pass-through tariff items and revenue-sensitive taxes, and the
cost of generating and purchasing electric energy sold to customers, including
transmission costs to bring electric energy to PSE’s service
territory.
 The
following table displays the details of gas margin changes for the three months
ended March 31, 2005 compared to the same period in 2004.
  GAS
      MARGIN(DOLLARS
      IN MILLIONS)
      THREE
      MONTHS ENDED MARCH 31
    2005
    2004
    CHANGE
    PERCENT
      CHANGEGas
      retail revenue
    $
    312.9
    
    $
    269.4
    
    $
    43.5
    
    
    16.1
    %Gas
      transportation revenue
    
    3.4
    
    
    3.4
    
    
    --
    
    
    --Total
      gas revenue for margin
    
    316.3
    
    
    272.8
    
    
    43.5
    
    
    15.9
    %Adjustments
      for amounts included in revenue:Pass-through
      tariff items
    
    (1.9
    )
    
    (1.0
    )
    
    (0.9
    )
    
    (90.0
    )%Pass-through
      revenue-sensitive taxes
    
    (25.1
    )
    
    (22.3
    )
    
    (2.8
    )
    
    (12.6
    )%Net
      gas revenue for margin
    
    289.3
    
    
    249.5
    
    
    39.8
    
    
    16.0
    %Minus
      purchased gas costs
    
    (201.7
    )
    
    (162.4
    )
    
    (39.3
    )
    
    (24.2
    )%Gas
      margin
    $
    87.6
    
    $
    87.1
    
    $
    0.5
    
    
    0.6
    %
 
 Gas
margin increased $0.5 million for the three months ended March 31, 2005 compared
to the same period in 2004. Gas margin increased $2.2 million as a result of the
gas general tariff rate case, which was approved February 18, 2005, with rates
effective March 4, 2005. These increases were offset by decreased retail
customer therm sales which decreased 3.2% in 2005 compared to 2004. The
decreased usage was primarily due to overall warmer weather for the three months
ended March 31, 2005 compared to the same period in 2004, with 3.5% less heating
degree days for the three months ended March 31, 2005 compared to the same
period in 2004. Gas margin is gas sales to retail and transportation customers
less pass-through tariff items and revenue-sensitive taxes and the cost of gas
purchased, including gas transportation costs to bring gas to PSE’s service
territory.
 
 **ELECTRIC
OPERATING REVENUES**
 The table
below sets forth changes in electric operating revenues for PSE for the three
months ended March 31, 2005 compared to the same period in 2004.
 
 (DOLLARS
      IN MILLIONS)
      THREE
      MONTHS ENDED MARCH 31
    2005
    2004
    CHANGE
    PERCENT
      CHANGEElectric
      operating revenues:Residential
      sales
    $
    211.8
    
    $
    204.4
    
    $
    7.4
    
    
    3.6
    %Commercial
      sales
    
    157.9
    
    
    153.6
    
    
    4.3
    
    
    2.8
    %Industrial
      sales
    
    22.1
    
    
    22.4
    
    
    (0.3
    )
    
    (1.3
    )%Other
      retail sales, including unbilled revenue
    
    (4.8
    )
    
    (12.9
    )
    
    8.1
    
    
    62.8
    %Total
      retail sales
    
    387.0
    
    
    367.5
    
    
    19.5
    
    
    5.3
    %Transportation
      sales
    
    2.7
    
    
    2.3
    
    
    0.4
    
    
    17.4
    %Sales
      to other utilities and marketers
    
    16.3
    
    
    11.5
    
    
    4.8
    
    
    41.7
    %Other
    
    14.0
    
    
    11.2
    
    
    2.8
    
    
    25.0
    %Total
      electric operating revenues
    $
    420.0
    
    $
    392.5
    
    $
    27.5
    
    
    7.0
    %
 _________________________________
 * *Percent
change not applicable* *.*
 
 Electric
retail sales increased $19.5 million for the three months ended March 31, 2005
compared to the same period in 2004 due primarily to rate increases related to
the PCORC and the electric general rate case, and increased retail customer
usage. The PCORC and electric general rate case provided an additional $9.3
million and $9.6 million to electric operating revenues, respectively, for the
three months ended March 31, 2005 compared to the same period in 2004. Retail
electricity usage increased 28,331 MWh or 0.5% for the three months ended March
31, 2005 compared to the same period in 2004. The increase in electricity usage
was mainly the result of a higher average number of customers served in the
three month period ended March 31, 2005 compared to the same period in 2004.
 During
the three month period ended March 31, 2005, the benefits of the Residential and
Farm Energy Exchange Benefit credited to customers reduced electric operating
revenues by $57.6 million compared to $56.2 million for the same period in 2004.
This credit also reduced power costs by a corresponding amount with no impact on
earnings. See discussion under PSE Electric Regulation and Rates.
 Sales to
other utilities and marketers increased $4.8 million compared to the three month
period ended March 31, 2004 primarily due to increased MWh sales of 76,174 MWh
or $3.6 million related to excess generation available for sale on the wholesale
market due to warmer temperatures in the first quarter 2005. In addition, $1.2
million of the increase related to higher wholesale market prices in the three
months ended March 31, 2005 compared to the same period in 2004.
 Other
electric revenues increased $2.8 million for the three month period ended March
31, 2005 compared to the same period in 2004, primarily from the sale of excess
non-core gas and electric transmission. Non-core gas sales are included in the
PCA mechanism calculation.
 
 **GAS
OPERATING REVENUES**
 The table
below sets forth changes in gas operating revenues for PSE for the three months
ended March 31, 2005 compared to the same period in 2004.
 
 (DOLLARS
      IN MILLIONS)
      THREE
      MONTHS ENDED MARCH 31
    2005
    2004
    CHANGE
    PERCENT
      CHANGEGas
      operating revenues:Residential
      sales
    $
    208.7
    
    $
    180.8
    
    $
    27.9
    
    
    15.4
    %Commercial
      sales
    
    91.2
    
    
    77.5
    
    
    13.7
    
    
    17.7
    %Industrial
      sales
    
    13.0
    
    
    11.1
    
    
    1.9
    
    
    17.1
    %Total
      retail sales
    
    312.9
    
    
    269.4
    
    
    43.5
    
    
    16.1
    %Transportation
      sales
    
    3.4
    
    
    3.4
    
    
    --
    
    
    --Other
    
    4.8
    
    
    2.9
    
    
    1.9
    
    
    65.5
    %Total
      gas operating revenues
    $
    321.1
    
    $
    275.7
    
    $
    45.4
    
    
    16.5
    %
 
 Gas
retail sales increased $43.5 million for the three months ended March 31, 2005
compared to the same period in 2004 due primarily to higher Purchased Gas
Adjustment (PGA) mechanism rates in 2005 and approval of a 3.5% general gas rate
increase in the gas general rate case effective March 4, 2005. The Washington
Commission approved a PGA mechanism rate increase effective October 1, 2004 that
increased rates 17.6% annually. The PGA mechanism passes through to customers
increases or decreases in the gas supply portion of the natural gas service
rates based upon changes in the price of natural gas purchased from producers
and wholesale marketers or changes in gas pipeline transportation costs. PSE’s
gas margin and net income are not affected by changes under the PGA mechanism.
For the three months ended March 31, 2005, the effects of the PGA mechanism rate
increases provided an increase of $46.4 million in gas operating revenues. In
addition, the gas general rate case increased gas rates by 3.5%, which provided
an additional $2.2 million in gas operating revenue for the three months ended
March 31, 2005 compared to the same period in 2004. These rate increases were
partially offset by lower therm sales due to 3.5% fewer heating degree days for
the three months ended March 31, 2005 compared to the same period in
2004.
 The
following gas rate adjustments were approved by the Washington Commission in
2005 and 2004:
 
 TYPE
      OF RATE
      ADJUSTMENT
    EFFECTIVE
      DATE
    PERCENTAGE
      INCREASE
      IN
      RATES
    ANNUAL
      INCREASE
      IN
      REVENUES
      (DOLLARS
      IN MILLIONS)PGA
    October
      1, 2004
    
    17.6
    %
    $
    121.7Gas
      General Rate Case
    March
      4, 2005
    
    3.5
    %
    
    26.3
 
 **OPERATING
EXPENSES**
 The table
below sets forth significant changes in operating expenses for PSE and its
subsidiaries for the three months ended March 31, 2005 compared to the same
period in 2004.
 
