UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

/X/

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)

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


For the fiscal year ended December 31, 20022003
OR

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


For the transition period from __________ to __________

/   /

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934


For the transition period from ___________ to ___________



Commission
FileNumber
 Exact name of registrant as specified
I.R.S.
in its charter, state of incorporation,
Employer
Commissionaddress of principal executive offices,
Identification
File Numbertelephone numberI.R.S.
Employer
Indentification
NumberNumbers


1-16305PUGET ENERGY, INC.91-1969407
 A Washington Corporation
411 - 108th Avenue N.E.
Bellevue, Washington 98004-5515
(425) 454-6363
Corporation. 
 10885 N.E. 4th Street, Suite 1200 
 Bellevue, Washington 98004-5591 
1-4393(425) 454-6363 


1-4393PUGET SOUND ENERGY, INC.91-0374630
 A Washington Corporation
411 - 108th AvenueCorporation.
10885 N.E.
4th Street, Suite 1200
Bellevue, Washington 98004-5515
98004-5591
(425) 454-6363 

Securities registered pursuant to Section 12(b) of the Act:


TITLE OF EACH CLASS
NAME OF EACH EXCHANGE
ON WHICH LISTED

 Puget Energy, Inc.

Common Stock, $.01$0.01 par value

N.Y.S.E.
   
      Preferred Share Purchase RightsN.Y.S.E.
   
 Puget Sound Energy, Inc.
     8.4% Capital Securities

N.Y.S.E.

Securities registered pursuant to Section 12(g) of the Act:

TITLE OF EACH CLASS
Puget Sound Energy, Inc.
     Preferred Stock, (cumulative, $100 par value)
 
7.45% Series II, Preferred Stock
(Cumulative, $25 Par Value)
N.Y.S.E.
   
      8.4% Capital SecuritiesN.Y.S.E.


Securities registered pursuant to Section 12(b) of the Act:


TITLE OF EACH CLASS
Puget Sound Energy, Inc.
Preferred Stock (Cumulative, $100 Par Value)
8.231% Capital Securities 


Puget Sound Energy, Inc. meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

        Indicate by check mark whether the registrant:registrants: (1) hashave filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant wasregistrants were required to file such reports), and (2) hashave been subject to such filing requirements for the past 90 days.
               Yes/X/ No/Yes /X/ No /

/
        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. / /


        Indicate by check mark whether the registrantPuget Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).
               Yes/X/ No/Yes /X/ No /

/
        Indicate by check mark whether Puget Sound Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).
               Yes / / No /X /
        The aggregate market value of the voting stock held by non-affiliates of Puget Energy, Inc. at June 28, 200230, 2003 (the last business day of Puget Energy’s most recently completed second fiscal quarter), was approximately $1,807,769,393.$2,238,688,000. The number of shares of Puget Energy, Inc.‘s common stock outstanding at February 28, 2003,27, 2004 was 93,827,455.99,246,495 shares.

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

Documents Incorporated by Reference

        Portions of the Puget Energy, Inc. proxy statement for its 20032004 Annual Meeting of Shareholders to be filed with the Commission pursuant to Regulation 14A not later than 120 days after December 31, 20022003 are incorporated by reference in Part III hereof.

        This Annual Report on Form 10-K is a combined report being filed separately by two different registrants: Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE). PSEPuget Sound Energy, Inc. makes no representation as to the information contained in this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy, Inc. other than PSEPuget Sound Energy, Inc. and its subsidiaries.



INDEX

Definitions
Forward-Looking Statements
Part I
 1.Business 
   General
   Utility Industry OverviewRegulation and Rates
   Regulation and RatesUtility Industry Overview
   Electric Operating Statistics
   Electric Supply
   Gas Operating Statistics
   Gas Supply
   Energy Conservation
   Environment
   Executive Officers of the Registrants
 2.Properties 
  3.Legal Proceedings
  4.Submission of mattersMatters to a Vote of Security Holders

Part II
 5.Market for Registrant's Common Equity and Related Shareholder Matters
  6.Selected Financial Data
 7.Management's Discussion and Analysis of
   Financial Condition and Results of Operations
 7a.Quantitative and Qualitative Disclosures about Market Risk
 8.Financial Statements and Supplementary Data
 9.Changes in and Disagreements with Accountants on Accounting
   and Financial Disclosure
9a.Controls and Procedures

Part III
 10.Directors and Executive Officers of the Registrants
 11.Executive Compensation
12.Security Ownership of Certain Beneficial Owners and Management
   and Related Stockholder Matters
 13.Certain Relationships and Related Transactions
 14.ControlsPrincipal Accountant Fees and ProceduresServices
 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K
 
 Signatures
  CertificationsReport of Puget EnergyManagement
  CertificationsReport of Independent Auditors - Puget Energy, Inc.
Report of Independent Auditors - Puget Sound Energy, Inc.
  Exhibit Index

DEFINITIONS

     AFUCEAllowance for Funds Used to Conserve Energy
AFUDCAllowance for Funds Used During Construction
 aMWAverage Megawatt
     BPABonneville Power Administration
 CAAAClean Air Act Amendments
     CAISOCalifornia Independent System Operator
 CabotCabot Oil & Gas Corporation
     ChelanPublic Utility District No. 1 of Chelan County, Washington
 
DthDekatherm (one Dth is equal to one MMBtu)
 
     FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
 
     FINFinancial Accounting Standards Board Interpretation
     FPAFederal Power Act
InfrastruXInfrastruX Group, Inc.
 
KWKilowatts
 
kWhKilowatt Hours
 
     LIBORLondon Interbank Offered Rate
LNGLiquefied Natural Gas
 
MMBtuOne Million British Thermal Units
 
MWMegawatts (one MW equals one thousand KW)
 
MWhMegawatt Hours
 NPC
     NOPRWilliams/Notice of Proposed Rulemaking
     NWPWilliams Northwest Pipeline Corporation
 
     PCAPower Cost Adjustment
PGAPurchased Gas Adjustment
 
PG&EPacific Gas & Electric Company
 PGTPacific Gas & Electric Gas Transmission - Northwest
     PSEPuget Sound Energy, Inc.
 
PUDsWashington Public Utility Districts
 
Puget EnergyPuget Energy, Inc.
 
PURPAPublic Utility Regulatory Policies Act
 
     RFPRequest for Proposal
RTORegional Transmission Organization
 
SFASStatement of Financial Accounting Standards
 
SMDFERC Standard Market Design
 WEGMWashington Energy Gas Marketing Company
     Washington CommissionWashington Utilities and Transportation Commission

FORWARD-LOOKING STATEMENTS

        Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) are including the following cautionary statement in this Form 10-K 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 which 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,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, financings, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation and construction of hydro,electric generating facilities, distribution and transmission facilities, licensing of hydro operations, recovery of other capital investments, recovery of power and gas costs, recovery of regulatory assets, and present or prospective wholesale and retail competition;

the bankruptcy filing by Enron Corporation, financial difficulties byof 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;

wholesale market disruption, which may result in a deterioration in market liquidity, increase the risk of counterparty default, by counterpartiesaffect the regulatory and legislative process in unpredictable ways, limit the availability of and access to capital credit markets, affect wholesale natural gas and electricity markets that owe PSE money energy prices and/or energy;

continued deterioration of liquidity in the forward markets in which PSE transacts hedgesimpede PSE’s ability to manage its energy portfolio risks which can limit PSE’s abilityrisks;

the effect of wholesale market structures (including, but not limited to, enter into forward contractsnew market design such as Regional Transmission Organization (RTO) West and therefore, its ability to manage its portfolio risks;

Standard Market Design);

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;

hydroelectric conditions, which can have a potentially serious impact on electric capacity and PSE’s ability to generate electricity;

the stability and liquidity of wholesale energy markets generally, including the effect of price controls by FERC on the availability and price of wholesale energy purchases and sales in the western United States;

the effect of wholesale and possible future retail competition (including, but not limited to, electric retail wheeling and transmission system access);

the amount of collection, if any, of PSE’s receivablereceivables from the California Independent System Operator (CAISO) and the amount of refunds found to be due from PSE to the CAISO or others;

industrial, commercial and residential growth and demographic patterns in the service territories of PSE;

general economic conditions in the Pacific Northwest;

the loss of significant customers or changes in the business of significant customers, which may result in changes in demand for PSE's services;

plant outages, which can have an impact on PSE’s expenses and its ability to procure adequate supplies to replace the lost energy;

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; and
the ability to relicense FERC hydro projects at a cost-effective level.

Risks relating to the non-regulated utility service business (InfrastruX Group, Inc.)

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 ability of InfrastruX to integrate acquired companies withwithin existing operations without substantial costs, delays or other operational or financial problems, which involves a number of special risks;

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 both price and quality;

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 associated with the financial conditions of InfrastruX’sInfrastruX'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;

and
the ability to obtain adequate bonding coverage and the cost of such bonding.

Risks relating to both the regulated and non-regulated businesses

the impact of acts of terrorism or similar significant events, such as the attack on September 11, 2001;

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;

changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies;

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.

insurance; and
the impacts of natural disasters such as earthquakes, hurricanes or landslides.

        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.


PART I

ITEM 1. BUSINESS

GENERAL
        Puget Energy, Inc. (Puget Energy) is an energy services holding company incorporated in the State of Washington in 1999. All of its operations are conducted through its subsidiaries, Puget Sound Energy, Inc. (PSE), a utility company, and InfrastruX Group, Inc. (InfrastruX), a construction services company. Puget Energy has no significant assets other than the stock of its subsidiaries. Subject to limited exceptions, Puget Energy is exempt from regulation as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935. Puget Energy and PSE are collectively referred to herein as “the Company.” The following table provides the percentages of Puget Energy’s consolidated operating revenues and net income generated and assets held by the reportable segments:

Segment      Percent of Revenue      Percent of Net Income      Percent of AssetsSegment      Percent of Revenue      Percent of Net Income      Percent of Assets
200220012000200220012000200220012000 200320022001200320022001200320022001
Puget Sound Energy86.2%92.9%98.2%88.3%75.0%105.6 %92.1%93.4%96.1% 86.0%86.2%92.9%98.2%88.3%75.0%92.6%92.2%93.5%
InfrastruX13.4%6.0%1.4%8.0%2.4%(0.3)%5.6%4.2%1.9% 13.7%13.4%6.0%1.5%8.0%2.4%6.0%5.5%4.0%
Other subsidiaries0.4%1.1%0.4%3.7%22.6%(5.3)%2.3%2.4%2.0% 0.3%0.4%1.1%0.3%3.7%22.6%1.4%2.3%2.5%

        Additional financial data regarding these segments isare included in Note 2019 to the Consolidated Financial Statements included with this report.

PUGET ENERGY STRATEGY
        Puget Energy is the parent company of the largest electric and natural gas utility headquartered in the State of Washington, State, primarily engaged in the business of electricityelectric transmission, distribution and generation, and natural gas transmission and distribution. Puget Energy’s business strategy is to generate stable earnings and cash flow by focusing primarily on the regulated utility business conducted through PSE. The key elements of this strategy include:

 Focus on regulated utility business. PSE intends to continue to focus on its core electric and natural gas transmission and distribution utility business.business, offering reliable electric and gas service at a fair value to PSE’s customers.

 Add electric generation and delivery infrastructure to meet customer needs. Ensuring stable, cost-based energy supply is one of PSE’s highest priorities. As regional demand for energy continues to grow, PSE’s committed power supply resources will not be adequate to meet anticipated demand, especially as existing long-term power purchase contracts begin to expire. The collapse of the merchant energy industry has resulted in the cancellation or delay of power plant construction projects that were expected to meet the region’s supply needs at competitive prices. Accordingly, assuring stable, cost-basedPSE has begun the process of acquiring generation to meet load by purchasing a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired electric generating facility located within PSE’s service territory, which is anticipated to be completed in the second quarter of 2004. Also, PSE has issued a request for proposals (RFP) to acquire approximately 50 average MW of energy supply is onefrom wind power for its electric resource portfolio and issued an RFP in February 2004 for an additional 305 MW of PSE’s highest priorities.new electric-power resources. PSE will also continue its expenditures on conservation through utility programs and an RFP for another 30 average MW of energy efficient projects. In addition to these strategies to increase capacity and energy, PSE will continue to focus on operational excellence and efficiency in the utility business through investment in, and development of, systems, technology and personnel.

 Rebuild financial strength to fund energy infrastructure and manage energy portfolio.PSE intends to focus on the regulated business to provide credit quality, liquidity and safe and predictable earnings to attract investors in Puget Energy. During 2003, Puget Energy was able to attract investors and sell additional common stock to those investors.


 Provide return to Puget Energy investorsshareholders through earnings growth and dividends.Generate return and attract equity capital through growth in PSE and InfrastruX earnings and dividends.

 Achieve PSE earnings growth.PSE earnings will grow through rebuilding common equity and increasing the ratebase by adding generating and delivery resources where needed with timely cost recovery. Puget Energy was able to invest additional capital in PSE through the sale of its common stock.

 Focus on InfrastruX growth.Focus on internal earnings growth opportunities within the InfrastruX subsidiaries.

PUGET SOUND ENERGY, INC.
        PSE is a public utility incorporated in the State of Washington. PSE furnishes electric and gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of Washington State.


the State of Washington.
        At December 31, 2002,2003, PSE had approximately 958,000977,700 electric customers, consisting of 845,200861,900 residential, 106,900109,700 commercial, 3,9004,000 industrial and 2,0002,100 other customers; and approximately 622,000644,600 gas customers, consisting of 572,300593,800 residential, 46,80048,000 commercial, 2,8002,700 industrial and 100 transportation customers. At December 31, 20022003, approximately 305,300310,900 customers purchased both forms of energy from PSE. For the year 2002,2003, PSE added approximately 17,40019,700 electric customers and approximately 16,00022,600 gas customers, representing annualized growth rates of 1.8%2.1% and 2.6%,3.6% respectively. During 20022003, PSE’s billed retail and transportation revenues from electric utility operations, excluding conservation trust collections, were derived 48% from residential customers, 42%43% from commercial customers, 7% from industrial customers and 3%2% from transportation and other customers. PSE’s retail revenues from gas utility operations were derived 62%64% from residential customers, 31%29% from commercial customers, 5% from industrial customers and 2% from transportation customers. During this period the largest customer accounted for approximately 1% of PSE’s operating revenues.
        PSE is affected by various seasonal weather patterns throughout the year and, therefore, utility 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 in the first and fourth quarters of the year. Sales of electricity to wholesale customers also vary by quarter and year depending principally upon streamflow conditions for the generation of surplus hydroelectric power after serving customer requirementseconomic factors and the market demand by wholesale customers.weather conditions. PSE has a Purchased Gas Adjustmentpurchased gas adjustment (PGA) mechanism (PGA) in retail gas rates to recover variations in gas supply and transportation costs. PSE also has a Power Cost Adjustmentpower cost adjustment (PCA) mechanism (PCA) in electric rates to recover variations in electricity costs on a shared basis between customers and PSE.
        DuringIn the five-year period from January 1, 1998 throughended December 31, 2002,2003, PSE’s gross electric utility plant additions were $894$941 million and retirements were $184$210 million. In the five-year period ended December 31, 2002,2003, PSE’s gross gas utility plant additions were $565$551 million and retirements were $72$76 million. In the same five-year period, PSE’s gross common utility plant additions were $328$211 million and retirements were $32$45 million. Gross electric utility plant at December 31, 20022003 was approximately $4.2$4.3 billion, which consisted of 59% distribution, 26%27% generation, 7%6% transmission and 8% general plant and other. Gross gas utility plant as of December 31, 20022003 was approximately $1.6$1.7 billion, which consisted of 86% distribution, 6% transmission and 8% general plant and other. Gross common utility general and intangible plant as ofat December 31, 20022003 was approximately $379$391 million.

        INFRASTRUX GROUP, INC.
        InfrastruX was incorporated in the State of Washington in 2000 to pursue the non-regulated construction services business. InfrastruX is a national leader in providing infrastructure construction services to the electric and gas utility industries. InfrastruX has acquired eleven12 companies, primarily in the south/Texas, and the north-central and eastern United States, that are engaged in some or all of the following services and activities in their respective regions or nationally:

Electric: Overhead and underground power line and cable construction, installation and maintenance, including high-voltage transmission and distribution lines, copper and fiberoptic cables; duct installation; revitalization and damage prevention for underground power lines and cables using the patented Cablecure® treatment; substation construction; and other specialty services for new and existing infrastructures.


Gas: Large diameterLarge-diameter pipeline installation and maintenance; service lines and meters; conventional river crossings and bridge maintenance; cathodic protection; power station fabrication and installation; vacuum excavation; hydrostatic testing; internal pipeline inspection; product pipelines; and other specialty services for distribution and transmission pipeline services including small, mid-size and large borelarge-bore directional drilling for virtually all pipeline diameters and soil conditions.


        The InfrastruX construction services business is affected by seasonal weather conditions and, therefore, revenues and associated expenses are not generated evenly during the year. InfrastruX will usually experience its highest revenues in the second and third quarters of the year.


INFRASTRUX OPERATING STRATEGYyear, as spring and summer months are routinely the most productive time of year for the construction industry due to longer daylight hours and generally better weather conditions.
        In InfrastruX’s initial three years, InfrastruX focused on acquiring and expanding business services inoperating strategy revolves around leveraging the natural gas and electric utilitysynergies of a core group of outstanding infrastructure market that have an established regional presence and are positioned to expand their market position. Implementation of InfrastruX’s strategy involved identifying acquisition targets with established operational experience and customerconstruction contractors whose asset base, expertise, local knowledge, relationships and years of successful operations form a strong management team. InfrastruX’s current operating strategy depends primarily upon generating internal growth through the addition of newbase for a growing business. The ability to share workforce, production equipment and expertise within and between regional geographies allows InfrastruX to provide local support for its customers and expansionalso move quickly to provide additional services as needs arise. The formation of services offered to existing customers rather than external growth through acquisitions.

INFRASTRUX COMPETITIONregional service centers in 2003, where appropriate, is providing enhanced oversight and control as well as cost efficiencies surrounding back office operations, equipment control and other operational areas.
        The construction services industry is both highly competitive and highly fragmented as a result of low barriers to entry, the historical geographic segmentation of utility customers and the natural limitations of service delivery. Competitors of InfrastruX include large established and emerging national companies and many smaller regional companies. Puget Energy believes that InfrastruX’s competitive strengths, including a diverse customer base, long-standing relationships with several key customers and operational expertise in construction services will benefit InfrastruX, but there can be no assurance that a competitor will not be able to develop expertise, experience and resources to provide services that are superior in quality or price to InfrastruX’s services.

MARKET OUTLOOK
        InWhile the general outlook appears to be improving, in the near term, InfrastruX’s market opportunities will continue to be limitedconstrained by the general economic and utility industry downturn that will resulthas resulted in reduced spending on infrastructure construction, including large pipeline and utility projects, by many of InfrastruX'sInfrastruX’s customers. As a result, competition on project bids will increase,continue to be very strong, which may reduce profit margins and adversely impact revenue and operational growth. Puget Energy believesmanagement continues to believe that in the long-termlong term the opportunities for InfrastruX are excellent given an aging transmission and distribution infrastructure, forecast forforecasted growth in energy demand and the need for greater network infrastructure construction services.

        EMPLOYEES
        As ofAt December 31, 2002,2003, Puget Energy and its subsidiaries had approximately 4,6605,164 full-time employees:

Puget Sound Energy2,1132,155 
InfrastruX2,5473,009 
Total Puget Energy4,6605,164 

        Approximately 1,100 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) andor the United Association of Plumbers and Pipefitters (UA). PSE has renegotiated contract extensionsThe labor contracts with the IBEW and UA run through 2007 and 2006, respectively.
        Approximately 200400 InfrastruX employees are represented by the IBEW, UA, United Steelworkers of America, and Laborers International Union of North America.America or other unions. Some unions have annual contract renewals while others are multiple-year.have multiple-year contracts.


        CORPORATE LOCATIONSLOCATION
        Puget Energy’s and PSE’s principal executive offices are located at 411 108th Avenue10885 N.E., 4th Street, Suite 1200, Bellevue, Washington 98004 and itsthe telephone number is (425) 454-6363. The Company’s principal executive offices will be relocating in July 2003 to 10885 N.E. 4th Street, Bellevue, Washington 98004.

        AVAILABLE INFORMATION
        The Annual ReportCompany’s website address is www.pse.com. The Company’s reports on Form 10-K, Quarterly Reportsquarterly reports on Form 10-Q, Current Reportscurrent reports on Form 8-K and amendments to those reports filed or furnished pursuant to SectionsSection 13(a) andor 15(d) of the Securities Exchange Act of 1934 as amended, are available or may be accessed free of charge through the Investors section of the Company’s website as soon as reasonably practical after the reports are electronically filed with, or furnished to, the SEC. The Company’s website and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K.
        In addition, the following corporate governance materials of the Company are available in the Investors section of the Company’s website, and a copy will be mailed upon request to Puget Energy’s website at www.pse.com.Energy, Inc., Investor Services, P.O. Box 97034, PSE-08S, Bellevue, Washington 98009-9734:


UTILITY INDUSTRY OVERVIEW
        On December 20, 1999, FERC issued Order 2000 to advance the formation

Corporate Governance Guidelines;
Corporate Ethics and Compliance Code
Audit Committee, Governance and Public Affairs Committee and Compensation and Leadership Development Committee charters;
Code of Regional Transmission Organizations (RTOs). This regulation required each public utility that owns, operates or controls facilitiesEthics for the transmissionCompany’s Chief Executive Officer and senior financial officers.

        If the Company waives any material provision of electric energy in interstate commerce to file with FERC by October 15, 2000 plansits Code of Ethics for formingits Chief Executive Officer and participating in an RTO. FERC’s goal is to promote efficiency in wholesale electricity marketssenior financial officers or its Corporate Ethics and to reduce prices electricity consumers pay toCompliance Code, or substantively changes the lowest price possiblecodes for reliable service. On October 16, 2000, PSE andany specific officer, the Company will disclose that waiver on its website within five other utilities filed with FERC their proposal for an independent transmission company, which would serve six states. The independent transmission company would be a member of the planned regional transmission organization. Any final proposal that emerges is subject to approval by FERC and relevant state public utility commissions. FERC has also issued a Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The SMD NOPR would have major implications for the delivery of electric energy throughout the United States if enacted in its proposed form. Major elements of FERC’s proposal include: (a) the use of Network Access Service to replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff; (b) vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems; (c) the formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states.
        Since 1986 PSE has been offering gas transportation as a separate service to industrial and commercial customers who choose to purchase their gas supply directly from producers and gas marketers. The continued evolution of the natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has served to increase the ability of large gas end-users to independently obtain gas supply and transportation services. Although PSE has not lost any substantial industrial or commercial load as a result of such activities, in certain years up to 160 customers annually have taken advantage of unbundled transportation service; in 2002, 134 commercial and industrial customers, on average, chose to use such service. The shifting of customers from sales to transportation does not materially impact utility margin, as PSE earns similar margins on transportation service as it does on large volume, interruptible gas sales.
        The electric utility business in Washington State is fully regulated. There are no proposals or prospects for retail deregulation in Washington State anticipated in the foreseeable future.
days.

REGULATION AND RATES
        PSE is subject to the regulatory authority of (1) the Washington Commission as to retail utility rates, accounting, the issuance of securities and certain other matters and (2) FERC with respect to the transmission of electric energy, the resale of electric energy at wholesale, accounting and certain other matters. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Rate Matters”.)

        ELECTRIC RATES AND REGULATIONSREGULATION
        On March 28, 2002,October 24, 2003, PSE filed a request with the Washington Commission approved a settlement agreement which resolved the Company’s request for an interimto increase its electric rates $64.4 million to recover higher projected power supply costs. The proposed rate increase and significant financial issuesincludes, among other things, the recovery of the projected costs associated with PSE’s proposed acquisition of a 49.85% share of Frederickson Power LP’s Frederickson 1 generation facility (250 MW) located near Tacoma, Washington.
        On January 30, 2004, the Washington Commission staff filed testimony responding to PSE’s filing. The Washington Commission staff’s testimony finds that the decision to acquire the interest in the Company’s electricFrederickson 1 plant was prudent and gas general rate cases. As a result, an interimthat PSE’s costs to do so were reasonable. Accordingly, the Washington Commission staff recommended to the Washington Commission that PSE’s costs be recovered in rates. No other party filed testimony questioning the decision or costs to acquire the Frederickson 1 plant. Favorable treatment of this acquisition will benefit PSE’s customers and PSE going forward.
        In the same proceeding, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate surchargeincrease. Among other things, they propose that a significant amount of $25 million wasPSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in effect for the period April 1, 2002 through June 30, 2002. The three important financial issueselectric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were resolved foravailable in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If the Washington Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.


        PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and their positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power cost only rate case is expected by mid-April 2004. Another step in completing the acquisition of the power generating facility is to obtain the approval of FERC in accordance with the Federal Power Act (FPA). In December 2003, FERC issued an order in a case involving Oklahoma Gas & Electric Company (OGE) that suggested that FERC would scrutinize these transactions. In the OGE case, FERC has decided to hold hearings to analyze the effects on market share and transmission availability that would flow from the OGE acquisition. PSE took that decision into account when it filed its application in January 2004. FERC issued a letter on February 12, 2004 in response to PSE’s filing seeking additional information. PSE responded to the request on February 27, 2004, and still anticipates FERC approval of the acquisition in early 2004.
        PSE is currently preparing to file a general tariff electric rate case with the Washington Commission in the second quarter of 2004. The resolution of the general rate case includedmay be up to an 11-month process from the equity capital ratio,time the return on equity and adoption of an electric power cost adjustment mechanism.general rate case is filed.
        On June 20, 2002, the Washington Commission issued final regulatory approval of the comprehensive electric-rateelectric rate settlement submitted by PSE, key constituents and customer groups, Washington Commission staff and the Washington State Attorney General’s Public Counsel Section. The authorization granted PSE a 4.6% electric general rate increase that willbegan July 1, 2002, which was intended to generate approximately an additional $59 million in additional revenue annually that began July 1, 2002.annually. In addition, the settlement provided for an 8.76% overall return on capital based on a projected capital structure with an equity component of 40% and an authorized 11% return on common equity. The settlement resolved all electric and gas cost allocation issues and established an 8.76% overall return on capital.



        The settlement also includesincluded 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 yearfour-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and wheeling cost variability). On an annual July through June basis, the 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' ShareCompany'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.

        (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.

        Interest will be accrued on any overcollection or undercollection of the customers’ share of the excess power cost that is deferred. The CompanyPSE can request a PCA rate surcharge if for any 12 month12-month period the actual or projected deferred power costs exceedsexceed $30 million. PSE’s cumulative share of the power costs through December 31, 20022003 was $5.2$40 million. BecausePrincipally because of adverse hydro conditions and escalating gas costs for electric generation in 2003, PSE anticipates reachingreached the $40 million cumulative cap under the PCA mechanism byin the fourth quarter of 2003. During 2003, PSE’s share of the excess power costs was $34.8 million compared to $5.2 million for 2002. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE. PSE is required to file a Compliance Filing with the Washington Commission annually on June 30, in relation to the power costs under the PCA mechanism.
        The settlement also givesgave PSE the financial flexibility to rebuild its common equity ratio to at least 39% over a three and a half yearthree-and-one-half-year period, with milestones of 34%, 36% and 39% at the end of 2003, 2004 and 2005, respectively. If PSE should fail to meet this schedule, it would be subject to a 2% rate reduction penalty. As of December 31, 2003, PSE has restored its common equity ratio to a 40% level, exceeding the required level for 2003 by 6%.


RESIDENTIAL AND SMALL FARM EXCHANGE CREDIT
        OnIn June 13, 2001, the Washington Commission approvedPSE and Bonneville Power Administration (BPA) entered into an amended settlement agreement regarding the Residential Purchase and Sale Agreement (Agreement) between PSE and the BPA,Program, under which PSE’s residential and small farm customers would continue to receive the benefits of federal power. Completion of this agreement enabled PSE to continue to provide and in fact increase, effective January 1, 2002, thea Residential and Farm Energy Exchange CreditBenefit credit to residential and small farm customers. The Agreementamended settlement agreement provides that, for its residential and small farm customers, PSE will receivereceive: (a) cash payment benefits during the period July 1, 2001 through September 30, 2006 and (b) benefits in the form of power or cash payments during the period October 1, 2006 through September 30, 2011.
        Under the amended settlement agreement regarding the Residential Purchase and Sale Program, PSE reduces residential and small farm customers revenue on a per kWh basis through the Residential and Farm Energy Exchange Benefit credit. The credit has no impact on PSE’s electric margin or net income, as a corresponding reduction is included in purchased electricity expenses. The amended settlement agreement regarding the Residential Purchase and Sale Program provides PSE’s residential and small farm customers the benefits of lower-cost federal power.
        On June 17, 2002, PSE entered into an agreement with the BPA, which amendedmodified the payment provisions of the Agreementamended settlement agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement.
        To implement this agreement for rate purposes, the Washington Commission approved tariff revisions that were intended to (a) transfer the Residential and Farm Energy Exchange credit in effect since October 1, 1995 in the amount of $0.01085 per kWh, to general rates effective July 1, 2001 and (b) to provide a supplemental Residential and Farm Exchange credit for eligible residential and small farm customers. On June 26, 2002, the Washington Commission then transferred the portion of the credit that had been in general rates back into Schedule 194.
        The Residential and Farm Exchange Benefit Supplemental Rider schedule was retitled Residential and Farm Energy Exchange Benefit, the portion of the credit that had been in general rates was transferred back into Schedule 194, and the credit was set at $0.01456 per kWh for the period July 1, 2002 through September 30, 2002, $0.01817 per kWh for the period October 1, 2002 through May 31, 2006 and $0.02302 per kWh for the period June 1, 2006 through September 30, 2006. The approval of these revised tariffs by the Washington Commission was effective July 1, 2002.
        In January 2003, PSE filed tariff sheets with the Washington Commission to reflect a modification to the agreement between PSE and the BPA that would reduce the Residential and Farm Energy Exchange Benefit credit. Under the modified agreement, BPA will deferdeferred paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred will bewas $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA is enteringentered into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA are agreeingagreed to BPA’s deferral of payments in theirits fiscal year 2003. The total cumulative amount to be deferred under the agreement with PSE and other such agreements equals $55 million, an amount that will help BPA address its current financial difficulties.million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA will begin paying back the amount deferred with interest over the sixty-month60-month period beginning NovemberOctober 1, 2006.
        In January 2003, PSE filed revised tariff sheets with the Washington Commission to reflect this modification to the agreement between PSE and BPA. The Washington Commission approvedaccepted the tariff changes and the RiderResidential and Farm Energy Exchange Benefit credit was changed to $0.01740 per kWh from $0.01817 per kWh for the period February 15, 2003 through September 30, 2006. The deferralOn June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula under the BPA benefitsrate adjustment clause to be used in adjusting the rate that will not have any impact on PSE earnings, as it is a direct pass-through to PSE customers.


        BPA’s rate case may affect the level of residential exchange benefits for PSE’s customers. For 2002,The adjustment under the formula went into effect on October 1, 2003, resulting in both a reduction of benefits of $1.0 million a month for a 12-month period and, under the modified amended settlement agreement mentioned above, an offsetting acceleration of the payment of the above-described $27.7 million deferral. The net result is no change in the cash being received from BPA for the 12-month period, but a reduction in the total benefits to be received in the October 1, 2003 through September 30, 2011 period.
        For 2003 and 2002, the Residential and Farm Energy Exchange Benefit credited to customers were $152.8was $181.9 million and $156.8 million, respectively, with a related offset to power costs. PSE received payments from BPA in the amount of $147.9 million and $171.2 million during 2002.2003 and 2002, respectively. The difference between the customers’ credit and the amount received from BPA iseither increases or decreases the previously deferred and creditedamount owed to customers in later periods.customers. The differenceaggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. TheAbsent certain adjustments tied to the BPA rate adjustment clause described above, the modified Agreement, if it goes into effect, wouldamended settlement agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for a pass-through of the same amount to eligible residential and small farm customerscustomers.
        On October 23, 2003, PSE signed conditional settlement agreements including a Stipulation and Agreement for Settlement, a Waiver and Covenant Not to Sue, and an Amendment No. 1 to the amended settlement agreement. These conditional settlement agreements, which are now void because certain conditions were not satisfied, included provisions for the dismissal of certain lawsuits regarding residential exchange benefits, an elimination of the same amount. The leveladjustment mentioned above for the 12-month period commencing October 1, 2003, the deferral of the receipt of certain benefits, a change in the methodology used to calculate residential benefits in the October 1, 2006 through September 30, 2011 period, and elimination of a risk premium that would otherwise have been payable by BPA credit does not affect PSE’s earnings, sinceunder certain conditions under the credit is a direct pass-through to residential customers. The credit does affect the net rates paid by those customers.
amended settlement agreement.


        There are several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the contractamended settlement agreement and the conditional settlement agreements between BPA and the CompanyPSE described above. BPA rates used in such contractamended settlement agreement between BPA and the CompanyPSE for determining the amounts of money to be paid to the CompanyPSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC on an interim basis, subjectFERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to refund with interest.law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates and the above-described District Court and U.S. Ninth Circuit Court of Appeals actions may have on the Company.PSE.

        GAS RATES AND REGULATION
        PSE has a PGA mechanism in retail gas rates to recover variations in gas supply and transportation costs. The PGA mechanism passes through to customers these variations in gas rates, and therefore PSE’s gas margin and net income are not affected by changes in the PGA rates. The following rate adjustments were approved by the Washington Commission in relation to the PGA during 2003, 2002 and 2001:

EFFECTIVE DATE
PERCENTAGE INCREASE
(DECREASE) IN RATES

ANNUAL INCREASE (DECREASE)
IN REVENUES
(DOLLARS IN MILLIONS)

October 1, 2003   13.3%$78.8
April 10, 2003   20.1% 103.6
November 1, 2002   (12.5)% (70.6)
September 1, 2002   (7.3)% (45.0)
June 1, 2002   (21.2)% (138.9)
September 1, 2001   (8.9)% (81.1)
January 12, 2001   26.4% 163.5

        On August 28, 2002, the Washington Commission approved a 5.8% gas rate increase in general rates to cover higher costs of providing natural gas serviceservices to customers. ThisThe increase willwas intended to provide approximately $35.6 million annually in revenues and was offset by an annual $45 million or 7.3% PGArevenues. This rate reduction, also approved on August 28, 2002. Both rate actionsincrease became effective September 1, 2002. The PGA mechanism passes through
        PSE is currently preparing to customers increases or decreasesfile a general tariff gas rate case with the Washington Commission in the second quarter of 2004. The resolution of the general rate case may be up to an 11-month process from the time the general rate case is filed.

UTILITY INDUSTRY OVERVIEW
FEDERAL REGULATION
        Since the mid-1990s FERC has required public utilities operating under the FPA to provide open access of their transmission systems to third parties under tariffs approved by FERC. As a result of open access, there has been no material effect on the financial statements of PSE.
        On July 31, 2002, FERC issued its Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The SMD NOPR would have major implications for the delivery of electric energy throughout the United States if enacted in its proposed form. Major elements of FERC’s proposal include: (a) The use of Network Access Service would replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff. (b) Vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems. (c) Regional State Advisory Committees and other regional entities would form to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. State regulators and industry representatives have pointed out that the western North American electricity market has unique characteristics that may not readily lend themselves to the SMD NOPR proposed by FERC. FERC has expressed its willingness to offer regional flexibility in its order on RTO West, Docket Nos. RT01-35-005 and RT01-35-007, issued September 18, 2002. In April 2003, FERC issued a white paper responding to concerns of state regulators regarding the impact of the SMD NOPR proposal on the western market. PSE cannot predict the outcome of the SMD NOPR or whether the ultimate resolution will have a material impact on the financial condition, results of operations or liquidity of the Company.

STATE REGULATION
        The electric utility business in the State of Washington is fully regulated and provides service to its customers under cost-based tariff rates. PSE is not aware of any proposals or prospects for retail deregulation in the State of Washington.
        Since 1986 PSE has been offering gas transportation as a separate service to industrial and commercial customers who choose to purchase their gas supply portiondirectly from producers and gas marketers. The continued evolution of the natural gas service rates based upon changes inindustry, resulting primarily from FERC Orders 436, 500 and 636, has served to increase the priceability of naturallarge 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 the change in PGA rates.
        On May 24, 2002, the Washington Commission allowed a PGA rate reduction that was filed on May 6, 2002, effective June 1, 2002, lowering overall natural gas rates by 21.2%. This ended a temporary surcharge that went into effect September 1, 2001.
        On September 30, 2002, PSE filed a proposal with the Washington Commissionend-users to reduce naturalindependently obtain gas supply rates under the PGA for a third time in 2002. The Washington Commission approved the proposal on October 30, 2002 and transportation services. Although PSE lowered gas rates overall through the PGA by approximately 12.5% effective November 1, 2002.
        Ashas not lost any substantial industrial or commercial load as a result of sharp increasessuch activities, in certain years up to 160 customers annually have taken advantage of unbundled transportation service; in 2003, 134 commercial and industrial customers, on average, chose to use such service. The shifting of customers from sales to transportation does not materially impact utility margin, as PSE earns similar margins on transportation service as it does on large-volume, interruptible gas costs during 2000 and 2001, PSE filed two PGA and deferral amortization filings with the Washington Commission which were approved. The PGA filings allowed PSE to recover increased gas costs. As a result, gas rates to all sales customers increased by an average of 30.2% on August 1, 2000, and 26.4% on January 12, 2001. Subsequent declines in gas costs led to PSE obtaining approval of another PGA and deferral amortization filing in 2001 resulting in an average 8.9% reduction in gas rates on September 1, 2001.sales.


ELECTRIC OPERATING STATISTICS

TWELVE MONTHS ENDED DECEMBER 31200220012000




  Generation and Purchased Power-kWh (thousands):        
    Company controlled resources   6,996,276  9,684,087  9,502,386 
    Contracted resources   12,085,729  11,901,762  14,735,707 
    Non-firm energy purchased   7,584,398  6,987,319  14,290,196 




         Total generation and purchased power   26,666,403  28,573,168  38,528,289 
       Less losses and company use   (1,341,126) (1,152,840) (1,582,446)




  Total energy sold, kWh   25,325,277  27,420,328  36,945,843 




  Electric energy sales, kWh (thousands):  
    Residential   9,845,527  9,555,264  9,810,393 
    Commercial   8,012,538  7,953,165  7,677,032 
    Industrial   1,416,107  2,540,722  4,026,344 
    Other customers   90,840  154,749  219,435 




       Total energy billed to customers   19,365,012  20,203,900  21,733,204 
    Unbilled energy sales - net increase (decrease)   (102,811) (278,392) 118,908 




       Total energy sales to customers   19,262,201  19,925,508  21,852,112 
    Sales to other utilities and marketers   6,063,076  7,494,820  15,093,731 




       Total energy sales, kWh   25,325,277  27,420,328  36,945,843 




    Less: optimization purchases for sales to other   (2,596,505) (2,512,478) (745,113)
     utilities and marketers  
    Transportation, including unbilled   2,307,081  363,826  -- 




       Net electric energy sales and transported, kWh   25,035,853  25,271,676  36,200,730 




  Electric operating revenues by classes (thousands):  
    Residential  $616,522 $583,714 $587,780 
    Commercial   536,021  509,134  476,052 
    Industrial   90,121  281,161  292,975 
    Other customers   26,500  25,351  98,888 




    Operating revenues billed to customers1   1,269,164  1,399,360  1,455,695 
    Unbilled revenues - net increase (decrease)   (7,118) (70,615) 66,700 




      Total operating revenues from customers   1,262,046  1,328,745  1,522,395 
    Transportation, including unbilled   15,551  2,537  6 
    Sales to other utilities and marketers   152,736  1,021,376  1,249,294 
    Less: optimization purchases for sales to other   (64,448) (487,431) (139,376)
     utilities and marketers  




      Total electric operating revenues  $1,365,885 $1,865,227 $2,632,319 




  Number of customers served (average):  
    Residential   839,878  826,187  811,443 
    Commercial   104,273  100,015  98,758 
    Industrial   3,953  4,012  4,111 
    Other   1,932  1,758  1,548 
    Transportation   16  5  -- 




      Total customers (average)   950,052  931,977  915,860 




  Average retail revenues per kWh sold:  
   Residential  $0.0632 $0.0628 $0.0617 
   Commercial   0.0675  0.0655  0.0638 
   Industrial   0.0649  0.1120  0.0739 
     Average retail revenue per kWh sold   0.0651  0.0701  0.0647 




  Average revenue billed to residential customers  $741 $726 $745 
  Average kWh used by residential customers   11,723  11,565  12,090 




  Heating degree days   4,946  4,993  4,970 
  Percent of normal of 30-year average   100.8% 101.7% 100.9%




  Load factor   61.6% 59.8% 62.2%





TWELVE MONTHS ENDED DECEMBER 312003 2002 2001 

  Generation and purchased power-kWh (thousands):        
    Company-controlled resources   6,965,840  6,996,276  9,684,087 
    Contracted resources   11,021,471  12,085,729  11,901,762 
    Non-firm energy purchased   8,121,009  7,584,398  6,987,319 

      Total generation and purchased power   26,108,320  26,666,403  28,573,168 
      Less losses and company use   (1,338,401) (1,341,126) (1,152,840)

  Total energy sold, kWh   24,769,919  25,325,277  27,420,328 

  Electric energy sales, kWh (thousands):  
    Residential   9,845,854  9,845,527  9,555,264 
    Commercial   8,222,166  8,012,538  7,953,165 
    Industrial   1,372,815  1,416,107  2,540,722 
    Other customers   93,438  90,840  154,749 

       Total energy billed to customers   19,534,273  19,365,012  20,203,900 
    Unbilled energy sales - net increase (decrease)   65,082  (102,811) (278,392)

       Total energy sales to customers   19,599,355  19,262,201  19,925,508 
    Sales to other utilities and marketers   5,170,564  6,063,076  7,494,820 

       Total energy sales, kWh   24,769,919  25,325,277  27,420,328 

    Less: optimization purchases for sales to other  
     utilities and marketers   (62,200) (2,596,505) (2,512,478)
    Transportation, including unbilled   2,020,562  2,307,081  363,826 

       Net electric energy sales and transported, kWh   26,728,281  25,035,853  25,271,676 

  Electric operating revenues by classes (thousands):  
    Residential  $603,722 $616,522 $583,714 
    Commercial   556,038  536,021  509,134 
    Industrial   88,201  90,121  281,161 
    Other customers   54,259  26,500  25,351 

    Operating revenues billed to customers1   1,302,220  1,269,164  1,399,360 
    Unbilled revenues - net increase (decrease)   4,193  (7,118) (70,615)

      Total operating revenues from customers   1,306,413  1,262,046  1,328,745 
    Transportation, including unbilled   11,542  15,551  2,537 
    Sales to other utilities and marketers   193,714  152,736  1,021,376 
    Less: optimization purchases for sales to other  
     utilities and marketers   (2,206) (64,448) (487,431)

      Total electric operating revenues  $1,509,463 $1,365,885 $1,865,227 

  Number of customers served (average):  
    Residential   854,088  839,878  826,187 
    Commercial   108,479  104,273  100,015 
    Industrial   3,952  3,953  4,012 
    Other   2,060  1,932  1,758 
    Transportation   16  16  5 

      Total customers (average)   968,595  950,052  931,977 

  Average retail revenues per kWh sold:  
   Residential  $0.0617 $0.0632 $0.0628 
   Commercial   0.0680  0.0675  0.0655 
   Industrial   0.0650  0.0649  0.1120 
     Average retail revenue per kWh sold   0.0646  0.0651  0.0701 

  Average revenue billed to residential customers  $711 $741 $726 
  Average kWh used by residential customers   11,528  11,723  11,565 

  Heating degree days   4,527  4,946  4,993 
  Percent of normal - NOAA 30-year average   94.4%  103.1%  104.1% 

Load factor   73.5%  61.6%  59.8% 

1

1Operating revenues in 2003, 2002 and 2001 and 2000 were reduced by $7.7 million, $12.7 million and $31.0 million and $35.4 million, respectively, as a result of PSE's sale of $237.7 million of its investment in customer-owned conservation measures. Beginning July 2003, these related revenues are now consolidated as a result of Financial Accounting Standards Board Interpretation No. 46. (See "Operating Revenues - Electric" in Management's Discussion and Analysis and Note 1 to the Consolidated Financial Statements.)



ELECTRIC SUPPLY
        At December 31, 2002,2003, PSE’s peak electric power resources were approximately 4,577,1354,537,495 KW. PSE’s historical peak load of approximately 4,847,000 KW occurred on December 21, 1998. In order to meet an extreme winter peak load, PSE supplements its electric power resources with call options and other instruments that may include, but are not limited to, weather relatedweather-related hedges and exchange agreements. During 2002,2003, PSE’s total electric energy production was supplied 26.2%26.7% by its own resources, 22.5%19.9% through long-term contracts with several of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River and 22.9%22.3% from other firm purchases. Non-firmShort-term wholesale purchases, net of resales,sales to other utilities and marketers, accounted for 7.4%14.1% of energy purchases in 2002.2003.
        The following table shows PSE’s electric energy supply resources at December 31, 20022003 and 2001,2002, and energy production during the year:

PEAK POWER RESOURCES
AT DECEMBER 31,


ENERGY PRODUCTION
(IN THOUSANDS)

2003200220032002
2002200120022001
 KW % KW % kWh % kWh %  KW % KW % kWh % kWh % 



Purchased resources:  
Columbia River PUD contracts 1,391,000 30.4%1,431,900 28.8%5,988,118 22.5%4,230,574 14.8% 1,349,460 29.8%1,391,000 30.4%5,191,346 19.9%5,988,118 22.5%
Other hydro1 175,660 3.8%535,660 10.8%717,215 2.7%964,628 3.4% 177,160 3.9%175,660 3.8%622,900 2.4%717,215 2.7%
Other producers1 1,209,675 26.4%1,211,675 24.4%5,380,396 20.2%6,706,560 23.4% 1,209,675 26.7%1,209,675 26.4%5,207,225 19.9%5,380,396 20.2%
Non-firm energy purchases2 N/A  N/AN/A  N/A7,584,398 28.4%6,987,319 24.5%
Short-term wholesale energy
purchases2
 N/A  N/AN/A  N/A8,121,009 31.1%7,584,398 28.4%



Total purchased 2,776,335 60.6%3,179,235 64.0%19,670,127 73.8%18,889,081 66.1% 2,736,295 60.4%2,776,335 60.6%19,142,480 73.3%19,670,127 73.8%



Company-controlled resources:  
Hydro 300,000 6.6%300,000 6.0%1,351,540 5.1%1,101,373 3.9% 310,400 6.8%300,000 6.6%1,238,900 4.7%1,351,540 5.1%
Coal 700,000 15.3%700,000 14.1%4,627,901 17.3%5,038,834 17.6% 700,000 15.4%700,000 15.3%4,950,734 19.0%4,627,901 17.3%
Natural gas/oil 800,800 17.5%790,800 15.9%1,016,835 3.8%3,543,880 12.4% 790,800 17.4%800,800 17.5%776,206 3.0%1,016,835 3.8%



Total Company controlled 1,800,800 39.4%1,790,800 36.0%6,996,276 26.2%9,684,087 33.9%
Total Company-controlled 1,801,200 39.6%1,800,800 39.4%6,965,840 26.7%6,996,276 26.2%



Total 4,577,135 100.0%4,970,035 100.0%26,666,403 100.0%28,573,168 100.0% 4,537,495 100.0%4,577,135 100.0%26,108,320 100.0%26,666,403 100.0%



        PSE submitted a preliminary least-cost plan to balance future energy resourcesfiled its electric Least Cost Plan on April 30, 2003 with energy needs to the Washington Commission onCommission. The plan supported a strategy of diverse electric power resource acquisitions including resources fueled by natural gas and coal, renewable resources (e.g., wind) and shared resources. A Least Cost Plan Update was filed in August 2003, which integrated conservation programs into the resource mix. The Least Cost Plan was followed with the proposed acquisition of a gas combined-cycle combustion turbine, and the issuing of a wind resource RFP in December 31, 2002. PSE plans to meet its resource needs either through asset acquisition, building its own generation, or entering into additional power purchase agreements, and pursuing energy conservation. PSE will submit its final least-cost plan to the Washington Commission2003. An all-source RFP was issued in the spring of 2003.February 2004.


        COMPANY-CONTROLLED ELECTRIC GENERATION RESOURCES
        In totalAt December 31, 2003, PSE has the following plants with an aggregate net generating capabilitycapacity of 1,800,8001,801,200 KW:


Plant Name
 
Plant Type
 Total KW
Capacity
 
Year Installed
Plant TypeTotal KW
Capacity
 Year Installed
Colstrip 1&2 (50% interest) Coal 330,000 1975 & 1976
Colstrip 3&4 (25% interest) Coal 370,000 1984 & 1986
Colstrip 1 & 2 (50% interest)Coal330,000  1975 & 1976
Colstrip 3 & 4 (25% interest)Coal370,000  1984 & 1986
Upper Baker River Hydro 91,000 1959Hydro91,000  1959
Lower Baker River Hydro 79,000 Reconstructed 1960
Upgraded 2001
Hydro79,000  Reconstructed 1960
White River Hydro 70,000 1911
   Upgraded 2001
White River3Hydro70,000  1911
Snoqualmie Falls Hydro 44,000 1898 to 1911 and 1957Hydro44,400  1898 to 1911 and 1957
Electron Hydro 26,000 1904 to 1929Hydro26,000  1904 to 1929
Fredonia 1 & 2 Dual fuel combustion turbines 210,000 1984
Fredonia Units 1 & 2Dual-fuel combustion turbines210,000  1984
Fredrickson Units 2 & 3 Dual fuel combustion turbines 150,000 1981Dual-fuel combustion turbines150,000  1981
Whitehorn Units 2 & 3 Dual fuel combustion turbines 150,000 1981Dual-fuel combustion turbines150,000  1981
Fredonia 3 & 4 Dual fuel combustion turbines 108,000 2001
Fredonia Units 3 & 4Dual-fuel combustion turbines108,000  2001
Encogen Natural gas cogeneration 170,000 1993Natural gas cogeneration170,000  1993
Crystal Mountain Internal combustion 2,800 1969Internal combustion2,800  1969

1Power received from other utilities is classified between hydro and other producers based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource.
2Non-firm Short-term wholesale purchases net of resales of 5,170,564 MWh and 6,063,076 kWhMWh for 2003 and 7,494,820 kWh for 2002, and 2001 respectively, account for 7.4%14.1% and (2.4%)7.4% of energy purchases.
3 Effective January 15, 2004, the White River generating plant ceased operations as a result of PSE rejecting the FERC license.

All        PSE and PPL Montana, the other owner of these generating facilities, exceptColstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana plants,will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are located inpart of PSE’s service territories.


PCA mechanism.
        On December 19,October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE was issued a 50-year license by FERCused the coal as fuel for its existingshare of the Colstrip Units 3 & 4 generating plant. PSE’s coal price for that period was reduced by a settlement PSE and operatingWestern Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.

FERC HYDROELECTRIC LICENSES
        As part of its hydroelectric operations, PSE is required to obtain licenses from FERC. A typical license contains mandatory conditions of operation, such as flow rate requirements, adherence to certain ramping protocols for outages, maintenance of reservoir levels, equipment upgrade projects, and fish and wildlife mitigation projects. The licensing and relicensing processes involve harmonizing conflicting rights and obligations of numerous governmental, non-governmental and private parties, and dealing with issues that may include environmental compliance, fish protection and mitigation, water quality, Native American rights, private landowner rights, title claims, operational and capital improvements, and flood control. As a result, a number of political, compliance and financial risks can arise from the licensing and relicensing processes.
        PSE owns four hydroelectric projects: the Baker River Project, the Snoqualmie Falls Project, the Electron Project and the White River project which includes authorizationProject. The Baker River and Snoqualmie Falls Projects are operating under the jurisdiction of FERC. FERC regulates dam safety and administers proceedings under the FPA to install an additional 14,000 KW generating unit. PSE has filedlicense jurisdictional hydropower projects. FERC licenses are generally issued for a rehearing withterm of 30-50 years. The Baker River and Snoqualmie Falls Projects are currently in FERC onrelicensing proceedings. Relicensing proceedings involve multiple parties and interests, and frequently take several years to complete. Relicensing proceedings also invoke the jurisdiction of other federal and state agencies, and these agencies determine various matters that affect the terms and conditions of the license relatedFERC license. The Electron Project is not subject to measures designed to enhance salmon runs on theFERC jurisdiction. The White River because those conditions may makeProject was shut down on January 15, 2004 as a result of PSE’s rejection of the plant uneconomicFERC license that made the project uneconomical to operate. On June 30, 1999 FERC issued
Baker River Project. The Baker River Project consists of the Lower Baker Development (constructed in 1925) and the Upper Baker Development (constructed in 1959) and is located upstream of the confluence of the Baker and Skagit Rivers in Whatcom and Skagit Counties. The project has a stay in the license proceeding. This additional time allows PSE, federal land agencies, state agencies, local governments and public interest groups to resolve common issues and explore alternatives relating to the plant’s continued operation and economics.current authorized capacity of 170.0 MW. The licensing proceeding is ongoing. In April 2001, PSE gave FERC notice of its intent to renew the licenseproject was licensed for its existing and operating 170,000 KW Baker Project.50 years, effective May 1, 1956. The 50-yearproject’s current license expires on April 30, 2006, withand PSE will issue its Notice of Intent to file a new license application due in April 2004. In 2002,Consultation has been


initiated with the National Marine Fisheries Service and United States Fish and Wildlife Service under Section 7 of the Endangered Species Act, and consultation is ongoing with PSE continued working with FERC, federal, state and local governments, Native American tribes, public interest groups and citizens to defineacting as the non-federal representative during said consultation. PSE anticipates submitting a new license application to relicense the project on or before April 30, 2004.
Snoqualmie Falls Project. The Snoqualmie Falls Project, built in 1898, was the world’s first electric generating facility to be built totally underground. It is located 3.5 miles downstream of the confluence of the North, Middle and South Forks of the Snoqualmie River. The project has a current authorized capacity of 44.4 MW. The original license of the project was issued May 13, 1975, effective March 1, 1956, and terminated on December 31, 1993. PSE filed its application to relicense the project on November 25, 1991, and has been operating the project pursuant to annual licenses issued by FERC since the original license expired.
        All necessary federal and state review processes prerequisite to FERC’s issuance of a new license were completed as of October 2003. The Snoqualmie Tribe filed an appeal of the State of Washington, Department of Ecology’s water quality certification in November 2003, which appeal is presently pending before the Washington State Pollution Control Hearings Board. The matter is set for hearing on March 22, 2004. The outcome of this matter is not expected to have a material impact upon the financial condition, results of operations or liquidity of the Company.
Electron Project.The Electron Project was built in 1904 in the upper reaches of the Puyallup River. The project’s capacity is currently 26.0 MW. In 1977, the project was determined to be a “pre-1935” project under the FPA and therefore not subject to FERC jurisdiction. In this status, the project can continue to operate without a FERC license absent “post-1935” construction of a nature sufficient to invoke FERC’s jurisdiction. PSE does not anticipate undertaking any betterments or improvements to the project that would entail “post-1935” construction.
        The project also operates in compliance with the terms and conditions throughof a collaborative process.“Resource Enhancement Agreement” with the Puyallup Indian Tribe. This agreement resolved the Tribe’s long-standing claims for resource and other damages allegedly associated with the construction and operation of the project. The initialagreement also provides that in 2018 PSE must decide to either retire the project by 2026 or, in lieu of retirement, undertake significant upgrades that would likely invoke FERC jurisdiction. The outcome of these deliberations is not expected to have a material impact upon the financial condition, results of operations or liquidity of the Company.
White River Project. The White River Project was built in 1911 and was operated as a hydropower facility until January 15, 2004. The project’s capacity was 70.0 MW. For many years, the project was believed to fall outside of the jurisdiction of the FPA. In the 1970s, FERC’s jurisdiction over the project was established. PSE submitted a license application to FERC in 1983. In December 1997, FERC issued a proposed license for the existingproject. PSE appealed the 1997 license because it contained terms and conditions that would render ongoing operations of the project uneconomic relative to alternative resources. In November 2003, PSE determined that it could no longer continue to economically operate the project due to additional conditions related to two listings under the Endangered Species Act. On December 23, 2003, PSE notified FERC of its intent to reject the 1997 license, cease generation of electricity and terminate the FERC licensing proceeding. PSE is actively seeking to sell the project to one or more entities interested in maintaining the reservoir for commercial purposes.
        On December 29, 2003, PSE entered into a one-year contract with the United States Army Corps of Engineers (COE) to maintain operation of the White River diversion dam to support the COE’s ongoing operation of its Mud Mountain Dam fish passage facilities. The agreement provides for reimbursement of a portion of PSE’s operating Snoqualmie Falls project expired in December 1993,costs and directs PSE continues to operate the diversion dam in accordance with measures determined by federal agencies to be necessary to protect listed species and habitat. Homeowners and others interested in preserving the project reservoir (Lake Tapps) have expressed concern over the possible loss of the reservoir and there has been a solicitation of interest in a potential lawsuit against PSE to preserve the reservoir, but no such lawsuit has been filed. In January 2001, certain environmental groups gave notice of their intent to sue for alleged violations of the Endangered Species Act, but no such lawsuit has been filed.
        On December 10, 2003, PSE filed a petition with the Washington Commission for an Accounting Order which will allow for rate recovery of the unrecovered investment in the project. The resolution of this projectmatter will be decided in the power cost only rate case, which is expected by mid-April 2004. The Washington Commission staff’s testimony in PSE’s pending power cost only rate case proceeding supports PSE’s petition. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset. To meet the demands of PSE’s retail customers, electric generation after January 15, 2004 will be purchased from the wholesale energy market.

NEW GENERATION RESOURCES
        In October 2003, PSE completed negotiations to purchase a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired electric generating facility located within Western Washington. The purchase will add approximately 137 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a power cost only rate case in October 2003 to the Washington Commission to recover the approximately $80 million cost of the new generating facility and other power costs. The power cost only rate case is expected to last approximately five months, with an order anticipated to be issued in mid-April 2004. Accordingly, the acquisition of the plant, subject to favorable approval by the Washington Commission, could be completed by April 2004. In addition, the acquisition will require approval from FERC under a temporary license.the FPA. PSE filed its application in January 2004 with FERC and anticipates approval in early 2004.
        In addition, PSE has issued an RFP to acquire approximately 50 average MW of energy from wind power for its electric-resource portfolio and is continuing the FERC application processcurrently evaluating responses to relicense this project.request. PSE issued an RFP in February 2004 for an additional 305 MW of electric power resource generation with proposals due back in March 2004.

        COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTS
        During 2002,2003, approximately 22.5%19.9% of PSE’s energy output was obtained at an average cost of approximately 13.96 mills$0.0164 per kWh through long-term contracts with several of the Washington PUDs that own and operate hydroelectric projects on the Columbia River.
        PSE’s purchases of power from the Columbia River projects are on a “cost of service” basis under which PSE pays a proportionate share of the annual debt service and operating and maintenance costs of each project in proportion to the contractual shares that PSE has rights to from such project. Such payments are not contingent upon the projects being operable, which means PSE is required to make the payments


even if power is not being delivered. These projects are financed through substantially level debt service payments, and their annual costs may vary over the term of the contracts as additional financing is required to meet the costs of major maintenance, repairs or replacements or license requirements.requirements, or changes to annual operating and maintenance expenses are required.
        PSE has contracted to purchase from Chelan County PUD (Chelan) a 50% share of the output of the original units of the Rock Island Project, which percentage will remain unchanged for the duration of the contract that expires in 2012. PSE has also contracted to purchase the output of the additional Rock Island units for the duration of the contract. As of December 31, 20022003, PSE’s aggregate annual capacity from all units of the Rock Island Project was 455,340413,900 KW. PSE’s share of output of the additional Rock Island units may be reduced by up to 10% per year whichyear. Chelan began July 1, 2000, subject to a maximum aggregate reductionwithdrawing 5% of 50%, upon the exercise of rights of withdrawal by Chelanpower from the additional Rock Island units for use in meeting its local service area.load on July 1, 2000. The maximum withdrawal that Chelan may make from the additional units is 50%. The schedule of withdrawals by Chelan for the additional Rock Island units is as follows:

Date of WithdrawalWithdrawal PercentagePSE Capacity after WithdrawalWithdrawal PercentagePSE Capacity after Withdrawal
July 1, 200210%85%
July 1, 200310%75%10%75%
February 1, 200510%65%10%65%
July 1, 200510%55%10%55%
November 1, 20065%50%5%50%

        PSE has contracted to purchase from Chelan 38.9% (505,000 KW of peak capacity as of December 31, 2002)2003) of the annual output of the Rocky Reach Project, which percentage remains unchanged for the remainder of the contract which expires in 2011.
        PSE has contracted to purchase from Douglas County PUD 31.3% (261,000 KW as of December 31, 2002)2003) of the annual output of the Wells Project, the percentage of which remains unchanged for the remainder of the contract which expires in 2018.
        Early in 2003, the Colville Confederated Tribes (Colville Tribe) presented a claim to Douglas County PUD based upon allegedly unpaid past annual charges for the Wells Hydroelectric Project for the use of Colville tribal lands. The Colville Tribe also claimed that annual charges would also be due for periods into the future. Since April 2003, Douglas County PUD and Colville Tribe representatives have discussed settlement of this issue. The settlement discussions may lead to a resolution of the claim. A settlement of this claim could affect the quantity or the price of the output of the Wells Project purchased by PSE. PSE has contracted to purchase from Grant County PUD 8.0% (72,000 KW as of December 31, 2002)2003) of the annual output of the Priest Rapids Development and 10.8% (98,000 KW of peak capacity as of December 31, 2002)2003) of the annual output of the Wanapum Development, which percentages remain unchanged for the remainder of the contractsoriginal contract terms which expire in 2005 and 2009, respectively.


On December 28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. Grant County PUD filed an “Application for New License for the Priest Rapids Project” on October 29, 2003. The new contractscontracts' terms begin in November 2005 for the Priest Rapids Development and in November 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts PSE’s share of power from the developments declines over time as Grant County PUD’s load increases.
        On March 8, 2002, the Yakama Nation filed a complaint with FERC, which alleged that Grant County’sCounty PUD’s new contracts unreasonably restrain trade and violate various sections of the Federal Power ActFPA and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, they haveFERC has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing haswas requested but was denied by FERC on April 16, 2003. Both the Yakama Nation and Grant County PUD have appealed the FERC decision and the appeals have been requested.consolidated in the Ninth Circuit Court of Appeals.

ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH OTHER UTILITIES
        PSE has entered into long-term firm purchased power contracts with other utilities in the West region. PSE is generally not obligated to make payments under these contracts unless power is delivered.
        Under a 1985 settlement agreement relating to Washington Public Power Supply System Nuclear Project No. 3, in which PSE had a 5% interest, PSE is entitled to receive electric power from BPA, beginning January 1, 1987, electric power during the months of November through April. Under the contract, PSE is guaranteed to receive not less than 191,667 MWh in each contract year until PSE has received total deliveries of 5,833,333 MWh. PSE expects the contract to be in effect until at least June 2008. Also pursuant to the 1985 settlement agreement, BPA has an option to request that PSE deliver up to 6456 MW of exchange energy to BPA in all months except May, July and August for contract year 2002/2003.2003 — 2004.
        On DecemberOctober 31, 2002,2003, a 15 year15-year contract for the purchase of firm power contractand energy between Avista CorporationPacifiCorp and PSE expired under the terms of the agreement. The contract provided for the delivery of 100 MW of capacity and 657,000 MWh of energy from the Avista system annually (75 annual average MW).
        On October 27, 1988, PSE executed a 15-year contract for the purchase of firm power and energy from PacifiCorp. Under the terms of the agreement, PSE receives 120 average MW of energy and 200 MW of peak capacity. This contract expires on October 31, 2003.capacity annually.
        On October 1, 1989, PSE signed a contract with The Montana Power Company, which subsequently sold its utility assets to Northwestern EnergyNorthWestern Corporation (NorthWestern) in 2002 under which Northwestern Energy2002. Under the contract, NorthWestern provides PSE from its share of Colstrip Unit 4, 71 average MW of energy (97 MW of peak capacity) over a 21-year period. This contract expires in December 2010. On September 14, 2003, NorthWestern filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. PSE has several long-term contracts with NorthWestern under which PSE jointly owns facilities or purchases power or transmission services from NorthWestern. PSE and NorthWestern entered into a settlement of one outstanding dispute concerning transmission losses associated with power deliveries to PSE under the 21-year power purchase agreement PSE has with NorthWestern. That settlement was approved by the bankruptcy court on December 11, 2003. PSE does not expect the filing of NorthWestern’s petition to have a material impact upon the financial condition, results of operations or liquidity of the Company.
        PSE executed an exchange agreement with Pacific Gas & Electric Company (PG&E) which became effective on January 1, 1992. Under the agreement, 300 MW of capacity together with up to 413,000 MWh of energy are exchanged seasonally every year on a unit-for-unit basis.each year. No payments are made under this agreement. PG&E is a summer peaking utility and will provideprovides power during the months of November through February. PSE is a


winter peaking utility and will provideprovides power during the months of June through September. Each party may terminate the contract for various reasons.
upon notifying the other party at least five years in advance. On December 20, 2001, PSE notified PG&E of its intent to terminate the agreement as of the end of 2006. In October 1997 a 10-year power exchange agreement betweenMay 2002, PG&E responded and stated its view that PSE’s notice was void due to PG&E’s bankruptcy. PSE and Powerex (a subsidiary of a British Columbia utility) became effective. Under this agreement Powerex pays PSE forhas not responded to the right to deliver power up to 1,200,000 MWh annually to PSE at the Canadian border in exchange for PSE delivering power to Powerex at various locations in the United States.PG&E letter.

ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITY GENERATORS
        As required by the federal Public Utility Regulatory Policies Act, (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The most significant of these are the contracts described below which PSE entered into in 1989, 1990 and 1991 with operators of natural gas-fired cogeneration projects. PSE purchases the net electrical output of these three projects at fixed and annually escalating prices, which were intended to approximate PSE’s avoided cost of new generation projected at the time these agreements were made.
        On February 24, 1989, PSE executed a 20-year contract to purchase 108 average MW of energy and 123 MW of capacity, beginning in April 1993, from Sumas Cogeneration Company, L.P., which owns and operates a natural gas-fired cogeneration project located in Sumas, Washington.



        On June 29, 1989, PSE executed a 20-year contract to purchase 70 average MW of energy and 80 MW of capacity, beginning October 11, 1991, from the March Point Cogeneration Company (March Point), which owns and operates a natural gas-fired cogeneration facility known as March Point Phase I located at the Equilon refinery in Anacortes, Washington. On December 27, 1990, PSE executed a second contract (having a term coextensive with the first contract) to purchase an additional 53 average MW of energy and 60 MW of capacity, beginning in January 1993, from another natural gas-fired cogeneration facility owned and operated by March Point, which facility is known as March Point Phase II and is located at the Equilon refinery in Anacortes, Washington.
        On March 20, 1991, PSE executed a 20-year contract to purchase 216 average MW of energy and 245 MW of capacity, beginning in April 1994, from Tenaska Washington Partners, L.P., which owns and operates a natural gas-fired cogeneration project located near Ferndale, Washington. In December 1997 and January 1998, PSE and Tenaska Washington Partners entered into revised agreements in which PSE became the principal natural gas supplier to the project and power purchase prices under the Tenaska contract were revised to reflect market-based prices for the natural gas supply. PSE obtained an order from the Washington Commission creating a regulatory asset related to the $215 million restructuring payment. Under terms of the order, PSE was allowed to accrue as an additional regulatory asset one-half the carrying costs of the deferred balance over the first five years, which ended December 2002. The balance of the regulatory asset at December 31, 20022003 was $231.0$216.7 million, which will be recovered in electric rates overthrough 2011. In the next nine years. In addition, PSEpower cost only rate case, the Washington Commission staff has identified a portion of this asset as a possible disallowance for the future rate recovery. The power cost only rate case order from the Washington Commission is responsible for any potential tax indemnification to the seller imposed by the Internal Revenue Service up to a maximum of $30 million.expected in mid-April 2004.
        In December 1999, PSE bought out the remaining 8.5 years of one of the natural gas supply contracts serving Encogen from Cabot Oil & Gas Corporation (Cabot) which provided approximately 60% of the plant’s natural gas requirements. PSE became the replacement gas supplier to the project for 60% of the supply under the terms of the Cabot Agreement.agreement. The balance of the regulatory asset at December 31, 2003 is $11.0 million, which will be recovered in electric rates through 2008. In the power cost only rate case, the Washington Commission staff has identified a portion of this asset as a possible disallowance for future rate recovery. The power cost only rate case order from the Washington Commission is expected in mid-April 2004.

ELECTRIC TRANSMISSION CONTRACTS WITH OTHER UTILITIES
        PSE has entered into numerous transmission contracts with BPA to integrate electric generation resources and energy contracts into the PSE system. These transmission contracts specify that PSE will pay based on the contracted level of transmission service, regardless of actual use.
        The general transmission agreement with BPA provides for the integration of PSE’s share of the Colstrip Project and the PG&E exchange. The hourly demand limit is 1,161 MW. This contract is effective through July 31, 2014.
        PSE has an additional six transmission agreements with BPA to integrate PSE’s share of the Mid-Columbia hydro projects. The hourly demand limit of all six contracts totals 1,136 MW. The contracts have remaining terms from 2 to 15 years.
        PSE’s transmission expenses for integrating its firm resources was $35.1 million in 2003. The transmission rates used by BPA for these contracts are effective through September 30, 2005. BPA rates change from time to time based upon BPA’s rate cases.
        In October 1997, a 10-year power exchange agreement between PSE and Powerex (a subsidiary of a British Columbia utility) became effective. Under this agreement, Powerex pays PSE for the right to deliver up to 1,200,000 MWh annually to PSE at the Canadian border in exchange for PSE delivering power to Powerex at various locations in the United States. The agreement also allows Powerex to make up any exchange volumes not used up to two years after the end of the annual period.


GAS OPERATING STATISTICS


TWELVE MONTHS ENDED DECEMBER 31  2002  2001  2000 TWELVE MONTHS ENDED DECEMBER 31200320022001



Gas operating revenues by classes (thousands):         
Residential $428,569 $486,761 $372,900  $   401,717 $   428,569 $   486,761 
Commercial firm  167,434  196,904  144,046  149,671 167,434 196,904 
Industrial firm  28,312  37,411  27,832  24,164 28,312 37,411 
Interruptible  48,889  71,997  44,485  34,046 48,889 71,997 



Total retail gas sales  673,204  793,073  589,263  609,598 673,204 793,073 
Transportation services  12,851  11,780  12,137  13,796 12,851 11,780 
Other  11,100  10,218  10,911  10,836 11,100 10,218 



Total gas operating revenues $697,155 $815,071 $612,311  $   634,230 $   697,155 $   815,071 



Number of customers served (average):  
Residential  565,003  548,497  532,333  583,439 565,003 548,497 
Commercial firm  45,916  45,998  44,817  46,813 45,916 45,998 
Industrial firm  2,727  2,789  2,863  2,685 2,727 2,789 
Interruptible  650  833  835  611 650 833 
Transportation  122  112  98  134 122 112 



Total customers  614,418  598,229  580,946  633,682 614,418 598,229 



Gas volumes, therms (thousands):  
Residential  500,672  494,648  517,561  500,116 500,672 494,648 
Commercial firm  218,716  214,713  221,170  216,951 218,716 214,713 
Industrial firm  39,142  42,287  48,348  36,890 39,142 42,287 
Interruptible  81,045  98,733  103,446  61,739 81,045 98,733 



Total retail gas volumes, therms  839,575  850,381  890,525  815,696 839,575 850,381 
Transportation volumes  207,852  188,196  204,035  209,497 207,852 188,196 



Total volumes  1,047,427  1,038,577  1,094,560  1,025,193 1,047,427 1,038,577 



Working-gas volumes in storage at year end, therms (thousands): 
Working gas volumes in storage at year end, therms (thousands): 
Jackson Prairie  64,583  59,537  67,827  60,365 64,583 59,537 
Clay Basin  51,225  73,800  28,275  49,314 51,225 73,800 



Average therms used by customer: 
Average therms used per customer: 
Residential  886  902  972  857 886 902 
Commercial firm  4,763  4,668  4,935  4,634 4,763 4,668 
Industrial firm  14,354  15,162  16,887  13,739 14,354 15,162 
Interruptible  124,685  118,527  123,888  101,046 124,685 118,527 
Transportation  1,703,705  1,680,321 ��2,081,989  1,563,410 1,703,705 1,680,321 



Average revenue per customer:  
Residential $759 $887 $701  $          689 $          759 $          887 
Commercial firm  3,647  4,281  3,214  3,197 3,647 4,281 
Industrial firm  10,382  13,414  9,721  9,000 10,382 13,414 
Interruptible  75,214  86,431  53,275  55,722 75,214 86,431 
Transportation  105,336  105,179  123,846  102,955 105,336 105,179 



Average revenue per therm sold:  
Residential $0.855 $0.984 $0.720 $      0.803$      0.855$      0.984 
Commercial firm  0.766  0.917  0.651  0.6900.7660.917
Industrial firm  0.723  0.885  0.576  0.6550.7230.885
Interruptible  0.603  0.729  0.430  0.5510.6030.729
Average retail revenue per therm sold  0.802  0.933  0.662  0.7470.8020.933
Transportation  0.062  0.063  0.059  0.0660.0620.063




GAS SUPPLY
        PSE currently purchases a blended portfolio of gas supplies ranging from long-term firm short-term firm and non-firmto daily gas supplies from a diverse group of major and independent producers and gas marketers in the United States and Canada. PSE also enters into short-term physical and financial derivative instruments to hedge the cost of gas to serviceserve its customers. All of PSE’s gas supply is ultimately transported through the facilities of Williams/Williams Northwest Pipeline Corporation (NPC)(NWP), the sole interstate pipeline delivering directly into the Western Washington area.


 20022001
  Peak Firm Gas Supply at December 31   Dth per Day % Dth per Day %





  Purchased gas supply:  
     British Columbia   145,500  18.2% 181,800  22.5%
     Alberta   64,900  8.1% 65,800  8.1%
     United States   113,800  14.2% 51,400  6.4%





  Total purchased gas supply   324,200  40.5% 299,000  37.0%





  Purchased storage capacity:  
     Clay Basin   63,000  7.9% 96,600  11.9%
     Jackson Prairie   47,600  5.9% 47,500  5.9%
     LNG   70,800  8.8% 70,700  8.7%





  Total purchased storage capacity   181,400  22.6% 214,800  26.5%





  Owned storage capacity:  
     Jackson Prairie   265,000  33.1% 265,000  32.8%
     Propane-air injection   30,000  3.8% 30,000  3.7%





  Total owned storage capacity   295,000  36.9% 295,000  36.5%





  Total peak firm gas supply   800,600  100.0% 808,800  100.0%





        All peak firm gas supplies and storage are connected to PSE's market with firm transportation capacity.

 20032002
  Peak Firm Gas Supply at December 31 Dth per % Dth per % 

  Purchased gas supply: 
     British Columbia 167,200 20.8%145,500 18.2%
     Alberta 76,700 9.6%64,900 8.1%
     United States 98,400 12.3%113,800 14.2%

  Total purchased gas supply 342,300 42.7%324,200 40.5%

  Purchased storage capacity: 
     Clay Basin 54,900 6.8%63,000 7.9%
     Jackson Prairie 54,200 6.8%47,600 5.9%
     LNG 69,400 8.6%70,800 8.8%

  Total purchased storage capacity 178,500 22.2%181,400 22.6%

  Owned storage capacity: 
     Jackson Prairie 251,600 31.4%265,000 33.1%
     Propane-air injection 30,000 3.7%30,000 3.8%

  Total owned storage capacity 281,600 35.1%295,000 36.9%

  Total peak firm gas supply 802,400 100.0%800,600 100.0%

All peak firm gas supplies and storage are connected to PSE’s market with firm transportation capacity.

        For baseload and peak-shaving purposes, PSE supplements its firm gas supply portfolio by purchasing natural gas at generally lower prices in months of low market demand for gas, injecting it into underground storage facilities and withdrawing it during the winter heating season. Storage facilities at Jackson Prairie in Western Washington and at Clay Basin in Utah are used for this purpose. PSE has been in the process of expanding the storage capacity at Jackson Prairie since March 2003, and plans to continue doing so through 2008. At the end of this project, PSE will have added approximately 2,000,000 Dekatherms (one Dekatherm, or Dth, is equal to one million British thermal units or MMBtu) of additional working storage capacity. Peaking needs are also met by using PSE ownedPSE-owned gas held in NPC’sNWP’s liquefied natural gas (LNG) facility at Plymouth, Washington, and by producing propane-air gas at a plant owned by PSE and located on its distribution system.system, and interrupting service to customers on interruptible service rates.
        In 1998, PSE took assignment from a third party of a peaking gas supply service contract whereby PSE can divert up to 48,000 DekathermsDth per day (one Dekatherm, or Dth, is equal to one million British thermal units or MMBtu) of gas it supplies to Tenaska away from the Tenaska Cogeneration Facility and toward its core gas load by causing Tenaska to operate its facility on distillate fuel and paying any additionalthe replacement costs of the distillate fuel for such operation.operations.
        PSE expects to meet its firm peak-day requirements for residential, commercial and industrial markets through its firm gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources. PSE believes it will be able to acquire incremental firm gas supply to meet anticipated growth in the requirements of its firm customers for the foreseeable future.

GAS SUPPLY PORTFOLIO
        For the 2002-20032003-2004 winter heating season, PSE contracted for approximately 18.2%20.8% of its expected peak-day gas supply requirements from sources originating in British Columbia under a combination of long-term, medium-term and winter-peakingseasonal purchase agreements. Long-term gas supplies from Alberta represent approximately 8.1%9.6% of the peak-day requirements. Long-term and winter peaking arrangements with U.S. suppliers and gas stored at Clay Basin make up approximately 22.1%19.1% of the peak-day portfolio. The balance of the peak-day requirements is expected to be met with gas stored at Jackson Prairie, LNG held at NPC’sNWP’s Plymouth facility and propane-air resources, which represent approximately 39.0%38.2%, 8.8%8.6% and 3.8%3.7%, respectively, of expected peak-day requirements. PSE also has the ability to curtail service to wholesale-level customers on interruptible service rates during a peak-day event.
        During 2002,2003, approximately 40%35% of gas supplies purchased by PSE originated in British Columbia while 21%22% originated in Alberta and 39%43% originated in the United States.
The current firm, long-term gas supply portfolio consists of arrangements with 1722 producers and gas marketers, with no single supplier representing more than 11%12% of expected peak-day requirements. Contracts have remaining terms ranging from less than 1one year to 9 years, with an average term of less than one year. With the exception of fixed price hedges for the period November 2002 through October 2003 making up a portion of the minimum planned customer requirements, gas supply contracts contain market-sensitive pricing provisions based on several published indices.eight years.
        PSE’s firm gas supply portfolio is structured to capitalize on regional price differentials when they arise.arise due to the nature of its


transportation arrangements. Gas and services are marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit. The geographic mix of suppliers and daily, monthly and annual take requirements permit a highsome degree of flexibility in managing gas supplies during off-peak periods to minimize costs.


GAS TRANSPORTATION CAPACITY
        PSE currently holds firm transportation capacity on pipelines owned by NPCNWP, Gas Transmission Northwest and PG&EDuke Energy Gas Transmission-Northwest (PGT).Transmission. Accordingly, PSE pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of gas from receipt points to delivery points on such pipelines each day for the term or terms of the applicable agreements.
        PSE holdsand WNG CAP I, a wholly-owned subsidiary of PSE, hold firm year-round capacity on NPC’sNWP through various contracts. PSE and WNG CAP I participate in the secondary pipeline totaling 447,493capacity market to achieve savings for PSE’s customers. As a result, PSE and WNG CAP I hold approximately 465,000 Dth per day acquired under several agreements at various times.of capacity due to capacity release and segmentation transactions on NWP which provides firm delivery to PSE’s service territory. In addition, PSE holds approximately 413,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of stored gas during the heating season. PSE has exchanged certain segments of its firm capacity with third parties to effectively lower transportation costs. PSE’s firm transportation capacity contracts with NPCNWP have remaining terms ranging from 2less than 1 year to 13.813 years. However, PSE has either the unilateral right to extend the contracts under their current terms or the right of first refusal to extend such contracts under current FERC orders. PSE’s firm transportation capacity on PGT’sGas Transmission Northwest’s pipeline, totaling 90,392approximately 90,000 Dth per day, has a remaining term of 2120 years.
        WNG CAP I, a wholly-owned subsidiary of PSE, holds PSE’s firm year-roundtransportation capacity on NPC’sDuke Energy Gas Transmission’s pipeline, totaling 75,494approximately 40,000 Dth per day, acquired under several agreements. WNG CAP I’shas a remaining term of 11 years for approximately 25,000 Dth per day and has a remaining term of 16 years for approximately 15,000 Dth per day.
        During 2003, NWP took one of its two parallel pipelines that serve Western Washington out of service as a result of a second failure of the affected pipeline. Together, these two pipelines had the ability to flow approximately 1,300,000 Dth per day of gas from British Columbia. The loss of the affected pipeline reduced this ability to approximately 950,000 Dth per day. Prior to the second failure, the affected line had been operating at 80% of its maximum allowable operating pressure. If the affected pipeline is not returned to service, the loss could potentially decrease PSE’s overall NWP capacity by 12%. NWP is exploring options to meet firm transportationcontract obligations to PSE, which may include new pipeline construction or purchase of firm capacity contracts with NPCfrom customers of NWP who have remaining terms ranging from 1 yearexcess capacity. PSE does not expect the line to 13.5 years.

remain out of service indefinitely, and this event, to date, has not adversely impacted PSE’s ability to serve its customers. PSE expects to continue meeting its customer needs throughout the pipeline repair or remediation period.

GAS STORAGE CAPACITY
        PSE holds storage capacity in the Jackson Prairie and Clay Basin underground gas storage facilities adjacent to NPC’sNWP’s pipeline. The Jackson Prairie facility, operated and one-third owned by PSE, is used primarily for intermediate peaking purposes since it is able to deliver a large volume of gas over a relatively short time period. Combined with capacity contracted from NPC’sNWP’s one-third stake in Jackson Prairie, PSE has peak firm delivery capacity of over 318,000349,000 Dth per day and total firm storage capacity exceeding 7,500,0007,900,000 Dth at the facility. The location of the Jackson Prairie facility in PSE’s market area ensures supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day gas requirements. The Clay Basin storage facility is a supply area storage facility that is used primarily to reduce portfolio costs through injections and withdrawals that take advantage of market price volatility and is utilizedalso used for withdrawals over the entire winter, capturing savings due to injecting lower cost gas supplies during the summer.system reliability. After the release of capacity, PSE hasretains maximum firm withdrawal capacity of over 64,00055,000 Dth per day from the Clay Basin facility with total storage capacity of almost 6,700,000 Dth. The capacity is held under two contracts with remaining terms of 1110 and 1716 years. PSE hasThe capacity release contracts PSE has with multiple parties at the Clay Basin storage facility withhave remaining terms ranging from 3 to 15of three months. PSE’s maximum firm withdrawal capacity and total storage capacity at Clay Basin is over 110,000 Dth per day and exceeds 13,000,000 Dth, respectively, when PSE has not released any of the capacity.


LNG AND PROPANE-AIR RESOURCES
        LNG and propane-air resources provide gas supply on short notice for short periods of time. Due to their typically high cost, these resources are normally utilized as the supply of last resort in extreme peak-demand periods, typically lasting a few hours or days. PSE has a long-term contractscontract for storage of approximately 240,000241,700 Dth of PSE ownedPSE-owned gas as LNG at NPC’sNWP’s Plymouth facility, which equates to approximately three and one-half days’ supply at a maximum daily deliverability of 72,00070,500 Dth. PSE owns storage capacity for approximately 1.5 million gallons of propane. The propane-air injection facilities are capable of delivering the equivalent of 30,000 Dth of gas per day for up to four days directly into PSE’s distribution system.

CAPACITY RELEASE
        FERC provided a capacity release mechanism as the means for holders of firm pipeline and storage entitlements to temporarily relinquish unutilized capacity to others in order to recoup all or a portion of the cost of such capacity. Capacity may be released through several methods including open bidding and by pre-arrangement. PSE continues to successfully mitigate a portion of the demand charges related to both storage and NPCNWP pipeline capacity not utilized during off-peak periods through capacity release. WNG CAP I a wholly-owned subsidiary of PSE, was formed to provide additional flexibility and benefits from capacity release. Capacity release benefits are passed on to customers through the PGA.


ENERGY CONSERVATION
        PSE offers programs designed to help new and existing customers use energy efficiently. PSE uses a variety of mechanisms including cost effectivecost-effective financial incentives, information and technical services to enable customers to make energy-efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices.
        Since May 1997, PSE has recovered electric energy conservation expenditures through a tariff rider mechanism. The rider mechanism allows PSE to defer the conservation expenditures and amortize them to expense as PSE concurrently collects the conservation expenditures in rates over a one-year period. As a result of the rider, there is no effect on earnings.
        Since 1995, PSE has been authorized by the Washington Commission to defer gas energy conservation expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows PSE to defer conservation expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows PSE to recover an Allowance for Funds Used to Conserve Energy (AFUCE) on any outstanding balance that is not being recovered in rates.

ENVIRONMENT
        Puget Energy’s operations are subject to environmental laws and regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental and energy laws and regulations, Puget Energy cannot determine the impact such laws may have on its existing and future facilities. (See Note 1618 to the Consolidated Financial Statements for further discussion of environmental sites.)

REGULATION OF EMISSIONS
        PSE has an ownership interest in coal-fired, steam-electric generating plants at Colstrip, Montana, which are subject to regulation of emissions and other regulatory requirements. PSE also owns combustion turbine units in Western Washington, which are capable of being fueled by natural gas or diesel fuel. These combustion turbines are operated to comply with emission limits set forth in their respective air operating permits.
        There is no assurance that in the future environmental regulations affecting sulfur dioxide, carbon monoxide, particulate matter or nitrogen oxide emissions may not be further restricted, or that restrictions on greenhouse gas emissions, such as carbon dioxide, or other combustion byproducts, such as mercury, may not be imposed.

FEDERAL ENDANGERED SPECIES ACT
        Since the 1991 listing of the Snake River Sockeye salmon as an endangered species, one more species of salmon has been listed and two more have been proposed which may further influence operations. Upper Columbia River Steelhead was listed by National Marine Fisheries Service in August 1997. Anticipating the Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal and state agencies, Native American tribes and non-governmental organizations to secure operational protection through a long-term settlement and habitat conservation plan which includes fish protection and enhancement measurementmeasures for the next 50 years. The negotiations have concluded among the Chelan and Douglas County PUDs and various fishery agencies, and final agreement is subject to a National Environmental Policy Act review and power purchaser approval. Generally, the agreement obligates the PUDs to achieve certain levels of passage efficiency for downstream migrants at their hydroelectric facilities and to fund certain habitat conservation measures. Grant County PUD has yet to reach agreement on these issues.
        The proposed listings of Puget Sound Chinook salmon and spring Chinook salmon for the upper Columbia River were approved in March 1999. The Company does not expect the listing of spring Chinook salmon for the upper Columbia River should notto result in markedly differing conditions for operations from previous listings in the area.
        The completed listings of Coastal/Puget Sound Distinct Population Segment of Bull Trout in the fall of 1999 and Puget Sound Chinook salmon in the winter of 2001 are causing a number of changes to operations of governmental agencies and private entities in the region, including PSE. These changes may adversely affect hydro plant operations and permit issuance for facilities construction, and increase costs for processprocesses and facilities. Because PSE relies substantially less on hydroelectric energy from the Puget Sound area than from the Mid-Columbia River and because the impact on PSE operations in the Puget Sound area is not likely to impair significant generating resources, the impact of listing for Puget Sound Chinook salmon and Bull Trout, while potentially representing cost exposure and operational constraints, should be


proportionately less than the effects of the Columbia River listings. PSE is actively engaging the federal agencies to address Endangered Species Act issues for PSE’s generating facilities. The consultationConsultation with the federal agencies is ongoing.


EXECUTIVE OFFICERS OF THE REGISTRANTS REGISTRANTS
        The executive officers of Puget Energy as of February 28, 2003January 31, 2004 are listed below. Puget Energy considers the Chief Executive Officer of InfrastruX to be an executive officer of Puget Energy. For their business experience during the past five years, please refer to the table below regarding Puget Sound Energy’s executive officers. Officers of Puget Energy are elected for one-year terms.

NAME
AGE
OFFICES
S.  P.  Reynolds5556President and Chief Executive Officer since January 2002. Director since January 2002.
J.  D. Durbin67Chairman and Chief Executive Officer of InfrastruX since 2002; President and Chief Executive Officer of InfrastruX, 2000 - 2002. Prior to joining InfrastruX, he was Executive Director of Emerge Corporation, 1999 - 2000; Principal in Olympic Capital Partners, 1996 - 1999.
J. W.  Eldredge5253Corporate Secretary and Chief Accounting Officer since April 1999.
D.  E.  Gaines46Vice President Finance and Treasurer since March 2002.
S.M.  T.  Lennon41President and Chief Executive Officer of InfrastruX since April 2003, President of InfrastruX, 2002 - 2003. Prior to joining InfrastruX, he served as Managing Director of Lennon Smith Advisors, LLC, an investment banking firm, 2000 - 2002, and Managing Director of Emerge Corporation, 1999 - - 2000.
J.  L.  O' Connor47Vice President and General Counsel since January 2003.
B.  A.  McKeonValdman5741Senior Vice President Finance and Chief Financial Officer since January 2003; Senior Vice President Finance and Legal and Chief Financial Officer, 2002; Vice President and General Counsel, 1999 - 2002.
J. L. O'Connor46Vice President and General Counsel since January 2003.2004.

        The executive officers of Puget Sound Energy as of February 28, 2003January 31, 2004 are listed below along with their business experience during the past five years. Officers of Puget Sound Energy are elected for one-year terms.

NAME
AGE
OFFICES
S.P.S.  P.  Reynolds5556President and Chief Executive Officer since January 2002; President and Chief Executive Officer of Reynolds Energy International, 1998 - 2002; Chief Executive Officer of PG&E Gas Transmission Texas, 1997 - 1998; President and Chief Executive Officer of Pacific Gas Transmission Company, 1987 - 1998. Director since January 2002.
D.P.D.  P.  Brady3940Vice President Customer Services since February 2003; Director and Assistant to Chief Operating Officer, 2002 - 2003;2003. Prior to joining PSE, he was Managing Director of Irvine Associates Merchant Banking Group, 2001 - 2002; Executive Vice President-Operations of Orcom Solutions, 2000 - 2001; Executive Vice President and Chief Financial Officer of Orcom Solutions, 1999 - 2000.
J.W.P.  K.  Bussey47Vice President Regional and Public Affairs since September 2003. Prior to joining PSE, he was President of the Washington Round Table, 1996 - 2003.
M.  N.  Clements44Vice President Human Resources and Labor Relations since September 2003. Prior to joining PSE, she was Vice President of Human Resources of Eddie Bauer, Inc., 1998 - 2003.
J.  W.  Eldredge5253Vice President, Corporate Secretary, Controller and Chief Accounting Officer since May 2001; Corporate Secretary, Controller and Chief Accounting Officer, 1993 - 2001.
D.E.D.  E.  Gaines46Vice President Finance and Treasurer since March 2002; Vice PresidentandPresident and Treasurer, 2001 - 2002; Treasurer, 1994 - 2001. Mr. Gaines is the brother of W. A. Gaines, Vice President Energy Supply.Engineering and Contracting.
W.A.W.  A.  Gaines4748 Vice President Engineering and Contracting since October 2003; Vice  President Energy Supply, since February 1997.1997 - 2003. Mr. Gaines is the brother of D. E.  Gaines, Vice President Finance and Treasurer.
D.A. Graham62Vice President Human Resources since April 1998; Director Human Resources, 1989 - 1998.
K.J.K.  J.  Harris3839Vice President Governmental and Regulatory Relations since February 2003; Vice President Regulatory Affairs, 2002 - 2003; Director Load Resource Strategies and Associate General Counsel, 2001 - 2002; Associate General Counsel, 1999 - 2001. For more than four years prior to that time, she was an attorney with the law firm of Perkins Coie LLP.
J.L.HenryJ.  L.  Henry5758Senior Vice President Energy Efficiency and Customer Services since February 2003; Director of Major Accounts, 2001 - 2003; Director Construction and Technical Field Services 2000 - 2001;2000-2001; Director Major Projects, 1997 - 2000.
T.J. Hogan51Senior Vice President Regional Services and Community Affairs since February 2003; Senior Vice President External Affairs 2002 - 2003; Vice President External Affairs, 2000 - 2002; Vice President Systems Operations, 1997 - 2000.
E.M.E.  M.  Markell5152Senior Vice President Energy Resources since February 2003; Vice President Corporate Development, 2002 - 2003. Prior to joining PSE, he was Chief Financial Officer, Club One, Inc., 2000 - 2002; Vice President andChiefand Chief Financial Officer, United American Energy Corp., 1990 - 2000.
S.A. McKeon57Senior Vice President Finance and Chief Financial Officer since January 2003; Senior Vice President Finance and Legal and Chief Financial Officer, 2002; Vice President and General Counsel, 1997 - 2002.
S.  McLain4647Senior Vice President Operations since February 2003; Vice President Operations - Delivery, 1999 - 2003; Vice President Corporate Performance, 1997 - 1999.2003.
J.L. O'ConnorJ.  L.  O' Connor4647Vice President and General Counsel since January 2003. Prior to joining PSE, she was interim General Counsel, Starbucks Corporation, 2002; Senior Vice President and Deputy General Counsel, Starbucks Corporation, 2001 - 2002; Vice President and Assistant General Counsel, Starbucks Corporation, 1998 - 2001.
J.M.J.  M.  Ryan4142Vice President Energy Portfolio Management since December 2001. Prior to joining PSE, she was Managing Director of North American Marketing of TransAlta USA, 2001; Managing Director Origination of Merchant Energy Group of the Americas, Inc., 1997 - 2001.

G.B. SwoffordB.  A.  Valdman6141Senior Vice President Finance and Chief OperatingFinancial Officer since March 2002; December 2003. Prior to joining PSE, he was Managing Director with JP Morgan Securities, Inc., 2000 - 2003 and a member of the National Resource Group of JP Morgan Securities, Inc. since 1993 and a banker with JP Morgan since 1987.
P.  M.  Wiegand51Vice President Project Development and Chief Operating Officer - Delivery, 1999 - 2002; Vice President Customer Operations, 1997 - 1999.
P.M. Wiegand50Contract Management since July 2003; Vice President Corporate Planning, since February 2003; Vice President Corporate Planning and Performance, 2002 - 2003; Vice President Risk Management and Strategic Planning 2000 - 2002; Director of Budgets and Performance Management, 1999 - 2000; Director of Information Technology, 1997 - 1999.2000.

ITEM 2. PROPERTIES

        The principal electric generating plants and underground gas storage facilities owned by PSE are described under Item 1, — Business —“Business – Electric Supply and Gas Supply.Supply”. PSE owns its transmission and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s Mortgage Indentures.mortgage indentures.
        InfrastruX operates a fleet of vehicles and machinesequipment that it uses in its utility construction business. Its fleet is comprisedcomposed of owned and leased trucks and other specialized equipment such as backhoes, trenchers, boring machines, cranes and other equipment required to perform its work. InfrastruX owns some of the facilities out of which it operates and rents the remaining facilities.

ITEM 3. LEGAL PROCEEDINGS

        See the section titled “Proceedings Relating to the Western Power Market” under Item 7, “Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operations” and the “Litigation” section of Note 16 of this Annual Report on Form 10-K.
Operations.” Contingencies arising out of the normal course of the Company’s business exist at December 31, 2002.2003. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        None.


PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
              SHAREHOLDER MATTERS

        Puget Energy’s common stock, the only class of common equity of Puget Energy, is traded on the New York Stock Exchange under the symbol PSD. As of“PSD.” At December 31, 20022003, there were approximately 45,20043,200 holders of record of Puget Energy’s common stock. The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not traded.
        The following table shows the market price range of, and dividends paid on, Puget Energy’s common stock during the periods indicated in 20022003 and 2001.2002. Puget Energy and its predecessor companies have paid dividends on common stock each year since 1943 when such stock first became publicly held.


2002

2001

Price RangeDividendsPrice RangeDividends
2003
 
2002
 
Quarter Ended
High
Low
Paid
High
Low
Paid
PRICE RANGEDIVIDENDSPRICE RANGEDIVIDENDS
QUARTER ENDED
QUARTER ENDED
HIGH
LOW
PAID
HIGH
LOW
PAID
March 31 $23.60$19.20$0.46$27.75$20.63$0.46 $23.00$18.10$0.25$23.60$19.20$0.46
June 30 21.2319.270.2526.2422.540.46  24.40 20.78 0.25 21.23 19.27 0.25
September 30 22.5016.630.2526.9520.500.46  24.17 21.02 0.25 22.50 16.63 0.25
December 31 22.6418.750.2523.1118.510.46  23.99 22.14 0.25 22.64 18.75 0.25

        The amount and payment of future dividends will depend on Puget Energy’s financial condition, results of operations, capital requirements and other factors deemed relevant by Puget Energy’s Board of Directors. The Board of Directors’ current policy is anticipated to pay out approximately 60% of normalized utility earnings in dividends.
        Puget Energy’s primary source of funds for the payment of dividends to its shareholders is dividends received from PSE.
PSE’s payment of common stock dividends to Puget Energy is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in PSE’s Articles of Incorporation and electric and gas mortgage indentures. Under the most restrictive covenants of PSE, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $202.7$235.9 million at December 31, 2002.2003.


ITEM 6. SELECTED FINANCIAL DATA

        The following tables show selected financial data. Puget Energy became the holding company for PSE on January 1, 2001 pursuant to a plan of exchange in which each share of PSE common stock was exchanged on a one-for-one basis for Puget Energy common stock.

Puget Energy results are not on a comparable basis as InfrastruX had acquisitions from 2000 to 2003.

PUGET ENERGY
SUMMARY OF OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)

YEARS ENDED DECEMBER 31
20031
2002
20012
2000
1999
Operating revenue $2,491,523$2,392,322$2,886,560$3,302,296$2,067,944
Operating income  305,175 309,669 297,121 363,872 307,816
Net income before cumulative effect 
    of accounting change  121,517 117,883 121,588 193,831 185,567
Income for common stock from 
   continuing operations  116,197 110,052 98,426 184,837 174,502
Basic earnings per common 
    share from continuing operations  1.23 1.24 1.14 2.16 2.06
Diluted earnings per common share 
   from continuing operations  1.22 1.24 1.14 2.16 2.06

Dividends per common share  1.00 1.21 1.84 1.84 1.84
Book value per common share  16.71 16.27 15.66 16.61 16.24

Total assets at year end $5,674,685$5,772,133$5,668,481$5,677,266$5,264,605
Long-term obligations  1,969,489 2,160,276 2,127,054 2,170,797 1,783,139
Preferred stock not subject to 
    mandatory redemption  -- 60,000 60,000 60,000 60,000
Preferred stock subject to 
    mandatory redemption  1,889 43,162 50,662 58,162 65,662
Corporation obligated, mandatorily 
   redeemable preferred securities of 
   subsidiary trust holding solely 
    junior subordinated debentures 
    of the corporation  -- 300,000 300,000 100,000 100,000
Junior subordinated debentures of 
    the corporation payable to a 
    subsidiary trust holding 
    mandatorily redeemable 
    preferred securities  280,250 -- -- -- --


PUGET SOUND ENERGY
SUMMARY OF OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)

YEARS ENDED DECEMBER 31
20031
2002
20012
2000
1999
Operating revenue $2,149,736$2,072,793$2,712,774$3,302,296$2,067,944
Operating income  297,904 294,593 288,480 363,872 307,816
Net income before cumulative effect of 
   accounting change  120,055 108,948 119,130 193,831 185,567
Income for common stock from 
   continuing operations  114,735 101,117 95,968 184,837 174,502

Total assets at year end $5,334,787$5,453,390$5,439,253$5,677,266$5,264,605
Long-term obligations  1,950,347 2,021,832 2,053,815 2,170,797 1,783,139
Preferred stock not subject to 
   mandatory redemption  -- 60,000 60,000 60,000 60,000
Preferred stock subject to mandatory 
   redemption  1,889 43,162 50,662 58,162 65,662
Corporation obligated, mandatorily 
   redeemable preferred securities of 
   subsidiary trust holding solely 
   junior subordinated debentures of 
   the corporation  -- 300,000 300,000 100,000 100,000
Junior subordinated debentures of the 
   corporation payable to a subsidiary 
   trust holding mandatorily 
   redeemable preferred securities  280,250 -- -- -- --


1In 2003, the FASB issued Interpretation No. 46 (FIN 46) which required the consolidation of PSE's 1995 Conservation Trust Transaction. As a result, revenues and expense increased $5.7 million, and assets and liabilities increased $4.2 million in 2003. FIN 46 also required deconsolidation of PSE's trust preferred securities that are now classified as junior subordinated debt. This deconsolidation has no impact on assets, liabilities, receivables or earnings for 2003.
2In 2001, SFAS No. 133 was implemented, which required derivative instruments to be valued at fair value.

Summary of Operations
(Dollars in thousands except per share data)

YEARS ENDED DECEMBER 31   2002  2001  2000  1999  1998 






Operating revenue  $2,392,322 $2,886,560 $3,302,296 $2,067,944 $1,923,856 
Operating income   309,669  297,121  363,872  307,816  295,098 
Income before cumulative effect of   117,883  121,588  193,831  185,567  169,612 
   accounting change  
Income for common stock from continuing   110,052  98,426  184,837  174,502  156,609 
   operations  
Basic and diluted earnings per common share   1.24  1.14  2.16  2.06  1.85 
   from continuing operations  
Dividends per common share   1.21  1.84  1.84  1.84  1.84 
Book value per common share   16.27  15.66  16.61  16.24  16.00 






Total assets at year-end  $5,657,491 $5,546,977 $5,556,669 $5,145,606 $4,709,687 
Long-term obligations   2,149,733  2,127,054  2,170,797  1,783,139  1,475,106 
Preferred stock not subject to mandatory   60,000  60,000  60,000  60,000  95,075 
   redemption  
Preferred stock subject to mandatory   43,162  50,662  58,162  65,662  73,162 
   redemption  
Corporation obligated, mandatorily   300,000  300,000  100,000  100,000  100,000 
   redeemable preferred securities of  
   subsidiary trust holding solely junior  
   subordinated debentures of the  
   corporation  

Puget Sound Energy
Summary of Operations
(Dollars in thousands)

  YEARS ENDED DECEMBER 31   2002  2001  2000  1999  1998 






Operating revenue  $2,072,793 $2,712,774 $3,302,296 $2,067,944 $1,923,856 
Operating income   294,593  288,480  363,872  307,816  295,098 
Income before cumulative effect of   108,948  119,130  193,831  185,567  169,612 
   accounting change  
Income for common stock from continuing   101,117  95,968  184,837  174,502  156,609 
   operations  






Total assets at year-end  $5,338,748 $5,317,750 $5,556,669 $5,145,606 $4,709,687 
Long-term obligations   2,021,832  2,053,815  2,170,797  1,783,139  1,475,106 
Preferred stock not subject to mandatory   60,000  60,000  60,000  60,000  95,075 
   redemption  
Preferred stock subject to mandatory   43,162  50,662  58,162  65,662  73,162 
   redemption  
Corporation obligated, mandatorily   300,000  300,000  100,000  100,000  100,000 
   redeemable preferred securities of  
   subsidiary trust holding solely junior  
   subordinated debentures of the  
   corporation  

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
             AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this annual report on Form 10-K. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy’s and PSE’s objectives, expectations and intentions. Puget Energy’s and PSE’s actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “plans,” “predicts,” “projects,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these 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. Readers are cautioned not to place undue reliance on these forward–looking statements, which speak only as of the date of this report. Except as required by law, neither Puget Energy nor PSE undertakes an obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect Puget Energy’s and PSE’s business, prospects and results of operations.


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.

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 FERC and Washington Commission regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements that may negatively impact earnings;


licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; storms which can damage transmission lines; and energy trading and wholesale market stability over time.
        PSE’s main operational goal has been to provide cost-effective and stable energy prices 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. As such, PSE is in the process of purchasing a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired generation facility within Western Washington, which is currently before the Washington Commission for approval in the power cost only rate case, with an expected order by mid-April 2004. In addition, the purchase will also require approval from FERC. PSE has filed its application with FERC and anticipates approval in early 2004. This purchase is the first step of PSE’s long-term electric Least Cost Plan that was filed April 30, 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.

INFRASTRUX
        InfrastruX generates revenues mainly from maintenance services and construction contracts in the south/Texas, north-central and eastern United States. A majority of its revenues are generated during the second and third quarters which are generally the most productive quarters for the construction industry due to longer daylight hours and generally better weather conditions.
        InfrastruX is subject to risks associated with the construction industry including inability to adequately estimate costs of projects that are bid upon under fixed-fee contracts; continued economic downturn that limits the amount of projects available thereby reducing available profit margins from increased competition; the ability to integrate acquired companies within its operations without significant cost; and the ability to obtain adequate financing and bonding coverage to continue expansion and growth.
        InfrastruX’s main goals have been continued growth and expansion into underdeveloped utility construction markets and to utilize its acquired entities to capitalize on depth of expertise, asset base, geographical location and workforce to provide services that local contractors cannot. InfrastruX has acquired 12 entities since 2000, including one acquisition in 2003.

FINANCIAL CONDITION AND RESULTS OF OPERATIONS
        PUGET ENERGY

        All of the operations of Puget Energy are conducted through its subsidiaries, PSE and InfrastruX. Net income in 20022003 was $121.3 million on operating revenues of $2.5 billion, compared to $117.9 million on operating revenues of $2.4 billion compared toin 2002 and $106.8 million on operating revenues of $2.9 billion in 2001 and $193.8 million on operating revenues of $3.3 billion in 2000.2001. Income for common stock was $116.2 million in 2003, compared to $110.1 million in 2002 compared toand $98.4 million in 2001 and $184.8 million in 2000.2001.
        Basic and diluted earnings per share in 20022003 were $1.23 on 94.8 million weighted average common shares outstanding compared to $1.24 on 88.4 million weighted average common shares outstanding compared toin 2002 and $1.14 on 86.4 million weighted average common shares outstanding in 2001 and $2.162001. Diluted earnings per share were $1.22 on 85.495.3 million weighted average common shares outstanding compared to $1.24 on 88.8 million weighted average common shares outstanding in 2000.2002 and $1.14 on 86.7 million weighted average common shares outstanding in 2001.
        Net income in 2003 was positively impacted by an increase in utility net income of $10.9 million due to increased electric and gas margins primarily from a full year’s effect of the September 1, 2002 general gas rate increase and from increased sales volumes for electric and gas loads compared to 2002. In addition, net income in 2003 was positively impacted by lower interest expenses of $11.4 million. This was offset by a $6.1 million downward adjustment in the carrying value of a non-utility venture capital investment in the fourth quarter of 2003, a $4.8 million increase in depreciation and amortization and an $11.7 million decrease in gains on derivative instruments due to a 2002 gain from de-designated contracts from a non-creditworthy counterparty under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In addition, federal tax refunds decreased in 2003 to $9.3 million compared to $10.3 million in 2002. Net income was also negatively impacted by a decrease in InfrastruX net income of $7.7 million, net of minority interest, due to unusually wet weather affecting productivity in the first quarter of 2003 and increased competition in the marketplace.
        Net income in 2002 was positively impacted by an increase in utility net income of $23.9$4.6 million from 2001 due to increased electric and gas margins resulting from general tariff rate increases. In addition, net income was positively impacted by $10.9$10.3 million of one-time federal tax refunds in 2002. Net income in 2002 was negatively impacted by a decrease in non-utility net income of $19.8$22.8 million primarily due to a decline in property sales from 2001 at PSE’s real estate investment and development subsidiary, Puget Western, Inc., and aan $8.0 million gain on PSE’s sale of the assets in its ConneXt subsidiary in August 2001. This was partially offset by an increase of $6.9 million in net income, net of minority interest, at InfrastruX.
        Total kilowatt-hourkWh energy sales to retail consumers in 20022003 were 19.319.6 billion compared with 19.3 billion in 2002 and 19.9 billion in 2001 and 21.9 billion in 2000.2001. Kilowatt-hour sales to wholesale customers were 5.1 billion in 2003, 3.5 billion in 2002 and 5.0 billion in 2001 and 14.2 billion in 2000. Kilowatt-hours transported to transportation customers under a new tariff established in 2001 were 2.3 billion in 2002 and 364 million in 2001. Kilowatt-hours transported to transportation customers under a terminated pilot program were 164 thousand2.0 billion in 2000.2003, 2.3 billion in 2002 and 0.4 billion in 2001.
        Total gas sales to retail consumers in 20022003 were 839.6815.7 million therms compared with 839.6 million therms in 2002 and 850.4 million therms in 2001 and 890.5 million therms in 2000.2001. Total gas sales to transportation customers in 20022003 were 209.5 million therms compared to 207.9 million therms compared within 2002 and 188.2 million therms in 2001.


PUGET SOUND ENERGY
        The table below sets forth changes in the results of operations for PSE and its subsidiaries.

INCREASE (DECREASE) OVER PRECEDING YEAR
(DOLLARS IN MILLIONS)
YEARS ENDED DECEMBER 31

2003
2002
  Operating revenue changes:        
    Electric interim and general rate increase  $2.3$57.0
    BPA residential exchange credit   (25.1) (49.7)
    Electric sales to other utilities and marketers   103.2 (445.7)
    Electric revenue sold at index rates to retail customers   (4.4) (183.9)
    Electric conservation trust credit   5.0 18.3
    Electric transportation revenue   (4.0) 13.0
    Electric load and other   66.6 91.7

     Total electric operating change   143.6 (499.3)

    Gas general rate increase   24.2 11.8
    Gas retail load and PGA rate change   (86.4) (131.7)
    Gas transportation revenue and other   (0.7) 2.0

     Total gas operating change   (62.9) (117.9)

    Other revenue   (3.8) (22.8)

       Total operating revenue change   76.9 (640.0)

  Operating expense changes:  
    Energy costs:  
      Purchased electricity   177.8 (273.3)
      Residential exchange power cost credit   (23.9) (74.1)
      Purchased gas   (77.9) (132.4)
      Electric generation fuel   (48.5) (167.9)
      Unrealized gain/loss on derivative instruments   11.7 (0.4)
    Utility operations and maintenance:  
      Production operations and maintenance   (2.0) 2.3
      Personal energy management expenses   (6.3) (5.9)
      Low-income program pass-through expenses   3.3 3.8
      Other utility operations and maintenance   8.4 20.2
    Other operations and maintenance   (0.4) (6.9)
    Depreciation and amortization   4.8 6.6
    Conservation amortization   16.0 11.0
    Taxes other than income taxes   (7.5) (5.0)
    Income taxes   18.1 (24.1)

       Total operating expense change   73.6 (646.1)

  Other income change (net of tax)   (3.6) (11.8)
  Interest charges change   (11.4) 4.5
  Cumulative effect of implementation of accounting change (net of tax)   0.2 (14.8)

  Net income change  $10.9$4.6

        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. The following is additional information pertaining to the changes outlined in the above table.
        Electric margin increased $19.3 million for 2003 compared to 2002 due primarily to the non-reoccurrence of losses associated with the


resale of gas supply for electric generation. Electric margin increased $2.7 million from 2001 to 2002 as a result of an increase in kWh sales and the full-year effect of the general rate case. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers including transmission costs to bring electric energy to PSE’s service territory.
        Electric margin for 2001 through 2003 was:

 ELECTRIC MARGIN
(DOLLARS IN MILLIONS)
TWELVE MONTHS ENDED DECEMBER 31:

2003
2002
2001
  Electric retail sales revenue  $1,272.7$1,260.9$1,366.3
  Electric transportation revenue   11.5 15.5 2.5
  Other electric revenue-gas supply resale   9.1 (20.3) (35.4)

  Total electric revenue for margin   1,293.3 1,256.1 1,333.4
  Adjustments for amounts included in revenue:  
     Pass-through tariff items (conservation and low-income tariffs)   (45.2) (32.1) (36.6)
     Pass-through revenue-sensitive taxes   (91.0) (88.5) (94.5)
     Residential exchange credit   173.8 150.0 75.9

        Net electric revenue for margin   1,330.9 1,285.5 1,278.2

  Minus power costs:  
     Electric generation fuel   (65.0) (113.5) (281.4)
     Purchased electricity, net of sales to other utilities and   (635.2) (557.1) (384.6)
     marketers  

        Total electric power costs   (700.2) (670.6) (666.0)

  Electric margin before PCA   630.7 614.9 612.2
  Power cost deferred under the PCA   3.5 -- --

  Electric margin  $634.2$614.9$612.2

        Gas margin increased $19.1 million in 2003 compared to 2002 due to the effects of the gas general rate increase effective September 1, 2002. Gas margin increased $19.5 million in 2002 compared to 2001 due primarily to the gas general rate increase effective September 1, 2002 and increased usage by customers. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
        Gas margin for 2001 through 2003 was:

 GAS MARGIN
(DOLLARS IN MILLIONS)
TWELVE MONTHS ENDED DECEMBER 31:

2003
2002
2001
  Gas retail revenue  $609.6$673.2$793.1
  Gas transportation revenue   13.8 12.9 11.8

  Total gas revenue for margin   623.4 686.1 804.9
  Adjustments for amounts included in revenue:  
     Gas revenue hedge   0.2 0.6 --
     Pass-through tariff items (conservation and low-income tariffs)   (3.8) (2.3) (0.5)
     Pass-through revenue-sensitive taxes   (48.5) (54.3) (61.4)

        Net gas revenue for margin   571.3 630.1 743.0
  Minus purchased gas costs   (327.1) (405.0) (537.4)

  Gas margin  $244.2$225.1$205.6


PUGET SOUND ENERGY
2003 COMPARED TO 2002

OPERATING REVENUES – ELECTRIC
        Electric operating revenues increased $143.6 million in 2003 compared to 2002 due primarily to an increase of $103.2 million in wholesale electric sales to other utilities and marketers from greater surplus volumes. Wholesale sales volumes increased by 1.6 billion kWh or 47.4% compared to 2002. Retail sales volumes increased 1.8% to 19.6 billion kWh as a result of increased usage by commercial customers in 2003 compared to 2002. Electric operating revenues also increased by $27.4 million due primarily to the non-occurrence of 2002 losses on the sale of excess gas supply used for electric generation.
        During 2003, the benefits of the Residential and Farm Energy Exchange Credit to customers reduced revenues by $181.9 million compared to $156.8 million in 2002. This credit also reduces power costs by a corresponding amount with no impact on earnings. See Item 1, Business – Regulation and Rates – Residential and Small Farm Exchange Credit for further discussion.
        During 2003, PSE collected in its electric general rate tariff as a reduction to revenue and remitted to a grantor trust $7.7 million as compared to $12.7 million for 2002 as a result of PSE’s 1995 sale of future electric revenues associated with its investment in conservation assets. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expense. PSE’s 1995 conservation trust transaction was consolidated in the third quarter of 2003 to meet the guidance of FASB Interpretation No. 46 (FIN 46) and, as a result, revenues increased $5.7 million while conservation amortization and interest expense increased by a corresponding amount with no impact on earnings. This amount was also forwarded to the grantor trust and any cash balance at the grantor trust is reported as restricted cash on the balance sheet. At December 31, 2003, the balance sheet assets and liabilities have increased by $4.2 million.
        PSE operates within the western wholesale market and has made sales into the California energy market. During the fourth quarter of 2000, PSE made sales to the California energy market on which the receivable amount is still outstanding. At December 31, 2003, PSE’s receivable from the California Independent System Operator (CAISO) and other counterparties, net of reserves, was $23.6 million. See the discussion of the CAISO receivable and California proceedings under “Proceedings Relating to the Western Power Market.”

OPERATING REVENUES – GAS
        Regulated gas utility revenues in 2003 compared to 2002 decreased by $62.9 million or 9.0% due primarily to lower Purchased Gas Adjustment (PGA) rates in 2003 as a result of refunding the previous overcollection of PGA gas costs. In addition, warmer temperatures in 2003 resulted in 8.5% fewer heating degree days as compared to 2002 resulting in lower therm sales.
        PGA rates charged to customers were lower in 2003 compared to 2002 as a result of rate decreases of 7.3% and 12.5% which took effect September 1, 2002 and November 1, 2002, respectively, offset by a rate increase of 20.1% which took effect April 10, 2003. On September 24, 2003, the Washington Commission approved a PGA rate increase of an annual average of 13.3% across all groups of customers effective October 1, 2003. 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 (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) and net income are not affected by changes under the PGA.

OTHER REVENUES
        Other operating revenues decreased $3.8 million primarily due to a decrease in property sales for Puget Western, Inc. which generates a majority of its revenue through the development and sale of property.

OPERATING EXPENSES
Purchased electricityexpenses increased $177.8 million in 2003 compared to 2002. PSE’s hydroelectric production and related power costs in 2003 were negatively impacted by below-normal winter precipitation and snow pack in the Pacific Northwest region associated with an El Nino weather condition. The January 25, 2004 Columbia Basin Runoff Summary published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff above Grand Coulee reservoir for the period January through December 2003 was 87% of normal. This compares to 108% of normal for the same period in 2002. PSE reached the $40 million cumulative cap under the PCA mechanism in 2003 primarily due to increased power costs and adverse hydro conditions. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to customers and 1% to PSE.
        To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro 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 and intermediate-term off-system physical purchases and sales, and through other risk management techniques. A PSE Risk Management Committee oversees energy portfolio exposures.
Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA increased $23.9 million in 2003 compared to 2002 due to the impact of a full year’s increased Residential and Farm Energy Exchange credit rate. The rate increased in January, March and October of 2002 for residential and small farm customers. Discussion of the amended Residential Purchase and Sale Agreement between PSE and BPA can be found under “Regulation and Rates – Residential and Small Farm Exchange Credit.” The residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.
Purchased gasexpenses decreased $77.9 million in 2003 compared to 2002 primarily due to a 2.1% decrease in sales volume which was partially offset by an increase in gas market prices. The PGA allows PSE to recover expected gas costs. PSE defers, as a receivable or liability,


any gas costs that exceed or fall short of the amount in PGA rates and accrues interest under the PGA. The PGA liability balance at December 31, 2003 was $12.0 million compared to a liability balance of $83.8 million at December 31, 2002.
Electric generation fuelexpense decreased $48.5 million in 2003 compared to 2002 as a result of lower fuel costs for PSE-controlled gas-fired generation facilities and the result of not operating the generating facilities due to available lower-cost wholesale power supply.
Unrealized gains/losses on derivative instrumentsincreased $11.7 million in 2003 compared to 2002 as a result of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and 204.0settled in 2002. The unrealized gains and losses recorded in the income statement are the result of the change in the market value of derivative instruments not meeting cash flow hedge criteria. (For further discussion see Note 15.)
        PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the mark-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.
Production operations and maintenancecosts decreased $2.0 million therms in 2003 compared to 2002 due primarily to decreased operating costs of PSE’s combustion turbine plants which were operated at lower levels in 2003 than in 2002 due to lower wholesale power prices.
        PSE’sPersonal Energy ManagementTMenergy-efficiency program costs decreased $6.3 million in 2003 compared to 2002 reflecting a decreased emphasis on the program in light of relatively moderate energy prices and cancellation of the Time of Use program in November 2002.
        TheLow-Income Programapproved by the Washington Commission in the general rate case settlement began in July 2002, which resulted in increased costs of $3.3 million in 2003 compared to 2002. These costs are fully recovered in retail rates beginning at the program’s inception on July 1, 2002 for electric service and September 1, 2002 for gas service.
Other utility operations and maintenancecosts increased $8.4 million in 2003 compared to 2002 due primarily to an increase in electric overhead and underground line costs, gas distribution main costs, least cost planning costs, due diligence costs for power resource acquisition, certain costs associated with preparing the power cost only rate case and meter reading expenses. Also included in the results is pension income related to PSE’s defined benefit pension plan recorded under SFAS No. 87, “Employers’ Accounting for Pensions.” Pension and benefit costs are allocated between capital and operations and maintenance expense based on the distribution of labor costs in accordance with FERC guidelines. As a result, approximately 67.0% of the annual qualified pension income of $12.9 million for 2003 was recorded as a reduction in operations and maintenance expense compared to 66.8% of $17.7 million for 2002. Qualified pension income is expected to decline to $8.6 million in 2004. During the fourth quarter of 2003, the Puget Sound region was hit by a severe windstorm that caused significant damage to PSE’s electric distribution system. The windstorm is considered a “catastrophic event” under Washington Commission guidelines and as a result, PSE was able to defer the repair cost of $10.1 million for later recovery in retail rates.
Depreciation and amortizationexpense increased $4.8 million in 2003 compared to 2002 due primarily to the effects of new plant placed in service during the past year.
Conservation amortizationincreased $16.0 million in 2003 compared to 2002 due to increased conservation expenditures and the result of consolidating the off-balance sheet conservation trust beginning July 1, 2003 in accordance with FIN 46. The consolidation of the conservation trust increased conservation amortization by $5.7 million for the period July through December 2003. Pass-through conservation costs are recovered through an electric conservation rider, a gas conservation tracker mechanism and a conservation trust rate schedule with no impact to earnings.
Taxes other than income taxesdecreased $7.5 million in 2003 compared to 2002 primarily due to the 2002 property tax expense of $5.2 million related to the State of Oregon property tax bills covering a six-year period ending June 30, 2001 not recurring in 2003, a $1.4 million reduction in expense in the second quarter of 2003 related to the settlement of the State of Oregon property tax bills and a $2.8 million decrease in revenue-based Washington State excise tax and municipal tax. This was offset by a $1.6 million increase in the State of Washington property taxes.
Income taxesincreased $18.1 million in 2003 compared to 2002 as a result of increased income offset by true-ups related to filing the prior year’s income tax returns that reduced income tax expense by $3.0 million and a $6.2 million reduction in tax expense related to the favorable resolution of a federal income tax matter from 1997 to 2002 in the second quarter of 2003. The increase is also the result of the 2002 refunds totaling $10.3 million. The $10.3 million is composed of a $4.1 million refund related to the audit of the Company’s 1998 and 1999 federal income tax returns, a $3.5 million reduction to income tax expense representing an adjustment to 2001 federal income tax based on the 2001 federal tax return and a $2.7 million reduction in expense related to a refund of federal income taxes for 2000.


OTHER INCOME
        Other income, net of federal income tax, decreased $3.6 million compared to 2002 reflecting a $4.0 million after-tax downward adjustment of the carrying value of a non-utility venture capital investment in the fourth quarter of 2003.

INTEREST CHARGES
        RESULTS OF OPERATION OF PUGET ENERGY
        Interest charges decreased $11.4 million for 2003 compared to 2002 primarily due to a decrease in long-term and short-term debt outstanding of $12.0 million and the maturity of $72.0 million of Medium-Term Notes with interest rates ranging from 6.20% to 7.02% during 2003, the early redemption of $123.0 million of Medium-Term Notes with interest rates ranging from 7.19% to 8.59% during 2003, and the refinancing of $161.9 million of Pollution Control Bonds with interest rates ranging from 5.875% to 7.25% to rates ranging from 5.00% to 5.10%. The decrease in interest expense was partially offset by the issuance of $150 million of 3.363% Senior Notes in May 2003. PSE was able to pay maturing notes and redeem other notes mainly with additional equity investments by Puget Energy in 2003 and 2002.

INFRASTRUX
INCREASE (DECREASE) OVER PRECEDING YEAR
YEARS ENDED DECEMBER 31
(Dollars in millions)
20022001



  Operating revenue changes:      
    Electric interim rate increase  $25.0$-- 
    Electric general rate increases   32.0 12.5
    BPA residential exchange credit   (49.7) 11.2
    Electric sales to other utilities and marketers   (443.2) (587.0)
    Electric revenue sold at index rates to retail customers   (183.9) (82.4)
    Electric conservation trust credit   18.3 4.4
    Electric transportation revenue   13.0 2.5
    Optimization sales and purchases to other utilities   (2.5) 11.0
    Electric conservation incentive credit   --  (19.5)
    Electric load and other   91.7 (119.8)



     Total electric operating change   (499.3) (767.1)



    Gas retail revenue change   (131.7) 203.8
    Gas general rate increase   11.8 -- 
    Gas transportation revenue and other   2.0 (1.1)



     Total gas operating change   (117.9) 202.7



    InfrastruX revenue   145.7 128.8
    Other revenue   (22.7) 19.8



     Total other operating revenue change   123.0 148.6



     Total operating revenue change   (494.2) (415.8)



  Operating expense changes:  
    Energy costs:  
      Purchased electricity   (273.3) (708.6)
      Residential exchange credit   (74.1) (34.8)
      Purchased gas   (132.4) 204.5
      Fuel   (167.9) 98.4
      Unrealized (gain)/loss on derivative instruments   (0.4) (11.2)
    Utility operations and maintenance :  
      Production operations and maintenance   2.3 2.8
      Personal energy management expenses   (5.9) 11.1
      Low income program pass through expenses   3.8 -- 
      Other utility operations and maintenance   20.2 11.8
    InfrastruX operations and maintenance   122.6 106.6
    Other operations and maintenance   (6.2) (10.5)
    Depreciation and amortization   11.2 21.0
    Conservation amortization   11.0 (0.3)
    Taxes other than income taxes   2.8 10.2
    Income taxes   (20.5) (50.0)



       Total operating expense change   (506.8) (349.0)



  Other income change (net of tax)   (9.1) 9.5
  Interest charges change   6.3 15.0
  Minority interest in earnings of consolidated subsidiary change   0.9 -- 



  Cumulative effect of implementation of accounting  
     change (net of tax)   (14.7) 14.7



  Net income change  $11.0$(87.0)



        The table below sets forth changes in the results of operations for InfrastruX, net of minority interest.

INCREASE (DECREASE) OVER PRECEDING YEAR
(DOLLARS IN MILLIONS)
YEARS ENDED DECEMBER 31

2003   
2002   
  Operating revenue change:       
       Other operating revenue  $22.3$145.7

  Operating expense change:  
       Other operations and maintenance   31.7 122.6
       Depreciation and amortization   3.3 4.6
       Taxes other than income taxes   0.5 7.8
       Income taxes   (5.1) 3.7

           Total operating expense change   30.4 138.7
  Other income change (net of tax)   (0.3) 2.7
  Interest charges change    -- 1.9
  Minority interest change   (0.7) 0.9

  Net income change  $(7.7)$6.9

        The following additional information pertains to the changes outlined in the table above:above.

INFRASTRUX
2003 COMPARED TO 2002

InfrastruX revenueincreased $22.3 million in 2003 compared to 2002 due primarily to acquisitions of several companies during 2002 and 2003, which contributed to an increase of $44.4 million. Excluding the impact of acquisitions, InfrastruX revenue decreased $22.1 million from 2002 due primarily to general market weakness and changing activities on certain lines of business. InfrastruX records revenues as services are performed or on a percent of completion basis for fixed-price projects.
InfrastruX operations and maintenanceexpenses increased $31.7 million in 2003 compared to 2002 due primarily to acquisitions of several companies during 2002 and 2003, which contributed to an increase of $37.1 million. Excluding the impact of acquisitions, operations and maintenance expenses decreased $5.4 million from 2002 due to lower productivity. The decrease, excluding the impact of acquisitions, was not proportionate to the decline in revenues due to the impact of severe wet weather on productivity during the first quarter of 2003 as well as the high costs of completing work in low-volume activities in 2003.
Depreciation and amortizationincreased by $3.3 million in 2003 compared to 2002 due to acquisitions during 2003 and 2002, which were not owned during the full year of 2002.
Income taxesdecreased $5.1 million in 2003 compared to 2002 due to lower income.


PUGET SOUND ENERGY
2002 COMPARED TO 2001

OPERATING REVENUES – ELECTRIC
        Electric operating revenues decreased $499.3 million in 2002 compared to 2001 due primarily to a decrease of $443.2$445.7 million in wholesale electric sales to other utilities and marketers due to lower surplus volumes and substantially lower prices in the wholesale electricity market. Wholesale sales volumes decreased by 1.5 billion kWh or 30.4%. Retail sales revenue decreased 7.7% primarily as a result of industrial and commercial customers on market index rates switching to transportation rate tariffs beginning in July 2001, as allowed by a Washington Commission order dated April 5, 2001 authorizing the establishment of a new electric transportation rate tariff. The decrease was offset by an interim electric rate surcharge in effect during the period April 1, 2002 through June 30, 2002, which increased electric revenue by $25 million, and a 4.6% electric general rate increase effective July 1, 2002, which increased electric revenue by approximately $32 million in 2002. Transportation revenues increased $13.0 million and volume increased 1.9 billion kWh in 2002.
        To meet customer demand, PSE dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydro 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 and intermediate-term off-system physical purchases and sales, and through other risk management techniques. PSE’s Risk Management Committee oversees energy price risk matters.
PSE operates its combustion turbine plants located in Western Washington primarily as peaking plants when it is cost-effective to do so. During 2001, PSE had operated its combustion turbine plants extensively to meet both on-system and regional load requirements largely due to adverse hydroelectric conditions in the Pacific Northwest. For 2002, PSE did not operate the combustion turbines to the extent it did in 2001 since market prices did not support the dispatching of these units, and PSE could serve its customers with lower costlower-cost resources. As a result, sales to other utilities and marketers declined in 2002 due to low wholesale energy prices and the reduction in operations of the combustion turbines.
        On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general rate case, putting new rates into effect on July 1, 2002. PSE established2002 and establishing a PCA mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE’s modified actual power costs relative to a power cost baseline. The mechanism would account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four yearfour-year period July 1, 2002 through June 30, 2006. PSE’s share of the cost through December 31, 2002 was $5.2 million. The factors influencing the variability of power costs included in the proposal are primarily weather or market related. PSE will be allowed to file for rate increases to implement limited power supply cost increases related to new resources.