 (DOLLARS
      IN MILLIONS)
      THREE MONTHS ENDED MARCH 31
    2005
    2004
    CHANGE
    PERCENT
      CHANGEPurchased
      electricity
    $
    208.2
    
    $
    196.4
    
    $
    11.8
    
    
    6.0
    %Electric
      generation fuel
    
    20.4
    
    
    14.0
    
    
    6.4
    
    
    45.7
    %Purchased
      gas
    
    201.7
    
    
    162.4
    
    
    39.3
    
    
    24.2
    %Utility
      operations and maintenance
    
    75.5
    
    
    73.8
    
    
    1.7
    
    
    2.3
    %Depreciation
      and amortization
    
    58.1
    
    
    55.9
    
    
    2.2
    
    
    3.9
    %Conservation
      amortization
    
    5.2
    
    
    8.2
    
    
    (3.0
    )
    
    (36.6
    )%Taxes
      other than income taxes
    
    69.7
    
    
    64.2
    
    
    5.5
    
    
    8.6
    %Income
      taxes
    
    46.5
    
    
    39.2
    
    
    7.3
    
    
    18.6
    %
 
 **Purchased
electricity** expenses
increased $11.8 million for the three months ended March 31, 2005 compared to
the same period in 2004 as a result of lower generation at PSE-controlled
hydroelectric facilities and higher wholesale market prices. Higher wholesale
market prices increased purchased electricity by $14.2 million as compared to
the same period in 2004. In addition, on February 23, 2005, the Washington
Commission issued an order concerning PSE’s compliance filing related to the PCA
2 period of July 1, 2003 through June 30, 2004. In its order, the Washington
Commission determined that PSE was allowed to reflect additional power costs
totaling $6.0 million during the PCA 2 period of July 1, 2003 through December
31, 2003. These costs were deferred under the PCA mechanism, which resulted in a
reduction in purchased electricity expense for the three month period ended
March 31, 2005.
 PSE’s
hydroelectric production and related power costs in 2005 and 2004 have continued
to be negatively impacted by below-normal winter precipitation and reduced snow
pack in the Pacific Northwest region. The April 11, 2005 Columbia Basin Runoff
Forecast published by the National Weather Service Northwest River Forecast
Center indicated that the total forecasted runoff above Grand Coulee Reservoir
for the period January through July 2005 would be 83% of normal, which compares
to 84% of normal for the same period in 2004. PSE cannot determine if this trend
of lower than normal runoff will continue in future years nor what impact such a
trend may have on the amount of electricity that will need to be
purchased.
 PSE had
reached the $40 million cumulative cap under the PCA mechanism in February 2005
primarily due to increased wholesale power costs and adverse hydroelectric
conditions. In 2004, PSE had reached and then fell below the $40 million
cumulative cap due to the Tenaska disallowance ordered in May 2004. Under the
PCA mechanism, excess power costs and further increases in variable power costs
through June 30, 2006 will be apportioned 99% to customers and 1% to PSE. For
further discussion see - Electric Regulation and Rates.
 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 core energy
portfolio through short-term and intermediate-term off-system physical purchases
and sales, and through other risk management techniques.
 **Electric
generation fuel** expense
increased $6.4 million for the three months ended March 31, 2005 compared to the
same period in 2004 as a result of higher fuel costs for PSE-controlled
gas-fired generation facilities and increased generation at PSE-controlled
generating facilities compared to the same period in 2004, including the
addition of the Frederickson 1 generating facility, which was purchased and went
into service in April 2004.
 **Purchased
gas** expenses
increased $39.3 million for the three months ended March 31, 2005 compared to
the same period in 2004 primarily due to an increase in PGA rates as approved by
the Washington Commission. The PGA mechanism allows PSE to recover expected gas
costs, and defer, as a receivable or liability, any gas costs that exceed or
fall short of this expected gas cost amount in PGA mechanism rates, including
accrued interest. The PGA mechanism receivable balance at March 31, 2005 and
December 31, 2004 was $22.3 million and $19.1 million, respectively. A
receivable balance in the PGA mechanism reflects a current underrecovery of
market gas cost through rates.
 **Utility
operations and maintenance** expense
increased $1.7 million in 2005 compared to 2004 which includes an increase of
$1.9 million related to low-income program costs that are passed-through in
retail rates with no impact on earnings. As a result, the pre-tax impact on net
income from utility operations and maintenance was a decrease of $0.2 million.
PSE anticipates operation and maintenance expense to increase in future years as
PSE invests in new generating resources and energy delivery infrastructure. The
timing and amounts of increases will vary depending on when new generating
resources come into service.
 **Depreciation
and amortization** expense
increased $2.2 million for the three months ended March 31, 2005 compared to the
same period in 2004. The increase was due to the effects of new plant placed in
service during 2004, including $80.8 million in costs for the Frederickson 1
generating facility in April 2004 and $32.8 million for the Everett Delta gas
transmission line late in 2004. PSE anticipates depreciation expense will
increase in future years as PSE invests in new generating resources and energy
delivery infrastructure.
 **Conservation
amortization** decreased $3.0 million for the three months ended March 31, 2005 compared to the
same period in 2004 due to the conservation trust assets being fully amortized
in September 2004. Conservation amortization is a pass-through tariff item with
no impact on earnings.
 **Taxes
other than income taxes** increased $5.5 million for the three months ended March 31, 2005 compared to the
same period in 2004 due to increases in revenue-based Washington State excise
tax and municipal tax due to increased operating revenues. Revenue sensitive
excise and municipal taxes have no impact on earnings.
 **Income
taxes** increased $7.3 million for the three months ended March 31, 2005 compared to the
same period in 2004 as a result of higher taxable income and a higher effective
federal income tax rate.
 
 **OTHER
INCOME AND INTEREST CHARGES**
 The table
below sets forth significant changes in other income, interest charges and
preferred stock dividends for PSE and its subsidiaries for the three months
ended March 31, 2005 compared to the same period in 2004.
 
 (DOLLARS
      IN MILLIONS)
      THREE
      MONTHS ENDED MARCH 31
    2005
    2004
    CHANGE
    PERCENT
      CHANGEOther
      income (net of tax)
    $
    1.2
    
    $
    0.1
    
    $
    1.1
    
    
    *Interest
      charges
    
    39.5
    
    
    42.0
    
    
    (2.5
    )
    
    (6.0
    )%
 _________________________________
 * *Percent
change not applicable* *.*
 
 **Other
income** increased
$1.1 million (after-tax) for the three months ended March 31, 2005 compared to
the same period in 2004 primarily due to increases in the surrender value of
corporate-owned life insurance policies and a higher level of allowance for
funds used during construction.
 **Interest
charges** decreased
$2.5 million for the three months ended March 31, 2005 compared to the same
period in 2004 due to the redemption of $137.5 million of long-term debt with
rates ranging from 6.45% to 7.80% in 2004, partially offset by the issuance of
$200 million of variable-rate senior notes in July 2004.
 
 **InfrastruX**
 Following
a strategic review of Puget Energy's unregulated subsidiary, InfrastruX, on
February 8, 2005, Puget Energy’s Board of Directors decided to exit the utility
construction services sector. Puget Energy intends to monetize its interest in
InfrastruX through a sale and to invest the proceeds of such monetization into
its regulated utility subsidiary, PSE. This planned disposal meets the criteria
established for recognition as a discontinued operation under SFAS No. 144,
“Accounting for the Impairment or Disposal of Long-Lived Assets,” and is
accounted for as such in Puget Energy’s consolidated financial statements. The
disposal of InfrastruX is expected to be completed during 2005.
 For the
three months ended March 31, 2005, InfrastruX’s loss from discontinued
operations (net of taxes and minority interest) totaled $1.0 million compared to
a loss of $0.4 million (net of taxes and minority interest) for the three months
ended March 31, 2004. The three months ended March 31, 2005 included a charge of
$1.1 million after-tax related to the estimated loss on disposal of InfrastruX.
In accordance with SFAS No 144, InfrastruX discontinued depreciation and
amortization of its assets effective February 8, 2005. This discontinuation of
depreciation and amortization resulted in $2.6 million ($1.6 million after-tax)
lower depreciation and amortization expense than otherwise would have been
recorded as continuing operations.
 InfrastruX’s
operations are dependent on a number of factors, including weather conditions
and availability of projects and capital to be spent on utility construction
projects. As such, Puget Energy cannot determine what income or loss InfrastruX
will generate during the period of time that Puget Energy continues to hold its
interest in InfrastruX, nor any ultimate gain or loss upon completion of the
sale of the entity. It is not anticipated that any funding will be needed from
Puget Energy to maintain operations at InfrastruX or to complete the sale
transaction.
 
 **Capital
Requirements**
 **Contractual
Obligations and Commercial Commitments**
 **Puget
Energy.** The
following are Puget Energy’s aggregate consolidated (including PSE) contractual
and commercial commitments from continuing operations as of March 31,
2005:
  **Puget
      Energy**
    
    
    PAYMENTS
      DUE PER PERIODCONTRACTUAL OBLIGATIONS
      (DOLLARS
      IN MILLIONS)
    
    TOTAL
    
    2005
    
    2006-
      2007
    
    2008-
      2009
    
    2010
      & THEREAFTERLong-term
      debt
    $
    2,100.4
    
    $
    31.0
    
    $
    411.0
    
    $
    337.5
    
    $
    1,320.9Short-term
      debt
    
    97.1
    
    
    97.1
    
    
    --
    
    
    --
    
    
    --Junior
      subordinated debentures payable to a subsidiary trust1
    
    280.3
    
    
    --
    
    
    --
    
    
    --
    
    
    280.3Mandatorily
      redeemable preferred stock
    
    1.9
    
    
    --
    
    
    --
    
    
    --
    
    
    1.9Service
      contract obligations
    
    177.5
    
    
    16.8
    
    
    54.1
    
    
    53.2
    
    
    53.4Non-cancelable
      operating leases
    
    132.1
    
    
    9.9
    
    
    33.0
    
    
    27.6
    
    
    61.6Fredonia
      combustion turbines lease2
    
    64.0
    
    
    3.3
    
    
    8.6
    
    
    8.3
    
    
    43.8Energy
      purchase obligations
    
    5,038.8
    
    
    865.4
    
    
    1,675.4
    
    
    1,211.9
    
    
    1,286.1Financial
      hedge obligations
    
    73.3
    
    
    45.1
    
    
    25.3
    
    
    2.9
    
    
    --Pension
      funding3
    
    44.8
    
    
    3.4
    
    
    8.2
    
    
    9.8
    
    
    23.4Total
      contractual cash obligations
    $
    8,010.2
    
    $
    1,072.0
    
    $
    2,215.6
    
    $
    1,651.2
    
    $
    3,071.4
 AMOUNT
      OF COMMITMENT
      EXPIRATION
      PER PERIODCOMMERCIAL
      COMMITMENTS
      (DOLLARS
      IN MILLIONS)
    
    TOTAL
    
    
    2005
    
    
    2006-
      2007
    
    
    2008-
      2009
    
    
    2010
      & THEREAFTERGuarantees
      4
    $
    131.0
    
    $
    --
    
    $
    131.0
    
    $
    --
    
    $
    --Liquidity
      facilities - available 5
    
    552.4
    
    
    150.0
    
    
    --
    
    
    --
    
    
    402.4Lines
      of credit - available 6
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Energy
      operations letter of credit
    
    0.5
    
    
    --
    
    
    0.5
    
    
    --
    
    
    --Total
      commercial commitments
    $
    683.9
    
    $
    150.0
    
    $
    131.5
    
    $
    --
    
    $
    402.4
 _______________________
 *1*
    *In
      1997 and 2001, PSE formed Puget Sound Energy Capital Trust I and Puget
      Sound Energy Capital Trust II, respectively, for the sole purpose of
      issuing and selling preferred securities (Trust Securities) to investors
      and issuing common securities to PSE. The proceeds from the sale of Trust
      Securities were used by the Trusts to purchase Junior Subordinated
      Debentures (Debentures) from PSE. The Debentures are the sole assets of
      the Trusts and PSE owns all common securities of the Trusts.*
 *2*
    *See
      “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements”
      below.*
 3
    Pension
      funding is based on an actuarial estimate.
 *4*
    *In
      May 2004, InfrastruX signed a three-year credit agreement with a group of
      banks to provide up to $150 million in financing. Under the credit
      agreement, Puget Energy is the guarantor of the line of credit. Certain
      InfrastruX subsidiaries also have certain borrowing capacities for working
      capital purposes of which Puget Energy is not a guarantor. Of the $150
      million available to InfrastruX, $131.0 was outstanding at March 31,
      2005.*
 *5*
    *At
      March 31, 2005, PSE had available a $500 million unsecured credit
      agreement expiring in April 2010 and a $150 million receivables
      securitization facility that expires in December 2005. At March 31, 2005,
      PSE had no amounts sold under its receivables securitization facility. See
      “Accounts Receivable Securitization Program” under “Off-Balance Sheet
      Arrangements” below for further discussion. The credit agreement and
      securitization facility provide credit support for outstanding commercial
      paper of $97.1 million and a letter of credit totaling $0.5 million,
      thereby effectively reducing the available borrowing capacity under these
      liquidity facilities to $552.4 million.*
 6
    *Puget
      Energy has a $5 million line of credit with a bank. At March 31, 2005,
      $5.0 million was outstanding, leaving no amounts available to borrow under
      the agreement. Puget Energy reduced the borrowing capacity under this line
      of credit from $15.0 million to $5.0 million on February 1,
      2005.*
  
 **Puget
Sound Energy** . The
following are PSE’s aggregate contractual and commercial commitments as of March
31, 2005:
 **Puget
      Sound Energy**
    
    
    
    PAYMENTS
      DUE PER PERIODCONTRACTUAL
      OBLIGATIONS
      (DOLLARS
      IN MILLIONS)
    
    TOTAL
    
    
    2005
    
    
    2006-
      2007
    
    
    2008-
      2009
    
    
    2010
      & THEREAFTERLong-term
      debt
    $
    2,095.4
    
    $
    31.0
    
    $
    406.0
    
    $
    337.5
    
    $
    1,320.9Short-term
      debt
    
    97.1
    
    
    97.1
    
    
    --
    
    
    --
    
    
    --Junior
      subordinated debentures payable to a subsidiary trust1
    
    280.3
    
    
    --
    
    
    --
    
    
    --
    
    
    280.3Mandatorily
      redeemable preferred stock
    
    1.9
    
    
    --
    
    
    --
    
    
    --
    
    
    1.9Service
      contract obligations
    
    177.5
    
    
    16.8
    
    
    54.1
    
    
    53.2
    
    
    53.4Non-cancelable
      operating leases
    
    132.1
    
    
    9.9
    
    
    33.0
    
    
    27.6
    
    
    61.6Fredonia
      combustion turbines lease2
    
    64.0
    
    
    3.3
    
    
    8.6
    
    
    8.3
    
    
    43.8Energy
      purchase obligations
    
    5,038.8
    
    
    865.4
    
    
    1,675.4
    
    
    1,211.9
    
    
    1,286.1Financial
      hedge obligations
    
    73.3
    
    
    45.1
    
    
    25.3
    
    
    2.9
    
    
    --Pension
      funding3
    
    44.8
    
    
    3.4
    
    
    8.2
    
    
    9.8
    
    
    23.4Total
      contractual cash obligations
    $
    8,005.2
    
    $
    1,072.0
    
    $
    2,210.6
    
    $
    1,651.2
    
    $
    3,071.4
 AMOUNT
      OF COMMITMENT
      EXPIRATION
      PER PERIODCOMMERCIAL
      COMMITMENTS
      (DOLLARS
      IN MILLIONS)
    
    TOTAL
    
    
    2005
    
    
    2006-
      2007
    
    
    2008-
      2009
    
    
    2010
      & THEREAFTERLiquidity
      facilities - available4
    $
    552.4
    
    $
    150.0
    
    $
    --
    
    $
    --
    
    $
    402.4Energy
      operations letter of credit
    
    0.5
    
    
    --
    
    
    0.5
    
    
    --
    
    
    --Total
      commercial commitments
    $
    552.9
    
    $
    150.0
    
    $
    0.5
    
    $
    --
    
    $
    402.4
 _______________________
 *1*
    *See
      note 1 above.*
 *2*
    *See
      note 2 above.*
 3
    See
      note 3 above.
 *4*
    *See
      note 5 above.*
 