        On June 13, 2001, the Washington Commission approved an amended Residential Purchase and Sale Agreement between PSE and the BPA, under which PSE’s residential and small farm customers would continue to receive benefits of federal power. Completion of this agreement enabled PSE to continue to provide, and in fact increase, effective January 1, 2002, the Residential and Farm Energy Exchange Credit to residential and small farm customers. The amended settlement agreement provides that, for its residential and small farm customers, PSE will receive (a) cash payment benefits during the period July 1, 2001 through September 30, 2006 and (b) benefits in the form of power or cash payments during the period October 1, 2006 through September 30, 2011. On June 17, 2002 PSE entered into an agreement with the BPA which amended the payment provisions of the Amended Settlement Agreement to provide for conditional deferral of payment by BPA of certain amounts to be paid under the original agreement.
        To implement this agreement for rate purposes, the Washington Commission approved tariff revisions that were intended (a) to transfer the Residential and Farm Energy Exchange credit in effect since October 1, 1995 in the amount of $0.01085 per kWh, to general rates effective July 1, 2001 and (b) to provide a supplemental Residential and Farm Exchange credit for eligible residential and small farm customers. On June 26, 2002, the Washington Commission then transferred the portion of the credit that had been in general rates back into Schedule 194.
        The Residential and Farm Exchange Benefit Supplemental Rider schedule was retitled Residential and Farm Energy Exchange Benefit, the portion of the credit that had been in general rates was transferred back into Schedule 194, and the credit was set at $0.01456 per kWh for the period July 1, 2002 through September 30, 2002, $0.01817 per kWh for the period October 1, 2002 through May 31, 2006 and $0.02302 per kWh for the period June 1, 2006 through September 30, 2006. The approval of these revised tariffs by the Washington Commission was effective July 1, 2002.
        In January 2003, PSE filed tariff sheets with the Washington Commission to reflect a modification to the agreement between PSE and the BPA that would reduce the Residential and Farm Energy Exchange Benefit credit. Under the modified agreement, BPA will defer paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred will be $3.5 million each month for the eight-month period beginning February 2003, for a total deferral of $27.7 million. Contemporaneously with entering into this agreement with PSE, BPA is entering into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA are agreeing to BPA’s deferral of payments in their fiscal year 2003. The total cumulative amount to be deferred under the agreement with PSE and other such agreements equals $55 million, an amount that will help BPA address its current financial difficulties. Absent certain adjustments, BPA will begin paying back the amount deferred with interest over the sixty-month period beginning November 2006. The Washington Commission approved the tariff changes and the Rider credit was changed to $0.01740 for the period February 15, 2003 through September 30, 2006.
        BPA’s rate case may affect the level of residential exchange benefits for PSE’s customers. For 2002, the benefits of the Residential and Farm Energy Exchange credited to customers were $152.8 million with a related offset to power costs. PSE received payments from BPA in the amount of $171.2 million during 2002. The difference between the customers’ credit and the amount received from BPA is deferred and will be credited to customers in later periods. The difference is recorded on PSE’s balance sheet as restricted cash. The modified Agreement will provide for payments from BPA in the amount of $630.6 million for the period January 2003 through September 2006 and for pass-through to eligible residential and farm customers of the same amount.
        There are several actions in the Ninth Circuit Court of Appeals against BPA, in which the petitioners assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the contract between BPA and the Company described above. BPA rates used in such contract between BPA and the Company for determining the amounts of money to be paid to the Company during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC on an interim basis, subject to refund with interest. It is not clear what impact, if any, review of such rates and the above-described Ninth Circuit Court of Appeals actions may have on the Company.
        In 2002, PSE collected and remitted to a grantor trust $12.7 million as a result of PSE’s sale of future electric revenues associated with its investment in conservation assets in its electric general rate tariff. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amounts owed by the trust to its bondholders was $18.9 million December 31, 2002.


OPERATING REVENUES – GAS
        Regulated gas utility revenues in 2002 compared to 2001 decreased by $117.9 million due primarily to PGA rate decreases as a result of lower natural gas prices that are passed through to customers. Gas delivered for transportation customers increased $1.1 million or 19.7 million therms in 2002.
        On August 29, 2001, the Washington Commission approved a decrease in PSE’s natural gas rates of 8.9% due to lower natural gas costs purchased for customers under terms of the PGA mechanism effective September 1, 2001. Also, on May 24, 2002, the Washington Commission allowed a decrease in PGA rates of 21.2% to become effective on June 1, 2002. This ended a temporary surcharge that went into effect September 1, 2001. 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.
        On August 28, 2002, the Washington Commission approved a 5.8% gas service rate increase in revenue to cover higher costs of providing natural gas service to customers. This service-related increase in revenues of approximately $35.6 million annually was offset by an annual $45 million or 7.3% PGA rate reduction, also approved on August 28, 2002. Both rate actions became effective September 1, 2002.
        On September 30, 2002, PSE filed a proposal with the Washington Commission to reduce natural gas supply rates under the PGA for a third time in 2002. The Washington Commission approved the proposal on October 30, 2002 and PSE lowered gas rates through the PGA by approximately 12.5% effective November 1, 2002.

OTHER REVENUES
        Other operating revenues decreased $22.7$22.8 million primarily due to a $22.9 million decrease in the gross margin on property sales from PSE’s real estate investment and development subsidiary, Puget Western, Inc.

OPERATING EXPENSES
        Purchased electricityexpenses decreased $273.3 million in 2002 compared to 2001 due to the dramatic decline of wholesale electricity prices since June 2001 and an 83-day unplanned outage of one of PSE’s 104 MW combustion turbine electric generating units located at its Fredonia generating station from February 21, 2001 to May 14, 2001, resulting in higher purchased electricity costs during 2001. In addition, the historic low hydroelectric power generation conditions experienced in 2001 in a high pricedhigh-priced wholesale market forced PSE to purchase additional energy during that period to meet retail electric customer loads.
        PSE’s hydroelectric production and related power costs in 2003 are expected to be impacted negatively by drought conditions in the Pacific Northwest region associated with El Nino weather conditions. The Northwest Rivers Forecast Center on February 6, 2003 predicted that streamflows in the Columbia River Basin above Grand Coulee Dam would be only 76 percent of normal. In a normal water year, PSE obtains about 38 percent38% of its energy supply from low-cost hydroelectric facilities, primarily from dams below Grand Coulee on the Columbia River. If the forecasted streamflow reductions occur, PSE will need to replace that low-cost hydropower with more expensive thermally-generated and purchased power. PSE’s share of the power costs through December 31, 2002 was $5.2 million. Because of adverse hydro conditions in 2003, PSE anticipates reaching the $40 million cumulative cap under the PCA mechanism by the frouth quarter of 2003. Under the PCA mechanism, further increases in variable power costs through June 30, 2006 would be apportioned 99% to cutomers and 1% to PSE.
        Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA increased $74.1 million in 2002 compared to 2001 due to the amended Residential Purchase and Sale Agreement between PSE and BPA as discussed in Operating Revenues – Electric reflecting increased benefits passed on to residential and small farm customers. As of July 2001, all residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.
        Purchased gasexpenses decreased $132.4 million in 2002 compared to 2001 primarily due to the impact of decreased gas costs, which are passed through to customers through the PGA mechanism, offset by a 1% increase in sales volumes. The PGA allows PSE to recover expected gas costs. PSE defers, as a receivable or liability, any gas costs that exceed or fall short of the amount in PGA rates and accrues interest under the PGA. The PGA balance was a receivable at December 31, 2001 of $37.2 million while the balance at December 31, 2002 was a liability of $83.8 million.


        Electric generation fuelexpense decreased $167.9 million in 2002 compared to 2001 as a result of decreased generation costs at PSE-controlled combustion turbine facilities and lower wholesale energy prices. These facilities operated at much higher levels during 2001 compared to 2002 to meet retail electric customer loads due to adverse hydroelectric conditions in 2001.



        Unrealized gains/losses on derivative instrumentsduring 2002 resulted in a decrease in expense of $0.4 million pre-tax ($0.3 million after-tax).million. The unrealized gains and losses recorded in the income statement are the result of the change in the market value of derivative instruments not meeting cash flow hedge criteria. In addition, SFAS No. 133 was adopted on January 1, 2001, and as a result, a one-time $14.7$14.8 million after-tax transition loss was recorded in 2001 from recognizing the cumulative effect of this change in accounting principle. (For further discussion see Note 17).
        Production operations and maintenancecosts increased $2.3 million in 2002 compared to 2001 due primarily to a $2.0 million pre-tax charge related to an industrial accident at Colstrip unitsUnits 1 and 2, of which PSE is a 50% owner, overall higher operating costs for the Colstrip generating facilities and the settlement of a combustion turbine insurance claim.
        PSE’sPersonal Energy ManagementTM
energy-efficiency program costs decreased $5.9 million in 2002 compared to 2001, reflecting a decreased emphasis on the program in light of relatively moderate energy prices and cancellation of the Time of Use program in November 2002.
        A newLow-incomeLow-Income Programapproved by the Washington Commission in the general rate case settlement began in July 2002 which resulted in increased costs of $3.8 million in 2002 compared to 2001. These costs are fully recovered in retail rates beginning at the program’s inception on July 1, 2002 for electric and September 1, 2002 for gas.
        Other utility operations and maintenancecosts increased $20.2 million in 2002 compared to 2001 due primarily to higher expense related to a one-time PSE employee severance cost totaling $4.2 million related to strategic outsourcing of operations work to service providers, and an overall increase in administrative and meter reading expenses. Also included in the results is pension income related to PSE’s defined benefit pension plan forrecorded under SFAS No. 87, “Employers’ Accounting for Pensions”.Pensions.” Pension and benefit costs are allocated between capital and operations and maintenance expenses based on the distribution of labor costs in accordance with FERC accounting instructions. As a result, approximately 65.9%66.8% of the annual qualified pension income of $17.7 million for 2002 was recorded as a reduction in operationoperations and maintenance expense compared to 58%58.0% of $20.0 million for 2001. Qualified pension income is expected to decline to $9.6 million in 2003 as a result of lower actual returns on pension assets during the last three years and declining expected rates of return on pension fund assets.
        PSE’sother operations and maintenanceexpenses decreased $6.2$6.9 million in 2002 compared to 2001 primarily due to a decrease in operating expenses at ConneXt, the assets of which were sold in the third quarter of 2001.
        Depreciation and amortizationexpense increased $11.2$6.6 million in 2002 compared to 2001 of which $6.6 million is due primarily to the effects of additional plant placed into service at PSE during 2002.
        Conservation amortizationincreased $11.0 million in 2002 compared to 2001 due to increased conservation expenditures. These costs are recovered in conservation rider and tracker mechanisms with no impact to earnings.
        Taxes other than income taxesincreased $2.8 million, of which PSE’s decreased $5.0 million in 2002 compared to 2001 due primarily to a decrease in revenue basedrevenue-based Washington State excise tax and municipal tax. This iswas offset by a municipal tax expense of $1.7 million recorded in 2002 related to various claims by cities that PSE underpaid municipal taxes owed as a result of not collecting the tax in certain rural areas that were annexed by cities. The offset also includes a one-time property tax expense of $5.2 million covering a six yearsix-year period ending June 30, 2001 related to Oregon State of Oregon property tax bills on PSE’s long-term Third AC Transmission Intertie contract.
        Income taxesdecreased $20.5$24.1 million in 2002 compared to 2001, of which PSE’s income taxes decreased by $24.1 million.2001. The decrease in 2002 includesincluded a total of $10.3 million in one-time refunds at PSE which are composed of which $4.7$4.1 million was recorded in the second quarter of 2002 related to the audit of the Company’s 1998 and 1999 federal income tax returns. Of this amount, $4.1 million reduced current tax expense and the balance, $0.6 million, was recorded as a deferred income tax liability. The decrease at PSE also includesreturns, a $3.5 million reduction to expense representing an adjustment to 2001 federal income taxtaxes based on the 2001 federal tax return filedand a $2.7 million reduction in the third quarter of 2002. The decrease in 2002 also includes flow-through benefits reducing federal income taxes of $2.7 millionexpense recorded in the fourth quarter of 2002 related to a refund of federal income taxes for 2000.

OTHER INCOME
        Other income, net of federal income tax, decreased $9.1$11.8 million in 2002 compared to 2001 due primarily to a one-time $8.0 million after-tax gain realized by PSE on the sale of ConneXt’s assets in the third quarter of 2001.


INTEREST CHARGES
        Interest charges, which consist of interest and amortization on long-term debt and other interest, increased $6.3$4.5 million in 2002 compared to 2001 of which PSE’s increased $4.4 millionprimarily as a result primarily of a full year’s interest expense on the issuance of $200 million 8.40% Trust Preferred Securities in May 2001. Other interest expense increased due primarily to a PGA liability (over-recovery of gas costs in rates) in 2002 compared to a PGA asset (under-recovery of gas costs in rates) in 2001. Under the PGA mechanism, interest is accrued on deferred balances.

INFRASTRUX
2002 COMPARED TO 2001

        InfrastruX revenueincreased $145.7 million in 2002 compared to 2001 due primarily to acquisitions of several companies during 2001 and 2002, which contributed to an increase of $127.0$126.0 million. Excluding the impact of acquisitions, InfrastruX revenue increased $18.7 million from 2001 and was impacted positively by ice storm restoration work performed in Oklahoma by InfrastruX’s Texas companies and continued strong performance of remediation services in the utility industry. InfrastruX records revenues as services are performed or on a percent of completion basis for fixed pricefixed-price projects.
        InfrastruX operationoperations and maintenanceexpenses increased $122.6 million in 2002 compared to 2001 primarily due to acquisitions during 2001 and 2002, which contributed to an increase of $103.8 million. Excluding the impact of acquisitions, InfrastruX operationoperations and maintenance expenses increased $18.9 million from 2001 and were impacted by the increase of corporate infrastructure to support a growing organization, additional costs of direct wages, construction costs and higher insurance costs incurred to support an increased revenue base.


        Depreciation and amortizationincreased by $4.6 million in 2002 compared to 2001 due to acquisitions during 2001 and 2000, which contributed $3.5 million. Increases in depreciation of $1.1 million from core companies were due primarily to the acquisition of strategic assets to support areas of the companyInfrastruX where significant growth opportunities exist.
        Taxes other than income taxesincreased $7.8 million in 2002 compared to 2001 primarily due to a $7.3 million increase in payroll tax resulting from an increased workforce as acquisitions have beenwere completed.
        Income taxesincreased $3.7 million in 2002 compared to 2001 due primarily to the acquisition of companies acquired during 2001 and 2002. Acquired companies accounted for an increase of $5.8 million offset by a reduction in the effective tax rate due to certain non-deductible or partially deductible items.
        Interest chargesincreased $1.9 million in 2002 compared to 2001 due to an increase in the amount drawn on itsInfrastruX’s revolving credit facilities primarily used for funding acquisitions.
        Other income,net of federal income tax, increased $2.7 million in 2002 compared to 2001 due primarily to implementation of SFAS No. 142 which ceased amortization of goodwill. Goodwill amortization expense in 2001 was $2.8 million.

PUGET SOUND ENERGY
2001 COMPARED TO 2000

OPERATING REVENUES — ELECTRIC
        Electric operating revenues decreased $767.1 million in 2001 compared to 2000 due to an overall average 0.9% general rate increase effective January 1, 2001 offset by sales to other utilities and marketers which decreased $587.0 million in 2001 due primarily to lower wholesale power volumes of 9.3 billion kWh and lower surplus capacity.
        Electric revenues in 2001 decreased due to lower regulated sales to customers, decreased prices and kilowatt-hours sold related to electric energy sales to other utilities and marketers and lower prices on market-index sales. This latter group of customers can choose another supplier or self-generate their energy needs. Several index rate customers switched to transportation rate tariffs beginning in July 2001 as allowed by a Washington Commission order dated April 5, 2001 authorizing the establishment of a transportation tariff. On June 19, 2001, FERC implemented price controls on wholesale electricity in the western states. Several factors contributed to the dramatic decline in wholesale electric prices by the end of the second quarter of 2001 and, therefore, greatly diminished the value of PSE’s excess electric energy during that period and into the foreseeable future. PSE and other western utilities filed an appeal asking FERC to review its June 19, 2001 order and make modifications to the price controls to stabilize wholesale prices in California and prevent the energy problems from spreading to other states. On December 19, 2001, FERC issued an order on clarification and rehearing addressing, in part, PSE’s petition for rehearing on the June 19, 2001 order. PSE and other entities have sought further rehearing and clarification of the December 19, 2001 order.


        Electric revenues were reduced by approximately $19.5 million in 2001 compared to 2000 related to a customer conservation incentive credit which was approved by the Washington Commission on April 25, 2001. The conservation incentive credit was to reduce customers’ bills by $0.05 per kWh for each kWh reduction in excess of 10% from the same billing period in the prior year through December 31, 2001. On November 7, 2001, the Washington Commission approved PSE’s request to terminate the conservation incentive credit program effective November 8, 2001.
        Revenues from electric customers in 2001 were reduced by a Residential and Farm Energy Exchange credit tariff in place since October 1, 1995. Under the rate plan approved by the Washington Commission in its merger order, PSE reflected in customers’ bills the level of Residential Exchange benefits in place at the time of the merger with Washington Energy Company in 1997. On January 29, 1997, PSE and BPA signed an agreement under which PSE received payments from BPA of approximately $235 million over an approximate five-year period that ended June 2001. These payments were recorded as a reduction of purchased electricity expenses. As a result of lower usage by residential and farm customers in 2001, the residential and farm exchange credit decreased by $11.2 million as compared to 2000. For calendar 2001, the benefits of the Residential and Farm Energy Exchange credited to customers was $103.1 million as compared to an offsetting reduction in Purchased Electricity Expense of $75.9 million. Eligible residential and small farm customers received credits to their bills in the same amount.
        In 2001, PSE collected and remitted to two grantor trusts $31.0 million as a result of PSE’s sale of future electric revenues associated with its investment in conservation assets in its electric general rate tariff. The impact of the sale of revenue was offset by reductions in conservation amortization and interest expenses. The principal amounts owed by the trusts to its bondholders were $31.8 million at December 31, 2001.
        On April 15, 2001, the Washington Commission issued an order allowing PSE’s large industrial customers whose rates were linked to a market index to choose their supplier of electricity or to self-generate. If an industrial customer chooses an alternate supplier, PSE will provide the transportation of electricity to the customer’s premises and charge that customer for the service.

OPERATING REVENUES – GAS
        Regulated gas utility sales revenue in 2001 compared to 2000 increased by $202.7 million from the prior year due primarily to higher natural gas prices which are passed through to customers in the PGA. Total gas volumes, including transported gas, decreased 5.1% in 2001 from 2000. Transportation and other revenue decreased $1.1 million or 15.8 million therms as industrial customers curtailed usage due to higher natural gas prices and water heater rental revenue declined.

OTHER REVENUES
        Other revenues increased $19.8 million in 2001 compared to 2000 due primarily to increased gross margins on property sales at PSE’s real estate investment and development subsidiary Puget Western, Inc.

OPERATING EXPENSES
Purchased electricityexpenses decreased $708.6 million in 2001 compared to 2000. The decrease in 2001 was due primarily to lower volumes and significantly lower prices for non-firm power purchases from other utilities and marketers due to declining prices in the West Coast power market beginning in the second half of 2001.
Residential exchange creditsassociated with the Residential Purchase and Sale Agreement with BPA increased $34.8 million in 2001 compared to 2000 due to the terms set out in the 1997 Residential Exchange Termination Agreement and the 2001 Residential Purchase and Sale Agreement between PSE and BPA discussed in Operating Revenues – Electric. Beginning July 2001, all residential exchange credits are passed through to eligible residential and small farm customers by a corresponding reduction in revenues.
Purchased gasexpenses increased $204.5 million in 2001 compared to 2000 primarily due to the impact of increased gas costs, which are passed through to customers through the PGA mechanism, offset by a 5.1% decrease in sales volumes.
Electric generation fuelexpense increased $98.4 million in 2001 compared to 2000 as a result of increased generation and higher fuel costs at combustion turbine facilities. These facilities operated at much higher levels in 2001 compared to the same period in 2000 due to adverse hydroelectric conditions.


Unrealized gains/losses on derivative instruments— During 2001, an increase to operating earnings of approximately $11.2 million pre-tax ($7.3 million after-tax) was recognized for unrealized gains associated with electric derivative transactions and a $14.7 million after-tax transition adjustment loss was recorded from recognizing the cumulative effect of this change in accounting principle. (For further discussion see Note 17.)
Production operations and maintenancecosts increased $2.8 million in 2001 compared to 2000 due primarily to an approximately $2.1 million increase in lease costs associated with PSE’s Fredonia 3 and 4 electric generation units offset by reduced operating costs resulting from the sale of the Centralia generating station in May 2000 and a net cost of $2.9 million after estimated insurance recovery to repair the PSE-owned Fredonia combustion turbine unit #1, which was out of service from February 21, 2001 through May 14, 2001.
        PSE’sPersonal Energy ManagementTM
energy-efficiency program costs increased $11.1 million in 2001, reflecting a full year of implementation compared to 2000. PSE began providing Personal Energy ManagementTM billing information to electric customers in December 2000.
Other utility operations and maintenancecosts increased $11.8 million in 2001 compared to 2000 due primarily to repair costs associated with storm and earthquake damage in 2001, increased meter reading expenses associated with providing Personal Energy ManagementTM, and a one-time insurance recovery received in 2000.
        PSE’sother operations and maintenanceexpenses decreased $10.5 million in 2001 compared to 2000 primarily due to a decrease in operating expenses at ConneXt, the assets of which were sold in the third quarter of 2001.
Depreciation and amortizationexpenses increased $21.0 million in 2001 compared to 2000 due to the effects of new plant placed into service during 2001, including ConsumerLinX, a customer information and billing system, which was placed into service in phases through late 2000 and early 2001.
Taxes other than income taxesincreased $10.2 million in 2001 of which $5.0 million was attributed to PSE as a result of increases in municipal taxes and state excise taxes that are revenue based.
Income taxesdecreased by $50.0 million in 2001 of which $52.9 million was attributed to PSE due to lower revenues and lower wholesale prices in the second half of the year.

OTHER INCOME
        Other income, net of federal income tax, increased $9.5 million in 2001 compared to 2000 due primarily to $11.8 million of reserves established in 2000 for a write-down to the fair values of certain assets held for sale by Hydro Energy Development Corp. to their net realizable values not recurring in 2001, $4.8 million of other income realized by Puget Western, Inc. on investments in 2000 not recurring in 2001, $7.4 million of increase in other income of ConneXt primarily from sales of assets in 2001, offset by reductions in other income in 2001 for additional amortization of goodwill from acquisitions by InfrastruX, officer incentive compensation accruals, and decreased other interest and dividend income.

INTEREST CHARGES
        Interest charges, which consist of interest and amortization on long-term debt and other interest, increased $15.0 million in 2001, of which $11.3 million at PSE was attributed to a full year’s interest expense on the issuance of $25 million 7.61% Senior Medium-Term Notes, Series B in September 2000 and the issuance of $260 million 7.69% Senior Medium-Term Notes, Series C, in November 2000. In addition, interest was incurred on the issuance of $200 million 8.4% Trust Preferred Securities in May 2001. Other interest expense decreased $16.9 million compared to 2000 as a result of lower weighted average interest rates and lower average daily short-term borrowings.


INFRASTRUX
2001 COMPARED TO 2000

InfrastruX revenueincreased $128.8 million in 2001 compared to 2000. InfrastruX was formed in June 2000 and completed two acquisitions late in the third quarter of 2000. An additional six companies were acquired in 2001.
InfrastruX operation and maintenanceexpenses increased $106.6 million in 2001 compared to 2000 due to limited operations in 2000 compared to a full year of operations and significant acquisition activity in 2001.
Depreciation and amortizationincreased $6.6 million in 2001 compared to 2000 due to the completion of six acquisitions in 2001.
Income taxesincreased $2.5 million in 2001 compared to 2000 due to the profitability of companies acquired during 2000 and 2001.
Interest chargesincreased $3.5 million in 2001 compared to 2000 due to an increase in the amount drawn on its revolving credit facilities primarily used for funding acquisitions.

CAPITAL RESOURCES AND LIQUIDITY

CAPITAL REQUIREMENTS
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
        Puget EnergyEnergy.
. The following are Puget Energy's aggregate consolidated (including PSE) contractual and commercial commitments as of December 31, 2002:2003:

Puget EnergyPuget EnergyPayments Due Per Period
Puget Energy Payments Due Per Period
Contractual Obligations
(Dollars in millions)
Total20032004-20052006-20072008 and
Thereafter

CONTRACTUAL OBLIGATIONS
(DOLLARS IN MILLIONS)

CONTRACTUAL OBLIGATIONS
(DOLLARS IN MILLIONS)

Total
2004
2005-
2006

2007-
2008

2009 and
Thereafter

Long-term debt $2,223.0$73.2$297.4$216.0$1,636.4 $2,216.3$246.8$128.3$307.3$1,533.9
Short-term debt  47.3 47.3 --  --  --   13.9 13.9 -- -- --
Trust preferred securities (1)  300.0 --  --  --  300.0
Preferred dividends (2)  1.1 1.1 --  --  -- 
Junior subordinated debentures payable to a 
subsidiary trust (1)  280.3 -- -- -- 280.3
Mandatorily redeemable preferred stock  1.9 -- -- -- 1.9
Service contract obligations  190.2 19.4 40.7 43.4 86.7  181.0 21.7 45.0 47.4 66.9
Capital lease obligations  8.3 2.0 3.2 2.2 0.9  6.5 1.6 2.9 2.0 --
Non-cancelable operating leases  66.1 18.2 23.8 14.6 9.5  72.5 18.0 25.1 19.0 10.4
Fredonia combustion turbines lease (3)  77.4 5.0 9.7 9.4 53.3
Fredonia combustion turbines lease (2)  69.6 4.5 8.7 8.5 47.9
Energy purchase obligations  4,603.8 849.6 951.1 827.9 1,975.2  4,737.4 928.2 1,245.0 1,036.7 1,527.5
Financial hedge obligations  (21.5) (6.3) (7.6) (6.3) (1.3)  67.0 30.5 17.7 18.8 --
Non-qualified pension funding  38.6 11.1 3.1 4.5 19.9


Total contractual cash obligations $7,495.7$1,009.5$1,318.3$1,107.2$4,060.7 $7,685.0$1,276.3$1,475.8$1,444.2$3,488.7


 Amount of Commitment
Expiration Per Period

Commercial Commitments
(Dollars in millions)
Total20032004-20052006-20072008 and
Thereafter






Guarantees (4)  $127.0$ --$127.0  --  --
Liquidity facilities - available (5)   369.7 219.7 150.0  --  --
Lines of credit - available (6)   35.8 12.8 23.0  --  --
Energy operations letter of credit (7)   0.5 0.5  --  --  --





   Total commercial commitments  $533.0$233.0$300.0  --  --

  Amount of Commitment
Expiration Per Period

COMMERCIAL COMMITMENTS
(DOLLARS IN MILLIONS)

Total
2004
2005-
2006

2007-
2008

2009 and
Thereafter

Guarantees (3)  $137.0$ --$137.0$ --$ --
Liquidity facilities - available (4)   288.5 249.5 39.0 --  --
Lines of credit - available (5)   39.1 26.1 3.0 10.0  --
Energy operations letter of credit (6)   0.5 0.5 -- --  --
 
   Total commercial commitments  $465.1$276.1$179.0$10.0$ --
 

(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) and lending the proceeds 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)

On October 8, 2002, the Board of Directors of PSE declared a dividend payable on January 1, 2003 for preferred stock outstanding on December 13, 2002.

(3)

In April 2001, PSE revised its master operating lease to $70 million plus interest with a financial institution. See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below for further discussion.

(4)(3)

In June 2001, InfrastruX signed a credit agreement with several 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 the guarantor.

(5)(4)

At December 31, 2002,2003, PSE had available a $250 million liquidity facility, which in part providesunsecured credit support for outstanding commercial paper totaling $30.3 million, thereby effectively reducing the available borrowing capacity under this line of credit to $219.7 million. At year end, the Company also hadagreement and a three year $150.0three-year $150 million receivables securitization facility available.facility. At December 31, 2003, PSE had available $39.0 million of receivables for sale under its receivables securitization facility. See “Accounts Receivable Securitization Program” under “Off-Balance Sheet Arrangements” below for further discussions.

The credit agreement and securitization facility provide credit support for an outstanding letter of credit totaling $0.5 million, thereby effectively reducing the available borrowing capacity under these liquidity facilities to $288.5 million.
(6)(5)

Puget Energy has a $15 million line of credit with a bank. At December 31, 2003, $5.0 million was outstanding, reducing the available borrowing capacity under this line of credit to $10 million. InfrastruX had $179.8has $34.7 million in lines of credit with various banks whichto fund capital requirements of InfrastruX and its subsidiaries. InfrastruX and its subsidiaries had outstanding loans of $144.0$13.9 million, effectively reducing the available borrowing capacity under these lines of credit to $35.8$20.8 million.

(7)(6)

In May 2002, PSE provided an energy trading counterparty a letter of credit in the amount of $0.5 million to satisfy the counterparty’s credit requirements following PSE’s senior unsecured debt downgrade in October 2001. The letter of credit has been renewed and expires on May 7, 2003.

March 15, 2004.


        Puget Sound EnergyEnergy.. The following are PSE’sPSE's aggregate contractual and commercial commitments as of December 31, 2002:2003:

Puget Sound EnergyPayments Due Per Period
Contractual Obligations
(Dollars in millions)
Total20032004-20052006-20072008 and
Thereafter






Long-term debt  $2,093.9$72.0$169.5$216.0$1,636.4
Short-term debt   30.3 30.3 --  --  -- 
Trust preferred securities (1)   300.0 --  --  --  300.0
Preferred dividends (2)   1.1 1.1 --  --  -- 
Service contract obligations   190.2 19.4 40.7 43.4 86.7
Non-cancelable operating leases   51.8 12.6 16.9 13.0 9.3
Fredonia combustion turbines lease (3)   77.4 5.0 9.7 9.4 53.3
Energy purchase obligations   4,603.8 849.6 951.1 827.9 1,975.2
Financial hedge obligations   (21.5) (6.3) (7.6) (6.3) (1.3)





   Total contractual cash obligations  $7,327.0$983.7$1,180.3$1,103.4$4,059.6


 Amount of Commitment
Expiration Per Period

Commercial Commitments
(Dollars in millions)
Total20032004-20052006-20072008 and
Thereafter






Liquidity facilities - available (4)  $369.7$219.7$150.0  --  --
Energy operations letter of credit (5)   0.5 0.5  --  --  --





   Total commercial commitments  $370.2$220.2$150.0  --  --
Puget Sound Energy Payments Due Per Period
CONTRACTUAL OBLIGATIONS
(DOLLARS IN MILLIONS)

Total
2004
2005-
2006

2007-
2008

2009 and
Thereafter

Long-term debt  $2,053.0$102.6$112.0$304.5$1,533.9
Junior subordinated debentures payable to a  
  subsidiary trust (1)   280.3 -- -- -- 280.3
Mandatorily redeemable preferred stock   1.9 -- -- -- 1.9
Service contract obligations   181.0 21.7 45.0 47.4 66.9
Non-cancelable operating leases   55.5 10.7 17.6 16.8 10.4
Fredonia combustion turbines lease (2)   69.6 4.5 8.7 8.5 47.9
Energy purchase obligations   4,737.4 928.2 1,245.0 1,036.7 1,527.5
Financial hedge obligations   67.0 30.5 17.7 18.8 --
Non-qualified pension funding   38.6 11.1 3.1 4.5 19.9
 
   Total contractual cash obligations  $7,484.3$1,109.3$1,449.1$1,437.2$3,488.7
 
  Amount of Commitment
Expiration Per Period

COMMERCIAL COMMITMENTS
(DOLLARS IN MILLIONS)

Total
2004
2005-
2006

2007-
2008

2009 and
Thereafter

Liquidity facilities - available (3)  $288.5$249.5$39.0$--$ --
Energy operations letter of credit (4)   0.5 0.5 -- --  --
 
   Total commercial commitments  $289.0$250.0$39.0$ --$ --
 


(1)

See note (1) above.

on previous table.
(2)

See note (2) above.

"Fredonia 3 and 4 Operating Lease" under "Off-Balance Sheet Arrangements" below for further discussion.
(3)

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

note (4) on previous table respect to PSE.
(4)

See note (5) above with respect to PSE.

(5)

    See note (7) above.

(6) on previous table.

OFF-BALANCE SHEET ARRANGEMENTS
        CONSERVATION TRUST
        In 1995 and 1997, PSE sold a stream of future electric revenues associated with $237.7 million of its investment in conservation assets in its electric general rate tariff to two grantor trusts. As a result of this sale, PSE collects these revenues from its electric customers and remits them to the trusts. On August 29, 2001, PSE purchased the remaining 1997 trust securities. During 2002, PSE collected and remitted $12.7 million to the 1995 trust as compared to $31.0 million for both trusts in 2001. The remaining principal expected to be collected on behalf of the 1995 trust is $18.9 million at December 31, 2002.

        ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM
        In order to provide a source of liquidity for PSE in December 2002,at attractive cost of capital rates, PSE entered into a Receivables Sales Agreement with Rainier Receivables, Inc., a wholly owned subsidiary of PSE, pursuantin December 2002. Pursuant to whichthe Receivables Sales Agreement, PSE sold all of its utility customerscustomer 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 several financial institutions.a third party. The Receivables Purchase


Agreement allows Rainier Receivables to sell the receivables purchased from PSE to the financial institutions.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 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 secured revolving line of credit. In the event Rainier Receivables elects to sell receivables under the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers of the receivables fees that are analogouscomparable 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 purchased by the purchasers declines until Rainier Receivables elects to sell additional receivables to the purchasers.
        The receivables securitization facility has a three yearthree-year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. At December 31, 2002 there were no amounts outstanding under the2003, Rainier Receivables had sold $111.0 million in accounts receivable securitization facility.

and the maximum remaining receivables available for sale was $39.0 million.

FREDONIA 3 AND 4 OPERATING LEASE
        In April 2001, PSE revised its master operating lease to $70 million plus interest with a financial institution. Under this revised agreement        PSE leases two combustion turbines for its Fredonia 3 and 4 electric generation facility.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 cancelledcanceled by PSE after three years.August 2004. Payments under the lease vary with changes in the London inter-bank offered rateInterbank Offered Rate (LIBOR). At December 31, 2002,2003, PSE’s outstanding balance under the lease was $61.7$59.1 million. Lease payments assume a LIBOR of 1.38%. 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 87% of the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency.

deficiency up to a maximum of 87% of the unamortized value of the equipment.

UTILITY CONSTRUCTION PROGRAM
        Current 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 $224.2$270.0 million in 2002.2003. PSE expects construction expenditures will be approximately $271.9$424.0 million $265.3in 2004, which includes $80.0 million for new generating resources subject to regulatory approval. The proposed generating resource, if approved in 2004, will be funded initially with short-term debt. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

NEW GENERATION RESOURCES
        In October 2003, PSE completed negotiations to purchase a 49.85% interest in a 275 MW (250 MW capacity with 25 MW planned capital improvements) gas-fired electric generating facility located within PSE’s service territory. The purchase will add approximately 137 MW of electric generation capacity to serve PSE’s retail customers. PSE submitted a power cost only rate case in October 2003 to the Washington Commission to recover the approximately $80 million cost of the new generating facility and other power costs. The power cost only rate case is expected to last approximately five months. Accordingly, the acquisition of the plant is subject to approval by the Washington Commission, and is expected by mid-April 2004. In addition, the acquisition will require approval from FERC. PSE filed its application in January 2004 with FERC and anticipates approval in early 2004.
        In addition, PSE has issued an RFP to acquire approximately 50 average MW of energy from wind power for its electric-resource portfolio. PSE issued an RFP in February 2004 for approximately 305 MW of thermal and other generation with proposals due back in March 2004.

OTHER ADDITIONS
        Other property, plant and equipment additions were $15.5 million in 2003. Puget Energy expects InfrastruX’s capital additions to be $16.2 million, $18.0 million and $265.0$20.0 million in 2003, 2004, 2005 and 2005,2006, respectively. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

OTHER ADDITIONS
        Other property, plant and equipment additions were $11.6 million in 2002. Puget Energy expects InfrastruX’s capital additions to be $16.6 million, $19.0 million, and $21.0 million in 2003, 2004 and 2005, respectively. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

CAPITAL RESOURCES
CASH FROM OPERATIONS
        Cash generated from operations (nettotaled $323.0 million at December 31, 2003. During the period, $87.2 million in cash was used for AFUDC and payment of dividendsdividends. Consequently, cash available for utility construction expenditures and AFUDC) totaled $944.8other capital expenditures was $235.7 million for the three-year period 2000-2002, and provided 117.7%or 77.7% of the $803.1$303.5 million of utilityin construction expenditures (net of AFUDC) and other capital expenditure requirements for thatthe period. Internal cash generation (net of dividends and AFUDC) provided 254.8% of total capital expenditure requirementsFor the same period in 2002, 57.7% in 2001,cash generated from operations was $709.7 million, $99.3 million of which was used for AFUDC and 57.2% in 2000. Puget Energy and PSE expect to continue financing thepayment of dividends. Therefore, cash available for utility construction programexpenditures and other capital expenditure requirements with internallyexpenditures at December 31, 2002 was $610.4 million. The reduction in cash generated fundsfrom operations in 2003 was primarily due to refunds reducing the PGA balance and externally financed capital.the reduction in cash received related to deferred tax items in 2002.
        During 2002, PSE received $121.0 million in excess of actual gas costs from customers through the PGA mechanism compared to refunds to customers through the PGA mechanism of $71.8 million for 2003. Cash from deferred income taxes decreased $93.8 million due primarily to federal income tax refunds and deferred tax credits in 2002 that did not occur in 2003. There was also a $21.4 million decrease in cash flows as a result of returning collateral to an energy trading counterparty in 2003 compared to a $21.4 million increase in cash flow from receiving the collateral in 2002. Cash from materials and supplies decreased $36.8 million due predominantly to higher gas injections in 2003 as compared to 2002 in order to increase gas storage levels. Cash used for accounts payable decreased $27.9 million due to fewer accrued incentives and operating-related costs at the end of 2003. In 2003, PSE also funded the qualified pension plan in the amount of $26.5 million


compared to no funding during 2002. Cash used for taxes payable increased in 2003 compared to 2002 by $31.7 million.

FINANCING PROGRAM
        Financing utility construction requirements and operational needs is dependent upon the amount of internally generated funds and 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 December 31, 2002,2003, PSE could issue:

approximately $466.8$927.9 million of additional first mortgage bonds at an assumed interest rate of 5.92% on a ten-year first mortgage bond due to a limitation of the interest coverage ratio. (PSE hasbased upon approximately $1.2$1.5 billion of electric and gas bondable property available for use for issuance of up to $700.8 million of first mortgage bonds, subject to the interest coverage ratio limitation of 2.0 times net earnings available for interest. PSE’s interest coverage ratio at December 31, 20022003 was 2.42.9 times net earnings available for interest);

interest;

approximately $157.1$454.5 million of additional preferred stock at an assumed dividend rate of 7.75%7.25%; and

approximately $243.5$261.3 million of unsecured long-term debt.


CREDIT RATINGS
        Neither Puget Energy nor PSE has any rating downgrade triggers that would accelerate the maturity dates of outstanding debt. However, a downgrade in the senior unsecuredcompanies’ credit ratings could adversely affect the companies’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. A further downgrade in commercial paper ratings could preclude entirely PSE’s ability to issue commercial paper. In addition, downgrades in any or a combination of PSE’s debt ratings may allow 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 current ratings of Puget Energy and PSE, as of February 13, 2003, are:March 8, 2004, were:

Ratings
Puget EnergyStandard & Poor'sPoor’sMoody'sMoody’s
  Corporate credit/issuer ratingBBB-Ba1
Puget Sound Energy
  Corporate credit/issuer ratingBBB-Baa3
  Senior secured debtBBBBaa2
  Shelf debt senior securedBBB(P)Baa2
  Senior unsecuredTrust preferred securitiesBB+BBBaa3Bal
  Preferred stockBBBa2
  Commercial paperA-3P-2
  Subordinate*Ba1
Revolving credit facility*Baa3
  Ratings outlookPositiveStable
NegativePuget Energy
  Corporate credit/issuer ratingBBB-Ba1


* No ratings provided.Standard & Poor’s does not rate credit facilities.

        Moody's Investors Service has stated that its negative outlook is based upon uncertainty about the outcome of investigations by FERC of western power markets. Moody's remains concerned about what conclusions will ultimately be drawn by FERC with respect to year 2000 sales in western power markets and what other steps they might take as the investigation runs its full course.


SHELF REGISTRATIONS, LONG-TERM DEBT AND COMMON STOCK ACTIVITY
        In February 2002,January 2004, 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 $500 million principal amount of:

common stock of Puget Energy,

and

senior notes of PSE, secured by a pledge of PSE'sPSE’s first mortgage bonds,

bonds.

unsecured debentures of        In March 2003, PSE and

trust preferred securities of Puget Sound Energy Capital Trust III.

        On November 5, 2002, Puget Energy sold 5.75 million shares of common stock in a public offering. The net proceeds of approximately $114.6 million were invested in PSE to reduce its debt. PSE is expected to refinancerefinanced $161.9 million of its Pollution Control Bonds seriesto lower the weighted average interest rate from 6.77% to 5.01%. In June 2003, PSE issued $150 million principal amount of senior notes. The proceeds of $149.1 million were used to repay debt. In November 2003, Puget Energy sold an additional 4.55 million shares of common stock. The proceeds of $100.1 million were invested in PSE and mainly used to repay debt and redeem high-cost preferred stock. During 2003, PSE redeemed the following long-term debt:


$49.8 million notes and junior subordinated debt of a subsidiary trust in February 2003 with interest rates ranging from 7.02% to 8.231%;
$20.0 million notes at an interest rate of 8.39% in March or April2003;
$60.0 million notes at interest rates ranging from 8.20% to 8.59% in May 2003;
$31.0 million notes at interest rates ranging from 6.23% to 7.19% in August 2003; and
$54.0 million notes at interest rates ranging from 6.20% to 6.40% in December 2003.

LIQUIDITY FACILITIES AND COMMERCIAL PAPER
        PSE's short-term borrowings and sales of commercial paper are used to provide working capital for the utility construction program.
         On December 23, 2002, PSE entered intohas a $250 million unsecured 364-day credit agreement with various banks which expires in June 2004 and a $150 million 3-yearthree-year receivables securitization program. These facilities replaced PSE's entire $375program which expires in December 2005. The receivables available for sale under the securitization program may be less than $150 million bank linedepending on the outstanding amount of creditPSE’s receivables which was scheduledfluctuate with the seasonality of energy sales to terminate on February 13, 2003.customers. At December 31, 2002,2003, PSE had available $400.0$250 million in the unsecured credit agreement and $39 million available from the receivables securitization facility (net of liquidity facilities,$111 million sold), which in part provide credit support for outstanding commercial paper and outstanding letters of $30.3credit. At December 31, 2003, there were no outstanding amounts under its commercial paper program and $0.5 million under the letters of credit, effectively reducing the available borrowing capacity under the liquidity facilities to $369.7$288.5 million.
        On May 27, 2003, Puget Energy entered into a $15 million, three-year credit agreement with a bank. Under the terms of the agreement, Puget Energy will pay a floating interest rate on borrowings based on the 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 will also pay a commitment fee on any unused portion of the credit facility. On May 30, 2003, Puget Energy borrowed $5 million under the credit agreement. The proceeds of the loan were invested in InfrastruX, which used the proceeds to acquire a construction services company in New Mexico.
        In June 2001, InfrastruX signed a three-year credit agreement with several banks to provide up to $150 million in financing. Puget Energy is the guarantor of the line of credit. In addition, InfrastruX'sInfrastruX’s subsidiaries have an additional $29.8$34.7 million in lines of credit with various banks. Borrowings available for InfrastruX are used to fund acquisitions and working capital requirements of InfrastruX and its subsidiaries. At December 31, 2002,2003, InfrastruX and its subsidiaries had outstanding loans of $144.0$150.9 million and letters of credit of $4.7 million, effectively reducing the available borrowing capacity under these lines of credit to $35.8$29.1 million.

STOCK PURCHASE AND DIVIDEND REINVESTMENT PLAN
        Puget Energy has a stock purchaseStock Purchase and dividend reinvestment planDividend Reinvestment Plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy'sEnergy’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 $15.5 million (721,340 shares) in 2003 compared to $16.9 million (801,205 shares) in 2002 compared2002.

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 $25.6 million (1,119,568 shares) in 2001. The decrease in the Stock Purchase and Dividend Reinvestment Plan from 2002 to 2001 was largely attributable to the reductiontime through these institutions as sales agents, or as principals. Sales of the common stock, dividendif 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 May 15, 2002 to a quarterly dividendthe New York Stock Exchange at market prices. In October 2003, Puget Energy sold 100,600 shares of $0.25 per share.common stock under its program with Cantor Fitzgerald & Company. Puget Energy received approximately $2.3 million in net proceeds from these sales.

RATE MATTERS - ELECTRIC
         On March 28, 2002, the Washington Commission approved and adopted an unopposed settlement stipulation to resolve the interim phase of the rate case, in order to allow $25 million in additional revenue to be recovered in rates over an approximate period of three months, commencing April 1, 2002. On June 6, 2002, the parties and intervenors to the general rate case filed a settlement stipulation for electric and common issues, which called for an electric general rate increase of $59 million annually. On June 20, 2002, the Washington Commission approved and adopted the settlement stipulation in the general case, putting new rates into effect on July 1, 2002. PSE established a PCA mechanism in the rate case settlement. The PCA mechanism will account for differences in PSE's modified actual power costs relative to a power cost baseline. The mechanism would account for a sharing of costs and benefits that are graduated over four levels of power cost variances, with an overall cap of $40 million (+/-) over the four year period July 1, 2002 through June 30, 2006. The factors influencing the variability of power costs included in the proposal are primarily weather or market related. PSE will be allowed to file for rate increases to implement limited power supply cost increases related to new resources. PSE’s share of the power costs through December 31, 2002 was $5.2 million. Because of adverse hydro conditions in 2003, PSE anticipates reaching the $40 million cumulative cap under the PCA mechanism by the fourth quarter of 2003. Under the PCA mechanism, further increases in variable power costs through June, 30, 2006 would be apportioned 99% to customers and 1% to PSE.


RATE MATTERS - GAS
        On August 29, 2001 the Washington Commission approved a decrease in PSE's natural gas rates of 8.9% due to lower natural gas costs purchased for customers under terms of the PGA mechanism effective September 1, 2001. Also, on May 24, 2002 the Washington Commission allowed a decrease in PGA rates of 21.2% to become effective on June 1, 2002. This ended a temporary surcharge that went into effect September 1, 2001. 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.
         On August 28, 2002, the Washington Commission approved a 5.8% gas service rate increase in revenue to cover higher costs of providing natural gas service to customers. This service-related increase in revenues of approximately $35.6 million annually was offset by an annual $45 million or 7.3% PGA rate reduction, also approved on August 28, 2002. On September 30, 2002, PSE filed a proposal with the Washington Commission to reduce natural gas supply rates under the PGA for the third time in 2002. The Washington Commission approved the proposal on October 30, 2002 and PSE lowered gas rates through the PGA by approximately 12.5% effective November 1, 2002.

PROCEEDINGS RELATING TO THE WESTERN POWER MARKET
        While PSE cannot predict the outcome of any of the individual ongoing proceedings relating to the western power markets, PSE generally is pleased that FERC appears to be narrowing the issues under review in the cases pending before it. The narrowing of issues allows PSE to compare the allegations in the various proceedings with PSE’s relevant records and to better anticipate the likely outcome of each case. In the aggregate, PSE does not expect the ultimate resolution of the issues and cases discussed below to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO) RECEIVABLE AND CALIFORNIA
        REFUND PROCEEDINGS

        PSE operates within the western wholesale market and made sales into the California energy market during the fourth quarter of 2000 through the CAISO. In 2001, PG&E and Southern California Edison defaultedAugust of 2000, San Diego Gas & Electric Company filed a complaint at FERC (Docket No. EL00-95) seeking price caps on payment obligations owed to various energy suppliers, including the CAISO. The CAISO in turn defaulted on its payment obligations to PSE and various other energy suppliers. On March 1, 2002, Southern California Edison paid its past due energy obligations tosold into the CAISO and various other parties; however, those funds were not used to pay the outstanding balanceCalifornia Power Exchange (PX) markets. The complaint also sought refunds of the CAISO obligations to PSE. PSE is continuing to pursue recovery of the CAISO receivable.
        On October 1, 2002, the CAISO determined a refund was due to PSE totaling $2.2 millionprices charged above any such caps put in connection with a FERC order of August 27, 2002 that determined parties that paid the CAISO transmission access charges for energy delivered into the CAISO's control area in calendar 2000 had been overcharged by the CAISO. PSE received $1.1 million of this refund on October 8, 2002, which was creditedplace. In response to the CAISO receivable, reducingcomplaint, after a number of orders that attempted to address the receivable balance recorded by PSE to $66.9 million. PSE hasCalifornia energy crisis in a bad debt reserve and a transaction fee reserve totaling $41.5 million in connection withvariety of manners, FERC issued an Order on June 19, 2001 that imposed caps on prices beginning the CAISO receivable, such that the net receivable at December 31, 2002 was $25.4 million. The balance of the refund has not been paid by the CAISO.next day.
        On July 25, 2001, FERC ordered an evidentiary hearing (Docketin Docket No. EL00-95)EL00-95 to determine the amount of refunds due to California energy buyers, including the CAISO, for purchases made in the spot markets operated by the CAISO during the period October 2, 2000 through June 20, 2001. Hearings on the FERC California refund proceeding commenced in August 2002 in San Francisco, California, and concluded in Washington, DC in September 2002.
On December 12, 2002, the Administrative Law Judge conducting the hearings issued his certification of proposed findings on California refund liability to FERC. The certification includes an appendix that reflects what the Administrative Law Judge labeled as "ballpark"“ballpark” estimates of amounts owed and owing. (The Judge did not make exact findings, because the report contemplates further calculations by the CAISO.) The report also enters various findings within the text of the opinion, but those findings are not reflected in the appendix. The appendix indicates that the net cash position as of March 2002 for PSE would be an amount due to PSE of $61.9 million, and the refund PSE would owe to the CAISO would be $26.3 million--making a net receivable for PSE of $35.6 million. The appendix calculations did not include, however, two stipulations and/or findings from the body of the opinion that excluded certain PSE transactions from refund liability, primarily because they were not "spot market" transactions. Applying those stipulations would reduce the refund PSE would owe by $6.4 million, and make the net PSE receivable approximately $42.0 million. The certification also statesstated that the amounts owing should be adjusted for interest, a calculation the Administrative Law Judge did not make. FERC has expressed an intention to act on the Administrative Law Judge's certification--and any other submissions in the docket, as discussed below--in the spring of 2003. The projected schedule for resolution of the refund proceedings could change significantly, however, if FERC were to adopt changes in the refund methodology employed during the hearings, as proposed in the FERC's Staff's report discussed below.
        The FERC Staffstaff issued a report in August 2002 (Docket No. PA02-2) that, among other things, recommendsrecommended that FERC modify the methodology for calculating refunds in the California refund proceeding (Docket No. EL00-95) by adopting, as a proxy for the cost of natural


gas, producing basin spot prices plus transportation costs, instead of reported spot prices for natural gas at California delivery points. If adopted as proposed, thisThis methodology of calculating the cost of natural gas would reducefurther reduced the amount owed by the CAISO to PSE for sales made during 2000 and 2001. PSE's estimates indicate that the changes in methodology would reduce PSE's net receivable to approximately $18 million (as compared to the $42.0 million, calculated by the Administrative Law Judge). The current net receivable recorded by PSE is $23.6 million. The CAISO receivable range including the effects of the CAISO refund and estimates of the gas price adjustment, including interest is $25.4between $23.6 million and $34.2 million.
        On August 13, 2002, FERC issued a notice (Docket No. EL00-95) requesting comments on: (1) whether the method used to determine the cost of natural gas for the refund calculation in the California refund proceeding should be modified; (2) whether the FERC Staff's substitute method is appropriate and, if not, what method should be used; and (3) what is the proper way to reflect the effects of scarcity on price. PSE jointly sponsored testimony and filed comments in opposition to the recommendations in the FERC Staff's report on October 15, 2002. The issue remains pending before FERC and no schedule for decision has been announced.
        On November 20, 2002, FERC issued an Order on Motion for Discovery Order in theDocket No. EL00-95 docket that granted a motion to allow parties to "adduce"“adduce” additional evidence into the refund proceedings "that“that is either indicative or counter-indicative of market manipulation." The order also authorized an appointment of an Administrative Law Judge as a discovery master, and permitspermitted the parties to conduct discovery and file any such evidence "no later than February 28, 2003." On February 10, 2003 FERC issued an order on "clarification" that provides for reply submissions by any party on or before March 17, 2003. Like the November 20 discovery order, the February 10 order expressly states that the Commission intends to "finalize the issues in these dockets expeditiously" and observes that the Commission sees "no need for additional discovery procedures following the February 28, 2003 submission of evidence." On February 24, 2003, FERC extended the filing deadlines towith FERC. In their March 3, 2003 for the initial submissions and March 20, 2003 for replies, due to the east coast blizzard. In the March 3 filing, by the California parties they reiterated their allegations of market manipulation against PSE and approximately 60 other companies. PSE and the other parties are expected to respondresponded on March 20, 2003.
        On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95 that substantially adopted the recommendations that the Administrative Law Judge made on December 12, 2002, except that the Order also substantially adopted the FERC staff gas price recommendation made in its August 2002 report. On October 16, 2003, FERC issued an Order on Rehearing that largely left the refund calculation methodologies established by the March 26, 2003 Order unchanged. The Order on Rehearing gives the CAISO a deadline to perform its “cost re-runs” (which are expected to establish actual amounts owing and owed) of five months from October 16, 2003. In February 2004, however, FERC issued an order giving the CAISO an indefinite period of time to complete its cost re-runs, subject to the CAISO filing monthly reports of its progress and its expected completion dates. The CAISO’s current estimates are that it will be unable to complete the cost re-run process any earlier than August 2004. Until the CAISO completes its cost re-run process, little other activity can take place in the FERC docket.
        The March 26, 2003 Order on Proposed Findings on Refund Liability also permitted generators to make a filing to recover actual fuel costs that exceeded the calculated proxy price under the staff methodology. PSE made such a filing on May 12, 2003. The California parties objected to all fuel cost filings on May 21, 2003. The Order on Rehearing issued on October 16, 2003 postpones resolution of this issue, so PSE’s application for fuel cost recovery remains pending.
        The Order on Rehearing issued on October 16, 2003 also expressly adopted and approved a stipulation that confirmed that two PSE “non-spot-market” transactions were not subject to refund. The total gross revenue associated with the transactions is approximately $26.0 million. On October 17, 2003, PSE sent a demand letter to the CAISO seeking payment of the amount due. The CAISO responded to the letter with its own letter of November 14, 2003, expressing an unwillingness to take the issue up separately or in advance of its “cost re-run” activities. PSE has not yet formally responded to that letter.
        Because of the numerous orders FERC has issued in Docket No. EL00-95 over a period of more than three years, more than 80 appeals from the proceeding have already been lodged with the U.S. Ninth Circuit Court of Appeals. The Ninth Circuit’s usual practice has been to consolidate those appeals as they are filed, and hold the appellate proceedings in abeyance pending a final determination by FERC of the issues before it. PSE has no ability to predict how soon the Ninth Circuit may choose to take up these matters for consideration on their merits, but the California parties have attempted to initiate a more active review from time to time. It is likely that the case will not be finally resolved before formal appellate review.

CALIFORNIA RECEIVABLE
        In 2001, PG&E and Southern California Edison defaulted on payment obligations owed to various energy suppliers, including the CAISO and the California PX. The CAISO in turn defaulted on its payment obligations to PSE and various other energy suppliers. The California PX itself filed bankruptcy in 2001, further constraining PSE’s ability to receive payments due to controls placed on the California PX’s distribution of funds by the California PX bankruptcy court and due to the fact that the vast majority of funds owed directly to the CAISO are owed by the California PX. In addition, the California PX’s inverse condemnation action against the State of California may influence the delivery of funds to energy sellers such as PSE. PSE has a bad debt reserve and a transaction fee reserve applied to the CAISO receivables, such that the net receivable at December 31, 2003 was $23.6 million. On March 1, 2002, Southern California Edison paid its past due energy obligations to the CAISO, the California PX and various other parties; however, those funds were not used to pay the outstanding balance of the CAISO obligations to PSE.
        In summary, the developments in the California Refund Proceeding described in the above section have the likely effect of reducing PSE’s gross receivable balance due from the CAISO to an amount approximately equivalent to collecting payment on the two “non-spot-market” transactions removed from the Refund Proceeding. PSE is attempting early collection of proceeds associated with those sales while recognizing that the ultimate resolution of the Refund Proceeding may be more distant in the future. PSE anticipates that the net results of the CAISO cost re-runs and the application of the refund calculations will extinguish or offset the CAISO receivable apart from the balance associated with the two “non-spot-market” transactions. PSE is continuing to pursue recovery of the CAISO receivable.

PACIFIC NORTHWEST REFUND PROCEEDING
        In October 2000, PSE filed a complaint at FERC (creating Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC supplied for the California markets. FERC dismissed PSE’s complaint on December 15, 2000, although PSE filed for rehearing in January 2001. When FERC issued its June 19, 2001 Order in Docket No. EL00-95, imposing west-wide price constraints on energy sales, PSE moved to withdraw its rehearing request and its complaint in the EL01-10 Docket, on the basis that the relief PSE sought was fully provided. Various parties, including the Port of Seattle and the cities of Seattle and Tacoma, moved to intervene in the proceeding. They asserted the ability to adopt PSE’s complaint to obtain retroactive refunds for numerous transactions, including many that were not within the scope of the PSE complaint. The proceeding became commonly referenced as the “Pacific Northwest Refund Proceeding,” despite the fact that the original complainant, PSE, did not seek retroactive refunds. A preliminary evidentiary hearing was held in September 2001, and an Administrative Law Judge recommendation against refunds followed. In December 2002, FERC issued an order permitting additional discovery and the submission of any additional evidence (parallel to the order issued in the California Refund Proceeding) that reopened the matter to permit parties to introduce any evidence they claimed to have of market


manipulation. A few parties made filings, asserting market manipulation in early March 2003, and numerous parties, including PSE, responded to those allegations in late March 2003. On June 25, 2003, FERC issued an order terminating the proceeding, largely on procedural, jurisdictional and equitable grounds. Various parties filed rehearing requests on July 25, 2003. On November 10, 2003, FERC denied the rehearing requests, and the matter has now been appealed to the Ninth Circuit Court of Appeals. PSE has filed its own appeal, on the basis that it had an absolute right to withdraw the complaint before any other party intervened. The California parties also sought rehearing on one new issue decided in the November 10, 2003 order, which request was denied by FERC on February 9, 2004. It is expected that all appeals from this proceeding will be consolidated and resolved together.

ORDERS TO SHOW CAUSE
        On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers. One show cause proceeding seeks to investigate approximately 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order, and in an order dismissing many of the already-named respondents in the “partnerships” proceedings on January 22, 2004, FERC stated that they had determined not to proceed further against other parties. Accordingly, PSE does not expect to be named in the case.
        The second show cause proceeding investigated approximately 55 entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE is one of the entities named in the “gaming” show cause order (Docket No. EL03-169). On July 16, 2003, CAISO provided data to FERC in connection with the “gaming” show cause order that indicated that, under the standards adopted by FERC in the June 25, 2003 orders, CAISO’s previously reported claims against PSE as to “ricochet” transactions completely disappear. Consistent with the show cause orders’ invitation to attempt settlement, PSE and FERC staff filed a settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement admits no wrongdoing on the part of PSE, but would result in the payment of $17,092 to settle all claims. The California parties and a few others filed oppositions to PSE’s settlement (and all others) on September 30, 2003. PSE replied to those arguments on October 20, 2003. The presiding Administrative Law Judge certified and recommended the PSE settlement to FERC on November 18, 2003. In January 2004, FERC issued an Order Approving Contested Settlement Agreement that finds PSE’s settlement to be in the public interest. On February 23, 2004, motions for rehearing were filed by the Port of Seattle and the California parties (the California Attorney General, the California Public Utilities Commission, the California Electricity Oversight Board, PG&E and Southern California Edison). PSE continues to believe that the orders to show cause do not raise new issues or concerns nor will they have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

ANOMALOUS BIDDING INVESTIGATION
        On June 25, 2003, FERC issued an order commencing a new investigatory proceeding, Docket No. IN03-10, to be conducted through its Office of Market Oversight and Investigations (OMOI). That docket is to review each seller’s bids into the CAISO or California PX markets that exceeded $250/MWh during the period of May 1, 2000 to October 1, 2000. The OMOI is to determine if each such entity’s bids show a pattern or an effort to manipulate the market, and if they do, to consider whether the entity should be required to disgorge any improper profits earned as a result of such patterns or efforts. PSE received a data request from the OMOI in this proceeding about its bids and responded on July 24, 2003. PSE has not received further information requests since responding. There is no established timetable for this proceeding, but FERC has indicated that it expects to work diligently to review the practices of each seller and to resolve the matter expeditiously. PSE does not expect any material adverse impacts on the financial condition of the Company from this FERC investigation.

PORT OF SEATTLE SUIT
        On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle, Washington against 22 energy sellers into the California market, alleging that the conduct of those sellers during 2000 and 2001 constituted market manipulation, violated antitrust laws and damaged the Port of Seattle, which had a contract to purchase its complete energy supply from PSE at the time. The Port’s contract with PSE linked the price of the energy sold to the Port to an index price for energy sold at wholesale at the Mid-Columbia trading hub. The Port alleged that the Mid-Columbia price was intentionally affected improperly by the defendants, including PSE. PSE moved to dismiss this case; other defendants moved to transfer the matter to a multi-district litigation panel in California. A conditional transfer order was issued in July 2003. After further proceedings before the judicial panel on multi-district litigation, an order transferring the case to the Southern District of California was entered on December 15, 2003. PSE’s motion to dismiss remains pending and is scheduled to be heard on March 26, 2004 in San Diego, California. PSE does not expect any material adverse impacts on the financial condition of the Company from this matter.

CALIFORNIA 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 Federal Power ActFPA by FERC and all sellers (including PSE) of electric power and energy into California. The complaint asserted that FERC'sFERC’s adoption and implementation of market rate authority was flawed and, as a result, that individual sellers such as PSE were liable for sales of energy at rates that were "unjust“unjust and unreasonable." The condition for dismissal was that all sellers re-filerefile 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 re-filedrefiled such transaction summaries on July 1 and July 8, 2002. The order of dismissal is now on appeal to the Ninth Circuit Court of Appeals.
        On the same day as FERC'sFERC’s order of dismissal in Docket No. EL02-71 was entered, the California Attorney General announced it had filed individual complaints against a number of sellers, including PSE, in California Superior Court in San Francisco. That complaint allegesalleged that PSE'sPSE’s sales to California violated the requirements of the Federal Power ActFPA and that, as such, the sales also violated certain sections of the California Business Practices Act forbidding unlawful business practices. The complaint assertsasserted that each such "violation"“violation” subjects PSE to a fine of up to $2,500 plus an award of attorneys'attorneys’ fees and asserts that there were "thousands"“thousands” of such violations. PSE has removed that suit to federal court and has


moved to dismiss it on the grounds that the issues are within the exclusive or primary jurisdiction of FERC. ThatOn March 25, 2003, the court granted the motion was arguedfor dismissal. The order of dismissal is now on September 26, 2002 and the question is under submissionappeal to the judge.Ninth Circuit Court of Appeals. PSE does not expect any material adverse impacts on the financial condition of the Company from these matters.