 **OFF-BALANCE
SHEET ARRANGEMENTS**
 **ACCOUNTS
RECEIVABLE SECURITIZATION PROGRAM**
 In order
to provide a source of liquidity to PSE at an attractive cost, PSE entered into
a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned
subsidiary of PSE in December 2002. Pursuant to the Receivables Sales Agreement,
PSE sold all its utility customers’ accounts receivable and unbilled utility
revenues to Rainier Receivables. Concurrently with entering into the Receivables
Sales Agreement, Rainier Receivables entered into a Receivables Purchase
Agreement with PSE and a third party. The Receivables Purchase Agreement allows
Rainier Receivables to sell the receivables purchased from PSE to the third
party. The amount of receivables sold by Rainier Receivables is not permitted to
exceed $150 million at any time. However, the maximum amount may be less
than $150 million depending on the outstanding eligible amount of PSE’s
receivables, which fluctuate with the seasonality of energy sales to
customers.
 The
receivables securitization facility is the functional equivalent of a revolving
line of credit secured by receivables. In the event Rainier Receivables elects
to sell receivables under the Receivables Purchase Agreement, Rainier
Receivables is required to pay fees to the purchasers that are comparable to
interest rates on a revolving line of credit. As receivables are collected by
PSE as agent for the receivables purchasers, the outstanding amount of
receivables held by the purchasers declines until Rainier Receivables elects to
sell additional receivables to the purchasers.
 The
receivables securitization facility expires in December 2005, but is terminable
by PSE and Rainier Receivables upon notice to the receivables purchasers. At
March 31, 2005, Rainier Receivables had no amounts sold under the receivables
securitization facility, leaving a maximum amount of receivables available to be
sold under the program of $150.0 million. During the three months ended March
31, 2004, Rainier Receivables sold a cumulative $122.0 million of receivables.
During the three months ended March 31, 2005, Rainier sold no additional
receivables under the receivables securitization program since the $150.0
million sold under the program at December 31, 2004.
  **FREDONIA
3 AND 4 OPERATING LEASE**
 PSE
leases two combustion turbines for its Fredonia 3 and 4 electric generating
facility pursuant to a master operating lease that was amended for this purpose
in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE
at any time. Payments under the lease vary with changes in the London Interbank
Offered Rate (LIBOR). At March 31, 2005, PSE’s outstanding balance under the
lease was $56.1 million. The expected residual value under the lease is the
lesser of $37.4 million or 60% of the cost of the equipment. In the event the
equipment is sold to a third party upon termination of the lease and the
aggregate sales proceeds are less than the unamortized value of the equipment,
PSE would be required to pay the lessor contingent rent in an amount equal to
the deficiency up to a maximum of 87% of the unamortized value of the
equipment.
 
 **UTILITY
CONSTRUCTION PROGRAM**
 Utility
construction expenditures for generation, transmission and distribution are
designed to meet continuing customer growth and to improve efficiencies of PSE’s
energy delivery systems. Construction expenditures, excluding equity Allowance
for Funds Used During Construction (AFUDC), were $117.9 million for the three
months ended March 31, 2005. Utility construction expenditures in 2005, 2006 and
2007 are anticipated to be approximately $580 million, $400 million and $384
million, respectively, including the new Hopkins Ridge wind project, but
excluding amounts for new generation resources currently under evaluation. New
generation resources under evaluation consist of the Wild Horse wind project
that is anticipated to be completed in 2006. The Wild Horse wind project, if
completed in 2006, is anticipated to have a total cost range of approximately
$300 to $350 million. The proposed utility construction expenditures and new
generation resource expenditures, if acquired, are anticipated to be funded with
a combination of short-term debt, long-term debt and equity. Construction
expenditure estimates, including the new generation resources, are subject to
periodic review and adjustment in light of changing economic, regulatory,
environmental and efficiency factors.
 
 **NEW
GENERATION RESOURCES**
 On March
11, 2005, PSE completed the acquisition of the Hopkins Ridge wind project from
Blue Sky Wind, LLC and issued its key contractor, RES America Construction, Inc.
a notice to proceed with construction of the project. Hopkins Ridge is situated
on 11,000 acres of remote, open wheat fields in southeastern Washington State.
The Hopkins Ridge wind project will feature approximately 80 Vestas 1.8-MW wind
turbines providing up to 150 MW of capacity, or 52 average MW. Upon completion
of construction, which is expected to take approximately nine months, the energy
will be delivered to PSE’s service territory by BPA’s transmission system via an
interconnection. PSE anticipates spending approximately $200 million on the
project, which it solely owns. Included in the $200 million estimate is $180
million to acquire and construct the wind plant, $10 million to fund upgrades to
the transmission systems of the Bonneville Power Administration and other
regional transmission providers, and the balance for development, transaction
and financing costs.
 In
September 2004, PSE signed a non-binding letter of intent to obtain a 100%
ownership interest in the proposed Wild Horse wind project. The project is
located in central Washington State. The Wild Horse project is expected to have
approximately 100 to 130 wind turbines and generate from 150 to 230 MW of power
or 77 average MW, depending on the final design agreement. The final agreement
to purchase the Wild Horse wind project is anticipated to be executed in 2005.
 
 **CAPITAL
RESOURCES**
 **CASH
FROM OPERATIONS**
 Cash
generated from operations for the three months ended March 31, 2005 was $45.7
million. During that period, $23.4 million in cash was used for AFUDC and
payment of dividends. Consequently, cash flows available for utility
construction expenditures and other capital expenditures were $22.3 million or
18.0% of the $124.1 million in construction expenditures (net of AFUDC and
customer refundable contributions) and other capital expenditure requirements
for the three months ended March 31, 2005. For the three months ended March 31,
2004, cash generated from operations was $106.9 million, $22.7 million of which
was used for AFUDC and payment of dividends. Therefore, cash flows available for
utility **** construction
expenditures and other capital **** expenditures
were $84.2 million, or 115.8% of the $72.7 million in construction expenditures
(net of AFUDC and customer refundable contributions) and other capital
expenditure requirements for the three month period ended March 31, 2004. The
overall cash generated from operating activities for the three month period
ended March 31, 2005 decreased $61.2 million compared to the same period in
2004. The decrease was primarily the result of changes in the utilization of
sales of accounts receivables to Rainier Receivables under the accounts
receivable securitization program which contributed $76.0 million of the
decrease in cash generated from operations. The decrease was partially offset by
increases in the PGA mechanism rates in October 2004, which provided a positive
cash flow of $7.8 million, and changes in cash flow from accounts payable, which
provided $6.6 million positive cash flow for the three months ended March 31,
2005 compared to the same period in 2004.
 
 **FINANCING
PROGRAM**
 Financing
utility construction requirements and operational needs are dependent upon the
cost and availability of external funds through capital markets and from
financial institutions. Access to funds is dependent upon factors such as
general economic conditions, regulatory authorizations and policies, and Puget
Energy’s and PSE’s credit ratings.
 
 **RESTRICTIVE
COVENANTS**
 In
determining the type and amount of future financing, PSE may be limited by
restrictions contained in its electric and gas mortgage indentures, articles of
incorporation and certain loan agreements. Under the most restrictive tests, at
March 31, 2005, PSE could issue:
 ·
    approximately
      $281 million of additional first mortgage bonds under PSE’s electric
      mortgage indenture based on approximately $468 million of electric
      bondable property available for issuance, subject to an interest coverage
      ratio limitation of 2.0 times net earnings available for interest, which
      PSE exceeded at March 31, 2005;
 ·
    approximately
      $192 million of additional first mortgage bonds under PSE’s gas mortgage
      indenture based on approximately $320 million of gas bondable property
      available for issuance, subject to an interest coverage ratio limitation
      of 1.75 times net earnings available for interest, which PSE exceeded at
      March 31, 2005;
 ·
    approximately
      $510 million of additional preferred stock at an assumed dividend rate of
      6.75%; and
 ·
    approximately
      $185 million of unsecured long-term debt.
 
 At March
31, 2005, PSE had approximately $3.6 billion in electric and gas ratebase to
support the interest coverage ratio limitation test for net earnings available
for interest.
 
 **CREDIT
RATINGS**
 Neither
Puget Energy nor PSE has had any rating downgrade triggers that would accelerate
the maturity dates of outstanding debt. However, a downgrade in the companies’
credit ratings could adversely affect their 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 spreads over the index
and commitment fee increase as PSE’s secured long-term debt ratings decline. A
downgrade in commercial paper ratings could preclude PSE’s ability to issue
commercial paper under its current programs. The marketability of PSE commercial
paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and
Moody’s Investors Service. In addition, downgrades in any or a combination of
PSE’s debt ratings may prompt counterparties on a contract by contract basis in
the wholesale electric, wholesale gas and financial derivative markets to
require PSE to post a letter of credit or other collateral, make cash
prepayments, obtain a guarantee agreement or provide other mutually agreeable
security.
 
 The ratings of Puget
Energy and PSE, as of April 22, 2005, were:
 
 RatingsStandard
      & Poor’s
    Moody’s**Puget
      Sound Energy**Corporate
      credit/issuer rating
    BBB-
    Baa3Senior
      secured debt
    BBB
    Baa2Shelf
      debt senior secured
    BBB
    (P)Baa2Trust
      preferred securities
    BB
    Ba1Preferred
      stock
    BB
    Ba2Commercial
      paper
    A-3
    P-2Revolving
      credit facility
    *
    Baa3Ratings
      outlook
    Positive
    Stable**Puget
      Energy**Corporate
      credit/issuer rating
    BBB-
    Ba1
 _______________________
 * *Standard
& Poor’s does not rate credit facilities* .
 