CALIFORNIA CLASS ACTIONS
        During May 2002, PSE was served with two cross-complaints, by Reliant Energy Services and Duke Energy Trading & Marketing, respectively, in six consolidated class actions pending in Superior Court in San Diego, California. The original complaints in the action, which were brought by or on behalf of electricity purchasers in California, allege that the original (approximately 40) defendants manipulated the wholesale electricity markets in violation of various California Business Practices Act or Cartwright Act (antitrust) provisions. The 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 assert essentially that the cross-defendants, including PSE, were also participants in the energy market in California at the relevant times, and that any remedies ordered against some market participants should be ordered against all. Reliant Energy Services and Duke Energy Trading & Marketing also seek indemnity and conditional relief as a buyer in transactions involving cross-defendants should the plaintiffs prevail. Those cross-complaints added over 30 new defendants, including PSE, to litigation that had been pending since 2000 and had been set for trial in state court. Some of the newly added defendants removed the litigation to federal court. The federal court in San Diego remanded the case to the California Statestate court in an order issued in December 2002. PSE and numerous other defendants added by the cross-complaints have moved to dismiss these claims. Those motions were argued on September 19, 2002, but the federal judge did not rule on those motions in his order remanding the case to state court. The remand order is now being reconsidered. PSE and the other defendants that moved to dismiss the claims intend to submit their motion to the appropriate court at the earliest practical date. As a result of the various motions, no trial date is set at this time.


OTHER PROCEEDINGS
         On May 8, 2002, FERC issued PSE does not expect the ultimate resolution of these matters to have a data request concerning specific trading strategies described in memos prepared by Enron Corporation to all sellers, including PSE,material adverse impact on the financial condition, results of wholesale electricity and/operations or ancillary services to the CAISO and/or the California Power Exchange Corporation during the years 2000-2001. On May 21 and May 22, 2002, FERC issued additional data requests to all sellers of wholesale electricity or natural gas in the western United States, including PSE, concerning "wash" or "roundtrip" trading activities. Eachliquidity of the three requests required the sellers to respond with an affidavit concerning the seller's use or knowledge of various trading practices identified in the request. In response to the data requests, PSE conducted a review of its activities and informed FERC that it did not engage in the trading activity described in the applicable request.
        In October 2002, PSE provided information in response to a request by the U.S. Commodity Futures Trading Commission (CFTC) for information about a limited number of specific transactions with regional counterparties which have been the subject of an investigation by the CFTC. PSE's own review of these trades concluded that all the transactions were lawful and served normal business purposes. In January 2003, PSE was asked to provide additional information to the CFTC, primarily concerning the results of any PSE internal investigation as to its trading activities and reports to indices. PSE responded to that request by providing information in February 2003.
        In December 2002, PSE was named as one of more than 30 defendants in two class actions, one filed in the federal district court in Seattle and the other in Multnomah County Circuit Court in Oregon. PSE was served with the complaint and summons in the Washington federal court case on February 3, but as of March 7, 2003 had not been served in the Oregon case. Nonetheless, the Oregon case was removed to Oregon federal court by Reliant Energy Services on February 5, 2003. The complaints allege that they are brought on behalf of all retail customers in Washington and Oregon, respectively, and seek relief against the defendants (each of which is a seller of electric energy at wholesale in certain markets) for "unfair or deceptive acts," "fraud by concealment," negligence and for an accounting. No specific amounts of damages are pled in the complaints.
         PSE cannot predict the outcome of any of these ongoing proceedings relating to the western power markets, or whether the ultimate impact on PSE will be material.Company.

OTHER
        On October 2, 2002, the United Association of Plumbers and Pipefitters ratified with PSE a new four-year collective bargaining agreement. Effective dates for the new contract are October 1, 2002 to October 1, 2006. The contract covers approximately 300 PSE employees. In addition, on December 3, 2002, the International Brotherhood of Electrical Workers ratified an agreement to extend their collective bargaining agreement with PSE through March 31, 2007. This contract covers approximately 800 PSE employees.
         On July 31, 2002, FERC issued its Notice of Proposed Rulemaking on Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The SMD NOPR would have major implications for the delivery of electric energy throughout the U.S if enacted in its proposed form. Major elements of FERC's proposal include: (a) the use of Network Access Service to replace the existing network and point-to-point services. All customers, including load-serving entities on behalf of bundled retail load, would be required to take network service under a new pro forma tariff; (b) Vertically integrated utilities would be required to retain Independent Transmission Providers to administer the new tariff and functionally operate transmission systems; (c) The formation of Regional State Advisory Committees and other regional entities to coordinate the planning, certification and siting of new transmission facilities in cooperation with states. State regulators and industry representatives have pointed out that the Western North American electricity market has unique characteristics that may not readily lend itself to the Standard Market Design proposed by FERC. FERC has expressed its willingness to offer regional flexibility in its order on RTO West, Docket Nos. RT01-35-005 and RT01-35-007, Issued September 18, 2002. On December 20, 2002, FERC issued a Notice extending the deadline for comments addressing market design for the Western Interconnection to February 18, 2003, but the notice also indicates FERC "will accept late-filed comments through February 28, 2003." The Company has filed comments.


CRITICAL ACCOUNTING POLICIES
        The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain:uncertain.

REVENUE RECOGNITION
        Utility revenue is recognized when the basis of service is rendered, including estimates used for unbilled revenue. Unbilled kWh are determined by taking kWh generated and purchased less billed kWh and estimated system losses. The estimated system losses are determined by reviewing historical billed kWh to generated and purchased kWh. This amount is then multiplied by the estimated average revenue per kWh. Non-utility revenue is recognized when services are performed, or upon the sale of assets.assets, or on a percentage of completion basis for fixed-price contracts. The recognition of revenue is in conformity with Generally Accepted Accounting Principles, which requires the use of estimates and assumptions that affect the reported amounts of revenue.

FERCREGULATORY ACCOUNTING
        Puget Energy'sEnergy’s regulated subsidiary, PSE, prepares its financial statements in accordance with Generally Accepted Accounting Principlesthe provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and in conformity with FERC'sFERC’s uniform system of accounts. The Washington Commission also requires PSE to use FERC'sFERC’s uniform system of accounts.

COST BASED REGULATION
         Puget Energy's The reason PSE prepares its financial statements in accordance with SFAS No. 71 is that its rates and tariffs are regulated subsidiary, PSE, is subject to regulation by the Washington Commission and FERC. The rates that are charged by PSE to its customers are based upon cost base regulation reviewed and approved by these regulatory commissions. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities in the amount of $483.7$461.8 million and $406.1 million as of December 31, 2002.2003 and 2002, respectively. If at some point in the future Puget Energy determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to PSE, Puget Energy could be required to write off its regulatory assets and liabilities.

DERIVATIVES
        Puget Energy uses derivative financial instruments primarily to manage its commodity price risks. Derivative financial instruments are accounted for under Statement of Financial Accounting Standards (SFAS)SFAS No. 133, - "Accounting“Accounting for Derivative Instruments and Hedging Activities",Activities,” as amended by SFAS No. 138.138 and SFAS No. 149. Accounting for derivatives continues to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the Financial Accounting Standards Board. To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change.
        To manage its electric and gas portfolios, Puget Energy enters into contracts to purchase or sell electricity and gas. These contracts are considered derivatives under SFAS No. 133 unless a determination is made that they qualify for normal purchases and normal sales exclusion. If the exclusion applies, those contracts are not marked-to-market and are not reflected in the financial statements until delivery occurs.
        The availability of the normal purchases and normal sales exclusion to specific contracts is based on a determination that a resource is available for a forward sale and similarly a determination that at certain times existing resources will be insufficient to serve load. This determination is based on internal models that forecast customer demand and generation supply. The models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice, and resource availability. The critical assumptions used in the determination of normal purchases and normal sales are consistent with assumptions used in the general planning process.
        Energy contracts that are considered derivatives may be eligible for designation as cash flow hedges. If a contract is designated as a cash


flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of derivatives not designated as cash flow hedges is recorded in current period earnings.
        When external quoted market prices are not available for derivative contracts, PugetPSE uses a valuation model which uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.

GOODWILL AND INTANGIBLES (PUGET ENERGY ONLY)
        On January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result Puget Energy ceased amortization of goodwill. During 2001, Puget Energy recorded approximately $2.8 million of goodwill amortization. Puget Energy performs an annual impairment review to determine if any impairment exists. In performing the goodwill impairment test, Puget Energy compares the present value of the future cash flows of InfrastruX with recorded equity. If goodwill is determined to have an impairment, Puget Energy will record in the period of determination an impairment charge to earnings.
        Intangibles with finite lives are amortized on a straight-line basis over the expected periods to be benefited. The Company believes thatgoodwill and intangibles recorded on the riskbalance sheet of non-performancePuget Energy are the result of acquisition of companies by its counterparties is remote.InfrastruX.


DEFINED BENEFIT PENSION PLAN
        Puget Energy has a qualified defined benefit pension plan covering substantially all employees of PSE. For 2003, 2002 2001 and 20002001 qualified pension income of $12.9 million, $17.7 million and $20.0 million, and $16.6 million, respectively, has beenwas recorded in the financial statements. Of these amounts, approximately 67.0%, 66.8% and 58.0% offset utility operations and maintenance expense in 2003, 2002 and 2001, respectively, and the remaining amounts were capitalized. Changes in market values of stocks or interest rates will affect the amount of income that Puget Energy can record in its financial statements in future years. Qualified pension income is expected to decline to $9.6$8.6 million in 20032004 as a result of lower actual returns on pension assets during the last three years and declining expected rates of return on pension fund assets. During 2003, PSE made a cash contribution to the qualified defined benefit plan of $26.5 million and is not expected to make a cash contribution to this qualified plan in 2004.

STOCK-BASED COMPENSATION
        During 2002, PSE transitioned 462 service jobs that had previously been heldThe Company has various stock-based compensation plans which prior to 2003 were accounted for according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by PSE employees to outside service providers. Under SFAS No. 88 "Employers' Accounting123, “Accounting for SettlementsStock-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 CurtailmentsDisclosure.” The Company will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of Defined Benefit Pension Plans and for Termination Benefits," PSE recorded a curtailment loss of approximately $0.3 million.APB No. 25.

CALIFORNIA INDEPENDENT SYSTEM OPERATOR RESERVE
        PSE operates within the western wholesale market and has made sales into the California energy market. DuringAt December 31, 2000, PSE’s receivables from the first quarterCAISO and other counterparties, net of 2001,reserves, were $41.8 million. PSE received the majority of the partial payments for sales made in the fourth quarter of 2000.2000 in the first quarter of 2001 and has since received a small amount of payments. At December 31, 2000, PSE's receivables from the CAISO and other counter-parties, net of reserves, were $41.8 million. At December 31, 2002,2003, such receivables, net of reserves, were approximately $25.4$23.6 million. The Company calculated
        During 2003, FERC issued an order in the reserve basedCalifornia Refund Proceeding adopting in part and modifying in part FERC’s earlier findings by the Administrative Law Judge. Based upon estimated credit quality and collection from the CAISOorder, PSE has determined that the receivables balance at December 31, 2002.2003 is collectible from the CAISO. See "Proceedings“Proceedings Related to the Western Power Market"Market” under Management'sManagement’s Discussion and Analysis of Financial Condition and Results of OperationOperations for further discussion.

NEW ACCOUNTING PRONOUNCEMENTS
        In January 2003, Financial Accounting Standards Board issued Interpretation No. 46 - "Consolidation of Variable Interest Entities" (FIN 46). FIN 46, clarifieswhich was further revised in December 2003 with FIN 46R, clarified the application of Accounting Research Bulletin No. 51, - "Consolidated“Consolidated Financial Statements"Statements,” to certain entities in which equity investors do not have controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. This InterpretationFIN 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 adoption of this InterpretationFIN 46R for all interests in variable interest entities created after January 31, 2003 is effective immediately. For variable interest entities created before February 1, 2003, it is effective July 1, 2003. The Company ishas evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance, and therefore it was consolidated in the processthird quarter of determining2003. As a result, revenues for 2003 increased $5.7 million, while conservation amortization and interest expense increased by the impactscorresponding amount with no impact on earnings. At December 31, 2003, the balance sheet assets and liabilities increased by $4.2 million. FIN 46R also impacted the treatment of this Interpretation.the Company’s mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities (junior subordinated debt) in the fourth quarter of 2003. This change had no impact on the Company’s results of operations for 2003. The Company is evaluating its purchase power agreements and any other agreements to determine if FIN 46R will have an impact on the financial statements.
        On January 1, 2002,In May 2003, the FASB issued SFAS No. 142, "Goodwill150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes the requirements for classifying and measuring as liabilities certain financial instruments that embody


obligations to redeem the financial instruments by the issuer. The adoption of SFAS No. 150 is effective with the first fiscal year or interim period beginning after June 15, 2003. However, on November 5, 2003, the FASB deferred for an indefinite period certain mandatorily redeemable noncontrolling interests associated with finite-lived subsidiaries. The Company does not have any noncontrolling interest in finite-lived subsidiaries and, therefore, is not affected by the deferral. Prior periods are not restated for the new presentation.
        SFAS No. 150 requires the Company to classify its mandatorily redeemable preferred stock as liabilities. As a result, the corresponding dividends on the mandatorily redeemable preferred stock are classified as interest expense on the income statement with no impact on income for common stock.
        In December 2003, SFAS No. 132, “Employers’ Disclosures about Pensions and Other Intangible Assets" becamePostretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective and as a result, Puget Energy ceased amortization of goodwill associated with the InfrastruX business. During 2001, Puget Energy had approximately $2.8 million of goodwill amortization. Puget Energy performed an initial impairment review of goodwill and will perform an annual impairment review thereafter. The initial review was completed during the first half of 2002, and did not result in an impairment charge. Puget Energy then performed its annual impairment review as of October 31, 2002 and determined that its goodwill was not impaired.for fiscal years ending after December 15, 2003.
        In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting“Accounting for Asset Retirement Obligations," which is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company will adoptadopted the new rules on asset retirement obligations on January 1, 2003. ApplicationAs a result, the Company recorded a $0.2 million charge to income for the cumulative effect of this accounting change. In addition, the new rules is not expectedCompany reclassified $124.9 million and $114.6 million in 2003 and 2002, respectively, from accumulated depreciation to result in a material increase in net property, plant and equipment or expense.


regulatory liability.
        The Emerging Issues TaskTax Force of the Financial Accounting Standards Board (EITF or Task Force)(EITF) at its June 2002July 2003 meeting came to a consensus on one of three items included inconcerning EITF Issue 02-3 "AccountingNo. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Contracts InvolvedTrading Purposes as Defined in Energy Trading and Risk Management Activities" (EITF 02-3).Issue No. 02-03.” The Task Force has agreedconsensus reached was that all mark-to-marketdetermining whether realized gains and losses on energyphysically settled derivative contracts not held for trading contracts whether realized or unrealized will be shown netpurposes reported in the income statement (costs offset against revenues), irrespectiveon a gross or net basis is a matter of whetherjudgment that depends on the contract is physically settled. The presentation will be applicable to financial statements for periods ending after July 15, 2002. The Company performs risk management activities to optimizerelevant facts and circumstances. Based on the value of energy supply and transmission assets and to ensure that physical energy supply is available to meet the customer demand loads. The Company also purchases energy when demand exceeds available suppliesguidance in its portfolio; likewiseEITF No. 03-11, the Company makes sales to other utilitiesdetermined that its non-trading derivative instruments should be reported net and marketers when surplus energy is available. These transactions are part of the Company's normal operations to meet retail load. The Company has reclassified all settled transactions that meet the definition of optimization (trading transactions that optimize hydro resources, and purchases and sales between trading points) net in the income statement to conform to the new presentation required under EITF 02-3. The Company previously reported these transactions when settled in a gross manner in the income statement in electric operatingimplemented this treatment effective January 1, 2004. Consequently, revenue and purchased electricity expense. Unrealized gains or losses onwill be reduced as a result of netting any non-trading derivative instruments that are required to be marked-to-market remain reflected in unrealized (gain) loss on derivative instruments on Puget Energy's and PSE's income statement as required by SFAS No. 133. The adoption ofmeet the EITF 02-3 does not have any impact on the previously reported net income of the Company. The following optimization transactions were recorded in electric operating revenue:03-11 criteria.

Years Ended December 31; (Dollars in thousands)   2002  2001  2000 




 Optimization sales  $66,992 $492,447 $133,361 
 Optimization purchases   64,448  487,431  139,376 



  Net margin on optimization transactions  $2,544 $5,016 $(6,015)



ITEM 7A.7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        The Company is exposed to market risks, including changes in commodity prices and interest rates.

PORTFOLIO MANAGEMENT
        The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted resources does exposeexposes the Company and its customers to some volumetric and commodity price risks.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:

(i)Ensure that physical energy supplies are available to serve retail customer requirements;
(ii)Manage portfolio risks to limit undesired impacts on the Company’s financial results and to stabilize earnings; and
(iii)Optimize the value of the Company’s energy supply assets.
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 portfolio is subject to major sources of variability (e.g., hydro 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; at other times they can exacerbate portfolio imbalances.
        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 secondthird priority is to fully optimize excess capacity or flexibility within the wholesale portfolio. Most hedges can be implemented in ways that retain the Company’s ability to use its energy supply optimization opportunities. Still otherOther hedges are structured similarly to insurance instruments, where PSE pays an insurance premium to protect against certain extreme conditions.
        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 has oversight of the Risk Management Committee.
        The prices of energy commodities are subject to fluctuations due to unpredictable factors including weather, generation outages and other factors which impact supply and demand. The volumetric and commodity price risk is a consequence of purchasing energy at fixed and variable prices and providing deliveries at different tarifftariffs and variable prices. Costs associated with ownership and operation of production facilities are another component of this risk. The Company may use forward physical delivery agreements swaps and option contractsfinancial derivatives for the purpose of hedging commodity price risk. Without jeopardizing the security of supply within its portfolio, the Company will also engage in optimizing the portfolio. Optimization may take the form of utilizing excess capacity, shaping flexible resources to capture their highest value, utilizing transmission capacity or capitalizing on market price movement. As a result, portions of the Company’s energy portfolio are monetized through the use of forward price instruments.
        The regulatory mechanisms of the PGA and the PCA mitigate the impact of commodity price volatility upon the Company. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. 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.


        Transactions that qualify as hedge transactions under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, 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 upon 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 December 31, 2002,2003, the Company had an after-tax net liabilityasset of approximately $7.5$16.2 million of energy contracts designated as qualifying cash flow hedges and a corresponding unrealized gain recorded in other comprehensive income. Of the amount in other comprehensive income.income, 99% has been reclassified out of other comprehensive income to a deferred account due to the Company reaching the $40 million cap under the PCA mechanism. The Company also had energy contracts that were marked-to-market at a loss through current earnings for 20022003 of $7.5 million after-tax.$0.1 million. 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 $5.2 million after-tax and would reduceincrease current earnings for those contracts marked-to-market in earnings by an immaterial amount. In addition, the Company believes its PCA and the PGA mechanism mitigate a portion of this risk.
        Market risk is managed subject to parameters established by the Board of Directors. The Company has established a Risk Management Committee composed of Company officers that monitors compliance with the Company’s policies and procedures. In addition, the Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.
        The fair value of energy contracts that are recorded in the balance sheet of the Company are comprised of the following (net of tax):

Derivative Contracts (Dollars in millions)   Amounts 

 Fair value of contracts outstanding December 31, 2001  $(35.4)
 Contracts realized or otherwise settled during 2002   39.9
 Changes in fair values of derivatives   6.7

  Fair value of contracts outstanding at December 31, 2002  $11.2



 Fair Value of Contracts with Settlement During Year
Source of Fair Value (Dollars in millions)
2003
2004-2005
2006-2007
2008 and
Thereafter

Total fair
value

Prices based on models and other valuation methods $   1.3$   4.9$   4.1$   0.9$    11.2

DERIVATIVE CONTRACTS (DOLLARS IN MILLIONS)
Amounts
Fair value of contracts outstanding December 31, 2002  $11.2
Contracts realized or otherwise settled during 2003   (1.4)
Changes in fair values of derivatives   2.8
 
Fair value of contracts outstanding at December 31, 2003  $12.6
 
 Fair Value of Contracts with Settlement During Year
SOURCE OF FAIR VALUE (DOLLARS IN MILLIONS)
2004
2005-2006
2007-2008
2009 and
Thereafter

Total fair
value

Prices based on models and other valuation methods  $4.0$6.3$2.3$-- $12.6

        Short-term derivative contracts for the purchase and sale of electricity are valued based upon daily quoted prices from an independent energy brokerage service. Values for short-term and medium-term natural gas swap contracts are derived from a combination of quotes from several independent energy brokers and are updated daily. Long-term gas swap contracts are valued based on published pricing from a combination of independent brokerage services and are updated monthly. Option contracts are valued using a modified Black-Scholes model approach.

INTEREST RATE RISK
        The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate 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 does utilizeutilizes bank borrowings, commercial paper, and line of credit facilities and accounts receivable securitization to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments to manage the interest rate risk associated with these debts anddebts. The Company did not have any swap instruments outstanding as of December 31, 20022003 or 2001.2002. The carrying amounts and fair values of Puget Energy’s fixed-rate debt instruments are:

(Dollars in millions) 2002
CARRYING
AMOUNT
2002
FAIR
VALUE
2001
CARRYING
AMOUNT
2001
FAIR
VALUE

  Financial liabilities: 
    Short-term debt $         47.3$     ��   47.3$       348.6$       348.6
    Long-term debt 2,223.02,381.82,246.72,131.2


 2003
2002
(DOLLARS IN MILLIONS)
CARRYING
AMOUNT

FAIR
VALUE

CARRYING
AMOUNT

FAIR
VALUE

  Financial liabilities:      
    Short-term debt $         13.9$         13.9$         47.3$         47.3
    Long-term debt 2,216.32,385.32,237.12,395.9

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

        See index on page 64.

ITEM 9.9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
              AND FINANCIAL DISCLOSURE

        None.


ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
        Under the supervision and with the participation of Puget Energy’s and PSE’s management, including the Companies’ President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy and PSE have evaluated the effectiveness of the Companies’ disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer of Puget Energy and PSE concluded that these disclosure controls and procedures are effective.

CHANGES IN INTERNAL CONTROLS
        There have been no significant changes in Puget Energy’s or PSE’s internal control over financial reporting during the quarter ended December 31, 2003 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s or PSE’s internal control over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

PUGET ENERGY
        The information required by Part IIIthis item with respect to Puget Energy is incorporated herein by reference to the material under “Available Information” in Part I of this report and “Proposal — Election of Directors,” “Directors Continuing in Office”, “Board of Directors and Corporate Governance” and “Security Ownership of Directors and Executive Officers — Section 16(a) Beneficial Ownership Reporting Compliance” in Puget Energy’s proxy statement for its 20032004 Annual Meeting of Shareholders (Commission File No. 1-16305). Reference is also made to the information regarding Puget Energy’s executive officers set forth in Part I of this report.

PUGET SOUND ENERGY
        The information called for by Item 10 with respect to PSE is omitted pursuant to General Instruction I(2)(c) to Form 10-K (omission of information by certain wholly owned subsidiaries).

ITEM 10. DIRECTORS AND11. EXECUTIVE OFFICERS OF THE REGISTRANTCOMPENSATION

PUGET ENERGY
        The information required by this item with respect to PSEPuget Energy is incorporated herein by reference to the material under “Election of Directors” and “Security Ownership of Directors and Executive Officers — Section 16(a) Beneficial Ownership Reporting Compliance” in Puget Energy’s proxy statement for its 2003 Annual Meeting of Shareholders (Commission File No. 1-16305), which is filed as Exhibit 99.3 to this report. Reference is also made to the information regarding PSE’s executive officers set forth in Part I of this report.

ITEM 11. EXECUTIVE COMPENSATION

        The information required by this item with respect to PSE is incorporated herein by reference to the material under “Structure and Compensation of Board of Directors—Director“Director Compensation,” “Executive Compensation” and “Employment Contracts, Termination of Employment and Change-In-Control Arrangements” in Puget Energy’s proxy statement for its 20032004 Annual Meeting of Shareholders (Commission File No. 1-16305), which.

PUGET SOUND ENERGY
        The information called for by Item 11 with respect to PSE is filed as Exhibit 99.3omitted pursuant to this report.General Instruction I(2)(c) to Form 10-K (omission of information by certain wholly owned subsidiaries).

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                MANAGEMENT AND RELATED STOCKHOLDER MATTERS

EQUITY COMPENSATION PLAN INFORMATION
        The following table sets forth information regarding ourthe common stock that may be issued upon the exercise of options, warrants and other rights granted to employees, consultants or directors under all of the Puget Energy existing equity compensation plans, as of December 31, 2002.2003.


 (a)
 (b)
 (c)
Plan Category
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights (#)

 Weighted-average
exercise price of
outstanding options,
warrants and rights ($)

 Number of securities
remaining available for
issuance under equity
compensation plans
(excluding securities
reflected in column (a))
(#)

Equity compensation plans
   approved by security holders
40,000  $22.51  1,322,051(2)(3)
Equity compensation plans not
   aproved by security holders

260,000


(1)


 


$22.51


(1)


 


56,967


(4)(5)


Total300,000  $22.51  1,379,018 


 (a)
 (b)
 (c)
Plan Category
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights

 Weighted-average
exercise price of
outstanding options,
warrants and rights

 Number of securities
remaining available for
issuance under equity
compensation plans
(excluding securities
reflected in column (a))

Equity compensation plans
   approved by security holders
40,000  $22.51  1,194,480   (1)(2)(3)
Equity compensation plans not
   aproved by security holders

260,000


   (4)


 


$22.51


   (4)


 


41,879


   (5)


Total300,000  $22.51  1,236,359 

        The table does not include 43,554 deferred stock units in the Company’s deferred compensation plans that are payable in stock, plus cash for any fractional shares, of which all are currently vested.

(1)Includes 259,662 shares remaining available for issuance under Puget Energy’s Employee Stock Purchase Plan.
(2)

Includes 934,818 shares remaining available for issuance under Puget Energy’s Amended and Restated 1995 Long-Term Incentive Plan (performance shares). Depending on the level of achievement of performance goals, the performance shares may be paid out at zero shares at minimum achievement level, 790,922 shares at target level, or 1,181,103 at maximum level. Because there is no exercise price associated with performance shares, such shares are not included in the weighted-average price calculation.

(3)In addition to stock options, Puget Energy may also grant stock awards, performance awards and other stock-based awards under the Puget Energy Amended and Restated 1995 Long-Term Incentive Plan.
(4)Does not include stock options that were assumed by PSE in connection with its acquisition of Washington Energy Company. The assumed options are for the purchase of 17,96011,301 shares of Puget Energy common stock and have a weighted-average exercise price of $19.26$20.21 per share. In the event that any assumed option is not exercised, no further option to purchase shares of common stock will be issued in place of such unexercised option.

(2)(5)

Includes 298,602 shares remaining available for purchase under Puget Energy’s Employee Stock Purchase Plan.

(3)

Includes 1,023,449 shares available under Puget Energy’s Amended and Restated 1995 Long-Term Incentive Plan, Puget Energy may also grant stock awards, performance awards and other stock-based awards. Includes 571,719 share grants of performance awards at the target level.

(4)

Includes 56,967Represents 41,879 shares available for issuance under Puget Energy’s Non-employeeNonemployee Director Stock Plan (Director Stock Plan). The Director Stock Plan provides for automatic stock payments to each of Puget Energy’s non-employeenonemployee directors. Each non-employeenonemployee director who is a non-employeenonemployee director at any time during a calendar year receives a stock payment as a portion of the quarterly retainer paid to such director. Effective JanuaryJuly 1, 2003, the number of shares that will be issued to each non-employeenonemployee director as a stock payment under the Director Stock Plan is determined by dividing between 50% and 100% (depending on participant’s election) of the quarterly retainer payable to such director for a fiscal quarter by the fair market value of Puget Energy’s common stock on the last business day of that fiscal quarter, except that 100% of the quarterly retainer will be paid to a director as a stock payment until the director owns that number of shares determined by dividing an amount equal to the value of two years of quarterly retainers (based on the amount of the quarterly retainer that is being paid for that fiscal quarter) by the fair market value of Puget Energy’s common stock on the last business day of that fiscal quarter. Prior to January 1, 2003, the number of shares that were issued to each non-employee director as a stock payment under the Director Stock Plan was determined by dividing 40%two-thirds of the quarterly retainer payable to such director for a fiscal quarter by the fair market value of Puget Energy’s common stock on the last business day of that fiscal quarter.

Prior to July 1, 2003, 40% of the quarterly retainer was payable in stock. A nonemployee director may elect to increase the percentage of his or her quarterly retainer that is paid in stock, up to 100%. A nonemployee director may also elect to defer the issuance of shares under the Director Stock Plan in accordance with the terms of the plan.
(5)

Does not include shares of Puget Energy common stock which may be issued in connection with cash amounts deferred into a stock fund measurement fund under PSE’s Deferred Compensation Plan for Key Employees or Deferred Compensation Plan for Non-employee Directors.


SUMMARY OF EQUITY COMPENSATION PLANS NOT APPROVED BY SHAREHOLDERS

Non-Plan GrantsNON-PLAN GRANTS
        On January 7, 2002, Puget Energy granted Stephen P. Reynolds, President and Chief Executive Officer of Puget Energy and PSE, two non-qualified stock option grants outside of any equity incentive plan adopted by Puget Energy (the “Non-Plan Grants”)Non-Plan Grants). These stock option grants were an inducement to Mr. Reynolds’ employment and in lieu of participation in the Companies’ Supplemental Executive Retirement Plan. One of the Non-Plan Grants made to Mr. Reynolds is for 150,000 shares of Puget Energy common stock and vests at a rate of 20% per year, for full vesting after five years. The other Non-Plan Grant made to Mr. Reynolds is for 110,000 shares of Puget Energy common stock and vests at a rate of 25% per year, for full vesting after four years. The exercise price of both Non-Plan Grants is $22.51 per share, equal to 100% of the fair market value of Puget Energy common stock on the date of grant. As of December 31, 2002,2003, all of the 260,000 shares subject to the Non-Plan Grants remained outstanding. Except as expressly provided in the option agreement relating to each of the Non-Plan Grants, the Non-Plan Grants are subject to the terms and conditions of the Company’s Amended and Restated 1995 Long-Term Incentive Plan.



        Upon a change of control (as defined in the Employment Agreement between Puget Energy and Mr. Reynolds, dated January 7, 2002), both Non-Plan Grants will become fully vested and immediately exercisable. If Mr. Reynolds’ employment or service relationship with Puget Energy is terminated by Puget Energy without cause or by Mr. Reynolds with good reason, the vesting and exercisability of the Non-Plan Grants will be accelerated as follows: (1) the vesting and exercisability of the 150,000 share150,000-share Non-Plan Grant will be accelerated such that the total number of shares vested and exercisable will be calculated as if the option had vested on a daily basis over the four-year period through the date of termination and (2) the vesting and exercisability of the 110,000 share110,000-share Non-Plan Grant will be accelerated by two years. For purposes of the Non-Plan Grants, the terms “cause” and “good reason” have the meanings given to them in the Employment Agreement between Puget Energy and Mr. Reynolds, dated January 1, 2002.
        Subject to the provisions regarding a change of control and termination of employment or service relationship by Puget Energy without cause or by Mr. Reynolds for good reason, as described above, upon termination of Mr. Reynolds’ employment or service relationship with


Puget Energy for any reason, the unvested portion of the Non-Plan Grants will terminate automatically and the vested portion may be exercised as follows: (1) generally, on or before the earlier of three months after termination and the expiration date of the option, (2) if termination is due to retirement, disability or death, on or before the earlier of one year after termination and the expiration date of the option, or (3) if death occurs after termination, but while the option is still exercisable, on or before the earlier of one year after the date of death and the expiration date of the option.
        The Non-Plan Grants provide for the payment of the exercise price of options by any of the following means: (1) cash, (2) check, (3) tendering shares of Puget Energy’s common stock, either actually or by attestation, already owned for at least six months (or any shorter period necessary to avoid a charge to Puget Energy’s earnings for financial reporting purposes) that on the day prior to the exercise date have a fair market value equal to the aggregate exercise price of the shares being purchased, (4) delivery of a properly executed exercise notice, together with irrevocable instructions to a brokerage firm designated by Puget Energy to deliver promptly to Puget Energy the aggregate amount of sale or loan proceeds to pay the option exercise price and any withholding tax obligations that may arise in connection with the exercise or (5) any other method permitted by the plan administrator.

BENEFICIAL OWNERSHIP OF PUGET SOUND ENERGY
        As of December 31, 2002,2003, all of the issued and outstanding shares of PSE’s common stock were held beneficially and of record by Puget Energy.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        None

ITEM 14. CONTROLS PRINCIPAL ACCOUNTANT FEES AND PROCEDURESSERVICES

Evaluation        The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent auditors, for the year ended December 31 were as follows:

 2003
2002
(DOLLARS IN THOUSANDS)
PUGET
ENERGY

PSE
PUGET
ENERGY

PSE
Audit fees1 $850$453$791$324
Audit related fees2  261 147 195 151
Tax fees3  200 168 288 139
All other fees4  -- -- 23 --

Total $1,311$768$1,297$614



1For professional services rendered for the audit of Puget Energy's and PSE's annual financial statements, reviews of financial statements included in the Companies' Forms 10-Q, and consents and reviews of documents filed with the Securities and Exchange Commission. The 2003 fees are estimated and include an aggregate amount of approximately $167,000 and $277,000 billed to Puget Energy and PSE, respectively, through December 31, 2003. The 2002 fees include an aggregate amount of $100,000 and $297,000 billed to Puget Energy and PSE, respectively, through December 31, 2002.
2Consists of employee benefit plan audits, due diligence reviews and assistance with Sarbanes-Oxley readiness
3Consists of tax planning, consulting and tax return reviews.
4For 2002, other fees consisted of financial information systems design and implementation fees relating to the final portion of work on the implementation of Puget Sound Energy's ConsumerLinX customer information system, initiated in 2001 and completed in February 2002.


        The Audit Committees of disclosure controlsthe Company have adopted policies for the pre-approval of all audit and procedures.non-audit services provided by the Company’s independent auditor. The policies are designed to ensure that the provision of these services does not impair the auditor’s independence. Under the supervisionpolicies, unless a type of service to be provided by the independent auditor has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee.
        The annual audit services engagement terms and with the participation of Puget Energy’s and PSE’s management, including the Companies’ President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer, Puget Energy and PSE have evaluated the effectiveness of the Companies’ disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934) within 90 days of the filing date of this annual report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President Finance and Chief Financial Officer of Puget Energy and PSE concluded that these disclosure controls and procedures are effective.
Changes in internal controls. There have been no significantfees, as well as any changes in Puget Energy’s or PSE’s internal controls or in other factors that could significantly affect internal controls subsequentterms, conditions and fees relating to the dateengagement, are subject to specific pre-approval by the Audit Committees. In addition, on an annual basis, the Audit Committees grant general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent auditor. With respect to each proposed pre-approved service, the independent auditor is required to provide detailed back-up documentation to the Audit Committees regarding the specific services to be provided. Under the policies, the Audit Committees may delegate pre-approval authority to one or more of their evaluation, includingmembers. The member or members to whom such authority is delegated shall report any corrective actions with regardpre-approval decisions to significant deficienciesthe Audit Committees at their next scheduled meeting. The Audit Committees do not delegate responsibilities to pre-approve services performed by the independent auditor to management.
        For 2003 all audit and material weaknesses.
non-audit services were pre-approved.



ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
                FORM 8-K

(a)

Documents filed as part of this report:

1)

Financial statement schedules see—see index

on page 64.
2)

Exhibits — see index

on page 111.

(b)

Reports on Form 8-K:
Puget Energy

1) 

Puget Energy and Puget Sound Energy

1)Form 8-K filed by Puget Energydated on October 17, 200224, 2003 Item 5 Other Events and Item 7 Exhibits, related to PSE’s acquisition of a 49.85% share of the Frederickson Power LP’s generation facility.
2)Form 8-K dated November 4, 2003 — Item 5 Other Events, related to Puget Energy’s third-quarter results of operation.

2)

Form 8-K filed by Puget Energy on November 1, 2002 – Item 5 Other Events, related to Puget Energy filing of exhibits to the Registration Statement relating to the public offeringsale of common stock.


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 its behalf by the undersigned, thereunto duly authorized.

PUGET ENERGY, INC.
 PUGET SOUND ENERGY, INC.
/s/ Stephen P. Reynolds
 /s/ Stephen P. Reynolds
Stephen P. Reynolds Stephen P. Reynolds
President and Chief Executive Officer President and Chief Executive Officer
   
Date: March 10, 20039, 2004 Date: March 10, 20039, 2004


        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.

SIGNATURE
 
TITLE
 
DATE
  (Puget Energy and PSE unless otherwise noted) 
     
     
/s/ Douglas P. BieghleBeighle
 Chairman of the Board March 7, 20039, 2004
(Douglas P. Bieghle)Beighle)    
     
     
/s/ Stephen P. Reynolds
 President, Chief Executive Officer and Director  
(Stephen P. Reynolds)    
     
     
/s/ StephenBertrand A. McKeonValdman
 Senior Vice President Finance and Chief Financial Officer  
(StephenBertrand A. McKeon)Valdman)    
     
     
/s/ James W. Eldredge
 Corporate Secretary and Chief Accounting Officer  
(James W. Eldredge)    
     
     
/s/ Charles W. Bingham
 Director  
(Charles W. Bingham)    
     
     
/s/ Phyllis J. Campbell
 Director  
(Phyllis J. Campbell)    
     
     
/s/ Craig W. Cole
 Director  
(Craig W. Cole)    
     
     
/s/ Robert L. Dryden
 Director  
(Robert L. Dryden)    
     
     
/s/ Stephen E. Frank
Director
(Stephen E. Frank)
/s/ Tomio Moriguchi
 Director  
(Tomio Moriguchi)    
     
     
/s/ Dr. Kenneth P. Mortimer
 Director  
(Dr. Kenneth P. Mortimer)    
     
     
/s/ Sally G. Narodick
 Director  
(Sally G. NarodickNarodick)    

CERTIFICATIONS OF PUGET ENERGY

I, Stephen P. Reynolds, certify that:

1.

I have reviewed this annual report on Form 10-K of Puget Energy;


2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;


3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;


4.

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;


b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and


c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


5.

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and


b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


6.

The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: March 10, 2003

/s/ Stephen P. Reynolds
Stephen P. Reynolds
President and Chief Executive Officer

I, Stephen A. McKeon, certify that:

1.

I have reviewed this annual report on Form 10-K of Puget Energy;


2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;


3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;


4.

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;


b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and


c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


5.

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and


b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


6.

The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: March 10, 2003

/s/ Stephen A. McKeon
Stephen A. McKeon
Sr. Vice President Finance and
Chief Financial Officer

CERTIFICATIONS OF PUGET SOUND ENERGY

I, Stephen P. Reynolds, certify that:

1.

I have reviewed this annual report on Form 10-K of Puget Sound Energy;


2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;


3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;


4.

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;


b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and


c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


5.

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and


b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


6.

The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: March 10, 2003

/s/ Stephen P. Reynolds
Stephen P. Reynolds
President and Chief Executive Officer

I, Stephen A. McKeon, certify that:

1.

I have reviewed this annual report on Form 10-K of Puget Sound Energy;


2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;


3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;


4.

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;


b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and


c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


5.

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and


b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


6.

The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: March 10, 2003

/s/ Stephen A. McKeon
Stephen A. McKeon
Sr. Vice President Finance and
Chief Financial Officer

REPORT OF MANAGEMENT
        PUGET ENERGY, INC.
          and
        PUGET SOUND ENERGY, INC.

        The accompanying consolidated financial statements of Puget Energy, Inc. and Puget Sound Energy, Inc. have been prepared under the direction of management, which is responsible for their integrity and objectivity. The statements have been prepared in accordance with generally accepted accounting principles and include amounts based on judgments and estimates by management where necessary. Management also prepared the other information in the Annual Report on Form 10-K and is responsible for its accuracy and consistency with the financial statements.
        Puget Energy and Puget Sound Energy maintain a system of internal control which, in management’s opinion, provides reasonable assurance that assets are properly safeguarded and transactions are executed in accordance with management’s authorization and properly recorded to produce reliable financial records and reports. The system of internal control provides for appropriate division of responsibility and is documented by written policy and updated as necessary. Puget Sound Energy’s internal audit staff assesses the effectiveness and adequacy of the internal controls on a regular basis and recommends improvements when appropriate. Management considers the internal auditor’s and independent auditor’s recommendations concerning Puget Energy’s and Puget Sound Energy’s internal controls and takes steps to implement those that they believe are appropriate in the circumstances.
        In addition, PricewaterhouseCoopers LLP, the independent accountants,auditors, have performed audit procedures deemed appropriate to obtain reasonable assurance about whether the financial statements are free of material misstatement.
        The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed solely of outside Directors.Directors and two of those Directors qualify as financial experts under the rules adopted by the Securities and Exchange Commission. The audit committee meets regularly with management, the internal auditors and the independent auditors, jointly and separately, to review management’s process of implementation and maintenance of internal accounting controls and auditing and financial reporting matters. The internal and independent auditors have unrestricted access to the audit committee.


/s/ Stephen P. Reynolds
 /s/ StephenBertrand A. McKeonValdman
 /s/ James W. Eldredge
Stephen P. Reynolds StephenBertrand A. McKeonValdman James W. Eldredge
President and Chief Executive OfficerSenior Vice President Finance and
Chief Financial Officer
Corporate Secretary and
Chief Accounting Officer

REPORT OF INDEPENDENT ACCOUNTANTSAUDITORS

To the Shareholders of Puget Energy, Inc.:

        In our opinion, the consolidated financial statements listed on page 57in the accompanying index of this Annual Report on Form 10-K present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiaries at December 31, 20022003 and 2001,2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed on page 100in the accompanying index of the document presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
        As described in Note 1715 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities as required by Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities.”
        As described in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations as required by Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.”

PricewaterhouseCoopers LLP
Seattle, Washington
February 12, 2003March 5, 2004



REPORT OF INDEPENDENT AUDITORS

To the Shareholder of Puget Sound Energy, Inc.:

        In our opinion, the consolidated financial statements listed on page 57in the accompanying index of this Annual Report on Form 10-K present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiaries at December 31, 20022003 and 2001,2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20022003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed on page 100in the accompanying index of the document presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
        As described in Note 1715 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities as required by Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities.”
        As described in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations as required by Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.”

PricewaterhouseCoopers LLP
Seattle, Washington
February 12, 2003March 5, 2004


Consolidated Financial Statements, Financial Statement Schedule Covered by the Foregoing Report of Independent Accountants and Exhibits

         CONSOLIDATED FINANCIAL STATEMENTS:
        PUGET ENERGY:
        Consolidated Statements of Income for the years ended December 31, 2003, 2002 2001 and 20002001

 Consolidated Balance Sheets, December 31, 20022003 and 20012002

 Consolidated Statements of Capitalization, December 31, 20022003 and 20012002

 Consolidated Statements of Common Shareholders' Equity
           for the years ended December 31, 2003, 2002 2001 and 20002001

 Consolidated Statements of Comprehensive Income for the years
           ended December 31, 2003, 2002 2001 and 20002001

 Consolidated Statements of Cash Flows for the years
          ended December 31, 2003, 2002 2001 and 20002001

         PUGET SOUND ENERGY:
        Consolidated Statements of Income for the years ended December 31, 2003, 2002 2001 and 20002001

 Consolidated Balance Sheets, December 31, 20022003 and 20012002

 Consolidated Statements of Capitalization, December 31, 20022003 and 20012002

 Consolidated Statements of Common Shareholders' Equity
          for the years ended December 31, 2003, 2002 2001 and 20002001

 Consolidated Statements of Comprehensive Income for the years
           ended December 31, 2003, 2002 2001 and 20002001

 Consolidated Statements of Cash Flows for the years
          ended December 31, 2003, 2002 2001 and 20002001

         NOTES:
        Combined Puget Energy and Puget Sound Energy Notes to Consolidated Financial Statements

        ScheduleSUPPLEMENTAL QUARTERLY FINANCIAL DATA:

SCHEDULE:

II. 

Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 2003, 2002 2001 and 20002001


         All other schedules have been omitted because of the absence of the conditions under which they are required,
        or because the information required is included in the financial statements or the notes thereto.

         Financial statements of PSE's subsidiaries are not filed herewith inasmuch as the assets, revenues, earnings
        and earnings reinvested in the business of the subsidiaries are not material in relation to those of PSE.

         ExhibitsEXHIBITS:
        Exhibit Index


Puget Energy Consolidated Statements of
          INCOME
(Dollars in thousands, except per share amounts)
FOR YEARS ENDED DECEMBER 31

(Dollars in thousands, except per share amounts)
FOR YEARS ENDED DECEMBER 31

2002
2001
2000
(Dollars in thousands, except per share amounts)
FOR YEARS ENDED DECEMBER 31

2003   
2002   
2001   
Operating revenues:              
Electric $1,365,885 $1,865,227 $2,632,319  $1,509,463 $1,365,885 $1,865,227 
Gas  697,155  815,071  612,311   634,230  697,155  815,071 
Non-utility construction services  341,787  319,529  173,786 
Other  329,282  206,262  57,666   6,043  9,753  32,476 

Total operating revenues  2,392,322  2,886,560  3,302,296   2,491,523  2,392,322  2,886,560 

Operating expenses:  
Energy costs:  
Purchased electricity  645,371  918,676  1,627,249   823,189  645,371  918,676 
Residential exchange  (149,970) (75,864) (41,000)  (173,840) (149,970) (75,864)
Purchased gas  405,016  537,431  332,927   327,132  405,016  537,431 
Fuel  113,538  281,405  182,978 
Unrealized gain on derivative instruments  (11,612) (11,182) -- 
Electric generation fuel  64,999  113,538  281,405 
Unrealized (gain) loss on derivative instruments  106  (11,612) (11,182)
Utility operations and maintenance  286,220  265,789  240,094   289,702  286,220  265,789 
Other operations and maintenance  273,157  156,731  60,612   303,972  273,157  156,731 
Depreciation and amortization  228,743  217,540  196,513   236,866  228,743  217,540 
Conservation amortization  17,501  6,493  6,830   33,458  17,501  6,493 
Taxes other than income taxes  215,429  212,582  202,398   208,395  215,429  212,582 
Income taxes  59,260  79,838  129,823   72,369  59,260  79,838 

Total operating expenses  2,082,653  2,589,439  2,938,424   2,186,348  2,082,653  2,589,439 

Operating income  309,669  297,121  363,872   305,175  309,669  297,121 
Other income  5,458  14,526  5,061   1,564  5,458  14,526 

Income before interest charges  315,127  311,647  368,933   306,739  315,127  311,647 

Interest charges:  
AFUDC  (1,969) (4,446) (9,303)  (3,343) (1,969) (4,446)
Interest expense  198,346  194,505  184,405   187,316  198,346  194,505 
Mandatorily redeemable securities interest expense  1,072  --  -- 

Total interest charges  196,377  190,059  175,102   185,045  196,377  190,059 


Minority interest in earnings of consolidated subsidiary  867  --  --   177  867  -- 

Net income before cumulative effect of accounting change  117,883  121,588  193,831   121,517  117,883  121,588 
Cumulative effect of implementation of accounting change (net of tax)  --  14,749  --   169  --  14,749 

Net income  117,883  106,839  193,831   121,348  117,883  106,839 
Less preferred stock dividends accrual  7,831  8,413  8,994 
Less: preferred stock dividends accrual  5,151  7,831  8,413 

Income for common stock $110,052 $98,426 $184,837  $116,197 $110,052 $98,426 

Common shares outstanding weighted average  88,372  86,445  85,411   94,750  88,372  86,445 

Diluted shares outstanding weighted average  88,777  86,703  85,690   95,309  88,777  86,703 

Basic and diluted earnings per common share before 
Basic earnings per common share before 
cumulative effect of accounting change $1.24 $1.31 $2.16  $1.23 $1.24 $1.31 
Basic and diluted for cumulative effect of accounting change  --  (0.17) -- 
Basic earnings for cumulative effect of accounting change  --  --  (0.17)

Basic and diluted earnings per common share $1.24 $1.14 $2.16 
Basic earnings per common share $1.23 $1.24 $1.14 

Diluted earnings per common share before 
cumulative effect of accounting change $1.22 $1.24 $1.31 
Diluted earnings for cumulative effect of accounting change  --  --  (0.17)


Diluted earnings per common share $1.22 $1.24 $1.14 


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


Puget Energy Consolidated Balance Sheets
          ASSETS
(DOLLARS IN THOUSANDS)
AT DECEMBER 31

2003
2002
  Utility plant:      
    Electric plant  $4,265,908 $4,229,352 
    Gas plant   1,749,102  1,645,865 
    Common plant   390,622  378,844 
    Less: Accumulated depreciation and amortization   (2,325,405) (2,223,190)

       Net utility plant   4,080,227  4,030,871 

  Other property and investments:  
    Investment in Bonneville Exchange Power Contract   47,609  51,136 
    Goodwill, net   133,302  125,555 
    Intangibles, net   18,707  18,652 
    Non-utility property, net   91,932  80,855 
    Other   110,543  101,932 

       Total other property and investments   402,093  378,130 

  Current assets:  
    Cash   27,481  176,669 
    Restricted cash   2,537  18,871 
    Accounts receivable, net of allowance for doubtful accounts   227,115  279,623 
    Unbilled revenues   131,798  112,115 
    Materials and supplies, at average cost   85,128  70,402 
    Current portion of unrealized gain on derivative instruments   7,593  3,741 
    Prepayments and other   12,200  11,323 

       Total current assets   493,852  672,744 

  Other long-term assets:  
    Regulatory asset for deferred income taxes   142,792  167,058 
    Regulatory asset for PURPA buyout costs   227,753  243,584 
    Unrealized gain on derivative instruments   8,624  9,870 
    PCA mechanism   3,605  -- 
    Other   315,739  269,876 

     Total other long-term assets   698,513  690,388 

  Total assets  $5,674,685 $5,772,133 

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

Puget Energy Consolidated Balance Sheets
          ASSETS          CAPITALIZATION AND LIABILITIES
(Dollars in thousands)
AT DECEMBER 31

2002
2001
  Utility plant:      
    Electric plant  $4,229,352 $4,167,920 
    Gas plant   1,645,865  1,551,439 
    Common plant   378,844  362,670 
    Less: Accumulated depreciation and amortization   (2,337,832) (2,194,048)

        Net utility plant   3,916,229  3,887,981 

  Other property and investments:  
    Investment in Bonneville Exchange Power Contract   51,136  54,663 
    Goodwill, net   125,555  102,151 
    Intangibles, net   18,652  16,059 
    Non-utility property, net   80,855  48,369 
    Other   101,932  96,007 

        Total other property and investments   378,130  317,249 

  Current assets:  
    Cash   176,669  92,356 
    Restricted cash   18,871  -- 
    Accounts receivable, net of allowance for doubtful accounts   279,623  279,321 
    Unbilled revenues   112,115  147,008 
    Purchased gas receivable   --  37,228 
    Materials and supplies, at average cost   70,402  90,333 
    Current portion of unrealized gain on derivative instruments   3,741  3,315 
    Prepayments and other   11,323  11,277 

        Total current assets   672,744  660,838 

  Other long-term assets:  
    Regulatory asset for deferred income taxes   167,058  193,016 
    Regulatory asset for PURPA buyout costs   243,584  244,635 
    Unrealized gain on derivative instruments   9,870  3,317 
    Other   269,876  239,941 

  Total other long-term assets   690,388  680,909 

  Total assets  $5,657,491 $5,546,977 

(DOLLARS IN THOUSANDS)
AT DECEMBER 31

2003
2002
  Capitalization:    
  (See Consolidated Statements of Capitalization): 
     Common equity$1,655,046$1,523,787
     Preferred stock not subject to mandatory redemption -- 60,000

       Total shareholders' equity 1,655,046 1,583,787

  Redeemable securities and long-term debt: 
     Preferred stock subject to mandatory redemption 1,889 43,162
    Corporation obligated, mandatorily redeemable preferred 
     securities of subsidiary trust holding solely junior 
     subordinated debentures of the corporation -- 300,000
    Junior subordinated debentures of the corporation payable to a 
     subsidiary trust holding mandatorily redeemable preferred 
     securities 280,250 --
     Long-term debt 1,969,489 2,160,276

       Total redeemable securities and long-term debt 2,251,628 2,503,438

       Total capitalization 3,906,674 4,087,225

  Minority interest in consolidated subsidiary 11,689 10,629

  Current liabilities: 
     Accounts payable 214,357 205,619
     Short-term debt 13,893 47,295
     Current maturities of long-term debt 246,829 76,837
     Purchased gas liability 11,984 83,811
     Accrued expenses: 
       Taxes 77,451 62,562
       Salaries and wages 12,712 11,441
       Interest 32,954 37,942
     Current portion of unrealized loss on derivative instruments 3,636 2,410
     Other 46,378 44,130

       Total current liabilities 660,194 572,047

Long-term liabilities: 
  Deferred income taxes 755,235 730,675
  Other deferred credits 340,893 371,557

        Total long-term liabilities 1,096,128 1,102,232

  Commitments and contingencies -- --

  Total capitalization and liabilities$5,674,685$5,772,133

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


Puget Energy Consolidated Balance SheetsStatements of
          CAPITALIZATION AND LIABILITIES
(Dollars in thousands)
AT DECEMBER 31

2002
2001
  Capitalization:      
  (See Consolidated Statements of Capitalization):  
     Common equity  $1,523,787 $1,362,724 
     Preferred stock not subject to mandatory redemption   60,000  60,000 
     Preferred stock subject to mandatory redemption   43,162  50,662 
     Corporation obligated, mandatorily redeemable preferred  
       securities of subsidiary trust holding solely junior  
       subordinated debentures of the corporation   300,000  300,000 
     Long-term debt   2,149,733  2,127,054 

       Total capitalization   4,076,682  3,900,440 

  Minority interest in consolidated subsidiary   10,629  -- 

  Current liabilities:  
     Accounts payable   205,619  167,426 
     Short-term debt   47,295  348,577 
     Current maturities of long-term debt   73,206  119,523 
     Purchased gas liability   83,811  -- 
     Accrued expenses:  
       Taxes   62,562  70,708 
       Salaries and wages   11,441  14,746 
       Interest   37,942  42,505 
     Current portion of unrealized loss on derivative instruments   2,410  35,145 
     Other   47,761  46,178 

       Total current liabilities   572,047  844,808 

Long-term liabilities:  
  Deferred income taxes   730,675  605,315 
  Unrealized loss on derivative instruments   --  75 
  Other deferred credits   267,458  196,339 

        Total long-term liabilities   998,133  801,729 

  Commitments and contingencies   --  -- 

  Total capitalization and liabilities  $5,657,491 $5,546,977 

(DOLLARS IN THOUSANDS)
AT DECEMBER 31

2003
 
2002
  Common equity:      
    Common stock $0.01 par value, 250,000,000 shares authorized, 99,074,070 and  
      93,642,659 shares outstanding at December 31, 2003 and 2002  $991 $936 
    Additional paid-in capital   1,603,901  1,484,615 
    Earnings reinvested in the business   58,217  36,396 
    Accumulated other comprehensive income (loss) - net of tax   (8,063) 1,840 

       Total common equity   1,655,046  1,523,787 

  Preferred stock not subject to mandatory redemption - cumulative - $25 par value:*  
    7.45% series II - 2,400,000 shares authorized, 0 and 2,400,000 shares outstanding at  
    December 31, 2003 and 2002   --  60,000 

       Total preferred stock not subject to mandatory redemption   --  60,000 

  Preferred stock subject to mandatory redemption - cumulative - $100 par value: *  
      4.84% series - 150,000 shares authorized,  
      14,583 and 14,808 shares outstanding at December 31, 2003 and 2002   1,458  1,481 
      4.70% series - 150,000 shares authorized,  
      4,311 shares outstanding at December 31, 2003 and 2002   431  431 
      7.75% series - 750,000 shares authorized,  
      0 and 412,500 shares outstanding at December 31, 2003 and 2002   --  41,250 

       Total preferred stock subject to mandatory redemption   1,889  43,162 

  Corporation obligated mandatorily redeemable preferred securities of  
    subsidiary trust holding solely junior subordinated debentures of the   --  300,000 
    corporation  
  Junior subordinated debentures of the corporation payable to a subsidiary trust  
    holding mandatorily redeemable preferred securities   280,250  -- 

  Long-term debt:  
    First mortgage bonds and senior notes   1,891,158  1,932,000 
    Pollution control revenue bonds:  
      Revenue refunding 1991 series, due 2021   --  50,900 
      Revenue refunding 1992 series, due 2022   --  87,500 
      Revenue refunding 1993 series, due 2020   --  23,460 
      Revenue refunding 2003 series, due 2031   161,860  -- 
    Other notes   163,313  143,281 
    Unamortized discount - net of premium   (13) (28)
    Long-term debt due within one year   (246,829) (76,837)

      Total long-term debt excluding current maturities   1,969,489  2,160,276 

  Total capitalization  $3,906,674 $4,087,225 

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


Puget Energy Consolidated Statements of
          CAPITALIZATION
  (Dollars in thousands)      
  AT DECEMBER 31   2002  2001 

  Common equity:  
    Common stock $0.01 par value, 250,000,000 shares authorized, 93,642,659  
       and 87,023,210 shares outstanding at December 31, 2002 and 2001  $936 $870 
    Additional paid-in capital   1,484,615  1,358,946 
    Earnings reinvested in the business   36,396  32,229 
    Accumulated other comprehensive income (loss) - net of tax   1,840  (29,321)

       Total common equity   1,523,787  1,362,724 

  Preferred stock not subject to mandatory  
    redemption - cumulative - $25 par value: *  
    7.45% series II 2,400,000 shares authorized and outstanding   60,000  60,000 

       Total preferred stock not subject to mandatory redemption   60,000  60,000 

  Preferred stock subject to mandatory redemption - cumulative - $100 par value: *    
      4.84% series - 150,000 shares authorized,
         14,808 shares outstanding
   1,481  1,481 
      4.70% series - 150,000 shares authorized,  
         4,311 shares outstanding   431  431 
         7.75% series - 750,000 shares authorized,  
         412,500 and 487,500 shares outstanding   41,250  48,750 

       Total preferred stock subject to mandatory redemption   43,162  50,662 

  Corporation obligated, mandatorily redeemable preferred  
    securities of subsidiary trust holding solely junior  
    subordinated debentures of the corporation   300,000  300,000 

  Long-term debt:  
    First mortgage bonds and senior notes   1,932,000  2,009,000 
    Pollution control revenue bonds:  
      Revenue refunding 1991 series, due 2021   50,900  50,900 
      Revenue refunding 1992 series, due 2022   87,500  87,500 
      Revenue refunding 1993 series, due 2020   23,460  23,460 
    Other notes   129,107  75,762 
    Unamortized discount - net of premium   (28) (45)
    Long-term debt due within one year   (73,206) (119,523)

      Total long-term debt excluding current maturities   2,149,733  2,127,054 

  Total capitalization  $4,076,682 $3,900,440 

* Puget Energy has 50,000,000 shares authorized for $0.01 par value preferred stock. PSE has 13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock.

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


Puget Energy Consolidated Statements of
          COMMON SHAREHOLDERS' EQUITY
 Common Stock
Additional Accumulated
Other
 
(Dollars in thousands)
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

Shares
Amount
Paid-in
Capital

Retained
Earnings

Comprehensive
Income

Total Amount
  Balance at December 31, 1999   84,922,405 $849,224 $454,982 $66,019 $8,848 $1,379,073 
  Net income   --  --  --  193,831  --  193,831 
  Preferred stock dividend declared   --  --  --  (9,067) --  (9,067)
  Loss on preferred stock redemptions   --  --  1,181  (1,181) --  -- 
  Common stock dividend declared   --  --  --  (156,929) --  (156,929)
  Common stock issued on dividend reinvestment   981,549  9,816  13,295  --  --  23,111 
    plan  
  Other   (163) (2) 721  --  --  719 
  Other comprehensive income   --  --  --  --  (4,098) (4,098)

  Balance at December 31, 2000   85,903,791 $859,038 $470,179 $92,673 $4,750 $1,426,640 
  Net income   --  --  --  106,839  --  106,839 
  Preferred stock dividend declared   --  --  --  (8,485) --  (8,485)
  Common stock dividend declared   --  --  --  (158,798) --  (158,798)
  Reclassification of par value in connection   --  (858,179) 858,179  --  --  -- 
    with the formation of Puget Energy  
  Common stock issued on dividend reinvestment   1,119,568  11  25,551  --  --  25,562 
    plan  
  Other   (149) --  5,037  --  --  5,037 
  Other comprehensive income   --  --  --  --  (34,071) (34,071)

  Balance at December 31, 2001   87,023,210 $870 $1,358,946 $32,229 $(29,321)$1,362,724 
  Net income   --  --  --  117,883  --  117,883 
  Preferred stock dividend declared   --  --  --  (7,904) --  (7,904)
  Common stock dividend declared   --  --  --  (105,687) --  (105,687)
  Common stock issued:  
    New issuance   5,750,000  57  114,639  --  --  114,696 
    Dividend reinvestment plan   801,205  8  16,900  --  --  16,908 
    Employee plans   68,252  1  550  --  --  551 
  Other   (8) --  (6,420) (125) --  (6,545)
  Other comprehensive income   --  --  --  --  31,161  31,161 

  Balance at December 31, 2002   93,642,659 $936 $1,484,615 $36,396 $1,840 $1,523,787 

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


Puget Energy Consolidated Statements of
          COMPREHENSIVE INCOME
(Dollars in thousands)
FOR YEARS ENDED DECEMBER 31

2002
2001
2000
  Net income  $117,883 $106,839 $193,831 

  Other comprehensive income, net of tax:  
     Unrealized holding losses on marketable securities during the period   (1,359) (1,823) (938)
     Reclassification adjustment for realized gains on marketable   --  (5) (3,160)
       securities included in net income        
     Foreign currency translation adjustment   63  --  -- 
     Minimum pension liability adjustment   (2,098) (5,148) -- 
     Transition adjustment for unrealized gain on derivative instruments   --  286,928  -- 
       as of January 1, 2001  
     Unrealized gains (losses) on derivative instruments during the period   2,853  (131,420) -- 
     Reversal of unrealized (gains) losses on derivative instruments   31,702  (182,603) -- 
       settled during the period  

      Other comprehensive income (loss)   31,161  (34,071) (4,098)

  Comprehensive income  $149,044 $72,768 $189,733 

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


Puget Energy Consolidated Statements of
          CASH FLOWS
(Dollars in thousands)
FOR YEARS ENDED DECEMBER 31

2002
2001
2000
  Operating activities:        
     Net income  $117,883 $106,839 $193,831 
     Adjustments to reconcile net income to net cash  
        provided by operating activities:  
          Depreciation and amortization   228,743  217,540  196,513 
          Deferred income taxes and tax credits - net   151,318  11,464  (7,446)
          Gain from sale of securities   --  --  (6,476)
          Net unrealized (gains) losses on derivative instruments   (11,612) 3,567  -- 
     Other (including conservation amortization)   10,872  (4,465) (7,276)
     Cash collateral received from energy supplier   21,425  --  -- 
     Change in certain current assets and liabilities  
       Accounts receivable and unbilled revenue   46,860  147,575  (220,568)
       Materials and supplies   22,088  10,611  (29,760)
       Prepayments and other   141  936  (1,742)
       Purchased gas receivable/liability   121,039  58,822  (62,350)
       Accounts payable   34,351  (254,944) 232,402 
       Taxes payable   (18,260) (33,288) 31,308 
       Accrued expenses and other   (971) 33,631  1,847 

            Net cash provided by operating activities   723,877  298,288  320,283 

  Investing activities:  
     Construction expenditures - excluding equity AFUDC   (224,165) (247,435) (296,480)
     Additions to other property, plant and equipment   (11,621) (5,193) -- 
     Energy conservation expenditures   (11,356) (15,591) (6,931)
     Restricted cash   (18,871) --  -- 
     Proceeds from sale of investment in Cabot preferred stock   --  --  51,463 
     Proceeds from sale of Centralia plant   --  --  37,449 
     Proceeds from sale of securities   --  --  6,757 
     Investments by InfrastruX   (41,602) (75,591) (85,506)
     Repayment from/(loans to) Schlumberger   --  51,948  (20,874)
     Other   (15,761) (16,446) (14,138)

            Net cash used by investing activities   (323,376) (308,308) (328,260)

  Financing activities:  
     Increase (decrease) in short-term debt - net   (301,281) (32,406) (226,395)
     Dividends paid   (97,321) (141,709) (142,886)
     Issuance of common stock   120,214  --  -- 
     Issuance of trust preferred stock   --  200,000  -- 
     Redemption of preferred stock   (7,500) (7,500) (7,503)
     Issuance of bonds and long-term debt   40,000  70,250  510,000 
     Redemption of bonds and notes   (65,937) (19,000) (150,980)
     Other   (4,363) (3,642) (3,583)

            Net cash provided (used) by financing activities   (316,188) 65,993  (21,347)

  Increase (decrease) in cash from net income   84,313  55,973  (29,324)
  Cash at beginning of year   92,356  36,383  65,707 

  Cash at end of year  $176,669 $92,356 $36,383 

  Supplemental Cash Flow Information:  
  Cash payments for:  
    Interest (net of capitalized interest)  $200,392 $191,004 $176,895 
    Income taxes (net of refunds)   (81,652) 87,470  114,100 

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


Puget Sound Energy Consolidated Statements of
          INCOME
(Dollars in thousands)
FOR YEARS ENDED DECEMBER 31

2002
2001
2000
  Operating revenues:        
  Electric  $1,365,885 $1,865,227 $2,632,319 
  Gas   697,155  815,071  612,311 
  Other   9,753  32,476  57,666 

       Total operating revenues   2,072,793  2,712,774  3,302,296 

  Operating expenses:  
  Energy costs:  
    Purchased electricity   645,371  918,676  1,627,249 
    Residential exchange   (149,970) (75,864) (41,000)
    Purchased gas   405,016  537,431  332,927 
    Fuel   113,538  281,405  182,978 
    Unrealized gain on derivative instruments   (11,612) (11,182) -- 
  Utility operations and maintenance   286,220  265,789  240,094 
  Other operations and maintenance   1,602  8,546  60,612 
  Depreciation and amortization   215,317  208,720  196,513 
  Conservation amortization   17,501  6,493  6,830 
  Taxes other than income taxes   202,381  207,365  202,398 
  Income taxes   52,836  76,915  129,823 

       Total operating expenses   1,778,200  2,424,294  2,938,424 

  Operating income   294,593  288,480  363,872 
  Other income   5,215  17,053  5,061 

  Income before interest charges   299,808  305,533  368,933 

  Interest charges:  
    AFUDC   (1,969) (4,446) (9,303)
    Interest expense   192,829  190,849  184,405 

       Total interest charges   190,860  186,403  175,102 

  Net income before cumulative effect of accounting change   108,948  119,130  193,831 
  Cumulative effect of implementation of accounting change (net of tax)   --  14,749  -- 

  Net income   108,948  104,381  193,831 
  Less preferred stock dividends accrual   7,831  8,413  8,994 

  Income for common stock  $101,117 $95,968 $184,837 

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


Puget Sound Energy Consolidated Balance Sheets
          ASSETS
(Dollars in thousands)
AT DECEMBER 31

2002
2001
  Utility plant:      
    Electric plant  $4,229,352 $4,167,920 
    Gas plant   1,645,865  1,551,439 
    Common plant   378,844  362,670 
    Less: Accumulated depreciation and amortization   (2,337,832) (2,194,048)

        Net utility plant   3,916,229  3,887,981 

  Other property and investments:  
    Investment in Bonneville Exchange Power Contract   51,136  54,663 
    Non-utility property, net   1,699  1,105 
    Other   101,922  94,762 

        Total other property and investments   154,757  150,530 

  Current assets:  
    Cash   161,475  82,708 
    Restricted cash   18,871  -- 
    Accounts receivable, net of allowance for doubtful accounts   208,702  235,348 
    Unbilled revenues   112,115  147,008 
    Purchased gas receivable   --  37,228 
    Materials and supplies, at average cost   63,563  85,318 
    Current portion of unrealized gain on derivative instruments   3,741  3,315 
    Prepayments and other   8,907  7,405 

        Total current assets   577,374  598,330 

  Other long-term assets:  
    Regulatory asset for deferred income taxes   167,058  193,016 
    Regulatory asset for PURPA buyout costs   243,584  244,635 
    Unrealized gain on derivative instruments   9,870  3,317 
    Other   269,876  239,941 

  Total other long-term assets   690,388  680,909 

  Total assets  $5,338,748 $5,317,750 

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


Puget Sound Energy Consolidated Balance Sheets
          CAPITALIZATION AND LIABILITIES
(Dollars in thousands)
AT DECEMBER 31

2002
2001
  Capitalization:      
  (See Consolidated Statements of Capitalization):  
     Common equity  $1,426,121 $1,267,654 
     Preferred stock not subject to mandatory redemption   60,000  60,000 
     Preferred stock subject to mandatory redemption   43,162  50,662 
     Corporation obligated, mandatorily redeemable preferred  
       securities of subsidiary trust holding solely junior  
       subordinated debentures of the corporation   300,000  300,000 
     Long-term debt   2,021,832  2,053,815 

       Total capitalization   3,851,115  3,732,131 

  Current liabilities:  
     Accounts payable   193,602  154,600 
     Short-term debt   30,340  338,168 
     Current maturities of long-term debt   72,000  117,000 
     Purchased gas liability   83,811  -- 
     Accrued expenses:  
       Taxes   64,433  70,210 
       Salaries and wages   11,441  14,746 
       Interest   37,942  42,505 
     Current portion of unrealized loss on derivative instruments   2,410  35,145 
     Other   25,456  25,178 

       Total current liabilities   521,435  797,552 

  Long-term liabilities:  
     Deferred income taxes   715,579  601,001 
     Unrealized loss on derivative instruments   --  75 
     Other deferred credits   250,619  186,991 

       Total long-term liabilities   966,198  788,067 

  Commitments and contingencies   --  -- 

  Total capitalization and liabilities  $5,338,748 $5,317,750 

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


Puget Sound Energy Consolidated Statements of
          CAPITALIZATION
(Dollars in thousands)
AT DECEMBER 31

2002
2001
  Common equity:      
    Common stock ($10 stated value) - 15,000,000 shares  
      authorized, 85,903,791 shares outstanding  $859,038 $859,038 
    Additional paid-in capital   498,335  382,592 
    Earnings reinvested in the business   66,971  55,345 
    Accumulated other comprehensive income (loss) - net   1,777  (29,321)

       Total common equity   1,426,121  1,267,654 

  Preferred stock not subject to mandatory  
    redemption - cumulative - $25 par value:*  
    7.45% series II - 2,400,000 shares authorized and outstanding   60,000  60,000 

       Total preferred stock not subject to mandatory redemption   60,000  60,000 

  Preferred stock subject to mandatory redemption - cumulative  
    $100 par value:*  
      4.84% series - 150,000 shares authorized,  
         14,808 shares outstanding   1,481  1,481 
      4.70% series - 150,000 shares authorized,  
         4,311 shares outstanding   431  431 
      7.75% series - 750,000 shares authorized, 412,500 and 487,500  
        shares outstanding   41,250  48,750 

       Total preferred stock subject to mandatory redemption   43,162  50,662 

  Corporation obligated, mandatorily redeemable preferred  
    securities of subsidiary trust holding solely junior  
    subordinated debentures of the corporation   300,000  300,000 

  Long-term debt:  
    First mortgage bonds and senior notes   1,932,000  2,009,000 
    Pollution control revenue bonds:  
      Revenue refunding 1991 series, due 2021   50,900  50,900 
      Revenue refunding 1992 series, due 2022   87,500  87,500 
      Revenue refunding 1993 series, due 2020   23,460  23,460 
    Unamortized discount - net of premium   (28) (45)
    Long-term debt due within one year   (72,000) (117,000)

      Total long-term debt excluding current maturities   2,021,832  2,053,815 

  Total capitalization  $3,851,115 $3,732,131 

*13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock.

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


Puget Sound Energy Consolidated Statements of
          COMMON SHAREHOLDERS'SHAREHOLDERS’ EQUITY
 Common Stock
Additional Accumulated
Other
 
(Dollars in thousands)
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

Shares
Amount
Paid-in
Capital

Retained
Earnings

Comprehensive
Income

Total Amount
  Balance at December 31, 1999   84,922,405 $849,224 $454,982 $66,019 $8,848 $1,379,073 
  Net income   --  --  --  193,831  --  193,831 
  Preferred stock dividend declared   --  --  --  (9,067) --  (9,067)
  Loss on preferred stock redemptions   --  --  1,181  (1,181) --  -- 
  Common stock dividend declared   --  --  --  (156,929) --  (156,929)
  Common stock issued on dividend reinvestment   981,549  9,816  13,295  --  --  23,111 
    plan  
  Other   (163) (2) 721  --  --  719 
  Other comprehensive income   --  --  --  --  (4,098) (4,098)

  Balance at December 31, 2000   85,903,791 $859,038 $470,179 $92,673 $4,750 $1,426,640 
  Net income   --  --  --  104,381  --  104,381 
  Preferred stock dividend declared   --  --  --  (8,485) --  (8,485)
  Common stock dividend declared   --  --  --  (133,224) --  (133,224)
  Return of Capital to Puget Energy   --  --  (86,556) --  --  (86,556)
  Other   --  --  (1,031) --  --  (1,031)
  Other comprehensive income   --  --  --  --  (34,071) (34,071)

  Balance at December 31, 2001   85,903,791 $859,038 $382,592 $55,345 $(29,321)$1,267,654 
  Net income   --  --  --  108,948  --  108,948 
  Preferred stock dividend declared   --  --  --  (7,904) --  (7,904)
  Common stock dividend declared   --  --  --  (89,418) --  (89,418)
  Investment received from Puget Energy   --  --  115,736  --  --  115,736 
  Other   --  --  7  --  --  7 
  Other comprehensive income   --  --  --  --  31,098  31,098 

  Balance at December 31, 2002   85,903,791 $859,038 $498,335 $66,971 $1,777 $1,426,121 



Puget Sound Energy Consolidated Statements of
          COMPREHENSIVE INCOME
(Dollars in thousands)
FOR YEARS ENDED DECEMBER 31

2002
2001
2000
  Net income  $108,948 $104,381 $193,831 

  Other comprehensive income, net of tax:  
     Unrealized holding losses on marketable securities during the period   (1,359) (1,823) (938)
     Reclassification adjustment for realized gains on marketable   --  (5) (3,160)
       securities included in net income  
     Minimum pension liability adjustment   (2,098) (5,148) -- 
     Transition adjustment for unrealized gain on derivative   --  286,928  -- 
      instruments at January 1, 2001  
     Unrealized gains (losses) on derivative instruments during the   2,853  (131,420) -- 
      period  
     Reversal of unrealized (gains) losses on derivative instruments   31,702  (182,603) -- 
      settled during the period  

      Other comprehensive income (loss)   31,098  (34,071) (4,098)

  Comprehensive income  $140,046 $70,310 $189,733 

 Common Stock
Additional Accumulated
Other
 
(DOLLARS IN THOUSANDS)
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

Shares
Amount
Paid-in
Capital

Retained
Earnings

Comprehensive
Income

Total Amount
  Balance at December 31, 2000   85,903,791 $859,038 $470,179 $92,673 $4,750 $1,426,640 
  Net income   --  --  --  106,839  --  106,839 
  Preferred stock dividend declared   --  --  --  (8,485) --  (8,485)
  Common stock dividend declared   --  --  --  (158,798) --  (158,798)
  Reclassification of par value in connection   -- 
    with the formation of Puget Energy   --  (858,179) 858,179  --  --  -- 
  Common stock issued on dividend
     reinvestment plan
   1,119,568  11  25,551  --  --  25,562 
  Other   (149) --  5,037  --  --  5,037 
  Other comprehensive income   --  --  --  --  (34,071) (34,071)

  Balance at December 31, 2001   87,023,210 $870 $1,358,946 $32,229 $(29,321)$1,362,724 
  Net income   --  --  --  117,883  --  117,883 
  Preferred stock dividend declared   --  --  --  (7,904) --  (7,904)
  Common stock dividend declared   --  --  --  (105,687) --  (105,687)
  Common stock issued:  
    New issuance   5,750,000  57  114,639  --  --  114,696 
    Dividend reinvestment plan   801,205  8  16,900  --  --  16,908 
    Employee plans   68,252  1  550  --  --  551 
  Other   (8) --  (6,420) (125) --  (6,545)
  Other comprehensive income   --  --  --  --  31,161  31,161 

  Balance at December 31, 2002   93,642,659 $936 $1,484,615 $36,396 $1,840 $1,523,787 
  Net income   --  --  --  121,348  --  121,348 
  Preferred stock dividend declared   --  --  --  (5,562) --  (5,562)
  Common stock dividend declared   --  --  --  (93,965) --  (93,965)
  Common stock issued:  
    New issuance   4,650,600  47  102,231  --  --  102,278 
    Dividend reinvestment plan   721,340  7  15,447  --  --  15,454 
    Employee plans   59,475  1  1,616  --  --  1,617 
  Other   (4) --  (8) --  --  (8)
  Other comprehensive income   --  --  --  --  (9,903) (9,903)

  Balance at December 31, 2003   99,074,070 $991 $1,603,901 $58,217 $(8,063)$1,655,046 

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


Puget Energy Consolidated Statements of
          COMPREHENSIVE INCOME
(DOLLARS IN THOUSANDS)
FOR YEARS ENDED DECEMBER 31

2003
2002
2001
  Net income  $121,348 $117,883 $106,839 

  Other comprehensive income, net of tax:  
     Unrealized holding losses on marketable securities during the period   (45) (1,359) 1,823)
     Reclassification adjustment for realized gains on marketable securiti    
       included in net income   (1,518) --  (5)
     Foreign currency translation adjustment   80  63  -- 
     Minimum pension liability adjustment   (1,122) (2,098) 5,148)
     Transition adjustment for unrealized gain on derivative instruments a    
       of January 1, 2001   --  --  286,928 
     Unrealized gains (losses) on derivative instruments during the period   8,576  2,853  (131,420)
     Reversal of unrealized (gains) losses on derivative instruments settl    
       during the period   181  31,702  (182,603)
     Deferral related to PCA   (16,055) --  -- 

     Other comprehensive income (loss)   (9,903) 31,161  (34,071)

  Comprehensive income  $111,445 $149,044 $72,768 

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

Puget Energy Consolidated Statements of
          CASH FLOWS
(DOLLARS IN THOUSANDS)
FOR YEARS ENDED DECEMBER 31

2003
2002
2001
  Operating activities:        
     Net income  $121,348 $117,883 $106,839 
     Adjustments to reconcile net income to net cash  
        provided by operating activities:  
          Depreciation and amortization   236,866  228,743  217,540 
          Deferred income taxes and tax credits - net   57,470  151,318  11,464 
          Gain from sale of securities   (2,889) --  -- 
          Net unrealized (gains) losses on derivative instrument   106  (11,612) 3,567 
     Other (including conservation amortization)   (7,412) 330  (4,465)
     Cash collateral received from (returned to) energy supplier   (21,425) 21,425  -- 
     Pension plan funding   (26,521) --  -- 
     Change in certain current assets and liabilities  
       Accounts receivable and unbilled revenue   37,769  46,860  147,575 
       Materials and supplies   (14,727) 22,088  10,611 
       Prepayments and other   (738) 141  936 
       Purchased gas receivable (liability)   (71,826) 121,039  58,822 
       Accounts payable   6,464  34,351  (254,944)
       Taxes payable   13,405  (18,260) (33,288)
       Accrued expenses and other   (4,939) (4,603) 33,631 

            Net cash provided by operating activities   322,951  709,703  298,288 

  Investing activities:  
    Construction and capital expenditures - excluding equity AFU   (285,510) (235,786) (252,628)
     Energy conservation expenditures   (18,579) (11,356) (15,591)
     Restricted cash   20,106  (18,871) -- 
     Proceeds from sale of securities   3,161  --  -- 
     Investments by InfrastruX   (10,659) (41,602) (75,591)
     Repayment from Schlumberger   --  --  51,948 
     Other   2,151  (15,761) (16,446)

            Net cash used by investing activities   (289,330) (323,376) (308,308)

  Financing activities:  
     Increase (decrease) in short-term debt - net   (33,402) (301,281) (32,406)
     Dividends paid   (86,671) (97,321) (141,709)
     Issuance of common stock   106,659  120,214  -- 
     Issuance of trust preferred stock   --  --  200,000 
     Issuance of bonds and long-term debt   319,497  107,518  70,250 
     Redemption of preferred stock   (60,000) --  -- 
     Redemption of mandatorily redeemable preferred stock   (41,273) (7,500) (7,500)
     Redemption of trust preferred stock   (19,750) --  -- 
     Redemption of bonds and notes   (357,510) (119,281) (19,000)
     Other   (10,359) (4,363) (3,642)

            Net cash provided (used) by financing activities   (182,809) (302,014) 65,993 

  Increase (decrease) in cash from net income   (149,188) 84,313  55,973 
  Cash at beginning of year   176,669  92,356  36,383 

  Cash at end of year  $27,481 $176,669 $92,356 

  Supplemental Cash Flow Information:  
  Cash payments for:  
    Interest (net of capitalized interest)  $192,845 $200,392 $191,004 
    Income taxes (net of refunds)   (2,777) (81,652) 87,470 

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

Puget Sound Energy Consolidated Statements of
          INCOME
(DOLLARS IN THOUSANDS)
FOR YEARS ENDED DECEMBER 31

2003
2002
2001
  Operating revenues:        
  Electric  $1,509,463 $1,365,885 $1,865,227 
  Gas   634,230  697,155  815,071 
  Other   6,043  9,753  32,476 

       Total operating revenues   2,149,736  2,072,793  2,712,774 

  Operating expenses:  
  Energy costs:  
    Purchased electricity   823,189  645,371  918,676 
    Residential exchange   (173,840) (149,970) (75,864)
    Purchased gas   327,132  405,016  537,431 
    Electric generation fuel   64,999  113,538  281,405 
    Unrealized (gain) loss on derivative instruments   106  (11,612) (11,182)
  Utility operations and maintenance   289,702  286,220  265,789 
  Other operations and maintenance   1,203  1,602  8,546 
  Depreciation and amortization   220,087  215,317  208,720 
  Conservation amortization   33,458  17,501  6,493 
  Taxes other than income taxes   194,857  202,381  207,365 
  Income taxes   70,939  52,836  76,915 

       Total operating expenses   1,851,832  1,778,200  2,424,294 

  Operating income   297,904  294,593  288,480 
  Other income   1,587  5,215  17,053 

  Income before interest charges   299,491  299,808  305,533 

  Interest charges:  
    AFUDC   (3,343) (1,969) (4,446)
    Interest expense   181,707  192,829  190,849 
    Mandatorily redeemable securities interest expense   1,072  --  -- 

       Total interest charges   179,436  190,860  186,403 

  Net income before cumulative effect of accounting change   120,055  108,948  119,130 
  Cumulative effect of implementation of accounting change (net of ta   169  --  14,749 

  Net income   119,886  108,948  104,381 
  Less preferred stock dividends accrual   5,151  7,831  8,413 

  Income for common stock  $114,735 $101,117 $95,968 

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

Puget Sound Energy Consolidated Balance Sheets
          ASSETS
(DOLLARS IN THOUSANDS)
AT DECEMBER 31

2003
2002
  Utility plant:      
    Electric plant  $4,265,908 $4,229,352 
    Gas plant   1,749,102  1,645,865 
    Common plant   390,622  378,844 
    Less: Accumulated depreciation and amortization   (2,325,405) (2,223,190)

        Net utility plant   4,080,227  4,030,871 

  Other property and investments:  
    Investment in Bonneville Exchange Power Contract   47,609  51,136 
    Non-utility property, net   2,150  1,699 
    Other   110,521  101,922 

        Total other property and investments   160,280  154,757 

  Current assets:  
    Cash   14,778  161,475 
    Restricted cash   2,537  18,871 
    Accounts receivable, net of allowance for doubtful account   155,649  208,702 
    Unbilled revenues   131,798  112,115 
    Materials and supplies, at average cost   77,206  63,563 
    Current portion of unrealized gain on derivative instrumen   7,593  3,741 
    Prepayments and other   6,285  8,907 

        Total current assets   395,846  577,374 

  Other long-term assets:  
    Regulatory asset for deferred income taxes   142,792  167,058 
    Regulatory asset for PURPA buyout costs   227,753  243,584 
    Unrealized gain on derivative instruments   8,624  9,870 
    PCA mechanism   3,605  -- 
    Other   315,660  269,876 

      Total other long-term assets   698,434  690,388 

  Total assets  $5,334,787 $5,453,390 

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

Puget Sound Energy Consolidated Statements ofBalance Sheets
           CAPITALIZATION AND LIABILITIES
(DOLLARS IN THOUSANDS)
AT DECEMBER 31

2003
2002
  Capitalization:      
  (See Consolidated Statements of Capitalization):  
     Common equity  $1,555,469 $1,426,121 
     Preferred stock not subject to mandatory redemption   --  60,000 

       Total shareholders' equity   1,555,469  1,486,121 

  Redeemable securities and long-term debt:  
     Preferred stock subject to mandatory redemption   1,889  43,162 
    Corporation obligated mandatorily redeemable preferred  
      securities of subsidiary trust holding solely junior  
      subordinated debentures of the corporation   --  300,000 
    Junior subordinated debentures of the corporation payable to a  
     subsidiary trust holding mandatorily redeemable preferred securiti   280,250  -- 
     Long-term debt   1,950,347  2,021,832 

       Total redeemable securities and long-term debt   2,232,486  2,364,994 

       Total capitalization   3,787,955  3,851,115 

  Current liabilities:  
     Accounts payable   206,465  193,602 
     Short-term debt   --  30,340 
     Current maturities of long-term debt   102,658  72,000 
     Purchased gas liability   11,984  83,811 
     Accrued expenses:  
       Taxes   82,342  64,433 
       Salaries and wages   12,712  11,441 
       Interest   32,954  37,942 
     Current portion of unrealized loss on derivative instruments   3,636  2,410 
     Other   26,514  25,456 

       Total current liabilities   479,265  521,435 

  Long-term liabilities:  
     Deferred income taxes   731,944  715,579 
     Other deferred credits   335,623  365,261 

       Total long-term liabilities   1,067,567  1,080,840 

  Commitments and contingencies   --  -- 

  Total capitalization and liabilities  $5,334,787 $5,453,390 

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

Puget Sound Energy Consolidated Statements of
          CAPITALIZATION
(DOLLARS IN THOUSANDS)
AT DECEMBER 31

2003
2002
  Common equity:      
    Common stock ($10 stated value) - 150,000,000 shares  
     authorized, 85,903,791 shares outstanding  $859,038 $859,038 
    Additional paid-in capital   604,451  498,335 
    Earnings reinvested in the business   100,186  66,971 
    Accumulated other comprehensive income (loss) - net   (8,206) 1,777 

       Total common equity   1,555,469  1,426,121 

  Preferred stock not subject to mandatory redemption - cumulative - $25 par value    
     7.45% series II - 2,400,000 shares authorized, 0 and 2,400,000 shares outstandi    
    at December 31, 2003 and 2002   --  60,000 

       Total preferred stock not subject to mandatory redemption   --  60,000 

  Preferred stock subject to mandatory redemption - cumulative  
    $100 par value:*  
      4.84% series - 150,000 shares authorized,  
         14,583 and 14,808 shares outstanding at December 31, 2003 and 2002   1,458  1,481 
      4.70% series - 150,000 shares authorized,  
          4,311 shares outstanding at December 31, 2003 and 2002   431  431 
      7.75% series - 750,000 shares authorized,  
           0 and 412,500 shares outstanding at December 31, 2003 and 2002   --  41,250 

       Total preferred stock subject to mandatory redemption   1,889  43,162 

  Corporation obligated mandatorily redeemable preferred securities of subsidiary  
    trust holding solely junior subordinated debentures of the corporation   --  300,000 
  Junior subordinated debentures of the corporation payable to a subsidiary trust  
    holding mandatorily redeemable preferred securities   280,250  -- 

  Long-term debt:  
    First mortgage bonds and senior notes   1,891,158  1,932,000 
    Pollution control revenue bonds:  
      Revenue refunding 1991 series, due 2021   --  50,900 
      Revenue refunding 1992 series, due 2022   --  87,500 
      Revenue refunding 1993 series, due 2020   --  23,460 
      Revenue refunding 2003 series, due 2031   161,860  -- 
    Unamortized discount - net of premium   (13) (28)
    Long-term debt due within one year   (102,658) (72,000)

      Total long-term debt excluding current maturities   1,950,347  2,021,832 

  Total capitalization  $3,787,955 $3,851,115 

*13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value
          preferred stock.
         The accompanying notes are an integral part of the consolidated financial statements.

Puget Sound Energy Consolidated Statements of
           COMMON SHAREHOLDERS’ EQUITY
 Common Stock
Additional Accumulated
Other
 
(DOLLARS IN THOUSANDS)
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

Shares
Amount
Paid-in
Capital

Retained
Earnings

Comprehensive
Income

Total Amount
  Balance at December 31, 2000   85,903,791 $859,038 $470,179 $92,673 $4,750 $1,426,640 
  Net income   --  --  --  104,381  --  104,381 
  Preferred stock dividend declared   --  --  --  (8,485) --  (8,485)
  Common stock dividend declared   --  --  --  (133,224) --  (133,224)
  Return of capital to Puget Energy   --  --  (86,556) --  --  (86,556)
  Other   --  --  (1,031) --  --  (1,031)
  Other comprehensive income   --  --  --  --  (34,071) (34,071)

  Balance at December 31, 2001   85,903,791 $859,038 $382,592 $55,345 $(29,321)$1,267,654 
  Net income   --  --  --  108,948  --  108,948 
  Preferred stock dividend declared   --  --  --  (7,904) --  (7,904)
  Common stock dividend declared   --  --  --  (89,418) --  (89,418)
  Investment received from Puget Ener   --  --  115,736  --  --  115,736 
  Other   --  --  7  --  --  7 
  Other comprehensive income   --  --  --  --  31,098  31,098 

  Balance at December 31, 2002   85,903,791 $859,038 $498,335 $66,971 $1,777 $1,426,121 
  Net income   --  --  --  119,886  --  119,886 
  Preferred stock dividend declared   --  --  --  (5,562) --  (5,562)
  Common stock dividend declared   --  --  --  (81,109) --  (81,109)
  Investment received from Puget Ener   --  --  106,124  --  --  106,124 
  Other   --  --  (8) --  --  (8)
  Other comprehensive income   --  --  --  --  (9,983) (9,983)

  Balance at December 31, 2003   85,903,791 $859,038 $604,451 $100,186 $(8,206)$1,555,469 




Puget Sound Energy Consolidated Statements of
           COMPREHENSIVE INCOME
(DOLLARS IN THOUSANDS)
FOR YEARS ENDED DECEMBER 31

2003
2002
2001
  Net income  $119,886 $108,948 $104,381 

  Other comprehensive income, net of tax:  
     Unrealized holding losses on marketable securities during the period   (45) (1,359) (1,823)
     Reclassification adjustment for realized gains on marketable securiti    
      included in net income   (1,518) --  (5)
     Minimum pension liability adjustment   (1,122) (2,098) (5,148)
     Transition adjustment for unrealized gain on derivative instruments    
      January 1, 2001   --  --  286,928 
     Unrealized gains (losses) on derivative instruments during the period   8,576  2,853  (131,420)
     Reversal of unrealized (gains) losses on derivative instruments settl    
      during the period   181  31,702  (182,603)
       Deferral related to PCA   (16,055) --  -- 

      Other comprehensive income (loss)   (9,983) 31,098  (34,071)

  Comprehensive income  $109,903 $140,046 $70,310 

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

Puget Sound Energy Consolidated Statements of
          CASH FLOWS
(Dollars in thousands)
FOR YEARS ENDED DECEMBER 31

2002
2001
2000
(DOLLARS IN THOUSANDS)
FOR YEARS ENDED DECEMBER 31

(DOLLARS IN THOUSANDS)
FOR YEARS ENDED DECEMBER 31

2003
2002
2001
Operating activities:              
Net income $108,948 $104,381 $193,831  $119,886 $108,948 $104,381 
Adjustments to reconcile net income  
to net cash provided by operating activities:  
Depreciation and amortization  215,317  208,720  196,513   220,087  215,317  208,720 
Deferred federal income taxes and tax credits - net  140,536  7,151  (7,446)  49,276  140,536  7,151 
Gain from sale of securities  --  --  (6,476)  (2,889) --  -- 
Net unrealized (gains) losses on derivative instruments  (11,612) 3,567  -- 
Net unrealized (gains) losses on derivative instrumen  106  (11,612) 3,567 
Other (including conservation amortization)  18,711  2,375  (7,276)  (6,353) 18,711  2,375 
Cash collateral received from energy supplier  21,425  --  -- 
Cash collateral received from (returned to) energy supplier  (21,425) 21,425  -- 
Pension plan funding  (26,521) --  -- 
Change in certain current assets and current liabilities:  
Accounts receivable and unbilled revenue  61,539  148,393  (220,568)  33,370  61,539  148,393 
Materials and supplies  21,755  8,460  (29,760)  (13,643) 21,755  8,460 
Prepayments and other  (1,501) 2,507  (1,742)  2,622  (1,501) 2,507 
Purchased gas receivable/liability  121,039  58,822  (62,350)
Purchased gas receivable (liability)  (71,826) 121,039  58,822 
Accounts payable  38,893  (247,931) 232,402   12,863  38,893  (247,931)
Taxes payable  (13,646) (33,785) 31,308   17,910  (13,646) (33,785)
Accrued expenses and other  277  21,952  1,847   (4,120) 277  21,952 

Net cash provided by operating activities  721,681  284,612  320,283   309,343  721,681  284,612 

Investing activities:  
Construction expenditures - excluding equity AFUDC  (224,165) (247,435) (296,480)  (269,973) (224,165) (247,435)
Energy conservation expenditures  (11,356) (15,591) (6,931)  (18,579) (11,356) (15,591)
Restricted cash  (18,871) --  --   20,106  (18,871) -- 
Proceeds from sale of investment in Cabot preferred stock  --  --  51,463 
Proceeds from sale of Centralia plant  --  --  37,449 
Proceeds from sale of securities  --  --  6,757   3,161  --  -- 
Investments by InfrastruX  --  --  (85,506)
Repayment from/(loans to) Schlumberger  --  51,948  (20,874)
Repayment from Schlumberger  --  --  51,948 
Other  (14,472) (16,446) (14,138)  3,671  (14,472) (16,446)

Net cash used by investing activities  (268,864) (227,524) (328,260)  (261,614) (268,864) (227,524)

Financing activities:  
Increase (decrease) in short-term debt - net  (307,828) (38,845) (226,395)
Decrease in short-term debt - net  (30,340) (307,828) (38,845)
Dividends paid  (97,321) (141,709) (142,886)  (86,671) (97,321) (141,709)
Issuance of bonds  40,000  --  510,000   304,465  40,000  -- 
Issuance of trust preferred stock  --  200,000  --   --  --  200,000 
Redemption of preferred stock  (7,500) (7,500) (7,503)  (60,000) --  -- 
Redemption of mandatorily redeemable preferred stock  (41,273) (7,500) (7,500)
Redemption of trust preferred stock  (19,750) --  -- 
Redemption of bonds and notes  (117,000) (19,000) (150,980)  (356,860) (117,000) (19,000)
Investment from Puget Energy  115,736  --  --   106,124  115,736  -- 
Other  (137) (3,709) (3,583)  (10,121) (137) (3,709)

Net cash used by financing activities  (374,050) (10,763) (21,347)  (194,426) (374,050) (10,763)

Increase (decrease) in cash from net income  78,767  46,325  (29,324)  (146,697) 78,767  46,325 
Cash at beginning of year  82,708  36,383  65,707   161,475  82,708  36,383 

Cash at end of year $161,475 $82,708 $36,383  $14,778 $161,475 $82,708 

Supplemental Cash Flow Information:  
Cash payments for:  
Interest (net of capitalized interest) $194,876 $187,347 $176,895  $187,256 $194,876 $187,347 
Income taxes (net of refunds)  (81,973) 87,020  114,100   (1,456) (81,973) 87,020 

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


NOTES
        To Consolidated Financial Statements of Puget Energy and Puget Sound Energy

NOTE 1.
        Summary of Significant Accounting Policies

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 is a majority owner of InfrastruX Group, Inc. (InfrastruX),. PSE is a public utility incorporated in the State of Washington corporation.furnishing electric and gas service in a territory covering 6,000 square miles, primarily in the Puget Sound region. InfrastruX is a non-regulated construction service company incorporated in the State of Washington which provides construction services to the electric and gas utility industries primarily in the south/Texas, north-central and eastern United States.
        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 majority interest in InfrastruX. The results of PSE and InfrastruX are presented on a consolidated basis. 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”.Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. Minority interests of InfrastruX’s operating results are reflected in Puget Energy’s consolidated financial statements. Certain amounts previously reported have been reclassified to conform with current yearcurrent-year presentations with no effect on total equity or net income.
        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. The Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q are available at the Securities and Exchange Commission website at www.sec.gov or at Puget Energy’s website at www.pse.com.

UTILITY PLANT
        The costs of additions to utility plant, including renewals and betterments, are capitalized at original cost. Costs include indirect costs such as engineering, supervision, certain taxes, and pension and other employee benefits, and an allowance for funds used during construction. Replacements of minor items of property are included in maintenance expense. The original cost of operating property togetheris charged to accumulated depreciation and costs associated with removal cost,of property, less salvage, is charged to accumulated depreciationthe cost of removal regulatory liability when the property is retired and removed from service.

NON-UTILITY PROPERTY, PLANT AND EQUIPMENT
        The costs of other property, plant and equipment are stated at cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacement of minor items is expensed, on a current basis. Gains and losses on assets sold or retired are reflected in earnings.

ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS
        The Company evaluates impairment of long-lived assets in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 establishes accounting standards for determining if long-lived assets are impaired and how losses, if any, should be recognized. The Company believes that the net cash flows are sufficient to cover the carrying value of theits assets.

DEPRECIATION AND AMORTIZATION
        For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is comprised of software, small tools and office equipment. The depreciation of automobiles, trucks, power-operated equipment and tools is allocated to asset and expense accounts based on usage. The annual depreciation provision stated as a percent of average original cost of depreciable electric utility plant was 2.9% in 2003, 2.9% in 2002 and 3.0% in 2001 and 2.9% in 2000;2001; depreciable gas utility plant was 3.5% in 2003, 3.3% in 2002 and 3.5% in 2001 and 3.3% in 2000;2001; and depreciable common utility plant was 4.7% in 2003, 4.3% in 2002 and 3.1% in 2001 and 1.9% in 2000.2001. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets ranging from 3 to 50 years.


CASH
        All liquid investments with maturities of three months or less at the date of purchase are considered cash. The Company maintains cash deposits in excess of insured limits with certain financial institutions.

MATERIAL AND SUPPLIES
        Material and supplies consists primarily of materials and supplies used in the operation and maintenance of the electric and gas systems, coal, diesel and natural gas held for generation, and natural gas and liquefied natural gas held in storage for future sales. These items are recorded at the lower of cost or market value, primarily using the weighted average cost method.


REGULATORY ASSETS AND AGREEMENTS
        The Company accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”.Regulation.” SFAS No. 71 requires the Company to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. Accounting under SFAS No. 71 is appropriate as long as: rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost-of-service;cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, the Company capitalizes certain costs in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.
        The Company is allowed a return on the net regulatory assets and liabilities of 8.76% for both electric rates beginning July 1, 2002 and gas rates beginning September 1, 2002. The 2001 allowed rate of return was 8.94% for electric rates and 9.15% for gas rates. The net regulatory assets and liabilities at December 31, 20022003 and 2001,2002 included the following:

(Dollars in millions)
REMAINING
AMORTIZATION
PERIOD

2002
2001
(DOLLARS IN MILLIONS)
(DOLLARS IN MILLIONS)
REMAINING
AMORTIZATION
PERIOD

2003
2002
PURPA electric energy supply contract buyout costs 5 to 8 years $227.8$243.6
Deferred income taxes   $167.1$193.0  142.8 167.1
PURPA electric energy supply contract buyout costs 6 to 9 years  243.6 244.6
Investment in BEP exchange contract 14 years  51.1 54.7
Unamortized energy conservation charges 1 to 3 years  8.2 15.2
Investment in Bonneville Exchange Power contract 13 years  47.6 51.1
Environmental remediation *  41.5 41.6
Deferred AFUDC 30 years  30.3 29.9
Tree watch costs 10 years  29.0 26.5
Storm damage costs - electric 4 years  21.9 26.6 4 years  26.0 21.9
Purchased gas receivable/(payable) 1 year  (83.8) 37.2
Deferred AFUDC 30 years  29.9 28.5
Environmental remediation    41.6 14.4
White River relicensing and other costs *  20.8 --
Colstrip common property 20 years  14.6 15.3
PCA mechanism *  3.6 --
Cost of removal **  (124.9) (114.6)
Various other regulatory assets 1 to 21 years  24.4 47.7 1 to 21 years  23.4 27.8
Deferred gains on property sales 3 years  (14.4) (17.3) 3 years  (10.1) (14.4)
Purchased gas payable 1 year  (5.4) (83.8)
Various other regulatory liabilities 1 to 17 years  (5.9) (6.7) 1 to 17 years  (5.2) (5.9)

Net regulatory assets and liabilities   $483.7$637.9 $461.8$406.1

*   Amortization period to be determined.
** The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.

        If the Company, at some point in the future, determines that all or a portion of the utility operations no longer meet the criteria for continued application of SFAS No. 71, the Company would be required to adopt the provisions of SFAS No. 101, “Regulated Enterprises — Accounting for the Discontinuation of Application of FASB Statement No. 71".71.” Adoption of SFAS No. 101 would require the Company to write off the regulatory assets and liabilities related to those operations not meeting SFAS No. 71 requirements. Discontinuation of SFAS No. 71 could have a material impact on the Company’s financial statements.
        The Company, in prior years, incurredIncluded within the regulatory assets are deferred costs associated with its 5% interestgas supply contracts with Tenaska and Cabot of $216.7 million and $11.0 million, respectively, at December 31, 2003. These regulatory assets were designed to be recovered in future rates. In the power cost only rate case, the Washington Commission staff has identified a now-terminated nuclear generating project (identified hereinportion of these assets as Investment in Bonneville Exchange Power (BEP)). Under termsa possible disallowance for future rate recovery based on an interpretation of a settlement agreement1994 Washington Commission order by the Washington Commission staff. The Company believes the disallowance proposed by the Washington Commission staff is legally and actually deficient. The power cost only rate case order from the Washington Commission is expected in mid-April 2004.
        In accordance with guidance provided by the Bonneville Power Administration (BPA), which settled claims ofSecurities and Exchange Commission, the Company relatingreclassified from accumulated depreciation to construction delays associated with that project, the Company is receiving powera regulatory liability $124.9 million and $114.6 million in 2003 and 2002, respectively, for non-legal cost of removal for utility plant. These amounts are collected from the federal power system resources marketed by BPA. The Company’s remaining investment in BEP is included in rate base and amortized on a straight-line basis over the life of the settlement agreement (amortization is included in purchased electricity expense). The Company has regulatory assets of approximately $243.6 million related to the buyout of purchased power and gas sales contracts of two non-utility generation projects. Washington Commission accounting orders have approved payments pursuant to these contracts for deferral and collection in rates over the remaining life of the energy supply contracts.PSE’s customers through depreciation expense.


ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
        The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant and is credited as a non-cash item to other income and interest charges currently. Cash inflow related to AFUDC does not occur until these charges are reflected in rates.


        The AFUDC rate allowed by the Washington Commission for gas utility plant additions was 8.76% beginning September 1, 2002 and 9.15% in 2001 and 2000.2001. The allowed AFUDC rate on electric utility plant was 8.76% beginning July 1, 2002 and 8.94% in 2001 and 2000.2001. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, the Company capitalizes the excess as a deferred asset, crediting miscellaneous income. The amounts included in income were $1.6 million for 2003, $2.6 million for 2002 and $2.7 million for 2001 and $2.8 million for 2000.2001. The deferred asset is being amortized over the average useful life of the Company'sCompany’s non-project utility plant.

REVENUE RECOGNITION
        Operating utility revenues are recorded on the basis of service rendered, which includes estimated unbilled revenue. Non-utility subsidiaries recognize revenue when services are performed, upon the sale of assets or on a percent of completion basis for fixed priced contracts.

ALLOWANCE FOR DOUBTFUL ACCOUNTS
        Allowance for doubtful accounts is calculated based upon historical write-offs as compared to operating revenues. The Company has also provided for a reserve for fiscal 2000 sales transactions related to the California Independent System Operator and counterparties based upon probability of collection. Puget Energy’s allowance for doubtful accounts for 2003 and 2002 and 2001 was $45.4$45.8 million and $47.0$45.4 million, respectively. PSE’s allowance for doubtful accounts for 2003 and 2002 and 2001 was $43.5$44.0 million and $45.2$43.5 million, respectively.

RESTRICTED CASH
        Restricted cash represents cash to be used for specific purposes. Approximately $17.8 million in restricted cash was received from BPA under the amended Residential Purchase and Sale Agreement for residential and small farm customers who receive a credit on their bills for the Residential and Farm Energy Exchange credit tariff. The restricted amount is the excess paid by the BPA over the credit provided to these customers. All funds received will be credited to these customers in the future. Approximately $1.1 million in restricted cash wasrepresents funds held by Puget Western, a PSE subsidiary, for a real estate development project that a city requires to ensure work is completed either by the Company or by the city. Approximately $1.4 million in restricted cash represents funds held for payment of principal and interest for conservation trust debt.

SELF-INSURANCE
        The Company currently has no insurance coverage for storm damage and is self-insured for a portion of the risk associated with comprehensive liability, industrial accidentsworkers’ compensation claims and catastrophic property losses.losses other than storm related. With approval of the Washington Commission, PSE is able to defer for collection in future rates certain uninsured storm damage costs associated with major storms.

FEDERAL INCOME TAXES
        The Company normalizes, with the approval of the Washington Commission, certain income tax items. Deferred taxes have been determined under SFAS No. 109. Investment tax credits are deferred and amortized based on the average useful life of the related property in accordance with regulatory and income tax requirements. (See Note 11.)

ENERGY CONSERVATION
        The Company offers programs designed to help new and existing customers use energy efficiently. The primary emphasis is to provide information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices.
        Since May 1997, the Company has recovered electric energy conservation expenditures through a tariff rider mechanism. The rider mechanism allows the Company to defer the conservation expenditures and amortize them to expense as PSE concurrently collects the conservation expenditures in rates over a one-year period. As a result of the rider, there is no effect on earnings per share.
        Since 1995, the Company has been authorized by the Washington Commission to defer gas energy conservation expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows the Company to defer conservation expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows the Company to recover an Allowance for Funds Used to Conserve Energy (AFUCE) on any outstanding balance that is not being recovered in rates.


RATE ADJUSTMENT MECHANISMMECHANISMS
        The Company has a Power Cost Adjustmentpower cost adjustment (PCA) mechanism that provides for an automatic rate adjustment 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 Company’s cumulative maximum pre-tax earnings exposure due to power cost variations over the four yearfour-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. All significant variable power supply cost drivers are included in the power cost adjustmentPCA 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). The mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers.
Any unrealized gains and losses from derivative instruments accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” are deferred in proportion to the cost-sharing arrangement under the PCA once the Company reaches its cap of $40 million.


        The differences between the actual cost of the Company’s gas supplies and gas transportation contracts and that currently allowed by the Washington Commission are deferred and recovered or repaid through the purchased gas adjustment (PGA) mechanism.

        The graduated scale is as follows:

Annual Power Cost Variability
Customer’s Share
Company's Share1
+/- $20 million 0%100%
+/- $20 million - $40 million 50%50%
+/- $40 million - $120 million 90%10%
+/- $120+ million 95%5%

NATURAL GAS OFF-SYSTEM SALES AND CAPACITY RELEASE
        The Company contracts for firm gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for gas for space heating by its firm customers. Due to the variability in weather and other factors, however, the Company holds contractual rights to gas supplies and transportation and storage capacity in excess of its immediate requirements to serve firm customers on its distribution system for much of the year which, therefore, are available for third-party gas sales, exchanges and capacity releases. The Company sells excess gas supplies, enters into gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate gas pipeline capacity and gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core gas customers. The proceeds from such activities, net of transactional costs, from such activities are accounted for as reductions in the cost of purchased gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, the Company does not reflectnets the sales revenue orand associated cost of sales for these transactions in its income statement.purchased gas.

ENERGY RISK MANAGEMENT
        The Company’s energy related businesses are exposed to risks related to changes in commodity prices and volumetric changes in its loads and resources. The Company’s energy risk management function manages the Company’s core electric and gas supply portfolios to achieve three primary objectives:

(i)

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

(ii)

Manage portfolio risks to limit undesired impacts on financial results; and

(iii)

Optimize the value of energy supply assets.


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 energy supply assets.

        The Company enters into physical and financial instruments for the purpose of hedging commodity price risk. Gains or losses on these derivatives are accounted for pursuant to SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 138.138 and SFAS No. 149. (See Note 1715 for further discussion.) The Company has established policies and procedures to manage these risks. A Risk Management Committee separate from the business units that create these risks monitors compliance with policies and procedures. In addition, the Audit Committee of the Company’s Board of Directors has oversight of the Risk Management Committee.


ACCOUNTING FOR DERIVATIVES
        On January 1, 2001, theThe Company adoptedfollows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138.138 and SFAS No. 133149, which requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. Under SFAS No. 149, any purchases from trading companies are now required to be marked-to-market if the party does not have physical plant to back up the transaction. This adoption did not have a significant effect on the Company in 2003. Certain contracts that would otherwise be considered derivatives are exempt from this SFAS No. 133 if they qualify for a normal purchase and normal sale exception. The Company enters into both physical and financial contracts to manage its energy resource portfolio. The majority of these contracts qualify for the normal purchase and normal sale exception. However, certain of these contracts are derivatives and, pursuant to SFAS No. 133, are reported at their fair value in the balance sheet. Changes in their fair value are reported in earnings unless they meet specific hedge accounting criteria, in which case changes in their fair market value are recorded in comprehensive income until the time when the transaction that they are hedging is recorded as income. The Company designates a derivative instrumentsinstrument as a qualifying cash flow hedge if the change in the fair value of the derivative is highly effective at offsetting the changes in the fair value of an asset, a liability or a forecasted transaction. To the extent that a portion of a derivative designated as a hedge is ineffective, changes in the fair value of the ineffective portion of that derivative are recognized currently in earnings. Finally, changesChanges in the market value of derivative transactions related to obtaining gas for the Company’s retail gas business are deferred as regulatory assets or liabilities as a result of the Company’s PGA mechanism and recorded in earnings as the transactions are executed. In addition, once the Company reaches the $40 million PCA cap, any unrealized gains or losses are deferred in proportion to the cost-sharing arrangement under the PCA.


1Over the four-year period July 1, 2002 through June 30, 2006, the Company's share of per-tax cost variation is capped at a cumulative $40 million plus 1% of the excess.


STOCK-BASED COMPENSATION
        The Company has various stockstock-based compensation plans which are described more fully in Note 14. As allowed by SFAS No. 123, “Accountingprior to 2003 were accounted for Stock-Based Compensation”, the Company accounts for the plans according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.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 exercise price of stock options granted was the market value of the stock on the date of grant, so no compensation expense was recorded in the income statement for the options. There was, however, compensation expense relatedCompany will apply SFAS No. 123 accounting prospectively to other stock compensation plans.awards granted in 2003 and future years, while grants that were made in years prior to 2003 will 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:

Years Ended December 31; (Dollars in thousands, except per share)
2002
2001
2000
Income for common stock, as reported  $110,052 $98,426 $184,837 
Add: Total stock-based employee compensation expense included in   4,103  1,352  2,553 
          net income, net of tax           
Less: Total stock-based employee compensation expense per the   (3,495) (2,429) (1,941)
          fair value method of SFAS 123, net of tax           

Pro forma income for common stock  $110,660 $97,349 $185,449 

Earnings per share:  
  ��Basic and diluted as reported  $1.24 $1.14 $2.16 
   Basic pro forma  $1.25 $1.13 $2.17 
   Diluted pro forma  $1.25 $1.12 $2.16 

(Dollars in thousands, except per share amounts)
Years Ended December 31

2003
2002
2001
Income for common stock, as reported  $116,197 $110,052 $98,426 
Add: Total stock-based employee compensation expense included  
      in net income, net of tax   4,180  4,103  1,352 
Less: Total stock-based employee compensation expense per the fair  
      value method of SFAS No. 123, net of tax   (3,314) (3,495) (2,429)
 
Pro forma income for common stock  $117,063 $110,660 $97,349 
 
Earnings per share:  
   Basic as reported  $1.23$1.24 $1.14 
   Diluted as reported  $1.22 $1.24 $1.14 
   Basic pro forma  $1.24 $1.24 $1.13 
   Diluted pro forma  $1.23 $1.25 $1.12 

DEBT RELATED COSTS
        Debt premium, discountpremiums, discounts and expenses are amortized over the life of the related debt. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment.

GOODWILL AND INTANGIBLES (PUGET ENERGY ONLY)
        On January 1, 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result Puget Energy ceased amortization of goodwill. During 2001, Puget Energy recorded approximately $2.8 million of goodwill amortization. Puget Energy performed an initial impairment review of goodwill and an annual impairment review thereafter. The initial review was completed during the first half of 2002, which did not result in an impairment charge. Goodwill is reviewed annually to determine if any impairment exists. If goodwill is determined to have an impairment, Puget Energy would record in the period of determination an impairment charge to earnings. Intangibles with finite lives are amortized on a straight-line basis over the expected periods to be benefited. For those acquisitions occurring subsequent to June 30, 2001, there was no amortization of goodwill. For acquisitions made prior to June 30, 2001, goodwill and intangibles were amortized on a straight-line basis over the expected periods to be benefited, up to 30 years through December 31, 2001. The goodwill and intangibles recorded on the balance sheet of Puget Energy are the result of InfrastruX acquiringseveral acquisitions of companies during 2000 through 2002.by InfrastruX.


EARNINGS PER COMMON SHARE (PUGET ENERGY ONLY)
        Basic earnings per common share has been computed based on weighted average common shares outstanding of 94,750,000, 88,372,000 and 86,445,000 for 2003, 2002 and 85,411,000 for 2002, 2001, and 2000, respectively. Diluted earnings per common share has been computed based on weighted average common shares outstanding of 95,309,000, 88,777,000 and 86,703,000 for 2003, 2002 and 85,690,000 for 2002, 2001, and 2000 respectively, which includes the dilutive effect of securities related to employee stock-based compensation plans.

ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM
        Rainier Receivables, Inc., is a wholly owned, bankruptcy-remote subsidiary of PSE formed in December 2002 for the purpose of purchasing customers’ accounts receivable, both billed and unbilled, of PSE. Rainier Receivables and PSE have an agreement whereby Rainier Receivables can sell, on a revolving basis, up to $150.0$150 million of those receivables. The current agreement expires in December 2005. Rainier Receivables is obligated to pay fees that approximate the third partythird-party purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. At December 31, 2002, there were2003, Rainier Receivables sold $111 million of receivables compared to no borrowings outstanding under the receivable securitization program.sales at December 31, 2002.


NEW ACCOUNTING PRONOUNCEMENTS
        In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46)., which was further revised in December 2003 with FIN 46 clarifies46R, which clarified the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements”Statements,” to certain entities in which equity investors do not have a controlling interest or sufficient equity at risk for the entity to finance its activities without additional financial support. This Interpretation 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 adoption of this Interpretation for all interests in variable interest entities created after January 31, 2003 is effective immediately. For variable interest entities created before February 1, 2003, it is effective July 1, 2003. The Company ishas evaluated its contractual arrangements and determined PSE’s 1995 conservation trust off-balance sheet financing transaction meets this guidance, and therefore it was consolidated in the processthird quarter of determining2003. As a result, electricity revenues for 2003 increased $5.7 million, while conservation amortization and interest expense increased by the impactscorresponding amount with no impact on earnings. At December 31, 2003, the balance sheet assets and liabilities increased by $4.2 million. FIN 46R also impacted the treatment of this Interpretation.the Company’s mandatorily redeemable preferred securities of a wholly owned subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities (junior subordinated debt) in the fourth quarter of 2003. This change had no impact on the Company’s results of operations for 2003. The Company is evaluating its purchase power agreements and any other agreements to determine if FIN 46R will have an impact on the financial statements.
        On January 1, 2002,In May 2003, the FASB issued SFAS No. 142, “Goodwill150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes the requirements for classifying and measuring as liabilities certain financial instruments that embody obligations to redeem the financial instruments by the issuer. The adoption of SFAS No. 150 is effective with the first fiscal year or interim period beginning after June 15, 2003. However, on November 5, 2003 the FASB deferred for an indefinite period certain mandatorily redeemable noncontrolling interests associated with finite-lived subsidiaries. The Company does not have any noncontrolling interest in finite-lived subsidiaries and therefore, is not affected by the deferral. Prior periods will not be restated for the new presentation.
        SFAS No. 150 requires the Company to classify its mandatorily redeemable preferred stock as liabilities. As a result, the corresponding dividends on the mandatorily redeemable preferred stock are classified as interest expense on the income statement with no impact on income for common stock.
        In December 2003, SFAS No. 132, “Employers’ Disclosures about Pensions and Other Intangible Assets” becamePostretirement Benefits” (SFAS No. 132R), was revised to include various additional disclosure requirements. SFAS No. 132R is effective and as a result, Puget Energy ceased amortization of goodwill. During 2001, Puget Energy recorded approximately $2.8 million of goodwill amortization. Puget Energy performed an initial impairment review of goodwill and an annual impairment review thereafter. The initial review was completed during the first half of 2002, which did not result in an impairment charge. Puget Energy then performed its annual impairment review as of October 31, 2002 and determined that its goodwill was not impaired.for fiscal years ending after December 15, 2003. (See Note 12.)
        In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company will adoptadopted the new rules on asset retirement obligations on January 1, 2003. ApplicationAs a result, the Company recorded a $0.2 million charge to income for the cumulative effect of the new rules is not expected to result in a material increase in net property, plant and equipment or expense.


this accounting change. (See Note 2.)
        The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF or Task Force) at its June 2002July 2003 meeting came to a consensus on one of three items included inconcerning EITF Issue 02-3 “AccountingNo. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Contracts InvolvedTrading Purposes’ as Defined in Energy Trading and Risk Management Activities” (EITF 02-3).Issue No. 02-03.” The Task Force has agreedconsensus reached was that all mark-to-marketdetermining whether realized gains and losses on energyphysically settled derivative contracts not held for trading contracts whether realized or unrealized will be shown netpurposes reported in the income statement (costs offset against revenues), irrespectiveon a gross or net basis is a matter of whetherjudgment that depends on the contract is physically settled. The presentation is applicable to financial statements for periods ending after July 15, 2002. The Company performs risk management activities to optimizerelevant facts and circumstances. Based on the value of energy supply and transmission assets and to ensure that physical energy supply is available to meet the customer demand loads. The Company also purchases energy when demand exceeds available supplies in its portfolio; likewiseguidance by EITF No. 03-11, the Company makes sales to other utilities and marketers when surplus energy is available. These transactions are part of the Company’s normal operations to meet retail load. The Company has reclassified all settled transactionsdetermined that meet the definition of optimization (trading transactions that optimize hydro resources, and purchases and sales between trading points) net in the income statement to conform to the new presentation required under EITF 02-3. The Company previously reported these transactions when settled in a gross manner in the income statement in electric operating revenue and purchased electricity expense. Unrealized gains or losses onits non-trading derivative instruments that are required toshould be marked-to-market remain reflected in unrealized (gain) loss on derivative instruments on Puget Energy’s and PSE’s income statement as required by SFAS No. 133. The adoption of EITF 02-3 does not have any impact on the previously reported net income of the Company. The following optimization transactions were recorded in electric operating revenue:and will implement this treatment effective January 1, 2004.

Years Ended December 31; (Dollars in thousands)
2002
2001
2000
Optimization sales  $66,992 $492,447 $133,361 
Optimization purchases   64,448  487,431  139,376 

Net margin on optimization transactions  $2,544 $5,016 $(6,015)


NOTE 2.
        Utility and Non-Utility Plant

        Utility plant at December 31, 2002 and 2001 included the following:

(Dollars in thousands)
At December 31

2002
2001
  Electric, gas and common utility plant classified by       
       prescribed accounts at original cost:  
    Distribution plant  $3,911,725 $3,736,590 
    Production plant   1,126,173  1,117,099 
    Transmission plant   368,959  361,662 
    General plant   365,409  376,119 
    Construction work in progress   108,658  123,307 
    Plant acquisition adjustment   76,623  76,623 
    Intangible plant (including capitalized software)   260,043  255,619 
    Underground storage   22,291  21,872 
    Liquefied natural gas   644  -- 
    Plant held for future use   8,729  8,331 
    Other   4,807  4,807 
    Less accumulated provision for depreciation   (2,337,832) (2,194,048)

       Net utility plant  $3,916,229 $3,887,981 


        Non-utility plant and intangibles at December 31, 2002 and 2001 included the following:

(Dollars in thousands)
At December 31

2002
2001
  Non-utility plant  $100,481 $58,318 
  Intangibles   21,933  18,004 
  Less accumulated depreciation and amortization   (22,907) (11,894)

       Net non-utility plant and intangibles  $99,507 $64,428 

UTILITY PLANT
(DOLLARS IN THOUSANDS)
At December 31

2003
2002
  Electric, gas and common utility plant classified      
       prescribed accounts at original cost:  
    Distribution plant  $4,030,570 $3,911,725 
    Production plant   1,144,354  1,126,173 
    Transmission plant   379,889  368,959 
    General plant   344,781  365,409 
    Construction work in progress   121,622  108,658 
    Plant acquisition adjustment   76,623  76,623 
    Intangible plant (including capitalized software   270,235  260,043 
    Underground storage   22,362  22,291 
    Liquefied natural gas storage   2,348  644 
    Plant held for future use   7,608  8,729 
    Other   5,240  4,807 
    Less accumulated provision for depreciation   (2,325,405) (2,223,190)

       Net utility plant  $4,080,227 $4,030,871 


NON-UTILITY PLANT
(DOLLARS IN THOUSANDS)
At December 31

2003
2002
  Non-utility plant  $122,926 $100,481 
  Intangibles   23,985  21,933 
  Less accumulated depreciation and amortizati   (36,272) (22,907)

       Net non-utility plant and intangibles  $110,639 $99,507 

        The non-utility plant is composed primarily of the property, plant and equipment of InfrastruX. The intangibles are composed of patents, contractual customer relationships and other amortizable intangible assets of InfrastruX.
        On January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that 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 recorded an after-tax charge to income of $0.2 million in the first quarter of 2003 for the cumulative effect of the accounting change. In accordance with guidance provided by the Securities and Exchange Commission, the Company reclassified $124.9 million in 2003 and $114.6 million in 2002 for non-legal cost of removal on utility plant from accumulated depreciation to a regulatory liability. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
        The Company identified various asset retirement obligations at January 1, 2003, which were included in the cumulative effect of the accounting change. 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 renegotiations 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; and (4) to restore ash holding ponds at a jointly owned coal-fired electric generating facility in Montana.


        The following table describes all changes to the Company’s asset retirement obligation liability during 2003:

(DOLLARS IN THOUSANDS)
AT DECEMBER 31, 2003

Amount
Asset retirement obligation at December 31, 2002  $-- 
Liability recognized in transition   3,592 
Liability settled in the period   (261)
Accretion expense   90 

Asset retirement obligation at December 31, 2003  $3,421 

        The pro forma asset retirement obligation liability balances as if SFAS No. 143 had been adopted on January 1, 2000 (rather than January 1, 2003) are as follows:

(DOLLARS IN THOUSANDS)

Pro forma amounts of liability for asset retirement obligation at December 31, 2000$3,405
Pro forma amounts of liability for asset retirement obligation at December 31, 20013,497
Pro forma amounts of liability for asset retirement obligation at December 31, 20023,592

        The pro forma income statement effect as if SFAS No. 143 had been adopted on January 1, 2000 (rather than January 1, 2003) is as follows:

(Dollars in thousands, except per share amounts)
2003
2002
2001
Income for common stock, as reported  $116,197 $110,052 $98,426 
Add: SFAS No. 143 transition adjustment, net of tax   169  --  -- 
Less: Pro forma accretion expense, net of tax   --  (62) (60)

Pro forma income for common stock  $116,366 $109,990 $98,366 

Earnings per share:  
   Basic as reported  $1.23 $1.24 $1.14 
   Diluted as reported  $1.22 $1.24 $1.14 
   Basic pro forma  $1.23 $1.24 $1.14 
   Diluted pro forma  $1.22 $1.24 $1.13 

NOTE 3.
        Preferred Stock

 PREFERRED STOCK
 
NOT SUBJECT TO
MANDATORY
REDEMPTION
$25 PAR VALUE

SUBJECT TO
MANDATORY
REDEMPTION
$100 PAR VALUE

Shares outstanding December 31, 1999
2,400,000 
656,619 
Acquired for sinking fund:  
   2000--(75,000)
   2001--(75,000)
   2002
--
(75,000)
Called for redemption or reacquired and canceled:  
   2000----
   2001  
   2002
--
--
Shares outstanding December 31, 2002
2,400,000 
431,619 

See “Consolidated Statements        On November 1, 2003, all the outstanding 2.4 million shares of Capitalization” for details on specific series.


        Thethe $25 par value 7.45% Series Preferredpreferred stock not subject to mandatory redemption may bewere redeemed at par on or after November 1, 2003.

PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
        The Company is required to deposit funds annually in a sinking fund sufficient to redeem the following number of shares of each series of preferred stock at $100 per share plus accrued dividends: 4.70% Series and 4.84% Series, 3,000 shares each and 7.75% Series, 37,500 shares. All previous sinking fund requirements have been satisfied. At December 31, 2002, there were 40,689 shares of the 4.70% Series and 24,192 shares of the 4.84% Series acquired by the Company and available for future sinking fund requirements. Upon involuntary liquidation, all preferred shares are entitled to their par value plus accrued dividends.
        The There were no other redemptions or reacquired shares of this preferred stock subject to mandatory redemption may also be redeemed by the Company at the following redemption prices per share plus accrued dividends: 4.70% Series, $101.00 and 4.84% Series, $102.00. The 7.75% Series may be redeemed by the Company, subject to certain restrictions, at $102.58 per share plus accrued dividends through February 15, 2003, and at per share amounts which decline annually to a price of $100 after February 15, 2007.

COMPANY-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES
        In 1997 and 2001, the Company formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling common and preferred securities (Trust Securities). The proceeds from the sale of Trust Securities were used to purchase Junior Subordinated Debentures (Debentures) from the Company. The Debentures are the sole assets of the Trusts and the Company owns all common securities of the Trusts.
        The Debentures of Trust I and Trust II have an interest rate of 8.231% and 8.40%, respectively, and a stated maturity date of June 1, 2027 and June 30, 2041, respectively. The Trust Securities are subject to mandatory redemption at par on the stated maturity date of the Debentures. The Trust Securitiesseries in the Capital Trust I may be redeemed earlier, under certain conditions, at the option of the Company. The Capital Trust II Securities may be redeemed at any time on2002 or after June 30, 2006 at par, under certain conditions, at the option of the Company. Dividends relating to preferred securities are included in interest expense. On February 26, 2003, the Company repurchased 19,750 shares of the 8.231% Trust Securities.2001.


NOTE 4.
Preferred Share Purchase Right

        On October 23, 2000, the Board of Directors declared a dividend of one preferred share purchase right (a Right) for each outstanding common share of Puget Energy. The dividend was paid on December 29, 2000 to shareholders of record on that date. The Rights will become exercisable only if a person or group acquires 10% or more of Puget Energy’s outstanding common stock or announces a tender offer which, if consummated, would result in ownership by a person or group of 10% or more of the outstanding common stock. Each rightRight will entitle the holder to purchase from Puget Energy one one-hundredth of a share of preferred stock with economic terms similar to that of one share of Puget Energy’s common stock at a purchase price of $65, subject to adjustments. The Rights expire on December 21, 2010, unless earlier redeemed or exchanged by Puget Energy.


NOTE 5.
        Dividend Restrictions

        The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in the Company’s Articles of Incorporation and Mortgage Indentures. Under the most restrictive covenants of PSE, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $202.7$235.9 million at December 31, 2002.2003. For the years 2003, 2002 and 2001, the aggregate dividends declared per share were $1.00, $1.21 and $1.84, respectively.
        Under the general rate settlement, PSE must rebuild its common equity ratio to at least 39%, with milestones of 34%, 35% and 39% at the end of 2003, 2004 and 2005, respectively. If PSE should fail to meet the schedule, it would be subject to a 2% rate reduction penalty. The common equity ratio for PSE at December 31, 20022003 was 36.1%40.0%.

NOTE 6.
Redeemable Securities

 PREFERRED STOCK SUBJECT TO
MANDATORY REDEMPTION $100 PAR VALUE

 
4.70%
SERIES

4.84%
SERIES

7.75%
SERIES

SHARES OUTSTANDING DECEMBER 31, 2000 4,311 14,808 562,500 

Acquired for sinking fund       
2001 -- -- (75,000)
2002��-- -- (75,000)
2003 -- -- (75,000)

Called for redemption or reacquired and canceled:    
2001 -- -- -- 
2002 -- -- -- 
2003 -- (225)(337,500)

Shares outstanding December 31, 2003 4,311 14,583 -- 

See “Consolidated Statements of Capitalization” for details on specific series.

PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
        The Company is required to deposit funds annually in a sinking fund sufficient to redeem the following number of shares of each series of preferred stock at $100 per share plus accrued dividends: 4.70% Series and 4.84% Series, 3,000 shares each and 7.75% Series, 37,500 shares. All previous sinking fund requirements have been satisfied. The $100 par value 7.75% Series preferred stock subject to mandatory redemption was fully redeemed at $102.07 per share plus accrued dividends on August 15, 2003. At December 31, 2003, there were 37,689 shares of the 4.70% Series and 21,192 shares of the 4.84% Series acquired by the Company and available for future sinking fund requirements. Upon involuntary liquidation, all preferred shares are entitled to their par value plus accrued dividends.
        The preferred stock subject to mandatory redemption may also be redeemed by the Company at the following redemption prices per share plus accrued dividends: 4.70% Series, $101.00 and 4.84% Series, $102.00.

JUNIOR SUBORDINATED DEBENTURES OF THE CORPORATION PAYABLE TO A SUBSIDIARY TRUST HOLDING MANDATORILY REDEEMABLE PREFERRED SECURITIES
        In 1997 and 2001, the Company formed Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, for the sole purpose of issuing and selling common and preferred securities (Trust Securities). The proceeds from the sale of Trust Securities were used to purchase Junior Subordinated Debentures (Debentures) from the Company. The Debentures are the sole assets of the Trusts and the Company owns all common securities of the Trusts.
        The Debentures of Trust I and Trust II have an interest rate of 8.231% and 8.40%, respectively, and a stated maturity date of June 1, 2027 and June 30, 2041, respectively. The Trust Securities are subject to mandatory redemption at par on the stated maturity date of the Debentures. The Trust Securities in the Capital Trust I may be redeemed earlier, under certain conditions, at the option of the Company. The Capital Trust II Securities may be redeemed at any time on or after June 30, 2006 at par, under certain conditions, at the option of the Company. Dividends relating to preferred securities are included in interest expense for all periods presented. On February 26, 2003, the Company repurchased 19,750 shares of the 8.231% Trust Securities.


NOTE 6.7.
        Long-Term Debt

FIRST MORTGAGE BONDS AND SENIOR NOTES
AT DECEMBER 31 (Dollars in thousands)(DOLLARS IN THOUSANDS)

SERIESDUE2002 2001 SERIESDUE2002 2001    DUE          2003        2002     SERIES      DUE          2003        2002 
7.07%2002$         -- $  27,000 6.51%2008$       1,000 
7.15%2002-- 5,000 6.53%20083,500 
7.53%2002-- 10,000 7.61%200825,000 
7.625%2002-- 25,000 6.46%2009150,000 
7.85%2002-- 30,000 6.61%20093,000 
7.91%2002-- 20,000 6.62%20095,000 
6.20%20033,000 7.12%20107,000 2003$         -- $   3,000  7.61%2008$  25,000 
6.23%20031,500 7.96%2010225,000 2003-- 1,500  6.46%2009150,000 
6.24%20031,500 7.69%2011260,000 2003-- 1,500  6.61%20093,000 
6.30%200320,000 8.20%201230,000 2003-- 20,000  6.62%20095,000 
6.31%20035,000 8.59%20125,000 2003-- 5,000  7.12%20107,000 
6.40%200311,000 6.83%20133,000 2003-- 11,000  7.96%2010225,000 
7.02%200330,000 6.90%201310,000 2003-- 30,000  7.69%2011260,000 
6.25%200440,000 -- 7.35%201510,000 2004-- 40,000  8.20%2012-- 30,000 
6.07%200410,000 7.36%20152,000 200410,000  8.59%2012-- 5,000 
6.10%20048,500 6.74%2018200,000 20048,500  6.83%20133,000 
7.70%200450,000 9.57%202025,000 200450,000  6.90%201310,000 
7.80%200430,000 8.25%202225,000 200430,000  7.35%201510,000 
6.92%200511,000 8.39%20227,000 200511,000  7.36%20152,000 
6.93%200520,000 8.40%20223,000 200520,000  6.74%2018200,000 
6.58%200610,000 7.19%20233,000 200610,000  9.57%202025,000 
8.06%200646,000 7.35%202455,000 200646,000  8.25%2022-- 25,000 
8.14%200625,000 7.15%202515,000 200625,000  8.39%2022-- 7,000 
7.02%200720,000 7.20%20252,000 200720,000  8.40%2022-- 3,000 
7.04%20075,000  7.19%2023-- 3,000 
7.75%2007100,000 7.02%2027300,000 2007100,000  7.35%202455,000 
7.04%20075,000 7.00%2029100,000 
8.40%200710,000 Total $1,932,000 $2,009,000 2007-- 10,000  7.15%202515,000 
3.363%2008150,000 --  7.20%20252,000 
6.51%20081,000  7.02%2027300,000 
6.53%20083,500  7.00%2029    100,000 
  Total $1,887,000$1,932,000

        In January 2002,June 2003, the Company issued $40.0$150 million of First Mortgage Bondsin first mortgage bonds, which are due June 2008. In January 2004. In February 2002,2004, the Company filed a shelf-registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $500 million of any combination of common stock of Puget Energy and principal amount of Senior Notes secured by a pledge of First Mortgage Bonds, Unsecured Debentures or Trust Preferred Securities. In February 2003, thefirst mortgage bonds. The Company notified investors of its intent to call threecalled and paid off 15 series of first mortgage bonds in 2003, totaling $20$195 million. The Company will repayrepaid the bonds using cash on hand.
        Substantially all utility properties owned by the Company are subject to the lien of the Company’s electric and gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must be at least twice the annual interest charges on outstanding first mortgage bonds. At December 31, 2002,2003, the earnings available for interest were 2.42.9 times the annual interest charges.


POLLUTION CONTROL BONDS
        The Company has outstanding threetwo series of Pollution Control Bonds. On February 19, 2003, the Board of Directors approved the refinancing of all Pollution Control Bonds series. The new series were issued in March 2003. Amounts outstanding were borrowed from the City of Forsyth, Montana (the City). The City obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 and 4.
        Each series of bonds is collateralized by a pledge of PSE’s First Mortgage Bonds,first mortgage bonds, the terms of which match those of the Pollution Control Bonds. No payment is due with respect to the related series of First Mortgage Bondsfirst mortgage bonds so long as payment is made on the Pollution Control Bonds.

At December 31 (Dollars in thousands)
AT DECEMBER 31 (DOLLARS IN THOUSANDS)
SERIES
DUE2003       2002 

SERIES  DUE   2002  2001 

2003A Series - 5.00%2031$138,460 $         --  
2003B Series - 5.10%2031    23,400 --  
1993 Series - 5.875% 2020 $23,460 $23,460 2020-- 23,460  
1991 Series - 7.05% 2021  27,500  27,500 2021-- 27,500  
1991 Series - 7.25% 2021  23,400  23,400 2021-- 23,400  
1992 Series - 6.80% 2022  87,500  87,500 2022-- 87,500  



Total $161,860 $161,860  $161,860 $161,860  



On February 19,CONSERVATION TRUST FINANCINGS
        In July 2003, FIN 46 required PSE to consolidate the Board of Directors approved the refinancing of all Pollution Control Bonds series. It is anticipated that the refinancing1995 Conservation Trust Transaction. The balance of the Pollution Control Bonds6.45% bonds was $4.2 million at December 31, 2003, and they will be completedmature in March or April 2003.

2004.

LONG-TERM REVOLVING CREDIT FACILITY (PUGET ENERGY ONLY)
        Puget Energy has a $15.0 million revolving credit facility available through a local bank. At December 31, 2003, there was $5.0 million outstanding at a weighted average interest rate of 2.86%, leaving $10.0 million available under the facility. Puget Energy is the guarantor of this credit facility.
        InfrastruX and its subsidiaries have signed credit agreements with several banks for up to $179.8$184.7 million, which expire in 20032004 and 2004.2005. Under the InfrastruX credit agreement, Puget Energy is the guarantor of $150.0 million of the line of credit. InfrastruX has borrowed $144.0$155.6 million at a weighted average interest rate of 3.27%2.61%, leaving a balance of $35.8$29.1 million available under the lines of credit at December 31, 2002.

2003. InfrastruX also has $19.3 million in equipment financing agreements with various vendors. These agreements mature at various dates from 2004 to 2009 and carry interest rates from 0% to 9.65%.

LONG-TERM DEBT MATURITIES
        The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:

PUGET ENERGY
(Dollars in thousands)
 2003
 2004
 2005
 2006
 2007
 Thereafter
 
Maturities of: 
  Long-term debt $73,206 $265,848 $31,525 $81,000 $135,000 $1,636,360 
PUGET ENERGY
(DOLLARS IN THOUSANDS)

2004
2005
2006
2007
2008
Thereafter 
Maturities Of:
   Long-term debt
$246,829$37,526$90,771$127,404$179,896$1,533,892 

PUGET SOUND ENERGY
(Dollars in thousands)
 2003
 2004
 2005
 2006
 2007
 Thereafter
 
Maturities of: 
  Long-term debt $72,000 $138,473 $31,000 $81,000 $135,000 $1,636,360 
PUGET SOUND ENERGY
(DOLLARS IN THOUSANDS)

2004
2005
2006
2007
2008
Thereafter 
Maturities Of:
   Long-term debt
$102,658$31,000$81,000$125,000$179,500$1,533,847 

NOTE 7.8.
Liquidity Facilities and Other Financing Arrangements

        At December 31, 2002,2003, PSE had short-term borrowing arrangements that included a $250 million unsecured 364-day line of credit with various banks and a $150 million 3-yearthree-year receivables securitization program. These agreements replaced a $375 million line of credit, which would have expired on February 13, 2003. The new agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The line of credit allows the Company to make floating rate advances at prime plus a spread and Eurodollar advances at LIBOR plus a spread. The agreement contains “credit sensitive” pricing with various spreads associated with various credit rating levels. The agreement also allows for drawing letters of credit up to $50 million.
        PSE has 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 sells all of its utility customer accounts receivable and unbilled utility revenues to Rainier Receivables. In addition, 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 amount of PSE’s receivables which fluctuate with the seasonality of energy sales to customers.
        The receivables securitization program allowsfacility is the Companyfunctional equivalent of a secured revolving line of credit. In the event Rainier Receivables elects to draw against eligiblesell receivables atunder the Receivables Purchase Agreement, Rainier Receivables is required to pay the purchasers fees that are comparable to interest rates on a rate equalrevolving line of credit. As receivables are collected by PSE as agent for the receivables purchasers, the outstanding amount of receivables purchased by the purchasers declines until Rainier Receivables elects to that of high grade commercial paper.sell additional receivables to the purchasers.
        The receivables securitization facility has a three-year term, but is terminable by PSE and Rainier Receivables upon notice to the receivables purchasers. During the year ended December 31, 2003, Rainier Receivables had sold $348.0 million in accounts receivable. At December 31, 2003, Rainier Receivables had sold $111.0 million in accounts receivable and the maximum remaining receivables available for sale was $39.0 million.
        In addition, PSE has agreements with severalcertain banks to borrow on an uncommitted, as available, basis at money-marketmoney market rates quoted by the banks. There are no costs, other than interest, for these arrangements. PSE also uses commercial paper to fund its short-term borrowing requirements. The following table presents the liquidity facilities and other financing arrangements at December 31, 20022003 and 2001.2002.


(Dollars in thousands)
At December 31

 2002
 2001
 
Short-term borrowings outstanding: 
  Commercial paper notes $  30,340 $123,168 
  Bank line of credit borrowings -- 215,000 
  Puget Energy bank line of credit borrowings 16,955 10,409 
  Weighted average interest rate 3.21% 2.72% 
InfrastruX revolving credit facility1 179,750 170,500 
PSE credit availability2 250,000 375,000 
PSE receivable securitization program 150,000 -- 
       (DOLLARS IN THOUSANDS)  
       At December 312003 2002 

          Short-term borrowings outstanding:
           Commercial paper notes$         -- $  30,340 
           InfrastruX bank line of credit borrowings13,893 16,955 
           Weighted average interest rate2.59%2.81%

         Financing arrangements:
           Puget Energy line of credit1$  15,000 $         -- 
           InfrastruX revolving credit facilities2184,725 179,750 
           PSE line of credit 3250,000 250,000 
           PSE receivables securitization program4150,000 150,000 

        The Company has, on occasion, entered into interest rate swap agreements to reduce the impact of changes in interest rates on portions of its floating-rate debt. There were no such agreements outstanding at December 31, 2003 and 2002.


1 Includes $5.0 million outstanding at December 31, 2003, effectively reducing the available borrowing capacity to $10.0 million.
2The revolving credit facility requires InfrastruX and its subsidiaries to maintain certain financial covenants, including requirements to maintain certain levels of net worth and debt coverage. The agreement also places certain restrictions on expenditures, other indebtedness and executive compensation. For 2003 and 2002, InfrastruX had $155.6 million and 2001.$144.0 million outstanding under the credit facilities, effectively reducing available borrowing capacity to $29.1 million and $35.8 million, respectively.
3Provides liquidity support for PSE's outstanding commercial paper in the amount of $0.5 million and $30.3 million for 2003 and 2002, respectively, effectively reducing the available borrowing capacity under these credit lines to $249.5 million and $219.7 million, respectively.
4Provides liquidity support for PSE's outstanding letters of credit and commercial paper. At December 31, 2003, PSE had sold $111.0 million in receivables, effectively reducing the available borrowing capacity to $39.0 million. There were no receivables sold as of December 31, 2002.


NOTE 8.9.
        Estimated Fair Value of Financial Instruments

        The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 20022003 and 2001:         2002:

 2002200220012001
 CARRYINGFAIRCARRYINGFAIR
(Dollars in millions)AMOUNTVALUEAMOUNTVALUE

  Financial assets:     
    Cash $       176.7$       176.7$         92.3$         92.3
    Restricted cash 18.918.9-- -- 
    Equity securities3 10.410.412.812.8
    Notes receivable and other 41.541.540.040.0
    Energy derivatives 13.613.66.66.6
  Financial liabilities: 
    Short-term debt 47.347.3348.6348.6
    Preferred stock subject to mandatory redemption 43.242.450.749.3
    Corporation obligated, mandatorily redeemable 300.0303.1300.0301.8
     preferred securities of subsidiary trust holding  
     solely junior subordinated debentures of the 
     corporation 
    Long-term debt4 2,223.02,381.82,246.72,131.2
    Energy derivatives 2.42.435.235.2
 2003
2002
(DOLLARS IN MILLIONS)
CARRYING
AMOUNT

FAIR
VALUE

CARRYING
AMOUNT

FAIR
VALUE

  Financial assets:          
    Cash  $27.5$27.5$176.7$176.7
    Restricted cash   2.5 2.5 18.9 18.9
    Equity securities1   3.6 3.6 10.4 10.4
    Notes receivable and other   44.9 44.9 41.5 41.5
    Energy derivatives   16.2 16.2 13.6 13.6

  Financial liabilities:  
    Short-term debt  $13.9$13.9$47.3$47.3
    Preferred stock subject to mandatory redemption   1.9 1.9 43.2 42.4
    Corporation obligated, mandatorily redeemable  
     preferred securities of subsidiary trust holdin    
     solely junior subordinated debentures of the  
     corporation   --  --  300.0 303.1
    Junior subordinated debentures of the corporatio    
     payable to a subsidiary trust holding mandatori    
     redeemable preferred securities   280.3 304.6 --  -- 
    Long-term debt2   2,216.3 2,408.7 2,237.1 2,395.9
    Energy derivatives   3.6 3.6 2.4 2.4

        The fair value of equity securities is based on valuations provided by the investment fund manager.
        The fair value of outstanding bonds including current maturities is estimated based on quoted market prices.
        The fair value of the preferred stock subject to mandatory redemption and corporation obligated, mandatorily redeemable preferred securities of a subsidiary trust holding solely junior subordinated debentures of the corporation is estimated based on dealer quotes.



1

The revolving credit facility requires InfrastruX and its subsidiaries to maintain certain financial covenants, including requirements to maintain certain levels of net worth and debt coverage. The agreement also places certain restrictions on expenditures, other indebtedness and executive compensation.

2

Provides liquidity support for PSE's outstanding commercial paper in the amount of $30.3 million and $338.2 million for 2002 and 2001, respectively, effectively reducing the available borrowing capacity under these credit lines to $219.7 million and $36.8 million, respectively.

3

The 2002 and 2001 carrying amount includes an adjustment of $2.4 million and $4.5 million, respectively, to report the available-for-sale securities at market value. This amount (or unrealized gain) has been included as a component of other comprehensive income net of deferred taxes of $0.8 million and $1.6 million for 2002 and 2001, respectively.

4

PSE's carrying and fair value of long-term debt for 2002 was $2,093.9 million and $2,252.7 million, respectively.

        The fair value of the junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities is estimated based on dealer quotes.

        The carrying valuevalues of short-term debt and notes receivable are considered to be a reasonable estimate of fair value. The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value.
        Derivative instruments have been used by the Company on a limited basis and are recorded at fair value. The Company has a policy that financial derivatives are to be used only to mitigate business risk.
        In 2003, PSE redeemed the 7.75% mandatorily redeemable preferred stock. 75,000 shares were redeemed in February 2003 at the par value of $100 per share and the remaining 337,500 shares were redeemed in August 2003 at $102.07 per share. Also in 2003, 19,750 shares of the 8.231% Capital Trust I preferred stock were redeemed at $990 per share, leaving 80,250 shares still outstanding.


1 The 2002 carrying amount includes an adjustment of $2.4 million, to report the available-for-sale securities at market value. This amount (or unrealized gain) was included as a component of other comprehensive income net of deferred taxes of $0.8 million for 2002.
2 PSE's carrying and fair value of long-term debt for 2003 was $2,053.0 million and $2,250.4 million, respectively.


NOTE 10.
Leases

        All of PSE’s leases are operating leases. Certain leases contain purchase options and renewal and escalation provisions. Operating and capital lease payments net of sublease receipts were:

(DOLLARS IN THOUSANDS)PUGET ENERGY
PSE
At December 31OperatingCapitalOperating

2003$26,842 $2,696 $19,301 
200226,368 2,486 20,176 
200125,373 1,966 20,135 

        Payments received for the subleases of properties were approximately $1.4 million, $2.6 million and $2.5 million for the years ended December 31, 2003, 2002 and 2001, respectively.
        Future minimum lease payments for non-cancelable leases net of sublease receipts are:

(DOLLARS IN THOUSANDS)PUGET ENERGY
PSE
At December 31OperatingCapitalOperating

2004$17,967 $1,611 $10,651 
200513,858 1,522 8,939 
200611,278 1,391 8,763 
20079,660 913 8,696 
20089,355 1,051 8,132 
Thereafter10,346 -- 10,346 

Total minimum lease payments$72,464 $6,488 $55,527 

        Future minimum sublease receipts for non-cancelable subleases are $0.1 million for 2004.


NOTE 11.
Income Taxes

        The details of income taxes are as follows:

 2003
2002
2001
  (DOLLARS IN THOUSANDS)   PUGET ENERGY  PSE  PUGET ENERGY  PSE  PUGET ENERGY  PSE 

  Charged to operating expense:  
  Current - federal  $18,119 $22,154 $(84,149)$(81,839)$58,749 $58,331 
  Current - state   (2,046) (1,460) (774) (548) 1,347  1,232 
  Deferred - net federal   56,004  50,880  144,230  135,884  19,945  18,040 
  Deferred -net state   927  --  614  --  485  -- 
  Deferred investment tax credits   (635) (635) (661) (661) (688) (688)

  Total charged to operations   72,369  70,939  59,260  52,836  79,838  76,915 

  Charged to miscellaneous income:  
  Current   (288) (276) (3,276) (3,406) 6,272  6,272 
  Deferred - net   (1,805) (1,805) 1,228  1,228  (2,259) (2,259)

  Total charged to miscellaneous income   (2,093) (2,081) (2,048) (2,178) 4,013  4,013 

  Cumulative effect of accounting change   (91) (91) --  --  (7,942) (7,942)

  Total income taxes  $70,185 $68,767 $57,212 $50,658 $75,909 $72,986 

        The following is a reconciliation of the difference between the amount of income taxes computed by multiplying pre-tax book income by the statutory tax rate and the amount of income taxes in the Consolidated Statements of Income for the Company:

 2003
2002
2001
  (DOLLARS IN THOUSANDS)   PUGET ENERGY  PSE  PUGET ENERGY  PSE  PUGET ENERGY  PSE 

  Income taxes at the statutory rate  $67,098 $66,028 $61,587 $55,862 $63,962 $62,079 

  Increase (decrease):  
    Depreciation expense deducted in  
     the financial statements in exce    
     of tax depreciation, net of  
     depreciation treated as a  
     temporary difference   9,130  9,130  10,041  10,041  11,726  11,726 
    AFUDC included in income in the  
     financial statements but exclude    
     from taxable income   (1,809) (1,809) (1,387) (1,387) (2,126) (2,126)
    Accelerated benefit on early  
     retirement of depreciable assets   (1,879) (1,879) (1,469) (1,469) (319) (319)
    Investment tax credit amortizatio   (635) (635) (661) (661) (689) (689)
    Energy conservation expenditures    
     net   8,096  8,096  6,259  6,259  6,859  6,859 
    Tax benefit of reduced salvage  
     values   --  --  (10,193) (10,193) --  -- 
     IRS issue resolution   (6,209) (6,209) --  --  --  -- 
    State income taxes net of the  
    federal income tax benefit   (877) (949) (104) (356) 1,191  801 
    Other - net   (2,730) (3,006) (6,861) (7,438) (4,695) (5,345)

  Total income taxes  $70,185 $68,767 $57,212 $50,658 $75,909 $72,986 

  Effective tax rate   36.6%  36.5%  32.5%  31.7%  41.5%  41.15% 

        The Company’s deferred tax liability at December 31, 2003, 2002 and 2001 is composed of amounts related to the following types of temporary differences:

 2003
2002
2001
  (DOLLARS IN THOUSANDS)   PUGET ENERGY  PSE  PUGET ENERGY  PSE  PUGET ENERGY  PSE 

  Utility plant  $607,203 $607,203 $578,137 $578,137 $570,982 $570,982 
  Energy conservation charges   9,446  9,446  16,473  16,473  23,782  23,782 
  Contributions in aid of construction   (46,520) (46,520) (44,770) (44,770) (36,044) (36,044)
  Bonneville Exchange Power   15,204  15,204  15,537  15,537  17,897  17,897 
  Cabot gas contract purchase   3,503  3,503  4,157  4,157  4,477  4,477 
  Deferred revenue   (4,680) (4,680) (5,292) (5,292) (5,904) (5,904)
  Software amortization   41,044  41,044  41,408  41,408  --  -- 
  Capitalized overhead costs   70,834  70,834  72,220  72,220  --  -- 
  Other   59,201  35,910  52,805  37,709  30,125  25,811 

  Total  $755,235 $731,944 $730,675 $715,579 $605,315 $601,001 

        Puget Energy’s totals of $755.2 million and $730.7 million for 2003 and 2002 consist of deferred tax liabilities of $876.5 million and $841.7 million net of deferred tax assets of $121.3 million and $111.0 million, respectively.
        PSE’s totals of $731.9 million and $715.6 million for 2003 and 2002 consist of deferred tax liabilities of $852.4 million and $824.2 million net of deferred tax assets of $120.5 million and $108.6 million, respectively.
        Deferred tax amounts shown above result from temporary differences for tax and financial statement purposes. Deferred tax provisions are not recorded in the income statement for certain temporary differences between tax and financial statement purposes because they are not allowed for ratemaking purposes.
        The Company calculates its deferred tax assets and liabilities under SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recording deferred tax balances, at the currently enacted tax rate, for all temporary differences between the book and tax bases of assets and liabilities, including temporary differences for which no deferred taxes had been previously provided because of use of flow-through tax accounting for ratemaking purposes. Because of prior and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, a regulatory asset for income taxes recoverable through future rates related to those differences has also been established by PSE. At December 31, 2003, the balance of this asset was $142.8 million.

NOTE 9.12.
        Retirement Benefits

        The Company has a defined benefit pension plan with a cash balance feature covering substantially all of its utility employees. Benefits are a function of age, salary and service. Additionally, Puget Energy maintains a non-qualified supplemental retirement plan for officers and certain director-level employees. The annual measurement date is December 31 of each year.
        In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company whose premiums are based on the benefits paid during the year.


 PENSION BENEFITS
OTHER BENEFITS
       (DOLLARS IN THOUSANDS)   2003  2002  2003  2002 

       Change in benefit obligation:  
       Benefit obligation at beginning of year  $369,692 $400,461 $31,693 $29,115 
       Service cost   8,284  8,474  175  168 
       Interest cost   24,406  25,858  1,828  1,930 
       Amendments1   940  3,073  --  3,493 
       Actuarial loss   19,354  2,055  (2,194) (419)
       Plan curtailment2   --  (9,518) --  (553)
       Special adjustments2   190  10,872  --  -- 
       Benefits paid   (22,825) (71,583) (2,282) (2,041)

       Benefit obligation at end of year  $400,041 $369,692 $29,220 $31,693 

       Change in plan assets:  
       Fair value of plan assets at beginning  $343,960 $443,512 $16,160 $15,978 
       Actual return on plan assets   79,488  (40,849) 98  650 
       Employer contribution   27,963  12,880  1,455  1,573 
       Benefits paid   (22,825) (71,583) (2,282) (2,041)

       Fair value of plan assets at end of yea  $428,586 $343,960 $15,431 $16,160 

       Funded status  $28,545 $(25,732)$(13,789)$(15,533)
       Unrecognized actuarial gain (loss)   48,217  66,784  (2,895) (1,878)
       Unrecognized prior service cost   15,949  18,228  2,712  3,021 
       Unrecognized net initial (asset) obliga   (1,267) (2,371) 3,783  4,201 

       Net amount recognized  $91,444 $56,909 $(10,189)$(10,189)

       Amounts recognized on statement of  
         financial position consist of:  
       Prepaid benefit cost  $112,737 $73,361 $(10,189)$(10,189)
       Accrued benefit liability   (38,704) (34,253) --  -- 
       Intangible asset   9,043  10,555  --  -- 
       Accumulated other comprehensive income   8,368  7,246  --  -- 

       Net amount recognized  $91,444 $56,909 $(10,189 )$(10,189)


1 In 2002, the Company had $3.1 million in pension benefit plan amendments due to changes in employment contracts, the addition of new entrants to the plan and the vesting of certain non-vested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefit plan amendments due to an increase in the Company's contribution to the retiree medical plan.
2 In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.

        In accounting for pension and other benefit costs under the plans, the following weighted average actuarial assumptions were used:

 PENSION BENEFITS
OTHER BENEFITS
 2003 2002 2001 2003 2002 2001 

  Discount rate6.25%6.75%7.25%6.25%6.75%7.25%
  Return on plan assets8.25%8.25%9.50%6-7.00%6-7.00%6-8.25%
  Rate of compensation increa4.50%4.50%5.0%-- -- -- 
  Medical trend rate-- -- -- 9.00%10.00%6.50%


        The Company has used the expected return on plan assets based on an analysis of rates of return over the past 50 years relevant to the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors and adjusted accordingly.

 PENSION BENEFITS
OTHER BENEFITS
  (DOLLARS IN THOUSANDS)   2003  2002  2001  2003  2002  2001 

  Components of net periodic benefit cost:  
  Service cost  $8,284 $8,474 $9,862 $175 $168 $243 
  Interest cost   24,406  25,858  26,734  1,828  1,930  2,022 
  Expected return on plan assets   (38,880) (43,032) (46,222) (934) (906) (947)
  Amortization of prior service cost   3,220  2,990  2,960  309  90  (34)
  Recognized net actuarial gain   (2,688) (5,120) (7,570) (341) (229) (109)
  Amortization of transition (asset) obligation   (1,104) (1,136) (1,230) 418  470  627 
  Plan curtailment   --  (1,353) --  --  1,691  -- 
  Special recognition of prior service costs   190  1,683  108  --  --  -- 

  Net pension benefit cost (income)  $(6,572)$(11,636)$(15,358)$1,455 $3,214 $1,802 

        The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the non-qualified pension plan, which has accumulated benefit obligations in excess of plan assets, were $45.0 million, $38.6 million and $0, respectively, as of December 31, 2003. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $355.1 million, $339.7 million and $428.6 million, respectively, as of December 31, 2003.
        The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ended December 31, 2004 are $11.1 million and an insignificant amount, respectively. The full amount of the pension funding for 2004 is for the Company’s non-qualified supplemental retirement plan.
        The fair value of the plan assets of the pension benefits and other benefits are invested as follows at December 31:

 2003
2002
 PENSION
BENEFITS
OTHER
BENEFITS
PENSION
BENEFITS
OTHER
BENEFITS

Short-term investments and cash3.0%100.0%4.1%100.0%
Equity securities63.8%--55.7%-- 
Fixed income securities22.9%--31.2%-- 
Mutual funds10.3%--9.0%-- 

        The expected total benefits to be paid under both plans for the next five years and the aggregate total to be paid for the five years thereafter is as follows:

(DOLLARS IN THOUSANDS)200420052006200720082009-2013

Total benefits$ 35,697$ 25,940$ 26,939$ 28,806$ 28,202$157,821

        The assumed medical inflation rate is 9.0% in 2004 decreasing to 6.0% in 2007. A 1% change in the assumed medical inflation rate would have the following effects:

 2003
2002
(DOLLARS IN THOUSANDS)
1%
INCREASE

1%
DECREASE

1%
INCREASE

1%
DECREASE

Effect on post-retirement benefit obligation  $589 $(529)$580 $(515)
Effect on service and interest cost components   38  (35) 36  (32)

        The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purpose of obtaining the optimum return for the pension benefit plans, while also keeping with the assumption of prudent risk and the Retirement Committee’s total return objectives. All changes to the investment policies are reviewed and approved by the Retirement Committee prior to being implemented.
        The Retirement Committee contracts with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Committee has established investment allocation percentages by asset classes as follows:

 ALLOCATION
 
  ASSET CLASSMINIMUMTARGETMAXIMUM

Domestic large capitalization equity securities30%42%50%
Domestic small capitalization equity securities-- 8%15%
Fixed-income securities20%30%40%
Foreign equity securities10%20%30%
Real estate-- -- 10%
Short-term investments and cash-- -- 5%

NOTE 13.
Employee Investment Plans

        The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options.
        Puget Energy’s contributions to the Employee Investment Plans were $7.1 million, $6.9 million and $8.0 million for the years 2003, 2002 and 2001, respectively.
        PSE’s contributions to the Employee Investment Plan were $6.1 million, $6.1 million and $6.8 million for the years 2003, 2002 and 2001, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.

NOTE 14.
Stock-based Compensation Plans

        The Company has various stock compensation plans which prior to 2003 were accounted for according to 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 will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Total compensation expense related to the plans was $6.4 million, $6.3 million and $2.1 million in 2003, 2002 and 2001, respectively.
        The Company’s shareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses many of the awards granted to employees. Established in 1995 and amended and restated in 1997, the LTI Plan applies to officers and key employees of the Company. Awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are purchased on the open market. The maximum number of shares that may be purchased for the LTI Plan is 1,200,000.

PERFORMANCE SHARE GRANTS
        Each year the Company awards performance share grants under the LTI Plan. These are granted to key employees and vest at the end of four years with the final number of shares awarded depending on a performance measure. The Company records compensation expense related to the shares based on the performance measure and changes in the market price of the stock. Compensation expense related to performance share grants was $5.1 million, $5.5 million and $2.3 million for 2003, 2002 and 2001, respectively. The fair value of the performance awards granted in 2003, 2002 and 2001 was $17.29, $14.82 and $17.86, respectively. There were a total of 334,608 performance awards granted in 2003, 247,184 in 2002 and 183,881 in 2001. As of December 31, 2003, there are four active grant cycles for a total of 790,922 share grants outstanding although they may not all be awarded.

STOCK OPTIONS
        In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside of the LTI Plan (for a total of 300,000 non-qualified stock options) to the president and chief executive officer. These options can be exercised at the grant date market price of $22.51 per share and vest yearly over four and five years although vesting is accelerated under certain conditions. The options expire 10 years from the grant date. All 300,000 options remained outstanding at December 31, 2003, with 67,500 options exercisable. No options were exercisable at December 31, 2002. The fair value of the options at the grant date was $3.37 per share. Following the intrinsic value method of APB 25, no compensation expense was recorded for these options. No additional options were granted in 2003.


RESTRICTED STOCK
        In 2003 and 2002, the Company granted 11,000 shares and 30,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market. Of the 2003 shares issued, 1,000 shares vested in 2003. The remaining shares will vest evenly over the next five years. The 2002 shares were fully vested as of December 2003. In 2002 the Company also issued 50,000 shares of restricted stock outside of the LTI Plan as approved by the Puget Energy Board of Directors. These shares were recorded as a separate component of stockholders’ equity and vest evenly over a five-year period. Compensation expense related to the restricted shares was $0.6 million and $0.5 million in 2003 and 2002, respectively. No restricted shares were issued in 2001. Dividends are paid on all outstanding restricted stock and are accounted for as a Puget Energy stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of restricted stock granted in 2003 and 2002 was $23.29 and $21.94, respectively.

EMPLOYEE STOCK PURCHASE PLAN
        The Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six-month intervals at the end of which the participating employees receive shares for 85% of the lower of the stock’s fair market price at the beginning or the end of the six-month period. A maximum of 500,000 shares may be sold to employees under the plan. Prior to 2002, the Company purchased shares for the plan on the open market. As of the second offering of 2002, the Company began issuing common stock for the ESPP rather than purchasing stock. In 2003, 38,940 shares were issued for the ESPP. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan, and in 2001, 45,659 shares were purchased. At December 31, 2003, 259,662 shares may still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003, ESPP is considered to be compensation expense. Total compensation expense related to the ESPP was $0.2 million in 2003. Dividends are not paid on ESPP shares until they are purchased by employees and thus are accounted for as dividends, not compensation expense. The weighted average fair value of the purchase rights granted in 2003, 2002 and 2001 was $4.25, $4.19 and $4.35, respectively.

INFRASTRUX STOCK OPTION PLAN
        The InfrastruX stock option plan, established in 2000, has 3,862,500 shares of InfrastruX stock authorized to be granted to officers, key employees and non-employee directors of InfrastruX. The options generally vest within four years and expire 10 years from the grant date. The following summarizes InfrastruX option information for 2003, 2002 and 2001:

 2003
2002
2001
 Shares
(in thousands)
Weighted
Average
Exercise Price
Shares
(in thousands)
Weighted
Average
Exercise Price
Shares
(in thousands
Weighted
Average
Exercise Price
 


Outstanding at beginning of year 2,643 $     4.311,995 $     4.05-- $     -- 
Granted 176 5.00725 5.002,043 4.05
Exercised -- -- -- -- -- -- 
Canceled (201)4.20(77)4.09(48)4.00
 


Outstanding at end of year 2,618 $     4.362,643 $     4.311,995 $     4.05
Options exercisable at year end 1,837 $     4.12802 $     4.02791 $     4.00
 


Weighted average fair value of options
 granted during the year
 $2.41
$2.23
$1.60

        The following summarizes InfrastruX's outstanding option information at December 31, 2003:

 Shares
Outstanding
(in thousands)
Weighted
Average
Contractual Life
(in years)
Weighted
Average
Exercise Price
 
Exercise Prices         
$4.00          1,666 7.11$4.00
$5.00             952 8.42  5.00
 
 2,618 7.59$4.36
 

        Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options have been granted at a discount requiring InfrastruX to record compensation expense. With the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX also recorded compensation expense related to options granted in 2003. Compensation expense of $0.2 million and $0.1 million related to stock options was recorded in 2003 and 2002, respectively.

NON-EMPLOYEE DIRECTOR STOCK PLAN
        The Company has a director stock plan created in 1998 for all non-employee directors of Puget Energy and PSE. Under the plan which has a 10-year term, non-employee directors receive a minimum of two-thirds of their quarterly retainer fees in Company stock except that 100% of quarterly retainers are paid in Company stock until the director holds a number of shares equal to two years of common stock in value of their retainer. Directors may optionally receive their entire retainer in Company stock. The compensation expense related to the director stock plan was $0.4 million, $0.2 million and $0.1 million in 2003, 2002 and 2001, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000 shares. As of December 31, 2003, 9,902 shares had been purchased for the director stock plan and 48,219 deferred, for a total of 58,121 shares.

OTHER PLANS
        In addition to current stock compensation plans, the Company also has outstanding shares related to two plans that were in effect prior to the 1997 merger between Puget Sound Power and Light (PSP&L) and Washington Energy Company (WECO). There are 2,400 vested, unexercised stock appreciation rights from the PSP&L Incentive Plan Awards granted to executives of PSP&L. These were granted in 1994, have an exercise price of $20.75 and expire 10 years after the grant date. There are also 11,301 vested, unexercised options from the WECO Incentive Stock Option Plan granted to key employees of WECO. The options were granted between 1994 and 1996 with exercise prices ranging from $15.55 to $23.11 and expire 10 years from the date of grant. These are generally paid out as stock appreciation rights at the discretion of the grantees. The Company records compensation expense each quarter related to the PSP&L and WECO shares as the difference between the exercise price and the current market price. Compensation expense related to the WECO plan was immaterial in 2003 and 2002, and $(0.2) million in 2001. Compensation expense related to the PSP&L plan was immaterial in 2003 and 2002, and $(0.1) million in 2001.

        The Company used the Black-Scholes option pricing model to determine the fair value of certain stock-based awards to employees. The following assumptions were used for awards granted in 2003, 2002 and 2001:

 200320022001

Stock options 
  Risk-free interest rate     --4.32%    --
  Expected lives - years     --4.50    --
  Expected stock volatility     --23.62%    --
  Dividend yield     --5.00%    --

InfrastruX stock option plan 
  Risk-free interest rate 2.80%4.05%4.87%
  Expected lives - years 4.004.004.00
  Expected stock volatility 60.00%60.00%50.00%

Performance awards 
  Risk-free interest rate 2.35%4.00%4.99%
  Expected lives - years 4.004.004.00
  Expected stock volatility 23.85%23.71%20.76%
  Dividend yield 4.86%8.85%7.67%

Employee Stock Purchase Plan 
  Risk-free interest rate 1.07%1.65%4.26%
  Expected lives - years 0.500.500.50
  Expected stock volatility 19.47%26.97%19.04%
  Dividend yield 4.39%5.81%7.72%


NOTE 15.
Accounting for Derivative Instruments and Hedging Activities

        The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
        For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income statement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
        In addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with no significant impact on the financial statements.
        On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
        PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.

NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)

        During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of cash and preferred or common stock. The 2003 acquisition includes a contingency which requires InfrastruX to make additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
        These companies provide utility infrastructure services which are relevant to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunications providers; pipeline construction, maintenance and rehabilitation services for the natural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission-oriented overhead electric construction services to electric utilities and cooperatives.
        The acquisitions have been accounted for using the purchase method of accounting and, accordingly, the operating results of these companies have been included in Puget Energy’s consolidated financial statements since their acquisition dates. Goodwill additions representing the excess of cost over the net tangible and identifiable intangible assets at the time of purchase were approximately $7.7 million in 2003 and $23.5 million in 2002.
        During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the annual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:


(DOLLARS IN THOUSANDS)2003 2002 2001 

Reported income for common stock$      116,197 $      110,052 $       98,426 
Add back goodwill amortization, net of tax-- -- 2,826 
 
Adjusted income for common stock$      116,197 $      110,052 $      101,252 
 
Basic earnings per share
  Reported income for common stock$             1.23$             1.24$             1.14
  Add back goodwill amortization-- -- 0.03
 
  Adjusted income for common stock$             1.23$             1.24$             1.17
 
Diluted earnings per share
        Reported income for common stock$             1.22$             1.24$             1.14
        Add back goodwill amortization-- -- 0.03
 
        Adjusted income for common stock$             1.22$             1.24$             1.17
 

        Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 years. In 2003 a total of $2.1 million was added to intangible assets — assigned $0.1 million to patents with an amortization period of 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.

 
AT DECEMBER 31, 2003
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  4,178    $2,009    $  2,169    
Developed technology14,190    2,454    11,736    
Contractual customer relationships4,702    747    3,955    
Patents915    68    847    

 Total$23,985    $5,278    $18,707    
 
 
AT DECEMBER 31, 2002
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  3,908    $1,105    $  2,803    
Developed technology14,190    1,744    12,446    
Contractual customer relationships3,042    383    2,659    
Patents793    49    744    

 Total$21,933    $3,281    $18,652    
 

        The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(DOLLARS IN THOUSANDS)20042005200620072008

Future intangible amortization$ 2,101$ 2,075$ 1,746$ 1,363$ 1,340

        The pro forma combined revenues, net income and earnings per common share of Puget Energy presented below give effect to the acquisitions as if they had occurred on January 1, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.

(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOR THE YEARS ENDED DECEMBER 31
200320022001

Operating revenues$     2,505,523$     2,469,122$     3,056,824
Net income for common116,636112,813104,338
Basic earnings per common share$  1.23$  1.28$  1.21
Diluted earnings per common share$  1.22$  1.27$  1.20

NOTE 17.
Other

        PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
        The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
        In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
        PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
        In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.


NOTE 18.
Commitments and Contingencies

COMMITMENTS – ELECTRIC
        For the year ended December 31, 2003, approximately 19.9% of the Company’s energy output was obtained at an average cost of approximately $0.01641 per kWh through long-term contracts with several of the Washington Public Utility Districts (PUDs) owning hydroelectric projects on the Columbia River.
        The purchase of power from the Columbia River projects is on a “cost-of-service” basis under which the Company pays a proportionate share of the annual cost of each project in direct proportion to the amount of power annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the lives of the contracts.
        As of December 31, 2003, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:

 BONDS
OUTSTANDING
COMPANY'S ANNUAL AMOUNT
PURCHASABLE (APPROXIMATE)

PROJECTCONTRACT
EXP. DATE
LICENSE1
EXP. DATE
12/31/032
(MILLIONS)
% OF
OUTPUT
MEGAWATT
CAPACITY
COSTS3
(MILLIONS)

  Rock Island         
     Original units 2012 2029 $         121.750.0 414 $    41.9
     Additional units 2012 2029 331.575.0 
  Rocky Reach 2011 2006 394.738.9 505 29.6
  Wells 2018 2012 151.331.3 261 6.9
  Priest Rapids4 2005 2005 184.78.0 72 2.6
  Wanapum4 2009 2005 186.510.8 98 4.1

  Total     $        1,370.4  1,350 $    85.1

        The Company’s estimated payments for power purchases from the Columbia River are $84.6 million for 2004, $81.4 million for 2005, $78.4 million for 2006, $81.4 million for 2007, $82.6 million for 2008 and in the aggregate, $123.5 million thereafter through 2018.
        The Company also has numerous long-term firm purchased power contracts with other utilities in the region. The Company is generally not obligated to make payments under these contracts unless power is delivered. The Company’s estimated payments for firm power purchases from other utilities, excluding the Columbia River projects, are $76.0 million for 2004, $77.7 million for 2005, $78.6 million for 2006, $80.7 million for 2007, $82.6 million for 2008 and in the aggregate, $433.3 million thereafter through 2037. These contracts have varying terms and may include escalation and termination provisions.
        As required by the federal Public Utility Regulatory Policies Act (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The Company purchases the net electrical output of four significant projects at fixed and annually escalating prices, which were intended to approximate the Company’s avoided cost of new generation projected at the time these agreements were made. The Company’s estimated payments under these contracts are $211.4 million for 2004, $217.3 million for 2005, $232.9 million for 2006, $211.9 million for 2007, $212.1 million for 2008 and in the aggregate, $746.0 million thereafter through 2012.
        The following table summarizes the Company’s estimated obligations for future power purchases:


(DOLLARS IN MILLIONS)200420052006200720082009 &
THERE-
AFTER
TOTAL

  Columbia River projects$    84.6$     81.4$     78.4$     81.4$     82.6$       123.5$     531.9
  Other utilities76.077.778.680.782.6433.3828.9
  Non-utility generators211.4217.3232.9211.9212.1746.01,831.6

      Total$   372.0$   376.4$   389.9$   374.0$   377.3$    1,302.8  $   3,192.4


1The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirm the Company's contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term.
2The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and refinancings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration date are: 43.7% at Rock Island; 58.3% at Rocky Reach; 94.5% at Priest Rapids; 79.6% at Wanapum; and 6.2% at Wells.
3The components of 2003 costs associated with the interest portion of debt service are: Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million; Wells, $8.2 million; Priest Rapids, $0.8 million; and Wanapum, $0.6 million.
4On December 28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. Grant County PUD filed an "Application for New License for the Priest Rapids Project" on October 29, 2003. The new contract terms begin in November of 2005 for the Priest Rapids Development and in November of 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts PSE's share of power from the developments declines over time as Grant County PUD's load increases. On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County PUD's new contracts unreasonably restrain trade and violate various sections of the Federal Power Act and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, it has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing has been requested.

        Total purchased power contracts provided the Company with approximately 11.0 million, 12.1 million and 11.9 million MWh of firm energy at a cost of approximately $479.2 million, $466.1 million and $496.3 million for the years 2003, 2002 and 2001, respectively.
        The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2003:

COMPANY'S SHARE
(DOLLARS IN MILLIONS)ENERGY
SOURCE (FUEL)
COMPANY'S
OWNERSHIP
SHARE
PLANT IN SERVICE
AT COST
ACCUMULATED
DEPRECIATION

Colstrip 1 & 2   Coal   50% $     207  $     133 
Colstrip 3 & 4   Coal   25% 464  240 

        Financing for a participant’s ownership share in the projects is provided for by such participant. The Company’s share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of Income.
        PSE and PPL Montana, the other owner of Colstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s PCA mechanism.
        On October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE used the coal as fuel for its share of Units 3 & 4 of the Colstrip generating plant. PSE’s coal price for that period was reduced by a settlement PSE and Western Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
        As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of Tenaska’s cogeneration facility. This obligation continues for the remaining term of the agreement, provided that no deliveries are required during the month of May. The price paid by Tenaska for this gas is reflective of the daily price of gas at the United States/Canada border near Sumas, Washington. PSE has entered into a financial arrangement to hedge a portion, 5,000 MMBtu to 10,000 MMBtu per day, of future gas supply costs associated with this obligation. The Company has a maximum financial obligation under this hedge agreement of $22.0 million in 2004.
        As part of its electric operations and in connection with the 1999 buyout of the Cabot gas supply contract, PSE is obligated to deliver to Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The Company entered into a financial arrangement to hedge a portion of future gas supply


costs associated with this obligation, 10,000 MMBtu per day, for the remaining term of the agreement. The Company has a maximum financial obligation under this hedge agreement of $8.5 million in 2004, $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter. Depending on actual market prices, these costs will be partially, or perhaps entirely, offset by floating price payments received under the hedge arrangement. Encogen has two gas supply agreements that comprise 40% of the plant’s requirements with remaining terms of 6.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7 million in 2005, $17.5 million in 2006, $18.4 million in 2007 and $12.9 million in the aggregate thereafter.
        PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are generally classified as normal purchases and normal sales or in some cases recorded at fair value in accordance with SFAS No. 133. Commitments under these contracts are $3.0million in 2004, $10.3 million in 2005, $1.1 million in 2006, $0.4 million in 2007 and $0.1 million thereafter.

GAS SUPPLY
        The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1 year to 20 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Two of PSE’s long-term firm gas supply agreements, that expire November 2004, obligate the Company to purchase a minimum annual quantity at market-based contract prices. If the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. PSE didn’t incur such charges in 2003. The Company incurred demand charges in 2003 for firm gas supply, firm transportation service and firm storage and peaking service of $24.7 million, $47.9 million and $5.3 million, respectively. WNG Cap I incurred demand charges in 2003 for firm transportation service of $9.4 million.
        The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.

DEMAND CHARGE OBLIGATIONS
(DOLLARS IN MILLIONS)
200420052006200720082009 &
THERE-
AFTER
TOTAL

  Firm gas supply$    18.7$     1.5$     1.0$     0.5$     0.5$       1.5$      23.7
  Firm transportation service66.658.857.057.048.0122.7410.1
  Firm storage service11.311.67.87.77.748.294.3

      Total$    96.6$    71.9$    65.8$    65.2$    56.2$    172.4$    528.1

SERVICE CONTRACT
        On August 30, 2001, PSE and Alliance Data Systems Corp. announced a contract under which Alliance Data will provide data processing and billing services for PSE. In providing services to PSE under the 10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by its ConneXt subsidiary. Alliance Data acquired the assets of ConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as part of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $21.7 million in 2004, $22.2 million in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008 and $66.9 million in the aggregate thereafter.

SURETY BOND
        The Company has a self-insurance surety bond in the amount of $5.9 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.

ENVIRONMENTAL
        The Company is subject to environmental laws and regulations by federal, state and local authorities and has been required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has also been named by the Environmental Protection Agency, the Washington State Department of Ecology, and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring these sites. Remediation and testing of Company vehicle service facilities and storage yards is also continuing.
        During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or under the Washington Commission’s order.
        The information presented here as it relates to estimates of future liability is as of December 31, 2003.


ELECTRIC SITES
        The Company has expended approximately $18.1 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.6 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $18.8 million from insurance carriers.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

GAS SITES
        The Company has expended approximately $65.9 million related to the remediation activities covered by a Washington Commission order and has accrued approximately $32.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $59.6 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

LITIGATION
        There are several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville Power Administration (BPA), in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the amended settlement agreement regarding the Residential Purchase and Sale Program and the conditional settlement agreements between BPA and PSE which modified the payment provisions of the Residential Purchase and Sale Program. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates may have on PSE.
        Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2003. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

NOTE 19.
Segment Information

        Puget Energy operates in primarily two business segments: regulated utility operations, or PSE, and construction services, or InfrastruX. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the State of Washington. InfrastruX specializes in construction services to other gas and electric utilities primarily in the south/Texas and the north-central and eastern United States.
        One minor non-utility business segment, a PSE subsidiary, which is a real estate investment and development company is described as other. The assets of ConneXt, the development and marketing of customer information and billing system software segment, were sold during the third quarter of 2001. The third quarter results of 2001 included an $8.0 million after-tax gain related to the ConneXt sale. Reconciling items between segments are not significant.


        Financial data for business segments are as follows:

  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2003UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,143,693 $341,787 $  6,043 $2,491,523 
  Depreciation and amortization219,851 16,779 236 236,866 
  Income tax69,823 1,594 952 72,369 
  Operating income295,219 7,452 2,504 305,175 
  Interest charges, net of AFUDC179,437 5,485 123 185,045 
  Net income119,144 1,766 438 121,348 
  Goodwill, net-- 133,302 -- 133,302 
  Total assets5,257,157 342,332 75,196 5,674,685 
  Construction expenditures - excluding equity AFUDC269,973 -- -- 269,973 
  Additions to other property, plant and equipment-- 15,536 -- 15,536 


  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2002UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,063,040 $319,529 $    9,753 $2,392,322 
  Depreciation and amortization215,097 13,426 220 228,743 
  Income tax50,600 6,703 1,957 59,260 
  Operating income289,511 15,595 4,563 309,669 
  Interest charges, net of AFUDC190,861 5,516 -- 196,377 
  Net income104,044 9,455 4,384 117,883 
  Goodwill, net-- 125,555 -- 125,555 
  Total assets5,323,129 319,248 129,756 5,772,133 
  Construction expenditures - excluding equity AFUDC224,165 -- -- 224,165 
  Additions to other property, plant and equipment-- 11,621 -- 11,621 


  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2001UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,680,298 $173,786 $  32,476 $2,886,560 
  Depreciation and amortization208,705 8,820 15 217,540 
  Income tax68,005 2,956 8,877 79,838 
  Operating income273,751 8,702 14,668 297,121 
  Interest charges, net of AFUDC186,403 3,656 -- 190,059 
  Net income80,137 2,518 24,184 106,839 
  Goodwill, net-- 102,151 -- 102,151 
  Total assets5,300,105 229,125 139,251 5,668,481 
  Construction expenditures - excluding equity AFUDC247,435 -- -- 247,435 
  Additions to other property, plant and equipment-- 5,193 -- 5,193 


NOTE 20.
Supplementary Income Statement Information

(Dollars in thousands)
PUGET
ENERGY
2002

PSE
2002

PUGET
ENERGY
2001

PSE
2001

PUGET ENERGY
AND PSE
2000

  Taxes other than income taxes:      
    Real estate and personal property $  48,890 $  48,408 $  41,858 $  41,588 $  47,357 
    State business 77,527 77,527 85,335 84,735 83,485 
    Municipal and occupational 67,770 67,770 71,819 71,819 65,155 
    Other 37,029 24,463 33,431 29,084 30,073 

  Total taxes other than income taxes $231,216 $218,168 $232,443 $227,226 $226,070 

  Charged to: 
    Operating expense $215,429 $202,381 $212,582 $207,365 $202,398 
    Other accounts, including construction work in progress 15,787 15,787 19,861 19,861 23,672 

  Total taxes other than income taxes $231,216 $218,168 $232,443 $227,226 $226,070 

NOTE 10.
LeasesRetirement Benefits

        AllThe Company has a defined benefit pension plan with a cash balance feature covering substantially all of PSE’s leasesits utility employees. Benefits are operating leases. Certain leases contain purchase options, renewala function of age, salary and escalation provisions.service. Additionally, Puget Energy maintains a non-qualified supplemental retirement plan for officers and certain director-level employees. The annual measurement date is December 31 of each year.
        OperatingIn addition to providing pension benefits, the Company provides certain health care and capital lease payments netlife insurance benefits for retired employees. These benefits are provided principally through an insurance company whose premiums are based on the benefits paid during the year.


 PENSION BENEFITS
OTHER BENEFITS
       (DOLLARS IN THOUSANDS)   2003  2002  2003  2002 

       Change in benefit obligation:  
       Benefit obligation at beginning of year  $369,692 $400,461 $31,693 $29,115 
       Service cost   8,284  8,474  175  168 
       Interest cost   24,406  25,858  1,828  1,930 
       Amendments1   940  3,073  --  3,493 
       Actuarial loss   19,354  2,055  (2,194) (419)
       Plan curtailment2   --  (9,518) --  (553)
       Special adjustments2   190  10,872  --  -- 
       Benefits paid   (22,825) (71,583) (2,282) (2,041)

       Benefit obligation at end of year  $400,041 $369,692 $29,220 $31,693 

       Change in plan assets:  
       Fair value of plan assets at beginning  $343,960 $443,512 $16,160 $15,978 
       Actual return on plan assets   79,488  (40,849) 98  650 
       Employer contribution   27,963  12,880  1,455  1,573 
       Benefits paid   (22,825) (71,583) (2,282) (2,041)

       Fair value of plan assets at end of yea  $428,586 $343,960 $15,431 $16,160 

       Funded status  $28,545 $(25,732)$(13,789)$(15,533)
       Unrecognized actuarial gain (loss)   48,217  66,784  (2,895) (1,878)
       Unrecognized prior service cost   15,949  18,228  2,712  3,021 
       Unrecognized net initial (asset) obliga   (1,267) (2,371) 3,783  4,201 

       Net amount recognized  $91,444 $56,909 $(10,189)$(10,189)

       Amounts recognized on statement of  
         financial position consist of:  
       Prepaid benefit cost  $112,737 $73,361 $(10,189)$(10,189)
       Accrued benefit liability   (38,704) (34,253) --  -- 
       Intangible asset   9,043  10,555  --  -- 
       Accumulated other comprehensive income   8,368  7,246  --  -- 

       Net amount recognized  $91,444 $56,909 $(10,189 )$(10,189)


1 In 2002, the Company had $3.1 million in pension benefit plan amendments due to changes in employment contracts, the addition of sublease receipts were:new entrants to the plan and the vesting of certain non-vested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefit plan amendments due to an increase in the Company's contribution to the retiree medical plan.
2 In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.

 (Dollars in thousands)PUGET ENERGYPSE 
 At December 31
Operating
Capital
Operating
 2002 $26,368 $2,486 $20,176 
 2001 25,373 1,966 20,135 
 2000 18,239 653 18,239 

        Payments receivedIn accounting for pension and other benefit costs under the plans, the following weighted average actuarial assumptions were used:

 PENSION BENEFITS
OTHER BENEFITS
 2003 2002 2001 2003 2002 2001 

  Discount rate6.25%6.75%7.25%6.25%6.75%7.25%
  Return on plan assets8.25%8.25%9.50%6-7.00%6-7.00%6-8.25%
  Rate of compensation increa4.50%4.50%5.0%-- -- -- 
  Medical trend rate-- -- -- 9.00%10.00%6.50%


        The Company has used the expected return on plan assets based on an analysis of rates of return over the past 50 years relevant to the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors and adjusted accordingly.

 PENSION BENEFITS
OTHER BENEFITS
  (DOLLARS IN THOUSANDS)   2003  2002  2001  2003  2002  2001 

  Components of net periodic benefit cost:  
  Service cost  $8,284 $8,474 $9,862 $175 $168 $243 
  Interest cost   24,406  25,858  26,734  1,828  1,930  2,022 
  Expected return on plan assets   (38,880) (43,032) (46,222) (934) (906) (947)
  Amortization of prior service cost   3,220  2,990  2,960  309  90  (34)
  Recognized net actuarial gain   (2,688) (5,120) (7,570) (341) (229) (109)
  Amortization of transition (asset) obligation   (1,104) (1,136) (1,230) 418  470  627 
  Plan curtailment   --  (1,353) --  --  1,691  -- 
  Special recognition of prior service costs   190  1,683  108  --  --  -- 

  Net pension benefit cost (income)  $(6,572)$(11,636)$(15,358)$1,455 $3,214 $1,802 

        The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the subleasenon-qualified pension plan, which has accumulated benefit obligations in excess of propertiesplan assets, were approximately $2.6$45.0 million, $2.5$38.6 million and $2.4$0, respectively, as of December 31, 2003. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $355.1 million, $339.7 million and $428.6 million, respectively, as of December 31, 2003.
        The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ended December 31, 2004 are $11.1 million and an insignificant amount, respectively. The full amount of the pension funding for 2004 is for the Company’s non-qualified supplemental retirement plan.
        The fair value of the plan assets of the pension benefits and other benefits are invested as follows at December 31:

 2003
2002
 PENSION
BENEFITS
OTHER
BENEFITS
PENSION
BENEFITS
OTHER
BENEFITS

Short-term investments and cash3.0%100.0%4.1%100.0%
Equity securities63.8%--55.7%-- 
Fixed income securities22.9%--31.2%-- 
Mutual funds10.3%--9.0%-- 

        The expected total benefits to be paid under both plans for the next five years and the aggregate total to be paid for the five years thereafter is as follows:

(DOLLARS IN THOUSANDS)200420052006200720082009-2013

Total benefits$ 35,697$ 25,940$ 26,939$ 28,806$ 28,202$157,821

        The assumed medical inflation rate is 9.0% in 2004 decreasing to 6.0% in 2007. A 1% change in the assumed medical inflation rate would have the following effects:

 2003
2002
(DOLLARS IN THOUSANDS)
1%
INCREASE

1%
DECREASE

1%
INCREASE

1%
DECREASE

Effect on post-retirement benefit obligation  $589 $(529)$580 $(515)
Effect on service and interest cost components   38  (35) 36  (32)

        The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purpose of obtaining the optimum return for the pension benefit plans, while also keeping with the assumption of prudent risk and the Retirement Committee’s total return objectives. All changes to the investment policies are reviewed and approved by the Retirement Committee prior to being implemented.
        The Retirement Committee contracts with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Committee has established investment allocation percentages by asset classes as follows:

 ALLOCATION
 
  ASSET CLASSMINIMUMTARGETMAXIMUM

Domestic large capitalization equity securities30%42%50%
Domestic small capitalization equity securities-- 8%15%
Fixed-income securities20%30%40%
Foreign equity securities10%20%30%
Real estate-- -- 10%
Short-term investments and cash-- -- 5%

NOTE 13.
Employee Investment Plans

        The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options.
        Puget Energy’s contributions to the Employee Investment Plans were $7.1 million, $6.9 million and $8.0 million for the years ended2003, 2002 and 2001, respectively.
        PSE’s contributions to the Employee Investment Plan were $6.1 million, $6.1 million and $6.8 million for the years 2003, 2002 and 2001, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.

NOTE 14.
Stock-based Compensation Plans

        The Company has various stock compensation plans which prior to 2003 were accounted for according to 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 will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Total compensation expense related to the plans was $6.4 million, $6.3 million and $2.1 million in 2003, 2002 and 2001, respectively.
        The Company’s shareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses many of the awards granted to employees. Established in 1995 and amended and restated in 1997, the LTI Plan applies to officers and key employees of the Company. Awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are purchased on the open market. The maximum number of shares that may be purchased for the LTI Plan is 1,200,000.

PERFORMANCE SHARE GRANTS
        Each year the Company awards performance share grants under the LTI Plan. These are granted to key employees and vest at the end of four years with the final number of shares awarded depending on a performance measure. The Company records compensation expense related to the shares based on the performance measure and changes in the market price of the stock. Compensation expense related to performance share grants was $5.1 million, $5.5 million and $2.3 million for 2003, 2002 and 2001, respectively. The fair value of the performance awards granted in 2003, 2002 and 2001 was $17.29, $14.82 and $17.86, respectively. There were a total of 334,608 performance awards granted in 2003, 247,184 in 2002 and 183,881 in 2001. As of December 31, 2003, there are four active grant cycles for a total of 790,922 share grants outstanding although they may not all be awarded.

STOCK OPTIONS
        In 2002, 2001,Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and 2000,an additional 260,000 options outside of the LTI Plan (for a total of 300,000 non-qualified stock options) to the president and chief executive officer. These options can be exercised at the grant date market price of $22.51 per share and vest yearly over four and five years although vesting is accelerated under certain conditions. The options expire 10 years from the grant date. All 300,000 options remained outstanding at December 31, 2003, with 67,500 options exercisable. No options were exercisable at December 31, 2002. The fair value of the options at the grant date was $3.37 per share. Following the intrinsic value method of APB 25, no compensation expense was recorded for these options. No additional options were granted in 2003.


RESTRICTED STOCK
        In 2003 and 2002, the Company granted 11,000 shares and 30,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market. Of the 2003 shares issued, 1,000 shares vested in 2003. The remaining shares will vest evenly over the next five years. The 2002 shares were fully vested as of December 2003. In 2002 the Company also issued 50,000 shares of restricted stock outside of the LTI Plan as approved by the Puget Energy Board of Directors. These shares were recorded as a separate component of stockholders’ equity and vest evenly over a five-year period. Compensation expense related to the restricted shares was $0.6 million and $0.5 million in 2003 and 2002, respectively.
        Future minimum lease payments No restricted shares were issued in 2001. Dividends are paid on all outstanding restricted stock and are accounted for non-cancelable leases netas a Puget Energy stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of sublease receipts are:


 (Dollars in thousands)PUGET ENERGYPSE 
 At December 31
Operating
Capital
Operating
 2003 $18,208 $2,040 $12,644 
 2004 14,694 1,774 10,404 
 2005 9,065 1,441 6,446 
 2006 7,604 1,335 6,502 
 2007 6,998 821 6,468 
 Thereafter

9,497
 
925
 
9,350
 
 Total minimum lease payments

$66,066
 
$8,336
 
$51,814
 

        Future minimum sublease receipts for non-cancelable subleases are $1 million for 2003.restricted stock granted in 2003 and 2002 was $23.29 and $21.94, respectively.

NOTE 11.
Income Taxes
EMPLOYEE STOCK PURCHASE PLAN
        The detailsCompany has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six-month intervals at the end of income taxeswhich the participating employees receive shares for 85% of the lower of the stock’s fair market price at the beginning or the end of the six-month period. A maximum of 500,000 shares may be sold to employees under the plan. Prior to 2002, the Company purchased shares for the plan on the open market. As of the second offering of 2002, the Company began issuing common stock for the ESPP rather than purchasing stock. In 2003, 38,940 shares were issued for the ESPP. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan, and in 2001, 45,659 shares were purchased. At December 31, 2003, 259,662 shares may still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003, ESPP is considered to be compensation expense. Total compensation expense related to the ESPP was $0.2 million in 2003. Dividends are not paid on ESPP shares until they are purchased by employees and thus are accounted for as follows:
dividends, not compensation expense. The weighted average fair value of the purchase rights granted in 2003, 2002 and 2001 was $4.25, $4.19 and $4.35, respectively.