 **SHELF
REGISTRATIONS, LONG-TERM DEBT AND COMMON STOCK ACTIVITY**
 On April
19, 2005, Puget Energy and PSE filed a shelf registration statement with
the Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $850 million of:
 ·
    common
      stock of Puget Energy, and
 ·
    senior
      notes of PSE, secured by a pledge of PSE’s first mortgage
      bonds.
 The shelf
registration statement, effective as of May 4, 2005, replaces Puget Energy and
PSE's previous $500 million shelf registration statement.  The new shelf
registration statement provides the Company with additional capacity and
flexibility when funding anticipated capital projects and meeting maturing debt
obligations.
 
 **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.
 In May
2004, PSE entered into a three-year, $350 million unsecured credit agreement
with a group of banks. In March 2005, PSE amended this credit agreement,
increasing the total borrowing capacity from $350 million to $500 million, and
extending the expiration date from June 2007 to April 2010. Under the terms of
the credit agreement, PSE pays a floating interest rate on outstanding
borrowings based either on the agent bank’s prime rate or on LIBOR plus a
marginal rate based on the Company’s long-term credit rating at the time of
borrowing. PSE pays a commitment fee on any unused portion of the credit
agreement also based on long-term credit ratings of the Company. PSE also has a
$150 million receivables securitization program which expires in December 2005.
At March 31, 2005, PSE had available $500 million in the unsecured credit
agreement and $150 million under its receivables securitization facility, both
of which provide credit support for outstanding commercial paper and letters of
credit. At March 31, 2005, there was $97.1 million in commercial paper
outstanding and $0.5 million outstanding under a letter of credit, effectively
reducing the available borrowing capacity under these liquidity facilities to
$552.4 million.
 In
February 2005, PSE entered into an uncommitted $20 million unsecured credit
agreement with a bank. Under the terms of the credit agreement, PSE pays a
varying interest rate on outstanding borrowings based on the terms entered into
at the time of borrowing. At March 31, 2005, there were no amounts outstanding
under this credit agreement.
 Puget
Energy previously had a $15 million credit agreement expiring in May 2006 with a
bank. On February 1, 2005, Puget Energy reduced the borrowing capacity of this
credit agreement to $5.0 million. Under the terms of the agreement, Puget Energy
pays a floating interest rate on borrowings based on LIBOR. The interest rate is
set for one, two, or three-month periods at the option of Puget Energy with
interest due at the end of each period. Puget Energy also pays a commitment fee
on any unused portion of the credit facility. Puget Energy had $5.0 million
outstanding under the credit agreement at March 31, 2005.
  **STOCK
PURCHASE AND DIVIDEND REINVESTMENT PLAN**
 Puget
Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which
shareholders and other interested investors may invest cash and cash dividends
in shares of Puget Energy’s common stock. Since new shares of common stock may
be purchased directly from Puget Energy, funds received may be used for general
corporate purposes. Puget Energy issued common stock from the Stock Purchase and
Dividend Reinvestment Plan of $3.6 million (151,800 shares) for the three months
ended March 31, 2005 compared to $3.9 million (175,600 shares) for the three
months ended March 31, 2004.
 
 **COMMON
STOCK OFFERING PROGRAMS**
 To
provide additional financing options, Puget Energy entered into agreements in
July 2003 with two financial institutions under which Puget Energy may offer and
sell shares of its common stock from time to time through these institutions as
sales agents, or as principals. Sales of the common stock, if any, may be made
by means of negotiated transactions or in transactions that may be deemed to be
“at-the-market” offerings as defined in Rule 415 promulgated under the
Securities Act of 1933, including in ordinary brokers’ transactions on the New
York Stock Exchange at market prices.
 
 
 **Other**
 
 **FERC
HYDROELECTRIC PROJECTS AND LICENSES**
 **Snoqualmie
Falls project.** The
Snoqualmie Falls project, built in 1898, had its original license issued May 13,
1975, which was made effective retroactive to March 1, 1956, and expired on
December 31, 1993. PSE filed its application to relicense the project on
November 25, 1991, and operated the project pursuant to annual licenses issued
by FERC since the original license expired. On June 29, 2004, FERC granted PSE a
new 40-year operating license for the Snoqualmie Falls project. PSE estimates
that the investment required to implement the conditions of the new license
agreement will cost approximately $44 million. These conditions include modified
operating procedures and various project upgrades that include better protection
of fish, development of riparian habitat to promote fish propagation, increased
minimum flows in the Snoqualmie River during low-water periods and the
development of recreational amenities near the down-river power house. On July
29, 2004, the Snoqualmie Tribe and certain other parties filed a request for
rehearing of the new license and a request to stay the FERC license. On March 1,
2005, FERC issued an Order on Rehearing and Dismissing Stay Request. The order
requires additional flows at Snoqualmie Falls during certain times of the year.
PSE requested rehearing of the order on the grounds that the order interferes
with the State Department of Ecology’s authority to regulate water quality and
that FERC arbitrarily and capriciously rebalanced the public interest without
support of substantive evidence in the record.
 
 **ELECTRIC
REGULATION AND RATES**
 **FERC
matter.** PSE’s
market-based rate tariff was accepted by FERC in an order dated January 29,
1999. Pursuant to this order, PSE is required to file an updated market power
analysis every three years. On August 11, 2004, PSE filed an updated market
power analysis with FERC as required by a FERC order dated May 13, 2004. The
August 11, 2004 filing was supplemented by additional filings on September 24,
2004 and November 19, 2004. On December 20, 2004, FERC issued an order (December
20 order) finding that PSE had not provided sufficient information for FERC to
determine if PSE had passed the generation market power screens with respect to
wholesale sales within PSE’s control area. The order instituted an investigation
under Section 206 of the Federal Power Act (FPA) and established a prospective
refund date of February 27, 2005. Both the proceeding and the refund effective
date affect only wholesale sales at market-based rates by PSE inside its own
control area. On February 1, 2005, PSE submitted to FERC additional information
in accordance with the December 20 order. On April 13, 2005, FERC issued an
order terminating the Section 206 investigation and accepting PSE’s updated
market power analysis.
 
 **Rate
case.** On
February 18, 2005, the Washington Commission approved a 4.1% general tariff
electric rate case increase to recover higher costs of providing electric
service to customers. The rate increase will increase electric revenues by
approximately $57.7 million annually effective March 4, 2005, as clarified in
its order of March 1, 2005. In the order, the Washington Commission also
approved a capital structure containing 43% common equity with a return on
common equity of 10.3%.
 
 **White
River project.** In
December 2003, PSE notified FERC that it rejected the 1997 license for the White
River project because the 1997 license contained terms and conditions that
rendered ongoing operations of the project uneconomical relative to alternative
resources. As a result of rejecting the license, generation of electricity
ceased at the White River project on January 15, 2004. The Company is actively
seeking to sell the project to one or more entities interested in maintaining
the reservoir for commercial purposes.
 On April
7, 2004 the Washington Commission approved PSE’s recovery on the unamortized
White River plant investment. At March 31, 2005, the White River project net
book value totaled $65.0 million, which included $46.0 million of net utility
plant, $14.7 million of capitalized FERC licensing costs, $3.2 million of costs
related to construction work in progress, and $1.1 million related to dam
operations and safety. In its February 18, 2005 general rate case order, the
Washington Commission approved a Washington Commission staff recommendation that
PSE be allowed recovery of the White River net utility plant costs noted above,
but defer recovery of other costs until all costs and any sales proceeds are
known.
 
 **PCA
Mechanism.** PSE has a
PCA mechanism that triggers if PSE’s costs to provide customers’ electricity
falls outside certain bands from a normalized level of power costs established
in the electric general rate case. The cumulative maximum pre-tax earnings
exposure due to power cost variations over the four-year period ending June 30,
2006 is limited to $40 million plus 1% of the excess. Upon expiration of the $40
million cumulative cap, the annual power cost variability is subject to the
bands in the table below. All significant variable power supply cost drivers are
included in the PCA mechanism (hydroelectric generation variability, market
price variability for purchased power and surplus power sales, natural gas and
coal fuel price variability, generation unit forced outage risk and wheeling
cost variability).
 Upon
expiration of the cumulative cap, the most significant risks are hydroelectric
generation variability and wholesale market prices of natural gas and power. On
an annual July through June basis, the PCA mechanism apportions increases or
decreases in power costs, on a graduated scale, between PSE and its customers in
the following manner:
 
 Annual
      Power
      Cost
      Variability
    
    Customers’
      Share
    
    Company’s
      Share 1+/-
      $20 million
    
    0%
    
    100%+/-
      $20 - $40 million
    
    50%
    
    50%+/-
      $40 - $120 million
    
    90%
    
    10%+/-
      $120 million
    
    95%
    
    5%
 __________________________
 *1*
    *Over
      the four-year period July 1, 2002 through June 30, 2006, the Company’s
      share of pre-tax power cost variations is capped at a cumulative $40
      million plus 1% of the excess. Power cost variation after June 30, 2006
      will be apportioned on an annual basis, based on the graduated
      scale.*
 
 Based on
past activity under the PCA mechanism and volatility of power costs, it is
possible that PSE could experience higher expenses associated with excess power
based on the sharing arrangement once the cumulative $40 million cap expires on
June 30, 2006. As such, the risk dynamics change for PSE and its customers. PSE
is required by the Washington Commission to make a PCORC filing or general
tariff filing by February 28, 2006 to reset the PCA power cost baseline rates
effective July 1, 2006.
 On
February 23, 2005, the Washington Commission issued an order concerning PSE’s
compliance filing related to the PCA 2 period of July 1, 2003 through June 30,
2004. In its order, the Washington Commission determined that PSE was allowed to
reflect additional power costs totaling $6.0 million during the PCA 2 period of
July 1, 2003 through December 31, 2003. These costs represent an additional
return on PSE’s regulatory assets for the Tenaska generating facility. These
costs were deferred under the PCA mechanism, which resulted in a reduction in
purchased electricity expense for the three month period ended March 31,
2005.
 