(Dollars in thousands)
PUGET
ENERGY
2002

PSE
2002

PUGET
ENERGY
2001

PSE
2001

PUGET ENERGY
AND PSE
2000

  Charged to operating expense:            
  Current - federal  $(84,149)$(81,839)$58,749 $58,331 $128,138 
  Current - state   (774) (548) 1,347  1,232  832 
  Deferred - net federal   144,230  135,884  19,945  18,040  1,557 
  Deferred- net state   614  --  485  --  -- 
  Deferred investment tax credits   (661) (661) (688) (688) (704)

  Total charged to operations   59,260  52,836  79,838  76,915  129,823 

  Charged to miscellaneous income:  
  Current   (3,276) (3,406) 6,272  6,272  7,843 
  Deferred - net   1,228  1,228  (2,259) (2,259) (10,150)

  Total charged to miscellaneous income   (2,048) (2,178) 4,013  4,013  (2,307)

  Cumulative effect of accounting change   --  --  (7,942) (7,942) -- 

  Total income taxes  $57,212 $50,658 $75,909 $72,986 $127,516 


INFRASTRUX STOCK OPTION PLAN
        The InfrastruX stock option plan, established in 2000, has 3,862,500 shares of InfrastruX stock authorized to be granted to officers, key employees and non-employee directors of InfrastruX. The options generally vest within four years and expire 10 years from the grant date. The following summarizes InfrastruX option information for 2003, 2002 and 2001:

 2003
2002
2001
 Shares
(in thousands)
Weighted
Average
Exercise Price
Shares
(in thousands)
Weighted
Average
Exercise Price
Shares
(in thousands
Weighted
Average
Exercise Price
 


Outstanding at beginning of year 2,643 $     4.311,995 $     4.05-- $     -- 
Granted 176 5.00725 5.002,043 4.05
Exercised -- -- -- -- -- -- 
Canceled (201)4.20(77)4.09(48)4.00
 


Outstanding at end of year 2,618 $     4.362,643 $     4.311,995 $     4.05
Options exercisable at year end 1,837 $     4.12802 $     4.02791 $     4.00
 


Weighted average fair value of options
 granted during the year
 $2.41
$2.23
$1.60

        The following issummarizes InfrastruX's outstanding option information at December 31, 2003:

 Shares
Outstanding
(in thousands)
Weighted
Average
Contractual Life
(in years)
Weighted
Average
Exercise Price
 
Exercise Prices         
$4.00          1,666 7.11$4.00
$5.00             952 8.42  5.00
 
 2,618 7.59$4.36
 

        Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options have been granted at a reconciliationdiscount requiring InfrastruX to record compensation expense. With the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX also recorded compensation expense related to options granted in 2003. Compensation expense of $0.2 million and $0.1 million related to stock options was recorded in 2003 and 2002, respectively.

NON-EMPLOYEE DIRECTOR STOCK PLAN
        The Company has a director stock plan created in 1998 for all non-employee directors of Puget Energy and PSE. Under the plan which has a 10-year term, non-employee directors receive a minimum of two-thirds of their quarterly retainer fees in Company stock except that 100% of quarterly retainers are paid in Company stock until the director holds a number of shares equal to two years of common stock in value of their retainer. Directors may optionally receive their entire retainer in Company stock. The compensation expense related to the director stock plan was $0.4 million, $0.2 million and $0.1 million in 2003, 2002 and 2001, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000 shares. As of December 31, 2003, 9,902 shares had been purchased for the director stock plan and 48,219 deferred, for a total of 58,121 shares.

OTHER PLANS
        In addition to current stock compensation plans, the Company also has outstanding shares related to two plans that were in effect prior to the 1997 merger between Puget Sound Power and Light (PSP&L) and Washington Energy Company (WECO). There are 2,400 vested, unexercised stock appreciation rights from the PSP&L Incentive Plan Awards granted to executives of PSP&L. These were granted in 1994, have an exercise price of $20.75 and expire 10 years after the grant date. There are also 11,301 vested, unexercised options from the WECO Incentive Stock Option Plan granted to key employees of WECO. The options were granted between 1994 and 1996 with exercise prices ranging from $15.55 to $23.11 and expire 10 years from the date of grant. These are generally paid out as stock appreciation rights at the discretion of the grantees. The Company records compensation expense each quarter related to the PSP&L and WECO shares as the difference between the exercise price and the current market price. Compensation expense related to the WECO plan was immaterial in 2003 and 2002, and $(0.2) million in 2001. Compensation expense related to the PSP&L plan was immaterial in 2003 and 2002, and $(0.1) million in 2001.

        The Company used the Black-Scholes option pricing model to determine the fair value of certain stock-based awards to employees. The following assumptions were used for awards granted in 2003, 2002 and 2001:

 200320022001

Stock options 
  Risk-free interest rate     --4.32%    --
  Expected lives - years     --4.50    --
  Expected stock volatility     --23.62%    --
  Dividend yield     --5.00%    --

InfrastruX stock option plan 
  Risk-free interest rate 2.80%4.05%4.87%
  Expected lives - years 4.004.004.00
  Expected stock volatility 60.00%60.00%50.00%

Performance awards 
  Risk-free interest rate 2.35%4.00%4.99%
  Expected lives - years 4.004.004.00
  Expected stock volatility 23.85%23.71%20.76%
  Dividend yield 4.86%8.85%7.67%

Employee Stock Purchase Plan 
  Risk-free interest rate 1.07%1.65%4.26%
  Expected lives - years 0.500.500.50
  Expected stock volatility 19.47%26.97%19.04%
  Dividend yield 4.39%5.81%7.72%


NOTE 15.
Accounting for Derivative Instruments and Hedging Activities

        The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
        For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income taxes computedstatement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
        In addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with no significant impact on the financial statements.
        On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by multiplying pre-tax bookrecording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
        PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the statutory taxoriginal counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.

NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)

        During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of cash and preferred or common stock. The 2003 acquisition includes a contingency which requires InfrastruX to make additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
        These companies provide utility infrastructure services which are relevant to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunications providers; pipeline construction, maintenance and rehabilitation services for the natural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission-oriented overhead electric construction services to electric utilities and cooperatives.
        The acquisitions have been accounted for using the purchase method of accounting and, accordingly, the operating results of these companies have been included in Puget Energy’s consolidated financial statements since their acquisition dates. Goodwill additions representing the excess of cost over the net tangible and identifiable intangible assets at the time of purchase were approximately $7.7 million in 2003 and $23.5 million in 2002.
        During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the annual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:


(DOLLARS IN THOUSANDS)2003 2002 2001 

Reported income for common stock$      116,197 $      110,052 $       98,426 
Add back goodwill amortization, net of tax-- -- 2,826 
 
Adjusted income for common stock$      116,197 $      110,052 $      101,252 
 
Basic earnings per share
  Reported income for common stock$             1.23$             1.24$             1.14
  Add back goodwill amortization-- -- 0.03
 
  Adjusted income for common stock$             1.23$             1.24$             1.17
 
Diluted earnings per share
        Reported income for common stock$             1.22$             1.24$             1.14
        Add back goodwill amortization-- -- 0.03
 
        Adjusted income for common stock$             1.22$             1.24$             1.17
 

        Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 years. In 2003 a total of $2.1 million was added to intangible assets — assigned $0.1 million to patents with an amortization period of 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.

 
AT DECEMBER 31, 2003
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  4,178    $2,009    $  2,169    
Developed technology14,190    2,454    11,736    
Contractual customer relationships4,702    747    3,955    
Patents915    68    847    

 Total$23,985    $5,278    $18,707    
 
 
AT DECEMBER 31, 2002
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  3,908    $1,105    $  2,803    
Developed technology14,190    1,744    12,446    
Contractual customer relationships3,042    383    2,659    
Patents793    49    744    

 Total$21,933    $3,281    $18,652    
 

        The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(DOLLARS IN THOUSANDS)20042005200620072008

Future intangible amortization$ 2,101$ 2,075$ 1,746$ 1,363$ 1,340

        The pro forma combined revenues, net income and earnings per common share of Puget Energy presented below give effect to the acquisitions as if they had occurred on January 1, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.

(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOR THE YEARS ENDED DECEMBER 31
200320022001

Operating revenues$     2,505,523$     2,469,122$     3,056,824
Net income for common116,636112,813104,338
Basic earnings per common share$  1.23$  1.28$  1.21
Diluted earnings per common share$  1.22$  1.27$  1.20

NOTE 17.
Other

        PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
        The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
        In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
        PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
        In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.


NOTE 18.
Commitments and Contingencies

COMMITMENTS – ELECTRIC
        For the year ended December 31, 2003, approximately 19.9% of the Company’s energy output was obtained at an average cost of approximately $0.01641 per kWh through long-term contracts with several of the Washington Public Utility Districts (PUDs) owning hydroelectric projects on the Columbia River.
        The purchase of power from the Columbia River projects is on a “cost-of-service” basis under which the Company pays a proportionate share of the annual cost of each project in direct proportion to the amount of income taxespower annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the lives of the contracts.
        As of December 31, 2003, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:

 BONDS
OUTSTANDING
COMPANY'S ANNUAL AMOUNT
PURCHASABLE (APPROXIMATE)

PROJECTCONTRACT
EXP. DATE
LICENSE1
EXP. DATE
12/31/032
(MILLIONS)
% OF
OUTPUT
MEGAWATT
CAPACITY
COSTS3
(MILLIONS)

  Rock Island         
     Original units 2012 2029 $         121.750.0 414 $    41.9
     Additional units 2012 2029 331.575.0 
  Rocky Reach 2011 2006 394.738.9 505 29.6
  Wells 2018 2012 151.331.3 261 6.9
  Priest Rapids4 2005 2005 184.78.0 72 2.6
  Wanapum4 2009 2005 186.510.8 98 4.1

  Total     $        1,370.4  1,350 $    85.1

        The Company’s estimated payments for power purchases from the Columbia River are $84.6 million for 2004, $81.4 million for 2005, $78.4 million for 2006, $81.4 million for 2007, $82.6 million for 2008 and in the aggregate, $123.5 million thereafter through 2018.
        The Company also has numerous long-term firm purchased power contracts with other utilities in the region. The Company is generally not obligated to make payments under these contracts unless power is delivered. The Company’s estimated payments for firm power purchases from other utilities, excluding the Columbia River projects, are $76.0 million for 2004, $77.7 million for 2005, $78.6 million for 2006, $80.7 million for 2007, $82.6 million for 2008 and in the aggregate, $433.3 million thereafter through 2037. These contracts have varying terms and may include escalation and termination provisions.
        As required by the federal Public Utility Regulatory Policies Act (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The Company purchases the net electrical output of four significant projects at fixed and annually escalating prices, which were intended to approximate the Company’s avoided cost of new generation projected at the time these agreements were made. The Company’s estimated payments under these contracts are $211.4 million for 2004, $217.3 million for 2005, $232.9 million for 2006, $211.9 million for 2007, $212.1 million for 2008 and in the aggregate, $746.0 million thereafter through 2012.
        The following table summarizes the Company’s estimated obligations for future power purchases:


(DOLLARS IN MILLIONS)200420052006200720082009 &
THERE-
AFTER
TOTAL

  Columbia River projects$    84.6$     81.4$     78.4$     81.4$     82.6$       123.5$     531.9
  Other utilities76.077.778.680.782.6433.3828.9
  Non-utility generators211.4217.3232.9211.9212.1746.01,831.6

      Total$   372.0$   376.4$   389.9$   374.0$   377.3$    1,302.8  $   3,192.4


1The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirm the Company's contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term.
2The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and refinancings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration date are: 43.7% at Rock Island; 58.3% at Rocky Reach; 94.5% at Priest Rapids; 79.6% at Wanapum; and 6.2% at Wells.
3The components of 2003 costs associated with the interest portion of debt service are: Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million; Wells, $8.2 million; Priest Rapids, $0.8 million; and Wanapum, $0.6 million.
4On December 28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. Grant County PUD filed an "Application for New License for the Priest Rapids Project" on October 29, 2003. The new contract terms begin in November of 2005 for the Priest Rapids Development and in November of 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts PSE's share of power from the developments declines over time as Grant County PUD's load increases. On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County PUD's new contracts unreasonably restrain trade and violate various sections of the Federal Power Act and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, it has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing has been requested.

        Total purchased power contracts provided the Company with approximately 11.0 million, 12.1 million and 11.9 million MWh of firm energy at a cost of approximately $479.2 million, $466.1 million and $496.3 million for the years 2003, 2002 and 2001, respectively.
        The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2003:

COMPANY'S SHARE
(DOLLARS IN MILLIONS)ENERGY
SOURCE (FUEL)
COMPANY'S
OWNERSHIP
SHARE
PLANT IN SERVICE
AT COST
ACCUMULATED
DEPRECIATION

Colstrip 1 & 2   Coal   50% $     207  $     133 
Colstrip 3 & 4   Coal   25% 464  240 

        Financing for a participant’s ownership share in the projects is provided for by such participant. The Company’s share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of IncomeIncome.
        PSE and PPL Montana, the other owner of Colstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s PCA mechanism.
        On October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE used the coal as fuel for its share of Units 3 & 4 of the Colstrip generating plant. PSE’s coal price for that period was reduced by a settlement PSE and Western Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the Company:federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
        As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of Tenaska’s cogeneration facility. This obligation continues for the remaining term of the agreement, provided that no deliveries are required during the month of May. The price paid by Tenaska for this gas is reflective of the daily price of gas at the United States/Canada border near Sumas, Washington. PSE has entered into a financial arrangement to hedge a portion, 5,000 MMBtu to 10,000 MMBtu per day, of future gas supply costs associated with this obligation. The Company has a maximum financial obligation under this hedge agreement of $22.0 million in 2004.
        As part of its electric operations and in connection with the 1999 buyout of the Cabot gas supply contract, PSE is obligated to deliver to Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The Company entered into a financial arrangement to hedge a portion of future gas supply

(Dollars in thousands)
PUGET
ENERGY
2002

PSE
2002

PUGET
ENERGY
2001

PSE
2001

PUGET
ENERGY
AND PSE
2000

  Income taxes at the statutory rate  $61,587 $55,862 $63,962 $62,079 $112,471 

  Increase (decrease):  
    Depreciation expense deducted in the  
      financial statements in excess of tax  
      depreciation, net of depreciation  
      treated as a temporary difference   10,041  10,041  11,726  11,726  10,807 
    AFUDC included in income in the financial  
      statements but excluded from taxable income   (1,387) (1,387) (2,126) (2,126) (3,274)
    Accelerated benefit on early retirement  
      of depreciable assets   (1,469) (1,469) (319) (319) (834)
    Investment tax credit amortization   (661) (661) (689) (689) (704)
    Energy conservation expenditures - net   6,259  6,259  6,859  6,859  10,634 
    Tax benefit of reduced salvage values   (10,193) (10,193) --  --  -- 
    State income taxes net of the federal income tax benefit   (104) (356) 1,191  801  541 
    Other - net   (6,861) (7,438) (4,695) (5,345) (2,125)

  Total income taxes  $57,212 $50,658 $75,909 $72,986 $127,516 

  Effective tax rate   32.5% 31.7% 41.5% 41.1% 39.7%


costs associated with this obligation, 10,000 MMBtu per day, for the remaining term of the agreement. The Company has a maximum financial obligation under this hedge agreement of $8.5 million in 2004, $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter. Depending on actual market prices, these costs will be partially, or perhaps entirely, offset by floating price payments received under the hedge arrangement. Encogen has two gas supply agreements that comprise 40% of the plant’s requirements with remaining terms of 6.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7 million in 2005, $17.5 million in 2006, $18.4 million in 2007 and $12.9 million in the aggregate thereafter.
        PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are generally classified as normal purchases and normal sales or in some cases recorded at fair value in accordance with SFAS No. 133. Commitments under these contracts are $3.0million in 2004, $10.3 million in 2005, $1.1 million in 2006, $0.4 million in 2007 and $0.1 million thereafter.

GAS SUPPLY
        The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1 year to 20 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Two of PSE’s long-term firm gas supply agreements, that expire November 2004, obligate the Company to purchase a minimum annual quantity at market-based contract prices. If the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. PSE didn’t incur such charges in 2003. The Company incurred demand charges in 2003 for firm gas supply, firm transportation service and firm storage and peaking service of $24.7 million, $47.9 million and $5.3 million, respectively. WNG Cap I incurred demand charges in 2003 for firm transportation service of $9.4 million.
        The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.

DEMAND CHARGE OBLIGATIONS
(DOLLARS IN MILLIONS)
200420052006200720082009 &
THERE-
AFTER
TOTAL

  Firm gas supply$    18.7$     1.5$     1.0$     0.5$     0.5$       1.5$      23.7
  Firm transportation service66.658.857.057.048.0122.7410.1
  Firm storage service11.311.67.87.77.748.294.3

      Total$    96.6$    71.9$    65.8$    65.2$    56.2$    172.4$    528.1

SERVICE CONTRACT
        On August 30, 2001, PSE and Alliance Data Systems Corp. announced a contract under which Alliance Data will provide data processing and billing services for PSE. In providing services to PSE under the principal components10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by its ConneXt subsidiary. Alliance Data acquired the assets of income taxesConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as reported:part of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $21.7 million in 2004, $22.2 million in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008 and $66.9 million in the aggregate thereafter.

(Dollars in thousands)
PUGET
ENERGY
2002

PSE
2002

PUGET
ENERGY
2001

PSE
2001

PUGET
ENERGY
AND PSE
2000

  Current income taxes - federal  $(87,425)$(85,245)$65,021 $64,603 $135,981 
  Current income taxes - state   (774) (548) 1,347  1,232  832 

  Deferred income taxes:  
    Conservation tax settlement   --  --  963  963  1,776 
    Deferred FAS-133   4,064  4,064  (4,028) (4,028) -- 
    Cabot preferred stock sale   --  --  --  --  (10,635)
    Deferred taxes related to insurance reserves   (1,662) (1,662) (1,225) (1,225) (384)
    Residential Purchase and Sale Agreement - net   --  --  3,390  3,390  2,226 
    Normalized tax benefits of the  
      accelerated cost recovery system   29,197  29,197  11,423  11,423  10,931 
    Energy conservation program   (96) (96) (1,337) (1,337) (1,666)
    Environmental remediation   1,392  1,392  1,326  1,326  721 
    WNP 3 tax settlement   (1,126) (1,126) (1,126) (1,126) (1,126)
    Demand charges   (8) (8) (98) (98) (79)
    Deferred revenue   612  612  (5,904) (5,904) -- 
    Software amortization   35,373  35,373  --  --  -- 
    Capitalized overhead costs deducted for tax purposes   72,220  72,220  --  --  -- 
    Allowance for doubtful accounts   --  --  --  --  (13,821)
    Other   6,106  (2,854) 6,845  4,455  3,464 

  Total deferred income taxes   146,072  137,112  10,229  7,839  (8,593)

  Deferred investment tax credits -  
    net of amortization   (661) (661) (688) (688) (704)

  Total income taxes  $57,212 $50,658 $75,909 $72,986 $127,516 

SURETY BOND
        The Company has a self-insurance surety bond in the amount of $5.9 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.

ENVIRONMENTAL
        The Company is subject to environmental laws and regulations by federal, state and local authorities and has been required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has also been named by the Environmental Protection Agency, the Washington State Department of Ecology, and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring these sites. Remediation and testing of Company vehicle service facilities and storage yards is also continuing.
        During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or under the Washington Commission’s order.
        The information presented here as it relates to estimates of future liability is as of December 31, 2003.


ELECTRIC SITES
        The Company has expended approximately $18.1 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.6 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $18.8 million from insurance carriers.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s deferred tax liabilityfinancial position, operating results or cash flow trends.

GAS SITES
        The Company has expended approximately $65.9 million related to the remediation activities covered by a Washington Commission order and has accrued approximately $32.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $59.6 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

LITIGATION
        There are several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville Power Administration (BPA), in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the amended settlement agreement regarding the Residential Purchase and Sale Program and the conditional settlement agreements between BPA and PSE which modified the payment provisions of the Residential Purchase and Sale Program. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates may have on PSE.
        Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 20022003. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

NOTE 19.
Segment Information

        Puget Energy operates in primarily two business segments: regulated utility operations, or PSE, and construction services, or InfrastruX. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the State of Washington. InfrastruX specializes in construction services to other gas and electric utilities primarily in the south/Texas and the north-central and eastern United States.
        One minor non-utility business segment, a PSE subsidiary, which is a real estate investment and development company is described as other. The assets of ConneXt, the development and marketing of customer information and billing system software segment, were sold during the third quarter of 2001. The third quarter results of 2001 is comprised of amountsincluded an $8.0 million after-tax gain related to the following types of temporary differences:

(Dollars in thousands)
PUGET
ENERGY
2002

PSE
2002

PUGET
ENERGY
2001

PSE
2001

  Utility plant  $578,137 $578,137 $570,982 $570,982 
  Energy conservation charges   16,473  16,473  23,782  23,782 
  Contributions in aid of construction   (44,770) (44,770) (36,044) (36,044)
  Bonneville Exchange Power   15,537  15,537  17,897  17,897 
  Cabot gas contract purchase   4,157  4,157  4,477  4,477 
  Deferred revenue   (5,292) (5,292) (5,904) (5,904)
  Software amortization   41,408  41,408  --  -- 
  Capitalized overhead costs   72,220  72,220  --  -- 
  Other   52,805  37,709  30,125  25,811 

  Total  $730,675 $715,579 $605,315 $601,001 

        Puget Energy’s totals of $730.7 million and $605.3 million for 2002 and 2001 consist of deferred tax liabilities of $841.7 million and $713.8 million net of deferred tax assets of $111.0 million and $108.5 million, respectively.
        PSE’s totals of $715.6 million and $601.0 million for 2002 and 2001 consist of deferred tax liabilities of $824.2 million and $707.4 million net of deferred tax assets of $108.6 million and $106.4 million, respectively.
        Deferred tax amounts shown above result from temporary differences for tax and financial statement purposes. Deferred tax provisionsConneXt sale. Reconciling items between segments are not recorded in the income statementsignificant.


        Financial data for certain temporary differences between tax and financial statement purposes because theybusiness segments are not allowed for ratemaking purposes.as follows:

  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2003UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,143,693 $341,787 $  6,043 $2,491,523 
  Depreciation and amortization219,851 16,779 236 236,866 
  Income tax69,823 1,594 952 72,369 
  Operating income295,219 7,452 2,504 305,175 
  Interest charges, net of AFUDC179,437 5,485 123 185,045 
  Net income119,144 1,766 438 121,348 
  Goodwill, net-- 133,302 -- 133,302 
  Total assets5,257,157 342,332 75,196 5,674,685 
  Construction expenditures - excluding equity AFUDC269,973 -- -- 269,973 
  Additions to other property, plant and equipment-- 15,536 -- 15,536 


        The Company calculates its deferred tax assets and liabilities under SFAS No. 109, “Accounting for Income Taxes”. SFAS No. 109 requires recording deferred tax balances, at the currently enacted tax rate, for all temporary differences between the book and tax bases of assets and liabilities, including temporary differences for which no deferred taxes had been previously provided because of use of flow-through tax accounting for ratemaking purposes. Because of prior and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, a regulatory asset for income taxes recoverable through future rates related to those differences has also been established by PSE. At December 31, 2002, the balance of this asset was $167.1 million.

  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2002UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,063,040 $319,529 $    9,753 $2,392,322 
  Depreciation and amortization215,097 13,426 220 228,743 
  Income tax50,600 6,703 1,957 59,260 
  Operating income289,511 15,595 4,563 309,669 
  Interest charges, net of AFUDC190,861 5,516 -- 196,377 
  Net income104,044 9,455 4,384 117,883 
  Goodwill, net-- 125,555 -- 125,555 
  Total assets5,323,129 319,248 129,756 5,772,133 
  Construction expenditures - excluding equity AFUDC224,165 -- -- 224,165 
  Additions to other property, plant and equipment-- 11,621 -- 11,621 


  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2001UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,680,298 $173,786 $  32,476 $2,886,560 
  Depreciation and amortization208,705 8,820 15 217,540 
  Income tax68,005 2,956 8,877 79,838 
  Operating income273,751 8,702 14,668 297,121 
  Interest charges, net of AFUDC186,403 3,656 -- 190,059 
  Net income80,137 2,518 24,184 106,839 
  Goodwill, net-- 102,151 -- 102,151 
  Total assets5,300,105 229,125 139,251 5,668,481 
  Construction expenditures - excluding equity AFUDC247,435 -- -- 247,435 
  Additions to other property, plant and equipment-- 5,193 -- 5,193 


NOTE 12.20.
        Retirement Benefits

        The Company has a defined benefit pension plan with a cash balance feature covering substantially all of its utility employees. Benefits are a function of both age, salary and salary.service. Additionally, Puget Energy maintains a non-qualified supplemental retirement plan for officers and certain director-level employees. The annual measurement date is December 31 of each year.
        In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company whose premiums are based on the benefits paid during the year.


PENSION BENEFITSOTHER BENEFITS PENSION BENEFITS
OTHER BENEFITS
(Dollars in thousands)
2002
2001
2002
2001
(DOLLARS IN THOUSANDS)   2003  2002  2003  2002 


Change in benefit obligation:           
Benefit obligation at beginning of year $400,461 $366,482 $29,115 $27,568  $369,692 $400,461 $31,693 $29,115 
Service cost  8,474  9,862  168  243   8,284  8,474  175  168 
Interest cost  25,858  26,734  1,930  2,022   24,406  25,858  1,828  1,930 
Amendments1  3,073  3,984  3,493  --   940  3,073  --  3,493 
Actuarial loss  2,055  15,417  (419) 1,101   19,354  2,055  (2,194) (419)
Plan curtailment2  (9,518) --  (553) --   --  (9,518) --  (553)
Special adjustments2  10,872  --  --  --   190  10,872  --  -- 
Benefits paid  (71,583) (22,018) (2,041) (1,819)  (22,825) (71,583) (2,282) (2,041)



Benefit obligation at end of year $369,692 $400,461 $31,693 $29,115  $400,041 $369,692 $29,220 $31,693 



Change in plan assets:  
Fair value of plan assets at beginning of year $443,512 $496,468 $15,978 $15,661 
Fair value of plan assets at beginning $343,960 $443,512 $16,160 $15,978 
Actual return on plan assets  (40,849) (32,025) 650  595   79,488  (40,849) 98  650 
Employer contribution  12,880  1,087  1,573  1,541   27,963  12,880  1,455  1,573 
Benefits paid  (71,583) (22,018) (2,041) (1,819)  (22,825) (71,583) (2,282) (2,041)



Fair value of plan assets at end of year $343,960 $443,512 $16,160 $15,978 
Fair value of plan assets at end of yea $428,586 $343,960 $15,431 $16,160 



Funded status $(25,732)$43,051 $(15,533)$(13,137) $28,545 $(25,732)$(13,789)$(15,533)
Unrecognized actuarial gain  66,784  (27,035) (1,878) (1,944)
Unrecognized actuarial gain (loss)  48,217  66,784  (2,895) (1,878)
Unrecognized prior service cost  18,228  20,250  3,021  (361)  15,949  18,228  2,712  3,021 
Unrecognized net initial (asset)/obligation  (2,371) (3,873) 4,201  6,894 
Unrecognized net initial (asset) obliga  (1,267) (2,371) 3,783  4,201 



Net amount recognized $56,909 $32,393 $(10,189)$(8,548) $91,444 $56,909 $(10,189)$(10,189)



Amounts recognized on statement of  
financial position consist of:  
Prepaid benefit cost $73,361 $54,335 $(10,189)$(8,548) $112,737 $73,361 $(10,189)$(10,189)
Accrued benefit liability  (34,253) (37,002) --  --   (38,704) (34,253) --  -- 
Intangible asset  10,555  9,912  --  --   9,043  10,555  --  -- 
Accumulated other comprehensive income  7,246  5,148  --  --   8,368  7,246  --  -- 



Net amount recognized $56,909 $32,393 $(10,189)$(8,548) $91,444 $56,909 $(10,189 )$(10,189)




1 In 2002, the Company had $3.1 million in pension benefit plan amendments due to changes in employment contracts, the addition of new entrants to the plan and the vesting of certain non-vested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefit plan amendments due to an increase in the Company's contribution to the retiree medical plan.
2 In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.

        In accounting for pension and other benefitsbenefit costs under the plans, the following weighted average actuarial assumptions were used:

         PENSION BENEFITS        OTHER BENEFITS
 
2002
2001
2000
2002
2001
2000
  Discount rate6.75%7.25%7.5%6.75%7.25%7.5%
  Return on plan assets8.25%9.50%9.75%6-7.00%6-8.25%6-8.5%
  Rate of compensation increase4.50%5.0%5.0%------
  Medical trend rate------10.00%6.5%7.0%







1

In 2002, the Company had $3.1 million in pension benefits plan amendments due to changes in employment contracts, the addition of new entrants to the plan and the vesting of certain nonvested participants who were affected by the transition of service jobs to service providers. The Company had $3.5 million in other benefits plan amendments due to an increase in the Company's contribution to the retiree medical plan.

2

In 2002, the Company had a $9.5 million curtailment credit and $9.2 million in special adjustments to the pension benefit plan related to the transition of service jobs to service providers. The Company also had a $1.7 million special adjustment to the pension benefit plan related to the non-qualified pension benefit plan required to reflect the special benefit agreement given upon termination of a plan participant.


 PENSION BENEFITS
OTHER BENEFITS
 2003 2002 2001 2003 2002 2001 

  Discount rate6.25%6.75%7.25%6.25%6.75%7.25%
  Return on plan assets8.25%8.25%9.50%6-7.00%6-7.00%6-8.25%
  Rate of compensation increa4.50%4.50%5.0%-- -- -- 
  Medical trend rate-- -- -- 9.00%10.00%6.50%





 PENSION BENEFITS OTHER BENEFITS   
  (Dollars in thousands)   2002  2001  2000  2002  2001  2000 







  Components of net periodic benefit cost:  
  Service cost  $8,474 $9,862 $9,005 $168 $243 $224 
  Interest cost   25,858  26,734  25,500  1,930  2,022  1,965 
  Expected return on plan assets   (43,032) (46,222) (42,280) (906) (947) (892)
  Amortization of prior service cost   2,990  2,960  2,884  90  (34) (34)
  Recognized net actuarial gain   (5,120) (7,570) (6,851) (229) (109) (195)
  Amortization of transition  
    (asset)/obligation   (1,136) (1,230) (1,230) 470  627  627 
  Plan curtailment   (1,353) --  --  1,691  --  -- 
  Special recognition of prior service costs   1,683  108  77  --  --  -- 







  Net pension benefit cost (income)  $(11,636)$(15,358)$(12,895)$3,214 $1,802 $1,695 

        The Company has used the expected return on plan assets based on an analysis of rates of return over the past 50 years relevant to the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors and adjusted accordingly.

 PENSION BENEFITS
OTHER BENEFITS
  (DOLLARS IN THOUSANDS)   2003  2002  2001  2003  2002  2001 

  Components of net periodic benefit cost:  
  Service cost  $8,284 $8,474 $9,862 $175 $168 $243 
  Interest cost   24,406  25,858  26,734  1,828  1,930  2,022 
  Expected return on plan assets   (38,880) (43,032) (46,222) (934) (906) (947)
  Amortization of prior service cost   3,220  2,990  2,960  309  90  (34)
  Recognized net actuarial gain   (2,688) (5,120) (7,570) (341) (229) (109)
  Amortization of transition (asset) obligation   (1,104) (1,136) (1,230) 418  470  627 
  Plan curtailment   --  (1,353) --  --  1,691  -- 
  Special recognition of prior service costs   190  1,683  108  --  --  -- 

  Net pension benefit cost (income)  $(6,572)$(11,636)$(15,358)$1,455 $3,214 $1,802 

        The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the non-qualified pension plan, which has accumulated benefit obligations in excess of plan assets, were $39.4$45.0 million, $34.2$38.6 million and $0, respectively, as of December 31, 2002.2003. For the qualified pension plan the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $330.3$355.1 million, $310.1$339.7 million and $344.0$428.6 million, respectively, as of December 31, 2002.2003.
        The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ended December 31, 2004 are $11.1 million and an insignificant amount, respectively. The full amount of the pension funding for 2004 is for the Company’s non-qualified supplemental retirement plan.
        The fair value of the plan assets of the pension benefits and other benefits are invested as follows at December 31:

 2003
2002
 PENSION
BENEFITS
OTHER
BENEFITS
PENSION
BENEFITS
OTHER
BENEFITS

Short-term investments and cash3.0%100.0%4.1%100.0%
Equity securities63.8%--55.7%-- 
Fixed income securities22.9%--31.2%-- 
Mutual funds10.3%--9.0%-- 

        The expected total benefits to be paid under both plans for the next five years and the aggregate total to be paid for the five years thereafter is as follows:

(DOLLARS IN THOUSANDS)200420052006200720082009-2013

Total benefits$ 35,697$ 25,940$ 26,939$ 28,806$ 28,202$157,821

        The assumed medical inflation rate is 10.0%9.0% in 20032004 decreasing 1.0% per year to 6.0%. in 2007. A 1% change in the assumed medical inflation rate would have the following effects:

 20022001
 1%1%1%1%
(Dollars in thousands)INCREASEDECREASEINCREASEDECREASE





  Effect on service and interest cost components  $580 $(515)$625 $(558)
  Effect on post retirement benefit obligation   36  (32) 47  (42)
 2003
2002
(DOLLARS IN THOUSANDS)
1%
INCREASE

1%
DECREASE

1%
INCREASE

1%
DECREASE

Effect on post-retirement benefit obligation  $589 $(529)$580 $(515)
Effect on service and interest cost components   38  (35) 36  (32)

        The Company has a Retirement Committee that establishes investment policies, objectives and strategies for the purpose of obtaining the optimum return for the pension benefit plans, while also keeping with the assumption of prudent risk and the Retirement Committee’s total return objectives. All changes to the investment policies are reviewed and approved by the Retirement Committee prior to being implemented.
        The Retirement Committee contracts with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Committee has established investment allocation percentages by asset classes as follows:

 ALLOCATION
 
  ASSET CLASSMINIMUMTARGETMAXIMUM

Domestic large capitalization equity securities30%42%50%
Domestic small capitalization equity securities-- 8%15%
Fixed-income securities20%30%40%
Foreign equity securities10%20%30%
Real estate-- -- 10%
Short-term investments and cash-- -- 5%

NOTE 13.
        Employee Investment Plans and Employee Stock Purchase Plan

        The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options.
        Puget Energy’s contributions to the Employee Investment Plans were $7.1 million, $6.9 million $8.0 million, and $7.2$8.0 million for the years 2003, 2002 2001 and 2000,2001, respectively.
        PSE’s contributions to the Employee Investment Plan were $6.1 million, $6.8$6.1 million and $7.2$6.8 million for the years 2003, 2002 2001 and 2000,2001, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
        The Company also has an Employee Stock Purchase Plan which was approved by shareholders on May 19, 1997, and commenced July 1, 1997, under which options are granted to eligible employees who elect to participate in the plan on January 1st and July 1st of each year. Participants are allowed to exercise those options six months later to the extent of payroll deductions or cash payments accumulated during that six-month period. The option price under the plan during 2002 was 85% of either the fair market value of the common stock at the grant date or the fair market value at the exercise date, whichever was less. Prior to 2002 the Company purchased stock for the plan on the open market. Starting with the purchase rights accumulated under the July 1, 2002 grant the Company began issuing rather than purchasing stock. The Company’s contributions to the plan were $0.1 million, $0.1 million and $0.3 million for 2002, 2001 and 2000, respectively.


NOTE 14.
        Stock-based Compensation Plans

        The Company has various stock compensation plans which prior to 2003 were accounted for according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.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 will apply SFAS No. 123 accounting prospectively to stock compensation awards granted in 2003 and future years, while grants that were made in years prior to 2003 will continue to be accounted for using the intrinsic value method of APB No. 25. Total compensation expense related to the plans was $6.4 million, $6.3 million and $2.1 million in 2003, 2002 and $3.9 million in 2002, 2001, and 2000 respectively.
        The Company’s shareholder approvedshareholder-approved Long-Term Incentive Plan (LTI Plan) encompasses many of the awards granted to employees. Established in 1995 and amended and restated in 1997, the LTI Plan applies to officers and key employees of the Company. Awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are purchased on the open market. The maximum number of shares that may be purchased for the LTI Plan is 1,200,000.

PERFORMANCE SHARE GRANTS
        Each year the Company awards performance share grants under the LTI Plan. These are granted to key employees and vest at the end of four years with the final number of shares awarded depending on a performance measure. The Company records compensation expense related to the shares based on the performance measure and changes in the market price of the stock. Compensation expense related to performance share grants was $5.1 million, $5.5 million and $2.3 million for 2003, 2002 and $3.2 million for 2002, 2001, and 2000, respectively. The fair value of the performance awards granted in 2003, 2002 and 2001 was $17.29, $14.82 and 2000 is $14.82, $17.86, and $14.19 respectively. 247,184There were a total of 334,608 performance awards were granted in 2003, 247,184 in 2002 and 183,881 in 2001 and 204,044 in 2000.2001. As of December 31, 2002,2003, there are four active grant cycles active for a total of 571,719790,922 share grants outstanding although they may not all be awarded.

STOCK OPTIONS
        In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside of the LTI Plan for(for a total of 300,000 non-qualified stock optionsoptions) to the new president and chief executive officer. These options were awardedcan be exercised at the grant date market price of $22.51 per share and vest yearly over four and five years although vesting is accelerated under certain conditions. The options expire 10 years from the grant date. As ofAll 300,000 options remained outstanding at December 31, 2002, no2003, with 67,500 options exercisable. No options were exercisable.exercisable at December 31, 2002. The grant date fair value of the options is $3.37.at the grant date was $3.37 per share. Following the intrinsic value method of APB 25, no compensation expense was recorded for these options.

No additional options were granted in 2003.


RESTRICTED STOCK
        In 2003 and 2002, the Company granted 11,000 shares and 30,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market. TheOf the 2003 shares vest monthly with all of theissued, 1,000 shares vested byin 2003. The remaining shares will vest evenly over the next five years. The 2002 shares were fully vested as of December 2003. TheIn 2002 the Company also issued 50,000 shares of restricted stock outside of the LTI Plan as approved by the Puget Energy Board of Directors. These shares were recorded as a separate component of stockholdersstockholders’ equity and vest at the rate of 20% per year.evenly over a five-year period. Compensation expense related to the restricted shares was $0.6 million and $0.5 million in 2002.2003 and 2002, respectively. No restricted shares were issued in 2001 and 2000.2001. Dividends are paid on all outstanding restricted stock and are accounted for as a Puget Energy stock dividend, not as compensation expense. At December 31, 2002 theThe weighted average grant date fair value for all outstanding shares of restricted stock granted in 2003 and 2002 was $21.94.

$23.29 and $21.94, respectively.

EMPLOYEE STOCK PURCHASE PLAN
        The Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six monthsix-month intervals at the end of which the participating employees receive shares for 85% of the lower of the stock’s fair market price at the beginning or the end of the six monthsix-month period. A maximum of 500,000 shares may be sold to employees under the plan. ThePrior to 2002, the Company purchased shares for the plan on the open market up untilmarket. As of the most recentsecond offering at which time common stock was issued rather than purchased. Theof 2002, the Company currently plans to issuebegan issuing common stock for the ESPP rather than purchasing stock. In 2003, 38,940 shares were issued for the ESPP. In 2002, 18,252 shares were issued and 19,407 shares were purchased for the plan, and 18,252in 2001, 45,659 shares were issued. 45,659 shares and 48,513 shares were purchased in 2001 and 2000 respectively.purchased. At December 31, 2002 298,6022003, 259,662 shares may still be sold to employees under the plan. Under the SFAS No. 123 accounting that the Company adopted in 2003, ESPP is considered to be compensation expense. Total compensation expense related to the ESPP was $0.2 million in 2003. Dividends are not paid on ESPP shares until they are purchased sharesby employees and thus are accounted for as a Puget Energy stock dividend,dividends, not as compensation expense. The weighted average fair value of the purchase rights granted in 2003, 2002 and 2001 was $4.25, $4.19 and 2000 was $4.19, $4.35, and $3.90 respectively.


INFRASTRUX STOCK OPTION PLAN
        The InfrastruX stock option plan, established in 2000, has 3,862,500 shares of InfrastruX stock authorized to be granted to officers, key employees and non-employee directors of InfrastruX. The options generally vest within four years and expire 10 years from the grant date. No options were granted under the InfrastruX plan in 2000. The following summarizes InfrastruX option information for 2003, 2002 and 2001:

2003
2002
2001
2002
2001
Shares
(in thousands)
Weighted
Average
Exercise Price
Shares
(in thousands)
Weighted
Average
Exercise Price
Shares
(in thousands
Weighted
Average
Exercise Price
Shares
(in thousands)

Weighted-
Average
Exercise Price

Shares
(in thousands)

Weighted-
Average
Exercise Price


Outstanding at beginning of year1,995 $4.05 -- --  2,643 $     4.311,995 $     4.05-- $     -- 
Granted725 5.00 2,043 $4.05  176 5.00725 5.002,043 4.05
Exercised-- -- -- --  -- -- -- -- -- -- 
Canceled(77)
 4.09
 (48)
 4.00
  (201)4.20(77)4.09(48)4.00

Outstanding at end of year2,643 $4.31 1,995 $4.05  2,618 $     4.362,643 $     4.311,995 $     4.05
Options exercisable at year end802 $4.02 791 $4.00  1,837 $     4.12802 $     4.02791 $     4.00
Weighted-average fair value of        
options granted during the year      $2.23       $1.60

Weighted average fair value of options
granted during the year
 $2.41
$2.23
$1.60

The following summarizes InfrastruXInfrastruX's outstanding option information at December 31, 2002:2003:

Shares
Outstanding
(in thousands)
Weighted
Average
Contractual Life
(in years)
Weighted
Average
Exercise Price
Shares
Outstanding
(in thousands

Weighted-
Average
Contractual Life
(in years)

Weighted-
Average
Exercise Price


Exercise Prices         
$4.001,828 9.12 $4.00 1,666 7.11$4.00
$5.00   815
 
9.31
 
  5.00
 
   952 8.42  5.00
2,643
 
9.18
 
$4.31
 

2,618 7.59$4.36


        Stock options awarded under the InfrastruX plan were generally granted at the InfrastruX market price on the date of grant although some options have been granted at a discount requiring InfrastruX to record compensation expense. A totalWith the prospective adoption of SFAS No. 123 fair value accounting in 2003, InfrastruX also recorded compensation expense related to options granted in 2003. Compensation expense of $0.2 million and $0.1 million in compensation expense related to stock options was recorded in 2002.

2003 and 2002, respectively.

NON-EMPLOYEE DIRECTOR STOCK PLAN
        The Company has a director stock plan created in 1998 for all non-employee directors of Puget Energy/Energy and PSE. Under the plan which has a 10-year term, non-employee directors receive parta minimum of two-thirds of their quarterly retainer fees in Company stock andexcept that 100% of quarterly retainers are paid in Company stock until the director holds a number of shares equal to two years of common stock in value of their retainer. Directors may optionally receive their entire retainer in Company stock if they choose.stock. The compensation expense related to the director stock plan was $0.4 million, $0.2 million and $0.1 million in 2003, 2002 and $0.3 million in 2002, 2001, and 2000, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 100,000 shares. As of December 31, 2002, 6,9162003, 9,902 shares havehad been purchased for the director stock plan and 36,11748,219 deferred, for a total of 43,03358,121 shares.


OTHER PLANS
        In addition to current stock compensation plans, the Company also has outstanding shares related to two plans that were in effect prior to the 1997 merger between Puget Sound Power and Light (PSP&L) and Washington Energy Company (WECO). There are 30,8002,400 vested, unexercised stock appreciation rights from the PSP&L Incentive Plan Awards granted to executives of PSP&L. These were granted in 1993 and 1994, for $27.63 andhave an exercise price of $20.75 respectively, and expire 10 years after the grant date. There are also 17,96011,301 vested, unexercised options from the WECO Incentive Stock Option Plan granted to key employees of WECO. The options were granted between 19931994 and 1996 forwith exercise prices ranging from $15.55 to $23.11 and expire 10 years from the date of grant. These are generally paid out as stock appreciation rights at the discretion of the grantees. The Company records compensation expense each quarter related to the PSP&L and WECO shares as the difference between the exercise price and the current market price. Compensation expense related to the WECO plan was near $0immaterial in 2003 and 2002, and $(0.2) million in 2001 and $0.2 million in 2000.2001. Compensation expense related to the PSP&L plan was near $0immaterial in 2003 and 2002, and $(0.1) million in 2001, and $0.2 million in 2000.
2001.

        The Company used the Black-Scholes option pricing model to determine the fair value of certain stock basedstock-based awards to employees. The following assumptions were used for awards granted in 2003, 2002 2001 and 2000:2001:

200320022001
  
2002
 
2001
 
2000

Stock Options 
Stock options 
Risk-free interest rate  4.32% --  --      --4.32%    --
Expected lives - years  4.50 --  --      --4.50    --
Expected stock volatility  23.62% --  --      --23.62%    --
Dividend yield  5.00% --  --      --5.00%    --

InfrastruX Stock Option Plan 
InfrastruX stock option plan 
Risk-free interest rate  4.05% 4.87% --  2.80%4.05%4.87%
Expected lives - years  4.00 4.00 --  4.004.004.00
Expected stock volatility  60.00% 50.00% --  60.00%60.00%50.00%

Performance Awards 
Performance awards 
Risk-free interest rate  4.00% 4.99% 6.66% 2.35%4.00%4.99%
Expected lives - years  4.00 4.00 4.00 4.004.004.00
Expected stock volatility  23.71% 20.76% 18.59% 23.85%23.71%20.76%
Dividend yield  8.85% 7.67% 9.14% 4.86%8.85%7.67%

Employee Stock Purchase Plan  
Risk-free interest rate  1.65% 4.26% 5.59% 1.07%1.65%4.26%
Expected lives - years  0.50 0.50 0.50 0.500.500.50
Expected stock volatility  26.97% 19.04% 22.73% 19.47%26.97%19.04%
Dividend yield  5.81% 7.72% 8.98% 4.39%5.81%7.72%



NOTE 15.
        Other InvestmentsAccounting for Derivative Instruments and Hedging Activities

        The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
        For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income statement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
        In March 1998,addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into an agreementor modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with Schlumberger North America (Schlumberger) (formerly known as CellNet Data Services Inc.), under whichno significant impact on the financial statements.
        On January 1, 2001, the Company would lend Schlumberger uprecognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to $35current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
        PSE has had two contracts with a counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.

NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)

        During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of multiple draws so that Schlumberger could finance an Automated Meter Reading (AMR) network systemcash and preferred or common stock. The 2003 acquisition includes a contingency which requires InfrastruX to be deployed inmake additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the Company’s service territory. In September 1999, the Company announced it was expanding its AMR network system from 800,000 meters to 1,325,000 meters andadditional amount as a result increased the authorized loan amount to $72 million.goodwill. As of December 31, 2000,2003, no payments were required.
        These companies provide utility infrastructure services which are relevant to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunications providers; pipeline construction, maintenance and rehabilitation services for the outstanding loan balancenatural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission-oriented overhead electric construction services to electric utilities and cooperatives.
        The acquisitions have been accounted for using the purchase method of accounting and, accordingly, the operating results of these companies have been included in Puget Energy’s consolidated financial statements since their acquisition dates. Goodwill additions representing the excess of cost over the net tangible and identifiable intangible assets at the time of purchase were approximately $7.7 million in 2003 and $23.5 million in 2002.
        During 2001, goodwill was $51.9being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the annual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:


(DOLLARS IN THOUSANDS)2003 2002 2001 

Reported income for common stock$      116,197 $      110,052 $       98,426 
Add back goodwill amortization, net of tax-- -- 2,826 
 
Adjusted income for common stock$      116,197 $      110,052 $      101,252 
 
Basic earnings per share
  Reported income for common stock$             1.23$             1.24$             1.14
  Add back goodwill amortization-- -- 0.03
 
  Adjusted income for common stock$             1.23$             1.24$             1.17
 
Diluted earnings per share
        Reported income for common stock$             1.22$             1.24$             1.14
        Add back goodwill amortization-- -- 0.03
 
        Adjusted income for common stock$             1.22$             1.24$             1.17
 

        Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 years. In August2003 a total of $2.1 million was added to intangible assets — assigned $0.1 million to patents with an amortization period of 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.

 
AT DECEMBER 31, 2003
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  4,178    $2,009    $  2,169    
Developed technology14,190    2,454    11,736    
Contractual customer relationships4,702    747    3,955    
Patents915    68    847    

 Total$23,985    $5,278    $18,707    
 
 
AT DECEMBER 31, 2002
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  3,908    $1,105    $  2,803    
Developed technology14,190    1,744    12,446    
Contractual customer relationships3,042    383    2,659    
Patents793    49    744    

 Total$21,933    $3,281    $18,652    
 

        The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, Schlumberger paid off its outstanding loanrespectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(DOLLARS IN THOUSANDS)20042005200620072008

Future intangible amortization$ 2,101$ 2,075$ 1,746$ 1,363$ 1,340

        The pro forma combined revenues, net income and earnings per common share of Puget Energy presented below give effect to the acquisitions as if they had occurred on January 1, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.

(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOR THE YEARS ENDED DECEMBER 31
200320022001

Operating revenues$     2,505,523$     2,469,122$     3,056,824
Net income for common116,636112,813104,338
Basic earnings per common share$  1.23$  1.28$  1.21
Diluted earnings per common share$  1.22$  1.27$  1.20

NOTE 17.
Other

        PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $64.1$0.3 million by the end of 2004.
        The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
        In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
        PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
        In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.


NOTE 16.18.
        CommitmentsAccounting for Derivative Instruments and ContingenciesHedging Activities

COMMITMENTS – ELECTRIC

        The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception.
        For the twelve monthsyear ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 approximately 22.5%gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the Company’s energy output was obtainedmark-to-market unrealized loss on physical electric contracts at an average costDecember 31, 2001 that were settled in 2002. As of approximately 13.96 mills per kWh through long-term contracts with several of the Washington Public Utility Districts (PUDs) owning hydroelectric projects on the Columbia River.


        The purchase of power from the Columbia River projects is on a “cost-of-service” basis under whichDecember 31, 2003, the Company pays a proportionate sharehad an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the annual cost of each project in direct proportion to thecriteria for designation as cash flow hedges under SFAS No. 133. The amount of power annually purchased bycash flow hedges that will reverse and be settled into the Company from such project. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the lives of the contracts.
income statement during 2004 will be immaterial. As of December 31, 2002, the Company was entitledhad a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to purchase portions ofcontracts which meet the power output ofcriteria for designation as cash flow hedges under SFAS No. 133.
        In addition, the PUDs’ projects as set forthCompany has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the following tabulation:

BONDS
OUTSTANDING
COMPANY'S ANNUAL AMOUNT
PURCHASABLE (APPROXIMATE)

PROJECTCONTRACT1
EXP. DATE
 LICENSE2
EXP. DATE
 12/31/023
(MILLIONS)
% OF
OUTPUT
 MEGAWATT
CAPACITY
 COSTS4
(MILLIONS)

  Rock Island         
     Original units 2012 2029 $         102.450.0 455 $    43.3
     Additional units 2012 2029 333.785.0 
  Rocky Reach 2011 2006 408.938.9 505 26.2
  Wells 2018 2012 165.531.3 261 9.8
  Priest Rapids 2005 2005 150.48.0 72 2.3
  Wanapum 2009 2005 136.210.8 98 4.1

  Total     $        1,297.1  1,391 $    85.7

        The Company’s estimated payments for power purchases fromthird quarter of 2003 with no significant impact on the Columbia River are $92.7financial statements.
        On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for 2003, $82.6 million for 2004, $78.9 million for 2005, $76.5 million for 2006, $79.3 million for 2007 and in the aggregate, $377.9 million thereafter through 2018.
fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
        PSE has numerous long-term firm purchased powerhad two contracts with other utilitiesa counterparty whose debt ratings were below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the novation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has been designated since inception in 2000 as a qualifying cash flow hedge. The second contract, a physical gas supply contract for one of PSE’s electric generating facilities was marked-to-market in the region.fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. PSE has concluded that it is appropriate to reserve the marked-to-market gain on this contract due to the credit quality of the counterparty in accordance with SFAS No. 133 guidance, as delivery is not probable through the term of the contract, which expires in December 2008.

NOTE 16.
Acquisitions and Intangibles (Puget Energy Only)

        During 2002, InfrastruX acquired 100% of three companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases were funded in the form of cash and preferred or common stock. The Company is generally not obligated2003 acquisition includes a contingency which requires InfrastruX to make additional payments underif certain 2003 and 2004 earnings measures are met. If these contracts unless power is delivered.earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
        These companies provide utility infrastructure services which are relevant to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunications providers; pipeline construction, maintenance and rehabilitation services for the natural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission-oriented overhead electric construction services to electric utilities and cooperatives.
        The Company’s estimated paymentsacquisitions have been accounted for firm power purchases from other utilities, excludingusing the Columbia River projects, are $124.0purchase method of accounting and, accordingly, the operating results of these companies have been included in Puget Energy’s consolidated financial statements since their acquisition dates. Goodwill additions representing the excess of cost over the net tangible and identifiable intangible assets at the time of purchase were approximately $7.7 million in 2003 and $23.5 million in 2002.
        During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for 2003, $75.5goodwill on two acquisitions made after June 30, 2001, which were not amortized per SFAS No. 142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million for 2004, $76.3 million for 2005, $77.9 million for 2006, $80.6 million for 2007 and inof intangible assets that no longer met the aggregate, $500.3 million thereafter through 2037. These contracts have varying terms and may include escalation and termination provisions.


1

On December 28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. The new contracts begin in November of 2005 for the Priest Rapids Development and in November of 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts PSE's share of power from developments declines over time as Grant County PUD's load increases. On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County's new contracts unreasonably restrain trade and violate various sections of the Federal Power Act and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, they have ordered Grant County PUD to remove specific Sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing has been requested.

2

The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirm the Company's contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term.

3

The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and refinancings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration date are: 41.7% at Rock Island; 55.1% at Rocky Reach; 89.7% at Priest Rapids; 67.9% at Wanapum; and 5.7% at Wells.

4

The components of 2002 costs associated with the interest portion of debt service are: Rock Island, $21.1 million for all units; Rocky Reach, $8.0 million; Wells, $2.6 million; Priest Rapids, $0.7 million; and Wanapum, $0.8 million.



criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the federal Public Utility Regulatory Policies Act (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The Company purchasesfirst quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. In addition to the net electrical output of four significant projects at fixed and annually escalating prices, which were intended to approximate the Company’s avoided cost of new generation projectedannual review, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:


(DOLLARS IN THOUSANDS)2003 2002 2001 

Reported income for common stock$      116,197 $      110,052 $       98,426 
Add back goodwill amortization, net of tax-- -- 2,826 
 
Adjusted income for common stock$      116,197 $      110,052 $      101,252 
 
Basic earnings per share
  Reported income for common stock$             1.23$             1.24$             1.14
  Add back goodwill amortization-- -- 0.03
 
  Adjusted income for common stock$             1.23$             1.24$             1.17
 
Diluted earnings per share
        Reported income for common stock$             1.22$             1.24$             1.14
        Add back goodwill amortization-- -- 0.03
 
        Adjusted income for common stock$             1.22$             1.24$             1.17
 

        Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from 5 to 20 years. In 2003 a total of $2.1 million was added to intangible assets — assigned $0.1 million to patents with an amortization period of 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years. In 2002, a total of $4.5 million was added to intangible assets — assigned $0.3 million to patents, $3.1 million to contractual customer relationships and $1.1 million to covenant not to compete. The total weighted average amortization period for the 2002 additions is eight years.

 
AT DECEMBER 31, 2003
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  4,178    $2,009    $  2,169    
Developed technology14,190    2,454    11,736    
Contractual customer relationships4,702    747    3,955    
Patents915    68    847    

 Total$23,985    $5,278    $18,707    
 
 
AT DECEMBER 31, 2002
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  3,908    $1,105    $  2,803    
Developed technology14,190    1,744    12,446    
Contractual customer relationships3,042    383    2,659    
Patents793    49    744    

 Total$21,933    $3,281    $18,652    
 

        The identifiable intangible amortization expense for the year ended December 31, 2003 was $2.1 million compared to $1.9 million and $1.1 million for 2002 and 2001, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(DOLLARS IN THOUSANDS)20042005200620072008

Future intangible amortization$ 2,101$ 2,075$ 1,746$ 1,363$ 1,340

        The pro forma combined revenues, net income and earnings per common share of Puget Energy presented below give effect to the acquisitions as if they had occurred on January 1, 2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these agreements were made.companies been consummated for the period for which they are being given effect.

(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOR THE YEARS ENDED DECEMBER 31
200320022001

Operating revenues$     2,505,523$     2,469,122$     3,056,824
Net income for common116,636112,813104,338
Basic earnings per common share$  1.23$  1.28$  1.21
Diluted earnings per common share$  1.22$  1.27$  1.20

NOTE 17.
Other

        PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s estimated payments underinvestment in these contracts are $202.7two venture capital funds totaled $3.6 million forat December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 $215.0 million for 2004, $220.3 million for 2005, $227.6 million for 2006, $210.4 million for 2007 and the other terminates December 31, 2007. The Company’s recorded investment in the aggregate, $946.5fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million thereafter through 2012.at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
        The following table summarizes the Company’s estimated obligations for future power purchases:

(Dollars in millions)   2003  2004  2005  2006  2007  2008 AND
THERE-
AFTER
  TOTAL 








  Columbia River Projects  $92.7$82.6$78.9$76.5$79.3$377.9$787.9
  Other utilities   124.0 75.5 76.3 77.9 80.6 500.3 934.6
  Non-utility generators   202.7 215.0 220.3 227.6 210.4 946.5 2,022.5








      Total  $419.4$373.1$375.5$382.0$370.3$1,824.7$3,745.0








        Total purchased power contracts provided the Company with approximately 12.1 million, 11.9 million and 15.1 million MWh of firm energy at a cost of approximately $466.1 million, $496.3 million, and $506.5 million for the years 2002, 2001 and 2000, respectively.
        As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of Tenaska’s cogeneration facility. This obligation continues for the remaining term of the agreement, provided that no deliveries are required during the month of May. The price paid by Tenaska for this gas is reflective of the daily price of gas at the United States/Canada border near Sumas, Washington.
        The following table indicates the Company’s percentage ownership and the extentcarrying value of the Company’s investment in jointly-owned generating plants in servicethe fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2002:

COMPANY'S SHARE
(Dollars in millions)
ENERGY
SOURCE (FUEL)

COMPANY'S
OWNERSHIP SHARE

PLANT IN SERVICE
AT COST

ACCUMULATED
DEPRECIATION

Colstrip 1 and 2   Coal   50% $     201  $     128 
Colstrip 3 and 4   Coal   25% 458  226 

        Financing for2003, which reflects the impact of recording a participant’s ownership share$6.1 million pre-tax loss on the Company’s original cost basis in the projects is provided for by such participant.fourth quarter of 2003. The Company’s sharefuture funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of related operating and maintenance expenses is includedcertain portfolio assets in corresponding accounts inits calendar year 2003 financial statements. As a result of this action, the Consolidated Statements of Income.
        As part ofCompany adjusted its electric operations and in connection withcarrying basis to the 1999 buy-out$2.1 million fair value of the Cabot gas supply contract, PSE is obligated to deliver to Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The Company entered into a financial arrangement to hedge a portion of future gas supply costs associated with this obligation, 10,000 MMBtu per day, for the remaining term of the agreement. The Company has a maximum financial obligation under this hedge agreement of $8.1 million in 2002, $8.2 million in 2003, $8.5 million in 2004, $8.7 million in 2005, $8.9 million in 2006 and $13.9 million thereafter. Depending on actual market prices, these costs will be partially, or perhaps entirely, offset by floating price payments received under the hedge arrangement. Encogen has two gas supply agreements that comprise 40% of the plant’s requirements with remaining terms of 6.5 years. The obligations under these contracts are $12.8 million in 2002, $13.5 million in 2003, $14.2 million in 2004, $14.9 million in 2005, $15.6 million in 2006 and $25.0 million in the aggregate thereafter.
        PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are classifiedCompany’s capital account as normal purchases and sales in accordance with SFAS No. 133. Commitments under these contracts for 2003 and 2004 total $47.2 million and $1.8 million, respectively.


GAS SUPPLY
        The Company has also entered into various firm supply, transportation and storage service contracts in order to assure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1 year to 21 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Certain of PSE’s firm gas supply agreements also obligate the Company to purchase a minimum annual quantity at market-based contract prices. Generally, if the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. Alternatively, under some of the contracts, the supplier may exercise a right to reduce its subsequent obligation to provide firm gas to the Company. The Company incurred demand charges in 2002 for firm gas supply, firm transportation service and firm storage and peaking service of $27.4 million, $49.0 million and $6.4 million, respectively. WNG Cap I incurred demand charges in 2002 for firm transportation service of $9.4 million.
        The following tables summarize the Company’s obligations for future demand charges through the primary terms of its existing contracts and the minimum annual take requirements under the gas supply agreements. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.

DEMAND CHARGE OBLIGATIONS
(Dollars in millions)  200320042005200620072008 AND THERE-AFTERTOTAL








  Firm gas supply  $20.6$12.5$1.1$1.1$1.2$2.8   $    39.3
  Firm transportation service   54.6 44.7 11.6 11.6 11.6 82.1 216.2
  Firm storage service   7.2 8.6 7.7 7.7 7.7 55.9 94.8








      Total  $82.4$65.8$20.4$20.4$20.5$140.8$    350.3









MINIMUM ANNUAL TAKE OBLIGATIONS
(Therms in thousands)
2003
2004
2005
2006
2007
2008 AND
THERE-
AFTER

TOTAL
Firm gas supply671,675228,8201,013------901,508

        The Company believes that all demand charges will be recoverable in rates charged to its customers. Further, pursuant to implementation of FERC Order No. 636, the Company has the right to resell or release to others any of its unutilized gas supply or transportation and storage capacity.
        The Company does not anticipate any difficulty in achieving the minimum annual take obligations shown, as such volumes represent approximately 64% of expected annual sales for 2003 and less than 11% of expected sales in subsequent years.
        The Company’s current firm gas supply contracts obligate the suppliers to provide, in the aggregate, annual volumes up to those shown below:


MAXIMUM SUPPLY AVAILABLE UNDER CURRENT FIRM SUPPLY CONTRACTS
(Therms in thousands)
2003
2004
2005
2006
2007
2008 AND
THERE-
AFTER

TOTAL
Firm gas supply719,821264,0357,0136,0006,00024,0001,026,869

SERVICE CONTRACT
        On August 30, 2001, PSE and Alliance Data Systems Corp. announced a contract under which Alliance Data will provide data processing and billing services for PSE. In providing services to PSE under the 10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by its ConneXt subsidiary. Alliance Data acquired the assets of ConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as part of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $19.4 million in 2003, $20.0 million in 2004, $22.5 million in 2005, $23.2 million in 2006, $23.9 million in 2007 and $86.7 million in the aggregate thereafter.


SURETY BOND
        The Company has a self-insurance surety bond in the amount of $5.2 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.

ENVIRONMENTAL
        The Company is subject to environmental regulation by federal, state and local authorities. The Company has been namedprovided by the Environmental Protection Agency (EPA) and/or the Washington State Department of Ecology as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks as required by federal and state laws and this process is nearing completion. Remediation and testing of Company vehicle service facilities and storage yards is also continuing.
        During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from either insurance companies, third parties or under the Washington Commission’s order.
        The information presented here as it relates to estimates of future liability isfund manager as of December 31, 2002.
2003.
        ELECTRIC SITESIn the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
        The Company has expended approximately $17.7 million related toPSE believes that the remediation activities coveredfuel cost disallowances proposed by the Washington Commission’s orderCommission staff are legally and has accrued approximately $1.7factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
        In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, as a liability for future remediationwhich included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs for these and other remediation activities. To date, the Company has recovered approximately $17.2$5.3 million from insurance carriers.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

        GAS SITES
        The Company has expended approximately $62.5 millionof costs related to the remediation activities covered byconstruction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a Washington Commission’s order and has accrued approximately $33.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $58.7 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.regulatory asset.


NOTE 18.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

LITIGATION
        Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2002. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

NOTE 17.
Accounting for Derivative Instruments and Hedging Activities

        On January 1, 2001, the

        The Company has adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”,Activities,” as amended by SFAS No. 138.138 and SFAS No. 149. SFAS No. 133 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 including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase and normal sale exception provided byexception.
        For the year ended December 31, 2003, the Company recorded a decrease in earnings of approximately $0.1 million compared to an increase of $11.6 million for 2002. Of the 2002 gain, $10.5 million represented the reversal of unrealized losses on gas hedge contracts that were de-designated in the fourth quarter of 2001 and the reversal of the mark-to-market unrealized loss on physical electric contracts at December 31, 2001 that were settled in 2002. As of December 31, 2003, the Company had an unrealized gain recorded in other comprehensive income of $0.2 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.


The amount of cash flow hedges that will reverse and be settled into the income statement during 2004 will be immaterial. As of December 31, 2002, the Company had a long-term unrealized gain recorded in other comprehensive income of $9.9 million after-tax and a short-term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133.
        In addition, the Company has adopted SFAS No. 149, which is effective for all contracts entered into or modified after June 30, 2003 except for certain hedging relationships designated after June 30, 2003. SFAS No. 149 clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in contracts and for hedging activities under SFAS No. 133. The Company implemented SFAS No. 149 in the third quarter of 2003 with no significant impact on the financial statements.
        On January 1, 2001, the Company recognized the cumulative effect of adopting SFAS No. 133 by recording a liability and an offsetting after-tax decrease to current earnings of approximately $14.7 million for the fair value of electric derivatives that did not meet hedge criteria. The Company also recorded an asset and an offsetting increase to other comprehensive income of approximately $286.9 million for the fair value of derivative instruments that did meet hedge criteria on the implementation date.
        During the year ended December 31, 2001, the Company recorded an increase to current earnings of approximately $11.2 million pre-tax ($7.2 million after-tax) to record the change in market value of outstanding derivative instruments not meeting cash flow hedge criteria. During the year ended December 31, 2002, the remainder of the contracts whichPSE has had given rise to the income statement losses were settled and resulted in an additional increase to earnings of $11.6 million pre-tax ($7.5 million after-tax). As of December 31, 2002, the Company had a long-term unrealized gain recorded in Other Comprehensive Income of $9.9 million after-tax and a short term unrealized loss of $2.4 million after-tax related to contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges that will reverse and be settled into the income statement during 2003 will be $4.1 million. In addition, on December 31, 2002 the Company had a short term unrealized gain on derivative contracts for the purchase of natural gas for core gas business of $3.7 million pre-tax.
        The Company has two contracts outstanding with a counterparty whose senior unsecured debt ratings were downgraded in September 2002 to Ba2 by Moody’s and in November 2002 to BB by Standard & Poor’s.below investment grade since 2002. The first contract is a fixed for floating price natural gas swap contract for one of its electric generating facilities. In the fourth quarter of 2003, PSE agreed to a novation of this contract to a new counterparty which has strong credit ratings. As a result of the Companynovation, the collateral that was held by the original counterparty was returned. The fixed for floating price natural gas swap contract has collected a collateral depositbeen designated since inception in the amount of $21.4 million from the counterparty to guarantee performance. The contract will expire in June 2008 and is accounted for2000 as a qualifying cash flow hedge under SFAS No. 133.hedge. The second iscontract, a physical gas supply contract expiringfor one of PSE’s electric generating facilities was marked-to-market in July 2008 which has beenthe fourth quarter of 2003. This contract was previously designated as a normal purchase under SFAS No. 133. In February 2003,PSE has concluded that it is appropriate to reserve the counterparty’smarked-to-market gain on this contract due to the credit was further downgraded althoughquality of the counterparty continues to perform as required under the terms of the two contracts. The Company believes the risk of non-performance by the counterparty is remote.
        At October 15, 2001, the Company had recorded a deferred liability of approximately $26.9 million after-tax for financial gas contracts to be used for electric production that until October 15, 2001 were designated as qualifying cash flow hedges. Changes in the market values of these de-designated contracts resulted in the recording of a loss of $7.8 million pre-tax ($5.1 million after-tax) to earnings in the fourth quarter of 2001. In the first quarter of 2002, the loss was reversed in its entirety when all of these contracts were settled or terminated.
        During 2001, the Financial Accounting Standards Board’s Derivative Implementation Group foraccordance with SFAS No. 133 issued guidance, under Issue C16 – “Applyingas delivery is not probable through the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and Purchased Option Contract” which became effective in the second quarter of 2002 for the Company. Issue C16 establishes that fuel supply contracts that combine a forward contract with a purchased option cannot qualify for the normal purchase and normal sales exception becauseterm of the optionality of the quantity of fuel to be delivered under the contract.
        A review of the fuel supply contracts by the Company determined that two long-term fuel supply contracts that deliver natural gas to the Company’s Encogen combustion turbine plant contained provisions for the purchase of optional quantities of fuel, and as originally written, would no longer qualify as normal purchase contracts upon implementation of Issue C16. In the second quarter of 2002, the Company signed amendments to those contracts that remove the optional provisions, requiring that the Company purchase 100% of the contractual fuel quantities for the remaining terms of the contracts. As a result, the contracts continue to qualify for the normal purchase-normal sale exception to SFAS 133.

contract, which expires in December 2008.

NOTE 18.
Supplemental Quarterly Financial Data (Unaudited)

        The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business.


PUGET ENERGY
     (Unaudited; dollars in thousands except per-share amounts)





  2002 QUARTER   FIRST  SECOND  THIRD  FOURTH 





Operating revenues  $739,060 $540,819 $458,476 $653,967 
Operating income   76,571  76,833  57,098  99,168 
Other income   384  3,441  230  1,403 
Net income   26,478  31,369  8,512  51,525 
Basic and diluted earnings per common share  $0.28 $0.34 $0.07 $0.55 
 
     (Unaudited; dollars in thousands except per-share amounts)  





  2001 QUARTER   FIRST  SECOND  THIRD  FOURTH 





Operating revenues  $1,024,234 $710,295 $478,966 $673,064 
Operating income   130,541  66,071  45,756  54,754 
Other income   1,941  1,568  7,892  3,123 
Net income   72,298  19,465  6,809  8,266 
Basic earnings per common share  $0.815 $0.201 $0.055 $0.071 
Diluted earnings per common share  $0.812 $0.201 $0.054 $0.071 
 
PUGET SOUND ENERGY
     (Unaudited; dollars in thousands except per-share amounts)
  





  2002 QUARTER   FIRST  SECOND  THIRD  FOURTH 





Operating revenues  $678,299 $464,697 $366,103 $563,694 
Operating income   74,732  72,724  51,367  95,769 
Other income   309  3,455  210  1,241 
Net income   25,698  28,839  4,701  49,709 
 
     (Unaudited; dollars in thousands)  





  2001 QUARTER   FIRST  SECOND  THIRD  FOURTH 





Operating revenues  $995,694 $664,827 $426,195 $628,058 
Operating income   130,111  61,629  42,360  54,383 
Other income   2,843  2,485  8,885  2,839 
Net income   72,879  17,275  5,474  8,754 

        Operating revenues for the Company include optimization transactions reported net in the income statement as required by EITF 02-03 effective after June 30, 2002. The operating revenues for all quarters of 2001 and the first and second quarters of 2002 have been reclassified to conform with the current presentation.

NOTE 19.16.
        Acquisitions and Intangibles (Puget Energy Only)

        During 2001, InfrastruX acquired 100% of six companies based in the eastern United States, mid-west and Texas for a total price of $83.6 million.        During 2002, InfrastruX acquired 100% of three additional companies based in Texas for a total price of $49.7 million, and during the second quarter of 2003 acquired 100% of one additional company based in New Mexico for $11.8 million. All purchases have beenwere funded in the form of cash and preferred andor common stock. The 2003 acquisition includes a contingency which requires InfrastruX to make additional payments if certain 2003 and 2004 earnings measures are met. If these earnings measures are met, InfrastruX would record the additional amount as goodwill. As of December 31, 2003, no payments were required.
        These companies provide utility infrastructure services such as:which are relevant to InfrastruX’s operating strategy including: installing, replacing and restoring underground cables and pipes for utilities and telecommunicationtelecommunications providers; pipeline construction, maintenance and rehabilitation services for the natural gas and petroleum industries, including directional drilling and vacuum excavation; and distribution and transmission orientedtransmission-oriented overhead electric construction services to electric utilities and cooperatives.



        The acquisitions have been accounted for using the purchase method of accounting and, accordingly, the operating results of these companies have been included in Puget Energy’s consolidated financial statements since their acquisition dates. Goodwill additions representing the excess of cost over the net tangible and identifiable intangible assets of the business at the time of purchase waswere approximately $130.0$7.7 million before amortization. During 2002, InfrastruX addedin 2003 and $23.5 million of goodwill for a balance of $125.6 million net of accumulated amortization.in 2002.
        During 2001, goodwill was being amortized on a straight-line basis using a 30-year life except for goodwill on two acquisitions made after June 30, 2001, which waswere not amortized per SFAS No. 142 – “Goodwill and Other Intangible Assets”.142. With the implementation of SFAS No. 142 on January 1, 2002, Puget Energy discontinued amortizing goodwill and reclassified $5.2 million of intangible assets that no longer met the criteria of identifiable intangible assets to goodwill. As required by SFAS No. 142, Puget Energy performed an initial impairment review of goodwill in the first quarter of 2002 and annual fourth-quarter impairment reviews thereafter and determined that no impairment had taken place. Puget Energy then performedIn addition to the annual impairment review, as of October 31, 2002 and determined that goodwill was not impaired. Puget Energy will perform an annual impairment review hereafter. In addition, Puget Energy will perform an impairment review at the time an event or circumstance arises that would indicate the fair value would be below its carrying value. Goodwill amortization for 2001, and 2000, including amortization on the intangible assets that were reclassified to goodwill in 2002, was approximately $3.4 million and $1.0 million, respectively.million. The income statement effects of discontinuing amortization of goodwill for the comparative periods are as follows for Puget Energy:

(Dollars in thousands)2002 2001 2000 




Reported income for common stock$      110,052 $       98,426 $      184,837 
Add back goodwill amortization, net of tax-- 2,826 907 



Adjusted income for common stock$      110,052 $      101,252 $      185,744 



Basic and diluted earnings per share
   Reported income for common stock$             1.24$             1.14$             2.16
   Add back goodwill amortization-- 0.030.01



   Adjusted income for common stock$             1.24$             1.17$             2.17




(DOLLARS IN THOUSANDS)2003 2002 2001 

Reported income for common stock$      116,197 $      110,052 $       98,426 
Add back goodwill amortization, net of tax-- -- 2,826 
 
Adjusted income for common stock$      116,197 $      110,052 $      101,252 
 
Basic earnings per share
  Reported income for common stock$             1.23$             1.24$             1.14
  Add back goodwill amortization-- -- 0.03
 
  Adjusted income for common stock$             1.23$             1.24$             1.17
 
Diluted earnings per share
        Reported income for common stock$             1.22$             1.24$             1.14
        Add back goodwill amortization-- -- 0.03
 
        Adjusted income for common stock$             1.22$             1.24$             1.17
 

        Identifiable intangible assets acquired as a result of acquisitions of companies are amortized over the expected useful lives of the assets, which range from five5 to 20 years. In 2003 a total of $2.1 million was added to intangible assets — assigned $0.1 million to patents with an amortization period of 17.0 years, $1.7 million to contractual customer relationships with an amortization period of 10.0 years and $0.3 million to covenant not to compete with an amortization period of five years. The total weighted average amortization period for the 2003 additions is 9.6 years. In 2002, a total of $4.5 million was added to intangible assets assigned $0.3 million to patents, with an amortization period of 16.0 years, $3.1 million to contractual customer relationships with an amortization period of 8.3 years and $1.1 million to covenant not to compete with an amortization period of 5.0 years.compete. The total weighted average amortization period for the 2002 additions is 8.0eight years. In 2001, $2.8 million was added to intangible assets, assigned entirely to covenant not to compete with an amortization period of 5.0 years. Total identifiable intangible assets are as follows:




At December 31, 2001
(Dollars in thousands)
Gross
Intangibles
Accumulated
Amortization
Net
Intangibles




Covenant not to compete$  3,908 $1,105 $  2,803 
Developed technology14,190 1,744 12,446 
Contractual customer relationships3,042 383 2,659 
Patents793 49 744 




 Total$21,933 $3,281 $18,652 







At December 31, 2002
(Dollars in thousands)
Gross
Intangibles
Accumulated
Amortization
Net
Intangibles




Covenant not to compete$  2,768 $364 $  2,404 
Developed technology14,190 1,006 13,184 
Patents1,046 575 471 




 Total$18,004 $1,945 $16,059 



 
AT DECEMBER 31, 2003
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  4,178    $2,009    $  2,169    
Developed technology14,190    2,454    11,736    
Contractual customer relationships4,702    747    3,955    
Patents915    68    847    

 Total$23,985    $5,278    $18,707    
 
 
AT DECEMBER 31, 2002
(DOLLARS IN THOUSANDS)
Gross
Intangibles
Accumulated
Amoritization
Net
Intangibles

Covenant not to compete$  3,908    $1,105    $  2,803    
Developed technology14,190    1,744    12,446    
Contractual customer relationships3,042    383    2,659    
Patents793    49    744    

 Total$21,933    $3,281    $18,652    
 

        The identifiable intangible amortization expense for the year ended December 31, 20022003 was $1.9$2.1 million compared to $1.9 million and $1.1 million for 2002 and $0.3 million for 2001, and 2000, respectively. The identifiable intangible assets amortization for future periods based on the current acquisitions will be:

(Dollars in thousands)20032004200520062007
(DOLLARS IN THOUSANDS)20042005200620072008



Future intangible amortization$1,879 $1,863 $1,534 $1,151 $ 2,101$ 2,075$ 1,746$ 1,363$ 1,340

        As InfrastruX acquires more companies the total amortization amount in future periods may change.
        The pro forma combined revenues, net income and earnings per common share of Puget Energy presented below give effect to the acquisitions as if they had occurred on January 1, 2000.2001. These results are not necessarily indicative of the results of operations that would have occurred had the acquisitions of these companies been consummated for the period for which they are being given effect.

(Dollars in thousands, except per share amounts)
(Unaudited)
For the twelve months ended December 31,
2002 2001 2000 
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
FOR THE YEARS ENDED DECEMBER 31
200320022001



Operating revenues$     2,413,122 $     3,000,824 $     3,577,354 $     2,505,523$     2,469,122$     3,056,824
Net income for common111,058 102,649 198,637 116,636112,813104,338
Basic earnings per common share$  1.26$  1.19$  2.33$  1.23$  1.28$  1.21
Diluted earnings per common share$  1.25$  1.18$  2.32$  1.22$  1.27$  1.20

NOTE 17.
Other

        PSE has minority ownership interests in two venture capital funds established as limited liability corporations that seek long-term capital appreciation by making capital investments in energy sector related businesses. The Company’s investment in these two venture capital funds totaled $3.6 million at December 31, 2003. The Company’s ownership interest in both funds is less than 20% and the managing members of the limited liability corporations have sole discretion over fund operations, management and investment decisions. Under the terms of the limited liability corporation agreements establishing the funds, one fund terminated December 31, 2003 and the other terminates December 31, 2007. The Company’s recorded investment in the fund that terminated on December 31, 2003, and is in the process of distributing assets to investing members, was $1.5 million at December 31, 2003. Subsequent to December 31, 2003, the Company has realized a total of $1.2 million in cash proceeds and anticipates realizing the remaining balance of $0.3 million by the end of 2004.
        The carrying value of the Company’s investment in the fund that will terminate on December 31, 2007 was $2.1 million at December 31, 2003, which reflects the impact of recording a $6.1 million pre-tax loss on the Company’s original cost basis in the fourth quarter of 2003. The Company’s future funding obligation to this fund is $0.4 million. The fund manager advised investors that it intended to record unrealized losses of certain portfolio assets in its calendar year 2003 financial statements. As a result of this action, the Company adjusted its carrying basis to the $2.1 million fair value of the Company’s capital account as provided by the fund manager as of December 31, 2003.
        In the power cost only rate case, Washington Commission staff and other parties, including the group Industrial Customers of the Northwest Utilities (ICNU), filed testimony seeking downward adjustments to PSE’s proposed electric rate increase of $64.4 million. Among other things, they propose that a significant amount of PSE’s future fuel costs associated with an electric generating facility be disallowed for recovery in electric rates based upon their interpretation of a 1994 Commission Order and a contention that PSE should have secured fixed-price fuel supply options that were available in late 1997. After factoring in such proposed fuel supply disallowances and certain lower estimates of future power costs which would be trued-up to incurred actuals through PSE’s PCA mechanism, the Washington Commission staff recommends a net rate increase of $7.5 million as compared to PSE’s requested $64.4 million. If, after hearings on the matter, the Commission were to adopt the Washington Commission staff’s or ICNU’s recommendations, the proposed fuel cost disallowances would adversely affect PSE’s future financial performance.
        PSE believes that the fuel cost disallowances proposed by the Washington Commission staff are legally and factually deficient, and PSE filed its rebuttal case on February 13, 2004. The Washington Commission staff is independent from the Washington Commission in such a litigated proceeding and its positions do not represent an indication of the final outcome of the proceeding. The hearing was held in late February and the resolution of the power only rate case is expected by mid-April 2004.
        In December 2003, PSE notified FERC that it rejected the 1997 license for the White River Project. As a result, generation of electricity ceased at the White River Project on January 15, 2004. The 1997 license would have made the Whiter River generation project uneconomical to produce electricity. In the same proceeding described above, the Washington Commission will be ruling on an Accounting Order that will allow for rate recovery of the unrecovered investment in the White River generating project. The Washington Commission staff’s testimony in PSE’s power cost only rate case supports PSE’s petition for recovery of the investment in the White River Project. At December 31, 2003, the White River Project net book value totaled $68.4 million, which included $47.9 million of net utility plant, $15.2 million of capitalized FERC licensing costs and $5.3 million of costs related to construction work in progress. The FERC licensing costs and construction work in progress charges were deferred to a regulatory asset.


NOTE 18.
Commitments and Contingencies

COMMITMENTS – ELECTRIC
        For the year ended December 31, 2003, approximately 19.9% of the Company’s energy output was obtained at an average cost of approximately $0.01641 per kWh through long-term contracts with several of the Washington Public Utility Districts (PUDs) owning hydroelectric projects on the Columbia River.
        The purchase of power from the Columbia River projects is on a “cost-of-service” basis under which the Company pays a proportionate share of the annual cost of each project in direct proportion to the amount of power annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the lives of the contracts.
        As of December 31, 2003, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:

 BONDS
OUTSTANDING
COMPANY'S ANNUAL AMOUNT
PURCHASABLE (APPROXIMATE)

PROJECTCONTRACT
EXP. DATE
LICENSE1
EXP. DATE
12/31/032
(MILLIONS)
% OF
OUTPUT
MEGAWATT
CAPACITY
COSTS3
(MILLIONS)

  Rock Island         
     Original units 2012 2029 $         121.750.0 414 $    41.9
     Additional units 2012 2029 331.575.0 
  Rocky Reach 2011 2006 394.738.9 505 29.6
  Wells 2018 2012 151.331.3 261 6.9
  Priest Rapids4 2005 2005 184.78.0 72 2.6
  Wanapum4 2009 2005 186.510.8 98 4.1

  Total     $        1,370.4  1,350 $    85.1

        The Company’s estimated payments for power purchases from the Columbia River are $84.6 million for 2004, $81.4 million for 2005, $78.4 million for 2006, $81.4 million for 2007, $82.6 million for 2008 and in the aggregate, $123.5 million thereafter through 2018.
        The Company also has numerous long-term firm purchased power contracts with other utilities in the region. The Company is generally not obligated to make payments under these contracts unless power is delivered. The Company’s estimated payments for firm power purchases from other utilities, excluding the Columbia River projects, are $76.0 million for 2004, $77.7 million for 2005, $78.6 million for 2006, $80.7 million for 2007, $82.6 million for 2008 and in the aggregate, $433.3 million thereafter through 2037. These contracts have varying terms and may include escalation and termination provisions.
        As required by the federal Public Utility Regulatory Policies Act (PURPA), PSE entered into long-term firm purchased power contracts with non-utility generators. The Company purchases the net electrical output of four significant projects at fixed and annually escalating prices, which were intended to approximate the Company’s avoided cost of new generation projected at the time these agreements were made. The Company’s estimated payments under these contracts are $211.4 million for 2004, $217.3 million for 2005, $232.9 million for 2006, $211.9 million for 2007, $212.1 million for 2008 and in the aggregate, $746.0 million thereafter through 2012.
        The following table summarizes the Company’s estimated obligations for future power purchases:


(DOLLARS IN MILLIONS)200420052006200720082009 &
THERE-
AFTER
TOTAL

  Columbia River projects$    84.6$     81.4$     78.4$     81.4$     82.6$       123.5$     531.9
  Other utilities76.077.778.680.782.6433.3828.9
  Non-utility generators211.4217.3232.9211.9212.1746.01,831.6

      Total$   372.0$   376.4$   389.9$   374.0$   377.3$    1,302.8  $   3,192.4


1The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirm the Company's contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term.
2The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and refinancings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration date are: 43.7% at Rock Island; 58.3% at Rocky Reach; 94.5% at Priest Rapids; 79.6% at Wanapum; and 6.2% at Wells.
3The components of 2003 costs associated with the interest portion of debt service are: Rock Island, $22.6 million for all units; Rocky Reach, $9.4 million; Wells, $8.2 million; Priest Rapids, $0.8 million; and Wanapum, $0.6 million.
4On December 28, 2001, PSE signed a contract offer for new contracts for the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. Grant County PUD filed an "Application for New License for the Priest Rapids Project" on October 29, 2003. The new contract terms begin in November of 2005 for the Priest Rapids Development and in November of 2009 for the Wanapum Development. Unlike the current contracts, in the new contracts PSE's share of power from the developments declines over time as Grant County PUD's load increases. On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County PUD's new contracts unreasonably restrain trade and violate various sections of the Federal Power Act and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, it has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing has been requested.

        Total purchased power contracts provided the Company with approximately 11.0 million, 12.1 million and 11.9 million MWh of firm energy at a cost of approximately $479.2 million, $466.1 million and $496.3 million for the years 2003, 2002 and 2001, respectively.
        The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2003:

COMPANY'S SHARE
(DOLLARS IN MILLIONS)ENERGY
SOURCE (FUEL)
COMPANY'S
OWNERSHIP
SHARE
PLANT IN SERVICE
AT COST
ACCUMULATED
DEPRECIATION

Colstrip 1 & 2   Coal   50% $     207  $     133 
Colstrip 3 & 4   Coal   25% 464  240 

        Financing for a participant’s ownership share in the projects is provided for by such participant. The Company’s share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of Income.
        PSE and PPL Montana, the other owner of Colstrip Units 1 & 2, are engaged in a dispute with Western Energy Company, a subsidiary of Westmoreland Coal Company, the supplier of coal to the Colstrip power plants. The dispute is in the binding arbitration process and concerns the price that PSE and PPL Montana will pay for coal under the contract for Colstrip Units 1 & 2 through the end of the contract in 2009. This arbitration is contemplated as a price adjustment mechanism in that contract. The present arbitration schedule would resolve the dispute in the second quarter of 2004. Any price adjustment could be retroactive to July 30, 2001 and would apply through the rest of the term. Fuel supply costs for electric generation after July 1, 2002 are part of PSE’s PCA mechanism.
        On October 13, 2003, PSE received a letter from Western Energy Company that enclosed an Audit Issue Letter dated July 25, 2003 from the Montana Department of Revenue, pertaining to some allegedly underpaid royalties on coal purchased by PSE from Western Energy Company between February 1997 and June 2000. PSE used the coal as fuel for its share of Units 3 & 4 of the Colstrip generating plant. PSE’s coal price for that period was reduced by a settlement PSE and Western Energy Company had entered into in 1997. Western Energy Company takes the position that PSE must reimburse Western Energy Company for any additional charges that result from the Audit Issue Letter. The Audit Issue Letter seeks payment of over $1.1 million for royalties for the federal government. If that position is correct, it could raise issues of other royalties and taxes that might apply. PSE will investigate and defend this claim vigorously. PSE cannot predict the outcome of this issue.
        As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of Tenaska’s cogeneration facility. This obligation continues for the remaining term of the agreement, provided that no deliveries are required during the month of May. The price paid by Tenaska for this gas is reflective of the daily price of gas at the United States/Canada border near Sumas, Washington. PSE has entered into a financial arrangement to hedge a portion, 5,000 MMBtu to 10,000 MMBtu per day, of future gas supply costs associated with this obligation. The Company has a maximum financial obligation under this hedge agreement of $22.0 million in 2004.
        As part of its electric operations and in connection with the 1999 buyout of the Cabot gas supply contract, PSE is obligated to deliver to Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The Company entered into a financial arrangement to hedge a portion of future gas supply


costs associated with this obligation, 10,000 MMBtu per day, for the remaining term of the agreement. The Company has a maximum financial obligation under this hedge agreement of $8.5 million in 2004, $8.7 million in 2005, $9.0 million in 2006, $9.2 million in 2007 and $9.6 million thereafter. Depending on actual market prices, these costs will be partially, or perhaps entirely, offset by floating price payments received under the hedge arrangement. Encogen has two gas supply agreements that comprise 40% of the plant’s requirements with remaining terms of 6.5 years. The obligations under these contracts are $15.9 million in 2004, $16.7 million in 2005, $17.5 million in 2006, $18.4 million in 2007 and $12.9 million in the aggregate thereafter.
        PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are generally classified as normal purchases and normal sales or in some cases recorded at fair value in accordance with SFAS No. 133. Commitments under these contracts are $3.0million in 2004, $10.3 million in 2005, $1.1 million in 2006, $0.4 million in 2007 and $0.1 million thereafter.

GAS SUPPLY
        The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1 year to 20 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Two of PSE’s long-term firm gas supply agreements, that expire November 2004, obligate the Company to purchase a minimum annual quantity at market-based contract prices. If the minimum volumes are not purchased and taken during the year, the Company is obligated to either: 1) pay a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. PSE didn’t incur such charges in 2003. The Company incurred demand charges in 2003 for firm gas supply, firm transportation service and firm storage and peaking service of $24.7 million, $47.9 million and $5.3 million, respectively. WNG Cap I incurred demand charges in 2003 for firm transportation service of $9.4 million.
        The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.

DEMAND CHARGE OBLIGATIONS
(DOLLARS IN MILLIONS)
200420052006200720082009 &
THERE-
AFTER
TOTAL

  Firm gas supply$    18.7$     1.5$     1.0$     0.5$     0.5$       1.5$      23.7
  Firm transportation service66.658.857.057.048.0122.7410.1
  Firm storage service11.311.67.87.77.748.294.3

      Total$    96.6$    71.9$    65.8$    65.2$    56.2$    172.4$    528.1

SERVICE CONTRACT
        On August 30, 2001, PSE and Alliance Data Systems Corp. announced a contract under which Alliance Data will provide data processing and billing services for PSE. In providing services to PSE under the 10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by its ConneXt subsidiary. Alliance Data acquired the assets of ConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as part of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $21.7 million in 2004, $22.2 million in 2005, $22.8 million in 2006, $23.4 million in 2007, $24.0 million in 2008 and $66.9 million in the aggregate thereafter.

SURETY BOND
        The Company has a self-insurance surety bond in the amount of $5.9 million guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.4 million.

ENVIRONMENTAL
        The Company is subject to environmental laws and regulations by federal, state and local authorities and has been required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has also been named by the Environmental Protection Agency, the Washington State Department of Ecology, and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring these sites. Remediation and testing of Company vehicle service facilities and storage yards is also continuing.
        During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or under the Washington Commission’s order.
        The information presented here as it relates to estimates of future liability is as of December 31, 2003.


ELECTRIC SITES
        The Company has expended approximately $18.1 million related to the remediation activities covered by the Washington Commission’s order and has accrued approximately $1.6 million as a liability for future remediation costs for these and other remediation activities. To date, the Company has recovered approximately $18.8 million from insurance carriers.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

GAS SITES
        The Company has expended approximately $65.9 million related to the remediation activities covered by a Washington Commission order and has accrued approximately $32.3 million for future remediation costs for these and other remediation sites. To date, the Company has recovered approximately $59.6 million from insurance carriers and other third parties. The Company expects to recover legal and remediation activities from either insurance companies or customers per Washington Commission orders.
        Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company’s financial position, operating results or cash flow trends.

LITIGATION
        There are several actions in the U.S. Ninth Circuit Court of Appeals against Bonneville Power Administration (BPA), in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing, a number of contracts, including the amended settlement agreement regarding the Residential Purchase and Sale Program and the conditional settlement agreements between BPA and PSE which modified the payment provisions of the Residential Purchase and Sale Program. BPA rates used in such amended settlement agreement between BPA and PSE for determining the amounts of money to be paid to PSE as residential exchange benefits during the period October 1, 2001 through September 30, 2006 have been confirmed, approved and allowed to go into effect by FERC. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. It is not clear what impact, if any, review of such rates may have on PSE.
        Other contingencies, arising out of the normal course of the Company’s business, exist at December 31, 2003. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.

NOTE 20.19.
        Segment Information

        Puget Energy operates in primarily two business segments: the Regulated Utility Operations,regulated utility operations, or PSE, and Utility Support,construction services, or InfrastruX, which was incorporated in the year 2000.InfrastruX. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in Washington State.the State of Washington. InfrastruX specializes in contractingconstruction services to other gas and electric utilities primarily in the mid-west, south/Texas and the north-central and eastern United States.
        The other principalOne minor non-utility line of business which issegment, a PSE subsidiary, which is a real estate investment and development company. Reconciling items between segments are not material.
company is described as other. The assets of ConneXt, the development and marketing of customer information and billing system software segment, were sold during the third quarter of 2001. The third quarter results of 2001 includeincluded an $8.0 million after-tax gain related to the ConneXt sale. Reconciling items between segments are not significant.


        Financial data for business segments are as follows:

(Dollars in thousands)
REGULATED PUGET ENERGY
2002UTILITY INFRASTRUXOTHER TOTAL 
(DOLLARS IN THOUSANDS)
REGULATED PUGET ENERGY
2003UTILITY INFRASTRUXOTHER TOTAL 



Revenues$2,063,040 $319,529 $9,753 $2,392,322 $2,143,693 $341,787 $  6,043 $2,491,523 
Depreciation and amortization215,097 13,426 220 228,743 219,851 16,779 236 236,866 
Income tax50,600 6,703 1,957 59,260 69,823 1,594 952 72,369 
Operating income289,511 15,595 4,563 309,669 295,219 7,452 2,504 305,175 
Interest charges, net of AFUDC190,860 5,517 -- 196,377 179,437 5,485 123 185,045 
Net income104,044 9,455 4,384 117,883 119,144 1,766 438 121,348 
Goodwill, net-- 125,555 -- 125,555 -- 133,302 -- 133,302 
Total assets5,208,487 319,248 129,756 5,657,491 5,257,157 342,332 75,196 5,674,685 
Construction expenditures - excluding equity AFUDC224,165 -- 224,165 269,973 -- 269,973 
Additions to other property, plant and equipment-- 11,621 -- 11,621 -- 15,536 -- 15,536 




(Dollars in thousands)
REGULATED PUGET ENERGY
2001UTILITY INFRASTRUXOTHER TOTAL 
(DOLLARS IN THOUSANDS)
REGULATED PUGET ENERGY
2002UTILITY INFRASTRUXOTHER TOTAL 



Revenues$2,680,298 $173,786 $32,476 $2,886,560 $2,063,040 $319,529 $    9,753 $2,392,322 
Depreciation and amortization208,705 8,820 15 217,540 215,097 13,426 220 228,743 
Income tax68,005 2,956 8,877 79,838 50,600 6,703 1,957 59,260 
Operating income273,751 8,702 14,668 297,121 289,511 15,595 4,563 309,669 
Interest charges, net of AFUDC186,403 3,656 -- 190,059 190,861 5,516 -- 196,377 
Net income80,137 2,518 24,184 106,839 104,044 9,455 4,384 117,883 
Goodwill, net-- 102,151 -- 102,151 -- 125,555 -- 125,555 
Total assets5,178,601 229,125 139,251 5,546,977 5,323,129 319,248 129,756 5,772,133 
Construction expenditures - excluding equity AFUDC247,435 -- 247,435 224,165 -- 224,165 
Additions to other property, plant and equipment-- 5,193 -- 5,193 -- 11,621 -- 11,621 




(Dollars in thousands)
REGULATED  PUGET ENERGY
2000UTILITY INFRASTRUXOTHER TOTAL 





  Revenues$3,244,630 $44,999 $12,667 $3,302,296 
  Depreciation and amortization194,228 2,268 17 196,513 
  Income tax131,262 415 (1,854) 129,823 
  Operating income363,559 865 (552) 363,872 
  Interest charges, net of AFUDC174,914 188 -- 175,102 
  Net income204,720 (543) (10,346) 193,831 
  Goodwill, net-- 57,887 -- 57,887 
  Total assets5,339,669 106,520 110,480 5,556,669 
  Construction expenditures - excluding equity AFUDC296,480 -- -- 296,480 





  (DOLLARS IN THOUSANDS)
REGULATED  PUGET ENERGY
                                              2001UTILITY INFRASTRUXOTHER TOTAL 

  Revenues$2,680,298 $173,786 $  32,476 $2,886,560 
  Depreciation and amortization208,705 8,820 15 217,540 
  Income tax68,005 2,956 8,877 79,838 
  Operating income273,751 8,702 14,668 297,121 
  Interest charges, net of AFUDC186,403 3,656 -- 190,059 
  Net income80,137 2,518 24,184 106,839 
  Goodwill, net-- 102,151 -- 102,151 
  Total assets5,300,105 229,125 139,251 5,668,481 
  Construction expenditures - excluding equity AFUDC247,435 -- -- 247,435 
  Additions to other property, plant and equipment-- 5,193 -- 5,193 


NOTE 21.20.
        Impairment of Long-Lived AssetsSupplementary Income Statement Information

 2003
2002
2001
  (DOLLARS IN THOUSANDS)PUGET
ENERGY 
PSE PUGET
ENERGY 
PSE PUGET
ENERGY 
PSE 

  Taxes other than income taxes:
    Real estate and personal proper$  45,660 $  44,757 $  48,890 $  48,408 $  41,858 $  41,588 
    State business75,523 75,524 77,527 77,527 85,335 84,735 
    Municipal and occupational64,861 64,861 67,770 67,770 71,819 71,819 
    Other38,273 25,638 37,029 24,463 33,431 29,084 

  Total taxes other than income tax$224,317 $210,780 $231,216 $218,168 $232,443 $227,226 

  Charged to:
    Operating expense$208,395 $194,857 $215,429 $202,381 $212,582 $207,365 
    Other accounts, including
    construction work in progress15,922 15,923 15,787 15,787 19,861 19,861 

  Total taxes other than income tax$224,317 $210,780 $231,216 $218,168 $232,443 $227,226 

SUPPLEMENTALQUARTERLY FINANCIAL DATA

        InThe following unaudited amounts, in the fourth quarter of 2000, Hydro Energy Development Corp., a wholly-owned subsidiary of PSE, recorded an after-tax loss of approximately $11.8 million in Other Incomeopinion of the non-regulated business segment. The loss provision represents the difference between the carrying valueCompany, include all adjustments (consisting of 13 small hydroelectric generating projects Hydro Energy Development Corp. was seeking approval to develop in western Washington State and management’s estimate of their net realizable value. Federal and state regulatory agencies that have jurisdiction over the construction and operationnormal recurring adjustments) necessary for a fair presentation of the proposed projects have made it increasingly difficultresults of operations for the interim periods. Quarterly amounts vary during the year due to complete and operate the projects in an economic manner. Hydro Energy Development Corp. owns and operates a 3.7 MW hydroelectric project located in western Washington State.seasonal nature of the utility business.

PUGET ENERGY

  (Unaudited; dollars in thousands except per share amounts)    
  2003 QUARTERFIRST SECOND THIRD FOURTH 

Operating revenues$   675,961 $557,856 $515,567 $ 742,139 
Operating income91,385 66,407 54,389 92,994 
Other income704 2,247 2,663 (4,050)
Net income before cumulative effect of
  accounting change44,756 22,392 11,003 43,366 
Net income44,587 22,392 11,003 43,366 
Basic earnings per common share$0.46 $0.22 $0.10 $0.44 
Diluted earnings per common share$0.45 $0.22 $0.10 $0.44 
 

  (Unaudited; dollars in thousands except per share amounts)
  2002 QUARTERFIRST SECOND THIRD FOURTH 

Operating revenues$   739,060 $540,819 $458,476 $ 653,967 
Operating income76,571 76,833 57,098 99,168 
Other income384 3,441 230 1,403 
Net income26,478 31,369 8,512 51,525 
Basic and diluted earnings per common share$0.28 $0.34 $0.07 $0.55 
 

  (Unaudited; dollars in thousands except per share amounts)
  2001 QUARTERFIRST SECOND THIRD FOURTH 

Operating revenues$1,024,234 $710,295 $478,966 $ 673,064 
Operating income130,541 66,071 45,756 54,754 
Other income1,941 1,568 7,892 3,123 
Net income before cumulative effect of
  accounting change87,047 19,465 6,809 8,266 
Net income72,298 19,465 6,809 8,266 
Basic earnings per common share$0.815 $0.201 $0.055 $0.071 
Diluted earnings per common share$0.812 $0.201 $0.054 $0.071 


PUGET SOUND ENERGY

  (Unaudited; dollars in thousands)
  2003 QUARTERFIRST SECOND THIRD FOURTH 

Operating revenues$   605,284 $465,513 $422,425 $ 656,514 
Operating income93,935 62,120 51,046 90,803 
Other income691 2,309 2,620 (4,033)
Net income before cumulative effect of
  accounting change48,270 19,614 9,488 42,683 
Net income48,101 19,614 9,488 42,683 
 

  (Unaudited; dollars in thousands)
  2002 QUARTERFIRST SECOND THIRD FOURTH 

Operating revenues$   678,299 $464,697 $366,103 $ 563,694 
Operating income74,732 72,724 51,367 95,769 
Other income309 3,455 210 1,241 
Net income25,698 28,839 4,701 49,709 
 

  (Unaudited; dollars in thousands)
  2001 QUARTERFIRST SECOND THIRD FOURTH 

Operating revenues$   995,694 $664,827 $426,195 $ 628,058 
Operating income130,111 61,629 42,360 54,383 
Other income2,843 2,485 8,885 2,839 
Net income before cumulative effect of
  accounting change87,628 17,275 5,474 8,754 
Net income72,879 17,275 5,474 8,754 


ScheduleSCHEDULE II.
Valuation and Qualifying Accounts and Reserves

(Dollars in thousands)
BALANCE AT
BEGINNING
OF PERIOD

ADDITIONS
CHARGED TO
COSTS AND
EXPENSES

DEDUCTIONS
BALANCE
AT END
OF PERIOD

(DOLLARS IN THOUSANDS)
(DOLLARS IN THOUSANDS)
BALANCE AT
BEGINNING
OF PERIOD

ADDITIONS
CHARGED TO
COSTS AND
EXPENSES

DEDUCTIONS
BALANCE
AT END
OF PERIOD

PUGET ENERGY                   


YEAR ENDED DECEMBER 31, 2001 


 
Accounts deducted from assets on balance sheet:   
Allowance for doubtful accounts receivable $3,863 $9,387 $8,891 $4,359 
Reserve on wholesale sales  41,488  --  --  41,488 
Industrial accident reserve  2,000  --  2,000  -- 
Gas transportation contracts reserve  139  --  139  -- 


 
YEAR ENDED DECEMBER 31, 2002  


 
Accounts deducted from assets on balance sheet:      
Allowance for doubtful accounts receivable $5,488 $11,191 $12,816 $3,863  $5,488 $11,191 $12,816 $3,863 
Reserve on wholesale sales  41,488  --  --  41,488   41,488 ��--  --  41,488 
Industrial accident reserve  --  4,000  2,000  2,000   --  4,000  2,000  2,000 
Gas transportation contracts reserve  139  --  --  139   139  --  --  139 



 
YEAR ENDED DECEMBER 31, 2001 


 
Accounts deducted from assets on balance sheet:   
Allowance for doubtful accounts receivable $1,538 $13,458 $9,508 $5,488 
Reserve on wholesale sales  41,488  --  --  41,488 
Gas transportation contracts reserve  1,657  32  1,550  139 


PUGET SOUND ENERGY  


YEAR ENDED DECEMBER 31, 2003 


 
Accounts deducted from assets on balance sheet:   
Allowance for doubtful accounts receivable $1,990 $9,385 $8,891 $2,484 
Reserve on wholesale sales  41,488  --  --  41,488 
Industrial accident reserve  2,000  --  2,000  -- 
Gas transportation contracts reserve  139  --  139  -- 


 
YEAR ENDED DECEMBER 31, 2002  


 
Accounts deducted from assets on balance sheet:      
Allowance for doubtful accounts receivable $3,666 $11,140 $12,816 $1,980  $3,666 $11,140 $12,816 $1,990 
Reserve on wholesale sales  41,488  --  --  41,488   41,488  --  --  41,488 
Industrial accident reserve  --  4,000  2,000  2,000   --  4,000  2,000  2,000 
Gas transportation contracts reserve  139  --  --  139   139  --  --  139 



PUGET ENERGY 
 
YEAR ENDED DECEMBER 31, 2001  


 
Accounts deducted from assets on balance sheet:      
Allowance for doubtful accounts receivable $1,538 $13,458 $9,508 $5,488  $1,538 $11,636 $9,508 $3,666 
Reserve on wholesale sales  41,488  --  --  41,488   41,488  --  --  41,488 
Gas transportation contracts reserve  1,657  32  1,550  139   1,657  32  1,550  139 



PUGET SOUND ENERGY 
YEAR ENDED DECEMBER 31, 2001 

Accounts deducted from assets on balance sheet:   
Allowance for doubtful accounts receivable $1,538 $11,636 $9,508 $3,666 
Reserve on wholesale sales  41,488  --  --  41,488 
Gas transportation contracts reserve  1,657  32  1,550  139 

PUGET ENERGY AND PUGET SOUND ENERGY 
YEAR ENDED DECEMBER 31, 2000 

Accounts deducted from assets on balance sheet:   
Allowance for doubtful accounts receivable $1,503 $7,552 $7,517 $1,538 
Reserve on wholesale sales  --  41,488  --  41,488 
Gas transportation contracts reserve  1,780  660  783  1,657 

EXHIBIT INDEX

        Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission and are incorporated herein by reference.

Certainof the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission and are incorporated herein by reference.
3(i).1Restated Articles of Incorporation of Puget Energy (Incorporated by reference to Exhibit 99.2, Puget Energy's Current Report on Form 8-K filed January 2, 2001, Commission File No. 333-77491).
3(i).2Restated Articles of Incorporation of PSE (included as Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996, Registration No. 333-617).
*3(ii).1Amended and Restated Bylaws of Puget Energy dated March 7, 2003.
*3(ii).2Amended and Restated Bylaws of PSE dated March 7, 2003.
4.1Fortieth through Seventy-eighthSeventy-ninth Supplemental Indentures defining the rights of the holders of PSE's First Mortgage Bonds (Exhibit 2-d to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4-h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200; Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393; Exhibits (4)-b and (4)-c to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4.25 to Registration No. 333-41181; Exhibit 4.27 to Current Report on Form 8-K dated March 5, 1999; and Exhibit 4.2 to Current Report on form 8-K dated November 2, 2000.2000; and Exhibit 4.2 to Current Report on Form 8-K dated June 3, 2003.
4.2Indenture defining the rights of the holders of PSE's senior notes (incorporated herein by reference to Exhibit 4-a to PSE's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393).
4.3First Supplemental Indenture defining the rights of the holders of PSE's Senior Notes, Series A (incorporated herein by reference to Exhibit 4-b to PSE's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393).
4.4Second Supplemental Indenture defining the rights of the holders of PSE's Senior Notes, Series B (incorporated herein beby reference to Exhibit 4.6 to PSE's Current Report on Form 8-K, dated March 5, 1999, Commission File No. 1-4393).
4.5Third Supplemental Indenture defining the rights of the holders of PSE's Senior Notes, Series C (incorporated herein by reference to Exhibit 4.1 to PSE's Current Report on Form 8-K, dated November 2, 2000, Commission File No. 1-4393).
4.6Fourth Supplemental Indenture defining the rights of the holders of PSE's Senior Notes (incorporated herein by reference to Exhibit 4.1 to PSE's Current Report on Form 8-K, dated June 3, 2003, Commission File No. 1-4393).
4.7Rights Agreement dated as of December 21, 2000 between Puget Energy and Mellon Investor Services LLC, as Rights Agent (incorporated herein by reference to Exhibit 2.1 to PSE's Registration Statement on Form 8-A, dated January 2, 2001, Commission File No. 1-16305).
4.74.8Indenture between PSE and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.1 of PSE's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393).
4.84.9Amended and Restated Declaration of Trust between Puget Sound Energy Capital Trust and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.2 of PSE's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393).
4.94.10Series A Capital Securities Guarantee Agreement between PSE and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.3 of PSE's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393).
4.10Pledge Agreement dated August 1, 1991 between PSE and The First National Bank of Chicago, as Trustee (Exhibit (4)-j to Registration No. 33-45916).
4.11Loan Agreement dated August 1, 1991 between the City of Forsyth, Rosebud County, Montana and PSE (Exhibit (4)-k to Registration No. 33-45916).
4.12Pledge Agreement dated as of March 1, 1992 by and between PSE and Chemical Bank relating to a series of first mortgage bonds (Exhibit 4.15 to Annual Report on Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-4393).
4.13Pledge Agreement dated as of April 1, 1993 by and between PSE and The First National Bank of Chicago, relating to a series of first mortgage bonds (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-4393).

4.14Indenture of First Mortgage dated as of April 1, 1957 (Exhibit 4-B, Registration No. 2-14307).
4.15First Supplemental Indenture dated as of October 1, 1959 (Exhibit 4-D to Registration No. 2-17876).
4.164.12Sixth Supplemental Indenture dated as of August 1, 1966 (Exhibit to Form 8-K for month of August 1966, File No. 0-951).
4.174.13Seventh Supplemental Indenture dated as of February 1, 1967 (Exhibit 4-M, Registration No. 2-27038).
4.184.14Sixteenth Supplemental Indenture dated as of June 1, 1977 (Exhibit 6-05 to Registration No. 2-60352).
4.194.15Seventeenth Supplemental Indenture dated as of August 9, 1978 (Exhibit 5-K.18 to Registration No. 2-64428).
4.204.16Twenty-second Supplemental Indenture dated as of July 15, 1986 (Exhibit 4-B.20 to Form 10-K for the year ended September 30, 1986, File No. 0-951).
4.214.17Twenty-seventh Supplemental Indenture dated as of September 1, 1990 (Exhibit 4-B.20, Form 10-K for the year ended September 30, 1998, File No. 10-951).
4.224.18Twenty-eighth Supplemental Indenture dated as of July 31, 1991 (Exhibit 4-A, Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
4.234.19Twenty-ninth Supplemental Indenture dated as of June 1, 1993 (Exhibit 4-A to Registration No. 33-49599).
4.244.20Thirtieth Supplemental Indenture dated as of August 15, 1995 (incorporated herein by reference to Exhibit 4-A of Washington Natural Gas Company's S-3 Registration Statement, Registration No. 33-61859).
4.254.21Statement of Relative Rights and Preferences for the 7 3/4% Series Preferred Stock Cumulative, $100 Par Value. (Exhibit 1.6 to Registration Statement on Form 8-A filedThirty-first Supplemental Indenture dated February 14, 1994, Commission File No. 1-4393).10, 1997.
4.264.22Unsecured Debt Indenture between Puget Sound Energy and Bank One Trust Company, N.A. dated as of May 18, 2001, defining the rights of the holders of Puget Sound Energy's unsecured debentures (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy's Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393).
4.274.23First Supplemental Indenture to the Unsecured Debt Indenture dated as of May 18, 2001 defining the rights of 8.40% Subordinated Deferrable Interest Debentures due June 30, 2041 (incorporated herein by reference to Exhibit 4.4 to Puget Sound Energy's Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393).
4.284.24Amended and Restated Declaration of Trust of Puget Sound Energy Trust II dated as of May 18, 2001 (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy's Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393).
4.294.25Preferred Securities Guarantee Agreement, dated May 18, 2001 between Puget Sound Energy and Bank One Trust Company, N.A. for the benefit of the holders of the trust preferred securities of the Puget Sound Energy Trust II (incorporated herein by reference to Exhibit 4.5 to Puget Sound Energy's Current Report on Form 8-K, filed May 22, 2001, Commission File No. 1-4393).
*4.304.26Thirty-first Supplement IndenturePledge Agreement dated February 10, 1997.March 11, 2003 between Puget Sound Energy and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to the Company's Post-Effective Amendment No. 1 to Registration Statement on Form S-3 dated July 11, 2003, Commission File No. 333-82940-02).
10.14.27Assignment andLoan Agreement dated as of August 13, 1964March 1, 2003, between Public Utility Districtthe City of Forsyth, Rosebud County, Montana and Puget Sound Energy (incorporated herein by reference to Exhibit 4.25 to the Company's Post-Effective Amendment No. 1 of Chelan County, Washington and PSE, relating to the Rock Island Project (Exhibit 13-b to Registration Statement on Form S-3, dated July 11, 2003, Commission File No. 2-24262)333-82490-02).
10.210.1First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 13-d to Registration No. 2-24252).
10.3Assignment and Agreement dated as of August 13, 1964 between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 13-e to Registration No. 2-24252).
10.4Assignment and Agreement dated as of August 13, 1964 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Development (Exhibit 13-j to Registration No. 2-24252).
10.5Assignment and Agreement dated as of August 13, 1964 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Wanapum Development (Exhibit 13-n to Registration No. 2-24252).

10.610.2First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-p to Registration No. 2-24252).
10.7First Amendment executed as of February 9, 1965 to Reserved Share Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-r to Registration No. 2-24252).
10.8Assignment and Agreement dated as of August 13, 1964 between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-u to Registration No. 2-24252).
10.910.3Pacific Northwest Coordination Agreement executed as of September 15, 1964 among the United States of America, PSE and most of the other major electrical utilities in the Pacific Northwest (Exhibit 13-gg to Registration No. 2-24252).
10.1010.4Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 4-1-a to Registration No. 2-13979).
10.1110.5Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE, relating to the Rocky Reach Project (Exhibit 4-c-1 to Registration No. 2-13979).
10.1210.6Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Project (Exhibit 4-d to Registration No. 2-13347).
10.1310.7First Amendment to Power Sales Contract dated as of August 5, 1958 between PSE and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (Exhibit 13-h to Registration No. 2-15618).
10.1410.8Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Wanapum Development (Exhibit 13-j to Registration No. 2-15618).
10.15Reserve Share Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Project (Exhibit 13-k to Registration No. 2-15618).
10.1610.9Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Wanapum Development (Exhibit 13-1 to Registration No. 2-21824).
10.1710.10Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824).
10.18Reserved Share Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and PSE, relating to the Wells Development (Exhibit 13-s to Registration No. 2-21824).
10.1910.11Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and PSE (Exhibit 5-b to Registration No. 2-45702).
10.2010.12Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and PSE (Exhibit 5-c to Registration No. 2-45702).
10.2110.13Coal Supply Agreement dated as of July 30, 1971 among Northwestern Resources formerly The Montana Power Company, PSE and Western Energy Company (Exhibit 5-d to Registration No. 2-45702).
10.2210.14Contract dated June 19, 1974 between PSE and P.U.DP.U.D. No. 1 of Chelan County (Exhibit D to Form 8-K dated July 5, 1974).
10.23Exchange Agreement executed August 13, 1964 between the United States of America, Columbia Storage Power Exchange and PSE, relating to Canadian Entitlement (Exhibit 13-ff to Registration No. 2-24252).
10.2410.15Loan Agreement dated as of December 1, 1980 and related documents pertaining to Whitehorn turbine construction trust financing (Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended December 31, 1980, Commission File No. 1-4393).
10.2510.16Coal Transportation Agreement dated as of July 10, 1981 (Exhibit 20-a to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981, Commission File No. 1-4393).
10.2610.17Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and PSE dated September 17, 1985 (Exhibit (10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).

10.2710.18Agreement to Dismiss Claims and Covenant Not to Sue dated September 17, 1985 between Washington Public Power Supply System (Energy Northwest) and PSE (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).
10.2810.19Irrevocable Offer of Washington Public Power Supply System (Energy Northwest) Nuclear Project No. 3 Capability for Acquisition executed by PSE dated September 17, 1985 (Exhibit A of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).
10.2910.20Settlement Exchange Agreement (Bonneville Exchange Power Contract) executed by the United States of America Department of Energy acting by and through the Bonneville Power Administration and PSE dated September 17, 1985 (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).
10.3010.21Settlement Agreement and Covenant Not to Sue between PSE and Northern Wasco County People's Utility District dated October 16, 1985 (Exhibit (10)-53 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).
10.3110.22Settlement Agreement and Covenant Not to Sue between PSE and Tillamook People's Utility District dated October 16, 1985 (Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).
10.3210.23Settlement Agreement and Covenant Not to Sue between PSE and Clatskanie People's Utility District dated September 30, 1985 (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393).
10.3310.24Stipulation and Settlement Agreement between PSE and Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October 31, 1986 (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1986, Commission File No. 1-4393).
10.3410.25Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and PSE (Colstrip Project) (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.3510.26Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.3610.27Ownership and Operation Agreement dated as of May 6, 1981 between PSE and other Owners of the Colstrip Project (Colstrip 3 and 4) (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.3710.28Colstrip Project Transmission Agreement dated as of May 6, 1981 between PSE and Owners of the Colstrip Project (Exhibit (10)-58 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.3810.29Common Facilities Agreement dated as of May 6, 1981 between PSE and Owners of Colstrip 1 and 2, and 3 and 4 (Exhibit (10)-59 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.3910.30Agreement for the Purchase of Power dated as of October 29, 1984 between South Fork II, Inc. and PSE (Weeks Falls Hydro-electric Project) (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.4010.31Agreement for the Purchase of Power dated as of October 29, 1984, between South Fork Resources, Inc. and PSE (Twin Falls Hydro-electric Project) (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.4110.32Agreement for Firm Purchase Power dated as of January 4, 1988 between the City of Spokane, Washington and PSE (Spokane Waste Combustion Project) (Exhibit (10)-62 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.4210.33Agreement for Evaluating, Planning and Licensing dated as of February 21, 1985 and Agreement for Purchase of Power dated as of February 21, 1985 between Pacific Hydropower Associates and PSE (Koma Kulshan Hydro-electric Project) (Exhibit (10)-63 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
10.4310.34Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSE (Rocky Reach Project) (Exhibit (10)-66 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).

10.4410.35Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and PSE (Rock Island Project) (Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
10.45Agreement for Purchase and Sale of Firm Capacity and Energy between The Washington Water Power Company and PSE dated as of January 1, 1988 (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, Commission File No. 1-4393).
10.4610.36Amendment dated as of August 10, 1988 to Agreement for Firm Purchase Power dated as of January 4, 1988 between the City of Spokane, Washington and PSE (Spokane Waste Combustion Project) (Exhibit (10)-76 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
10.4710.37Agreement for Firm Power Purchase dated October 24, 1988 between Northern Wasco People's Utility District and PSE (The Dalles Dam North Fishway) (Exhibit (10)-77 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
10.48Agreement for the Purchase of Power dated as of October 27, 1988 between Pacific Power & Light Company (PacifiCorp) and PSE (Exhibit (10)-78 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
10.49Agreement for Sale and Exchange of Firm Power dated as of November 23, 1988 between the Bonneville Power Administration and PSE (Exhibit (10)-79 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
10.5010.38Agreement for Firm Power Purchase dated as of February 24, 1989 between Sumas Energy, Inc. and PSE (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1989, Commission File No. 1-4393).
10.5110.39Settlement Agreement dated as of April 27, 1989 between Public Utility District No. 1 of Douglas County, Washington, Portland General Electric Company (Enron), PacifiCorp, The Washington Water Power Company (Avista) and PSE (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393).
10.5210.40Agreement for Firm Power Purchase (Thermal Project) dated as of June 29, 1989 between San Juan Energy Company and PSE (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393).
10.5310.41Agreement for Verification of Transfer, Assignment and Assumption dated as of September 15, 1989 between San Juan Energy Company, March Point Cogeneration Company and PSE (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393).
10.5410.42Power Sales Agreement between Northwestern Resources formerly The Montana Power Company and PSE dated as of October 1, 1989 (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393).
10.5510.43Conservation Power Sales Agreement dated as of December 11, 1989 between Public Utility District No. 1 of Snohomish County and PSE (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393).
10.5610.44Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among theThe Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company (Enron), PacifiCorp and PSE (Exhibit (10)-91 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393).
10.57Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated as of April 18, 1990 between PacifiCorp and PSE (Exhibit (10)-93 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393).
10.5810.45Settlement Agreement dated as of October 1, 1990 among Public Utility District No. 1 of Douglas County, Washington, PSE, Pacific Power and Light Company (PacifiCorp), The Washington Water Power Company (Avista), Portland General Electric Company (Enron), the Washington Department of Fisheries, the Washington Department of Wildlife, the Oregon Department of Fish and Wildlife, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the Confederated Tribes and Bands of the Yakama Indian Nation, the Confederated Tribes of the Umatilla Reservation, and the Confederated Tribes of the Colville Reservation (Exhibit (10)-95 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393).

10.5910.46Agreement for Firm Power Purchase (Thermal Project) dated December 27, 1990 among March Point Cogeneration Company, a California general partnership comprising San Juan Energy Company, a California corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation; and PSE (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393).
10.6010.47Agreement for Firm Power Purchase dated March 20, 1991 between Tenaska Washington, Inc., a Delaware corporation, and PSE (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393).
10.61Letter Agreement dated April 25, 1991 between Sumas Energy, Inc. and PSE, to amend the Agreement for Firm Power Purchase dated as of February 24, 1989 (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393).
10.62Amendment dated June 7, 1991 to Letter Agreement dated April 25, 1991 between Sumas Energy, Inc. and PSE (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393).
10.6310.48Amendatory Agreement No. 3 dated August 1, 1991 to the Pacific Northwest Coordination Agreement executed September 15, 1964 among the United States of America, PSE and most of the other major electrical utilities in the Pacific Northwest (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393).
10.6410.49Agreement between the 40 parties to the Western Systems Power Pool (PSE being one party) dated July 27, 1991 (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393).
10.6510.50Memorandum of Understanding between PSE and the Bonneville Power Administration dated September 18, 1991 (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393).
10.6610.51Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and PSE (Exhibit (10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
10.6710.52Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and PSE (Exhibit (10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
10.68Intertie and Network Transmission Agreement, dated as of October 4, 1991 between Bonneville Power Administration and PSE (Exhibit (10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
10.6910.53Amendment to Agreement for Firm Power Purchase dated as of September 30, 1991 between Sumas Energy, Inc. and PSE (Exhibit (10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
10.7010.54Letter Agreement dated October 12, 1992 between Tenaska Washington Partners, L.P. and PSE regarding clarification of issues under the Agreement for Firm Power Purchase (Exhibit (10)-121 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393).
10.7110.55Consent and Agreement dated October 12, 1992 between PSE and The Chase Manhattan Bank, N.A., as agent (Exhibit (10)-122 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393).
10.7210.56General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and PSE (BPA Contract No. DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
10.7310.57PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and PSE (BPA Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
10.7410.58Power Exchange Agreement dated as of September 27, 1995 between British Columbia Power Exchange Corporation and PSE (Exhibit 10.117 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393).
10.75Contract with G. B. Swofford, Senior Vice President Customer Operations, dated October 18, 1996 (Exhibit 10.120 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393).

10.7610.59Service Agreement dated April 14, 1993 between Questar Pipeline Corporation and Washington Natural Gas Company for FSS-1 firm storage service at Clay Basin (Exhibit 10-B Form 10-K for the year ended September 30, 1994, File No. 11271).
10.77Service Agreement dated November 1, 1989 with Northwest Pipeline Corporation covering liquefaction storage gas service filed under cover of Form SE dated December 27, 1989.
10.7810.60Firm Transportation Service Agreement dated October 1, 1990 between Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-D to Form 10-K for the year ended September 30, 1994, File No. 11271).
10.7910.61Gas Transportation Service Contract dated June 29, 1990 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A to Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.8010.62Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A to Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.8110.63Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 10-E.2 to Form 10-K for the year ended September 30, 1995, File No. 11271).
10.8210.64Gas Transportation Service Contract dated July 15, 1994 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 10-E.3 to Form 10-K for the year ended September 30, 1995, File No. 11271).
10.8310.65Amendment to Gas Transportation Service Contract dated August 15, 1994 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 10-E.4 to Form 10-K for the year ended September 30, 1995, File No. 11271).
10.8410.66Firm Transportation Service Agreement dated March 1, 1992 between Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-O to Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.8510.67Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (Exhibit 10-P to Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.8610.68Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (Exhibit 10-Q to Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.87Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Plymouth, LNG (Exhibit 10-R to Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.88Service Agreement dated July 9, 1991 with Northwest Pipeline Corporation for SGS-2F Storage Service filed under cover of Form SE dated December 23, 1991 (Exhibit 10-S to Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.8910.69Firm Transportation Agreement dated October 27, 1993 between Pacific Gas Transmission Company and Washington Natural Gas Company for firm transportation service from Kingsgate (Exhibit 10-T, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.9010.70Firm Storage Service Agreement and Amendment dated April 30, 1991 between Questar Pipeline Company and Washington Natural Gas Company for firm storage service at Clay Basin filed under cover of Form SE dated December 23, 1991.
10.91Change in control agreement with T. J. Hogan dated August 17, 1995 (Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File No. 1-4393).
10.92Employment agreement with S. A. McKeon, Vice President and General Counsel, dated May 27, 1997 (Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December 31, 1998, Commission File No. 1-4393).
10.9310.71Puget Energy, Inc. Non-employee Director Stock Plan. (incorporated herein by reference to Exhibit 99.1 to Puget Energy's Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-41157-99).
*10.9410.72Amendment No. 1 to the Puget Energy, Inc. Non-employee Director Stock Plan, effective as of January 1, 2003.

10.9510.73Puget Energy, Inc. Employee Stock Purchase Plan. (incorporated herein by reference to Exhibit 99.1 to Puget Energy's Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-41113-99).
10.9610.741995 Long-Term Incentive Compensation Plan. (Exhibit 10.108 to Annual Report on Form 10-K for the fiscal year ended December 31, 2000, Commission File No. 1-4393 and 1-16305.)1-16305).
10.9710.751995 Long-Term Incentive Compensation Plan (incorporated herein by reference to Exhibit 99.1 to Puget Energy's Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-61851-99).
10.98Retention Agreement with S .A. McKeon, Vice President and General Counsel, dated July 1, 2001.
10.9910.76Employment agreement with S. P. Reynolds, Chief Executive Officer and President dated January 7, 2002.
10.10010.77Credit Agreement dated June 29, 2001, among InfrastruX Group, Inc. and various Banks named therein, BankOne, NA as Administrative Agent. (Exhibit 10-1, Form 10-Q for the quarterly period ended June 30, 2001, Commission File No. 1-4393 and 1-16305).
10.10110.78Power Sales Contract dated April 15, 2002 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Project. (Exhibit 10-1 to Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and 1-4393).
10.10210.79Reasonable Portion Power Sales Contract dated April 15, 2002 between Public Utility District No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Project. (Exhibit 10-2 to Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and 1-4393).
10.10310.80Additional Power Sales Contract dated April 15, 2002 between Public Utility district No. 2 of Grant County, Washington and PSE, relating to the Priest Rapids Project. (Exhibit 10-3 to Form 10-Q for the quarter ended June 30, 2002, File No1-16305 and 1-4393).
10.104Change-in-control agreement with G. B. Swofford, Senior Vice President and Chief Operating Officer dated March 12, 1999. (Exhibit 10-4 to Form 10-Q for the quarter ended June 30, 2002, File NoNo. 1-16305 and 1-4393).
10.105Change-in-control agreement with T.J. Hogan, Senior Vice President, External Affairs dated March 12, 1999. (Exhibit 10-5 to Form 10-Q for the quarter ended June 30, 2002, File No 1-16305 and 1-4393).
*10.10610.81Credit Agreement dated December 23, 2002 covering PSE and various banks named therein, Bank One, NA as administrative agent.
*10.10710.82Receivable Purchase Agreement dated December 23, 2002 among PSE, Rainier Receivables, Inc., and Bank One, NA as agent.
*10.10810.83Receivable Sale Agreement dated December 23, 2002 among PSE and Rainier Receivables, Inc.
*10.10910.84Employment agreement with J.M. Ryan, Vice President Energy Portfolio Management, dated November 30, 2001.
*10.11010.85Change-in-Control Agreement with J.M. Ryan, Vice President, Energy Portfolio Management, dated November 30, 2001.
*12-110.86Change-in-Control Agreement with B. A. Valdman, Senior Vice President, Finance and Chief Financial Officer, dated November 28, 2003.
*10.87Change-in-Control Agreement with S. McLain, Senior Vice President, Operations, dated March 12, 1999.
*10.88Change-in-Control Agreement with M. T. Lennon, President and Chief Executive Officer of InfrastruX, dated May 6, 2002.
*10.89Termination Agreement with T.J. Hogan, Senior Vice President, Regional Service and Community Affairs, dated July 31, 2003.
*10.90Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2004.
*10.91Restricted Stock Unit Award Agreement with S. P. Reynolds, Chief Executive Officer and President dated, January 8, 2004.
*12.1Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy (1998(1999 through 2002)2003).
*12-212.2Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy (1998(1999 through 2002)2003).
*21.121.1Subsidiaries of Puget Energy.
*21.221.2Subsidiaries of PSE.
*23.123.1Consent of PricewaterhouseCoopers LLP.
*99.131.1Certification of Puget Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley act of 2002 - Stephen P. Reynolds.
*31.2Certification of Puget Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley act of 2002 - Bertrand A. Valdman.
*31.3Certification of Puget Sound Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley act of 2002 - Stephen P. Reynolds.
*31.4Certification of Puget Sound Energy - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley act of 2002 - Bertrand A. Valdman.
*32.1Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley act of 2002 - Stephen P. Reynolds.
*99.232.2Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley act of 2002 - StephenBertrand A. McKeon.Valdman.
*99.3Puget Energy proxy statement for 2003 Annual Meeting of Shareholders (Commission File No. 1-16305).


        *Filed herewith.