 **Colstrip
Matter.** The
Mineral Management Service of the United States Department of the Interior (MMS)
issued two orders to Western Energy Company (WECO), the supplier of coal to
Colstrip Units 3 & 4, in 2002 and 2003 to pay additional royalties
concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that
additional royalties are owed as a result of WECO not paying royalties on
revenue received by WECO from the Colstrip Units 3 & 4 owners under a coal
transportation agreement during the period October 1, 1991 through December 31,
2001. The State of Montana has made similar claims against WECO for taxes that
would apply to the additional royalties if the MMS position prevails. WECO
appealed the MMS orders to a board of appeals internal to the MMS. On March 30,
2005, the MMS issued a decision on the appeals, granting them in part but
denying them in part, a result that reduced the royalty claim by $0.8 million
based on PSE's 25% ownership interest in Colstrip Units 3 & 4. WECO will
seek further review of the March 30, 2005 order by the Department of the
Interior Board of Land Appeals, a process that will likely take another two
years. After the reduction in amount claimed due to the statute of limitations
ruling, PSE’s share of the alleged additional royalties is $1.1 million, which
is based upon PSE’s 25% ownership interest in Colstrip Units 3 & 4. PSE’s
share of the alleged additional State of Montana taxes would be $0.5 million.
WECO is also appealing the State of Montana tax claims, and anticipates that
process will take several years. PSE is monitoring the process and believes that
the Colstrip Units 3 & 4 owners have reasonable defenses in this matter
based upon its review. Neither the outcome of this matter nor the associated
costs can be predicted at this time.
 
 **GAS
REGULATION AND RATES**
 On
February 18, 2005, the Washington Commission approved a 3.5% general tariff gas
rate case increase to recover higher costs of providing natural gas service to
customers. The rate increase will increase gas revenues by approximately $26.3
million annually, effective March 4, 2005. In the order, the Washington
Commission also approved a capital structure containing 43% common equity with a
return on common equity of 10.3%. In the proceeding, PSE had filed a request for
an increase of 6.3% or $46.2 million annually on final rebuttal during the rate
case for gas customers.
 
 **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,
2004 includes a summary of the western power market proceedings described below.
The following discussion provides a summary of material developments in these
proceedings that occurred during the period covered by this report and of any
new material proceedings instituted during the period covered by this report.
PSE intends to vigorously defend against each of these cases and does not expect
the ultimate resolution of these proceedings in the aggregate to have a material
adverse impact on the financial condition, results of operations or liquidity of
the Company. However, there can be no assurances in that regard because
litigation is subject to numerous uncertainties and PSE is unable to predict the
ultimate outcome of these matters. Accordingly, there can be no guarantee that
these proceedings, either individually or in the aggregate, will not materially
and adversely affect PSE’s financial condition, results of operations or
liquidity.
 
 **1.**
    **California
      Receivable and California Refund Proceeding.**In
      2001, Pacific Gas & Electric (PG&E) and Southern California Edison
      failed to pay the California Independent System Operator Corporation
      (CAISO) and the California PX for energy purchases. The CAISO in turn
      failed to pay various energy suppliers, including PSE, for energy sales
      made by PSE into the California energy market during the fourth quarter
      2000. Both PG&E and the California PX filed for bankruptcy in 2001,
      further constraining PSE’s ability to receive payments due to bankruptcy
      court controls placed on the distribution of funds by the California PX
      and the escrow of funds owed by PG&E for purchases during the fourth
      quarter 2000 are owed by the California PX.
 
 **a.**
    ***California
      Refund Proceeding.***On
      July 25, 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to
      determine the amount of refunds due to California energy buyers for
      purchases made in the spot markets operated by the CAISO and the
      California PX during the period October 2, 2000 through
      June 20, 2001 (refund period). The CAISO continues its efforts
      to prepare revised settlement statements based on newly recalculated costs
      and charges for spot market sales to California during the refund period
      and currently estimates that it will determine “who owes what to whom” in
      early 2005. On September 2, 2004, FERC issued an order selecting Ernst
      & Young LLP as the independent auditor of fuel cost allowance claims
      made by sellers, including PSE. A review of that claim is
      pending.
 Many
      f the numerous orders that FERC issued in Docket No. EL00-95 are on appeal
      and have been consolidated before the United States Court of Appeals for
      the Ninth Circuit. Last fall, the Ninth Circuit ordered that briefing
      proceed in two rounds. The first round is limited to three issues: (1)
      which parties are subject to FERC’s refund jurisdiction in light of the
      exemption for government-owned utilities in section 201(f) of the Federal
      Power Act (FPA); (2) the temporal scope of refunds under section 206 of
      the FPA; (3) which categories of transactions are subject to refunds. PSE
      joined the brief of the Competitive Supplier Group, which argued that FERC
      has proposed to require payment of refunds without proper notice to
      sellers, without proper limits on the type of transactions affected and
      without finding that the transactions subject to refund in fact produced
      prices that were just and reasonable. Oral argument was held on April 12
      and 13, 2005 on the first round of issues. Procedures will be established
      for the remaining issues, if necessary, after the court’s disposition of
      the first round of issues.
  **b.**
    ***CAISO
      Receivable****.*PSE has a bad debt reserve and a transaction fee reserve applied to the
      CAISO receivable, such that PSE’s net receivable from the CAISO as of
      March 31, 2005 is approximately $21.3 million. PSE estimates the range for
      the receivable to be between $21.3 million and $22.5 million, which
      includes estimated credits for fuel and power purchase costs and interest.
      In its October 16, 2003 Order on Rehearing in this docket, FERC expressly
      adopted and approved a stipulation that confirmed that two of PSE’s
      “non-spot market” transactions are not subject to mitigation in the Refund
      Proceeding. PSE has formally requested payment of these amounts from the
      CAISO and has pursued the issue in filing through FERC processes.
 **2.**
    **Pacific
      Northwest Refund Proceeding.**On
      June 25, 2003, FERC issued an order terminating the proceeding, largely on
      procedural, jurisdictional and equitable grounds. Various parties filed
      rehearing requests, which were denied by FERC in an order affirming the
      termination of the Pacific Northwest Refund Proceeding, (Docket No.
      EL01-10). Seven petitions for review, including PSE’s, are now pending
      before the United States Court of Appeals for the Ninth Circuit. Opening
      briefs were filed on January 14, 2005. PSE’s opening brief addressed
      procedural flaws underlying the action of FERC. Specifically, PSE argued
      that because PSE’s complaint in the underlying docket was withdrawn as a
      matter of law on July 9, 2001, FERC erred in relying on it to serve as the
      basis to initiate a “preliminary” investigation into whether refunds for
      individually negotiated bilateral transactions in the Pacific Northwest
      were appropriate. Briefing is expected to be completed in the first half
      of 2005.
 
 **3.**
    **Wah
      Chang v. Avista Corp., PSE and others.**In
      June 2004, Puget Energy and PSE were served a federal summons and
      complaint by Wah Chang, an Oregon company. Wah Chang claims that during
      1998 through 2001 the Company and other energy companies (and in a
      separate complaint, energy marketers) engaged in various fraudulent and
      illegal activities including the transmittal of electronic wire
      communications to transmit false or misleading information to manipulate
      the California energy market. The claims include submitting false
      information such as energy schedules and bids to the California PX, CAISO,
      electronic trading platforms and publishers of energy indexes, alleges
      damages of not less than $30 million and seeks treble and punitive
      damages, attorneys’ fees and costs. The complaint is similar to the
      allegations made by the Port of Seattle currently on appeal in the Ninth
      Circuit. The Judicial Panel on Multi District Litigation consolidated this
      case with another pending Multi District case and transferred it to
      Federal District Court in San Diego. Both cases were dismissed on the
      grounds that FERC has the exclusive jurisdiction over plaintiff’s claims
      and the filed rate doctrine and Federal preemption barred the court from
      hearing the plaintiff’s claims. On March 10, 2005, Wah Chang filed a
      notice of appeal to the United States Court of Appeals for the Ninth
      Circuit.
 
 **4.**
    **California
      Litigation.***Attorney
      General Cases.*On
      May 31, 2002, FERC conditionally dismissed a complaint filed on March 20,
      2002 by the California Attorney General in Docket No. EL02-71 that alleged
      violations of the FPA by FERC and all sellers (including PSE) of electric
      power and energy into California. The complaint asserted that FERC’s
      adoption and implementation of market rate authority was flawed and, as a
      result, individual sellers such as PSE were liable for sales of energy at
      rates that were “unjust and unreasonable.” The condition for dismissal was
      that all sellers refile transaction summaries of sales to (and, after a
      clarifying order issued on June 28, 2001, purchases from) certain
      California entities during 2000 and 2001. PSE refiled such transaction
      summaries on July 1 and July 8, 2002. The order of dismissal went on
      appeal to the Ninth Circuit Court of Appeals. On September 9, 2004, the
      Ninth Circuit issued a decision on the California Attorney General’s
      challenge to the validity of FERC’s market-based rate system (Lockyer v.
      FERC). The Ninth Circuit upheld FERC’s authority to authorize sales of
      electric energy at market based rates, but found the requirement that all
      sales at market-based rates be contained in quarterly reports filed with
      FERC to be integral to a market-based rate tariff. The California parties,
      among others, have interpreted the decision as providing authority to FERC
      to order refunds for different time frames and based on different
      rationales than are currently pending in the California Refund
      Proceedings, discussed above in “California Refund Proceeding.” The
      decision itself defers the question of whether to seek refunds to FERC.
      PSE, along with other defendants in the proceeding, sought rehearing of
      the Ninth Circuit’s decision on October 25, 2004. The Ninth Circuit has
      yet to issue an order on the rehearing request. Because the current Ninth
      Circuit decision may open new periods of transactions to refund claims
      under new theories, PSE cannot predict the scope, nature or ultimate
      resolution of this case. That additional uncertainty may make the outcomes
      of certain other western energy market cases less predictable than
      previously anticipated.
 *California
Class Actions.* In May
2002, PSE was served with two cross-complaints, by Reliant Energy Services and
Duke Energy Trading & Marketing, respectively, in six consolidated class
actions filed in Superior Court in San Diego, California. Plaintiffs in the
lawsuit seek, among other things, restitution of all funds acquired by means
that violate the law and payment of treble damages, interest and penalties. The
cross-complaints asserted essentially that the cross-defendants, including PSE,
were also participants in the California energy market at relevant times, and
that any remedies ordered against some market participants should be ordered
against all. Reliant and Duke also seek indemnification and conditional relief
as buyers in transactions involving cross-defendants should the plaintiffs
prevail. The case was removed to federal court and some of the newly added
defendants, including PSE, moved to dismiss the action. In December 2002, the
federal district court remanded the proceeding to state court, an action which
Duke and Reliant later appealed to the Ninth Circuit. The appeal stayed further
action in the state court proceeding pending the outcome of the appeal. The
cross-complaints and the addition of the 40 new defendants raised issues of
foreign sovereign immunity, jurisdiction and indemnity in the case, all of which
are now part of the appeal. In June 2003, PSE and other defendants filed motions
to respond to the indemnity issues. On May 13, 2004, the Ninth Circuit issued an
order granting PSE status as a cross-appellant but did not permit PSE to
participate in the oral argument heard on June 14, 2004. On December 8, 2004,
the Ninth Circuit issued an opinion affirming the district court’s decision to
remand the case to state court. Powerex filed a petition for rehearing which
argues that although not immune from suit, as a government entity it should be
allowed to litigate in federal, not state court. The court twice rejected
attempts by Powerex to keep the case in federal court, first by denying
Powerex’s request for rehearing and second by denying Powerex’s subsequent
motion to recall the mandate. The case is now in the process of being remanded
to state court.
 
 
 Item 3.**Quantitative
and Qualitative Disclosure About Market Risk**
 
 **ENERGY
PORTFOLIO MANAGEMENT**
 The
regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity
price volatility on the Company. The PGA mechanism passes through increases and
decreases in the cost of natural gas supply to customers. The PCA mechanism
provides for a sharing of costs and benefits that are graduated over four levels
of power cost variances with an overall cap of $40 million (+/-) plus 1% of the
excess over the $40 million cap over the four-year period ending June 30, 2006.
 The
Company is focused on commodity price exposure and risks associated with
volumetric variability in the gas portfolio and electric portfolio for its
customers. Gas and electric portfolio exposure is managed in accordance with
Company polices and procedures. The Risk Management Committee, which is composed
of Company officers, provides policy-level and strategic direction for
management of the energy portfolio. The Audit Committee of the Company’s Board
of Directors periodically assesses risk management policies.
 The
nature of serving regulated electric customers with its wholesale portfolio of
owned and contracted resources exposes the Company and its customers to some
volumetric and commodity price risks within the sharing mechanism of the PCA.
The Company’s energy risk management function monitors and manages these risks
using analytical models and tools. The Company manages its energy supply
portfolio to achieve three primary objectives:
 ·
    ensure
      that physical energy supplies are available to serve retail customer
      requirements;
 ·
    manage
      portfolio risks to limit undesired impacts on the Company’s costs;
      and
 ·
    maximize
      the value of the Company’s energy supply
assets.
 The
Company is not engaged in the business of assuming risk for the purpose of
speculative trading revenues. Therefore wholesale market transactions are
focused on balancing the Company’s energy portfolio, reducing costs and risks
where feasible, and reducing volatility in wholesale costs and margin in the
portfolio. In order to manage risks effectively, the Company enters into
physical and financial transactions, which are appropriate for the service
territory of the Company and are relevant to its regulated electric and gas
portfolios.
 The risk
metrics the Company employs are aimed at assessing exposure for the purposes of
developing strategies to reduce the potential exposure on a cost-effective basis
in regulated utility gas and electric portfolios. Specifically, the amount of
risk exposure is defined by time period and by portfolio. It is determined
through statistical methods aimed at forecasting risk.
 The
energy risk management staff models forecasted load requirements and expected
resource availability, and projects the net deficit or surplus position
resulting from any imbalance between load requirements and existing resources.
However, the portfolios are subject to major sources of variability (e.g.,
hydroelectric generation, outage risk, regional economic factors,
temperature-sensitive retail sales and market prices for gas and power
supplies). At certain times, these sources of variability can mitigate portfolio
imbalances and at other times they can exacerbate portfolio imbalances. Because
of the volumetric and cost variability within the electric and gas portfolios,
the Company runs market simulations to model potential risk scenarios. In this
way, strategies can be developed to address the expected case as well as other
potential scenarios. Resources in the gas portfolio include gas supply
arrangements, gas storage and gas transportation contracts. Resources in the
electric portfolio include power purchase agreements, generating resources and
transmission contracts.
 The
Company’s energy risk management staff develops hedging strategies to manage
deficit or surplus positions in the portfolios. The Company’s energy risk policy
states that hedging and optimization strategies will be consistent with Company
objectives. The Company relies on risk analysis, operational factors,
professional judgment of its employees and fundamental analysis. The Company
will engage in transactions that reduce risks in its electric and gas
portfolios, and optimize unused capacity where possible. Cost and reliability
factors are considered in its hedging strategies. The Company’s hedging
activities are aimed at removing risks from the Company’s electric and gas
portfolios, giving important consideration to cost of hedges and lost
opportunity in order to find a balance between price stability and least cost.
The hedge strategies for the gas and electric portfolios incorporate risk
analysis, operational factors and professional judgment of its employees as well
as fundamental analysis. Programmatic hedge plans are developed to ensure
disciplined hedging, and discretion is used in hedging within specific
guidelines of the programmatic hedge plans approved by the Risk Management
Committee. Most hedges can be implemented in ways that retain the Company’s
ability to use its energy supply optimization opportunities. Some hedges are
structured similarly to insurance instruments, where the Company pays an
insurance premium to protect against certain extreme conditions.
 Without
jeopardizing the security of supply within its portfolio, the Company also
engages in optimizing the portfolio. Optimization may take the form of utilizing
excess capacity, shaping flexible resources to capture their highest value and
utilizing transmission capacity through third party transactions. As a result,
portions of the Company’s energy portfolio are monetized through the use of
forward price instruments which help reduce overall costs.
 The
Company has entered into master netting agreements with counterparties when
available to mitigate credit exposure to those counterparties. The Company
believes that entering into such agreements reduces risk of settlement default
with the ability to make only one net payment. In addition, the Company believes
risk is mitigated with an improved position in potential counterparty bankruptcy
situations due to a consistent netting approach. At March 31, 2005, the Company
was subject to a range of netting provisions, including both stand alone
agreements and the provisions associated with the Western Systems Power Pool
agreement of which many energy suppliers in the western United States are a
part.
 Transactions
that qualify as hedge transactions under SFAS No. 133 are recorded on the
balance sheet at fair value. Changes in fair value of the Company’s derivatives
are recorded each period in current earnings or other comprehensive income.
Short-term derivative contracts for the purchase and sale of electricity are
valued based on daily quoted prices from an independent energy brokerage
service. Valuations for short-term and medium-term natural gas financial
derivatives are derived from a combination of quotes from several independent
energy brokers and are updated daily. Long-term gas financial derivatives are
valued based on published pricing from a combination of independent brokerage
services and are updated monthly. Option contracts are valued using market
quotes and a Monte Carlo simulation based model approach.
 At March
31, 2005, the Company had an after-tax net asset of approximately $57.0 million
of energy contracts designated as qualifying cash flow hedges and a
corresponding unrealized gain of $37.0 million after-tax recorded in other
comprehensive income. Of the amount in other comprehensive income, 99% of the
mark-to-market gain beginning February 1, 2005 though June 30, 2006 has been
reclassified out of other comprehensive income to a deferred account in
accordance with SFAS No. 71 due to the Company reaching the $40 million cap
under the PCA mechanism. Amounts settling after June 30, 2006 have not been
deferred under the PCA mechanism as the $40 million cap expires at June 30,
2006, and the sharing band under the PCA mechanism reset. The Company also had
energy contracts that were marked-to-market at a loss of $0.3 million after-tax
through current earnings for the three months ended March 31, 2005. These
mark-to-market adjustments were primarily the result of excluding certain
contracts from the normal purchase normal sale exception under SFAS No. 133. A
portion of the mark-to-market adjustments beginning April 1, 2005, has been
reclassified to a deferred account in accordance with SFAS No. 71 due to the
Company reaching the $40 million cap under the PCA mechanism. At March 31, 2005,
the Company also has an asset of approximately $28.3 million related to the fair
value of gas contracts. All mark-to-market adjustments relating to the natural
gas business have been reclassified to a deferred account in accordance with
SFAS No. 71 due to the PGA mechanism. The PGA mechanism passes on to customers
increases and decreases in the cost of natural gas supply. A hypothetical 10%
increase in the market prices of natural gas and electricity would increase the
fair value of qualifying cash flow hedges by approximately $11.3 million
after-tax and would increase current earnings for those contracts
marked-to-market in earnings by $0.4 million after-tax.
 
 **INTEREST
RATE RISK**
 The
Company believes its interest rate risk primarily relates to the use of
short-term debt instruments, variable-rate notes and leases and long-term debt
financing needed to fund capital requirements. The Company manages its interest
rate risk through the issuance of mostly fixed-rate debt of various maturities.
The Company utilizes bank borrowings, commercial paper, line of credit
facilities and accounts receivable securitization to meet short-term cash
requirements. These short-term obligations are commonly refinanced with
fixed-rate bonds or notes when needed and when interest rates are considered
favorable. The Company may at times enter into variable rate long-term bonds to
take advantage of lower interest rates. The Company may enter into swap
instruments or other financial hedge instruments to manage the interest rate
risk associated with these debts.
 In the
third quarter 2004, the Company entered into two treasury lock contracts to
hedge against potential rising interest rate exposure for a debt offering
anticipated to be performed in the first half of 2005. A treasury lock is a
financial arrangement between the Company and a counterparty whereby one of the
parties will be required to make a payment to the other party on a specific
valuation date based upon the change in value of a 30-year treasury bond. If
interest rates rise related to the hedged debt from the date of issuance of the
treasury lock instruments, the Company would receive a payment from the
counterparty for the change in the bond value. Alternatively, if interest rates
decrease related to the hedged debt from the date of issuance of the treasury
lock instruments, the Company would pay the counterparty for the change in bond
value. These treasury lock contracts were designated under SFAS No. 133 criteria
as cash flow hedges, with all changes in market value for each reporting period
being presented net of tax in other comprehensive income. 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. At March 31, 2005, the unrealized loss associated with the two
treasury lock contracts was $10.6 million after-tax and is included in other
comprehensive income. A hypothetical 10% decrease in the interest rate of a
30-year treasury note would result in an additional loss of $12.1 million
after-tax in other comprehensive income. The treasury lock contracts will settle
completely in 2005.
 
 
 Item
4.******Controls
and Procedures**
 
 **PUGET
ENERGY**
 **EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES**
 Under the
supervision and with the participation of Puget Energy’s management, including
the President and Chief Executive Officer and Senior Vice President Finance and
Chief Financial Officer, Puget Energy has evaluated the effectiveness of its
disclosure controls and procedures (as defined in Rule 13a-15(e) under the
Securities Exchange Act of 1934) as of March 31, 2005, the end of the period
covered by this report. Based upon that evaluation, the President and Chief
Executive Officer and Senior Vice President Finance and Chief Financial Officer
of Puget Energy concluded that these disclosure controls and procedures are
effective.
 
 **CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING**
 There
have been no changes in Puget Energy’s internal control over financial reporting
during the quarter ended March 31, 2005 that have materially affected, or are
reasonably likely to materially affect, Puget Energy’s internal control over
financial reporting.
 
 **PUGET
SOUND ENERGY**
 **EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES**
 Under the
supervision and with the participation of PSE’s management, including the
President and Chief Executive Officer and Senior Vice President Finance and
Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure
controls and procedures (as defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934) as of March 31, 2005, the end of the period covered by
this report. Based upon that evaluation, the President and Chief Executive
Officer and Senior Vice President Finance and Chief Financial Officer of PSE
concluded that these disclosure controls and procedures are effective.
 
 **CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING**
 There
have been no changes in PSE’s internal control over financial reporting during
the quarter ended March 31, 2005, that have materially affected, or are
reasonably likely to materially affect, PSE’s internal control over financial
reporting.
 
 
 **PART
II****OTHER
INFORMATION**
 
 
 Item
1.**Legal
Proceedings**
 
 See the
section titled “Proceedings Relating to the Western Power Market” under Item 2
“Management’s Discussion and Analysis of Financial Conditions and Results of
Operations” of this Quarterly Report on Form 10-Q.
 Contingencies
arising out of the normal course of the Company’s business exist at March 31,
2005. The ultimate resolution of these issues in part or in the aggregate is not
expected to have a material adverse impact on the financial condition, results
of operations or liquidity of the Company.
 
 
 Item
6.**Exhibits**
 
 See Exhibit Index for list of exhibits.
 
 
 
 **SIGNATURES**
 
 Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, each registrant has duly caused this report to be signed on their behalf
by the undersigned thereunto duly authorized.
 
 
 **PUGET
      ENERGY, INC.****PUGET
      SOUND ENERGY, INC.**/s/
      James W. Eldredge**James
      W. Eldredge**Corporate
      Secretary and ChiefAccounting
      OfficerDate:
      May 4, 2005Chief
      accounting officer and officer duly authorizedto
      sign
      this report on behalf of each
registrant
  Table of Contents
  **EXHIBIT INDEX**
 
 The
following exhibits are filed herewith:
 
 
 12.1
    Statement
      setting forth computation of ratios of earnings to fixed charges (2000
      through 2004 and 12 months ended March 31, 2005) for Puget Energy.
 
 12.2
    Statement
      setting forth computation of ratios of earnings to fixed charges (2000
      through 2004 and 12 months ended March 31, 2005) for
  PSE.
 
 31.1
    Chief
      Executive Officer certification of Puget Energy pursuant to 18 U.S.C.
      Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
      of 2002.
 
 31.2
    Chief
      Financial Officer certification of Puget Energy pursuant to 18 U.S.C.
      Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
      of 2002.
 
 31.3
    Chief
      Executive Officer certification of Puget Sound Energy pursuant to 18
      U.S.C. Section 1350, as adopted pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.
 
 31.4
    Chief
      Financial Officer certification of Puget Sound Energy pursuant to 18
      U.S.C. Section 1350, as adopted pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.
  32.1
    Chief
      Executive Officer certification pursuant to 18 U.S.C. Section 1350, as
      adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002.
 
 32.2
    Chief
      Financial Officer certification pursuant to 18 U.S.C. Section 1350, as
      adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002.