FORM 10-K

DEFINITIONS

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; 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:

        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:

        Additional financial data regarding these segments are included in Note 19 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, primarily engaged in the business of electric 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:

         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 the State of Washington.
        At December 31, 2003, PSE had approximately 977,700 electric customers, consisting of 861,900 residential, 109,700 commercial, 4,000 industrial and 2,100 other customers; and approximately 644,600 gas customers, consisting of 593,800 residential, 48,000 commercial, 2,700 industrial and 100 transportation customers. At December 31, 2003, approximately 310,900 customers purchased both forms of energy from PSE. For the year 2003, PSE added approximately 19,700 electric customers and approximately 22,600 gas customers, representing annualized growth rates of 2.1% and 3.6% respectively. During 2003, PSE’s billed retail and transportation revenues from electric utility operations, excluding conservation trust collections, were derived 48% from residential customers, 43% from commercial customers, 7% from industrial customers and 2% from transportation and other customers. PSE’s retail revenues from gas utility operations were derived 64% from residential customers, 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 economic factors and weather conditions. PSE has a purchased gas adjustment (PGA) mechanism in retail gas rates to recover variations in gas supply and transportation costs. PSE also has a power cost adjustment (PCA) mechanism in electric rates to recover variations in electricity costs on a shared basis between customers and PSE.
        In the five-year period ended December 31, 2003, PSE’s gross electric utility plant additions were $941 million and retirements were $210 million. In the five-year period ended December 31, 2003, PSE’s gross gas utility plant additions were $551 million and retirements were $76 million. In the same five-year period, PSE’s gross common utility plant additions were $211 million and retirements were $45 million. Gross electric utility plant at December 31, 2003 was approximately $4.3 billion, which consisted of 59% distribution, 27% generation, 6% transmission and 8% general plant and other. Gross gas utility plant as of December 31, 2003 was approximately $1.7 billion, which consisted of 86% distribution, 6% transmission and 8% general plant and other. Gross common utility general and intangible plant at December 31, 2003 was approximately $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 12 companies, primarily in the south/Texas, 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:

        InfrastruX 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, 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.
        InfrastruX’s operating strategy revolves around leveraging the synergies of a core group of outstanding infrastructure construction contractors whose asset base, expertise, local knowledge, relationships and years of successful operations form a strong base 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 also move quickly to provide additional services as needs arise. The formation of regional 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.
        While the general outlook appears to be improving, in the near term, InfrastruX’s market opportunities will continue to be constrained by the general economic and utility industry downturn that has resulted in reduced spending on infrastructure construction, including large pipeline and utility projects, by many of InfrastruX’s customers. As a result, competition on project bids will continue to be very strong, which may reduce profit margins and adversely impact revenue growth. Puget Energy management continues to believe that in the long term the opportunities for InfrastruX are excellent given an aging transmission and distribution infrastructure, forecasted growth in energy demand and the need for greater network infrastructure construction services.

        EMPLOYEES
        At December 31, 2003, Puget Energy and its subsidiaries had approximately 5,164 full-time employees:

        Approximately 1,100 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) or the United Association of Plumbers and Pipefitters (UA). The labor contracts with the IBEW and UA run through 2007 and 2006, respectively.
        Approximately 400 InfrastruX employees are represented by the IBEW, UA, United Steelworkers of America, Laborers International Union of North America or other unions. Some unions have annual contract renewals while others have multiple-year contracts.

        CORPORATE LOCATION
        Puget Energy’s and PSE’s principal executive offices are located at 10885 N.E. 4th Street, Suite 1200, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.

         AVAILABLE INFORMATION
        The Company’s website address is www.pse.com. The Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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, Inc., Investor Services, P.O. Box 97034, PSE-08S, Bellevue, Washington 98009-9734:

        If the Company waives any material provision of its Code of Ethics for its Chief Executive Officer and senior financial officers or its Corporate Ethics and Compliance Code, or substantively changes the codes for any specific officer, the Company will disclose that waiver on its website within five business 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.

        ELECTRIC RATES AND REGULATION
        On October 24, 2003, PSE filed a request with the Washington Commission to increase its electric rates $64.4 million to recover higher projected power supply costs. The proposed rate increase includes, 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 Frederickson 1 plant was prudent and that 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 increase. 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 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 may be up to an 11-month process from the time the general rate case is filed.
        On June 20, 2002, the Washington Commission issued final regulatory approval of the comprehensive electric 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 began July 1, 2002, which was intended to generate approximately $59 million in additional revenue 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 included a PCA mechanism that triggers if PSE’s costs to provide customers’ electricity falls outside certain bands from a normalized level of power costs established in the electric general rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ending June 30, 2006 is limited to $40 million plus 1% of the excess. 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:

        (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. PSE can request a PCA rate surcharge if for any 12-month period the actual or projected deferred power costs exceed $30 million. PSE’s cumulative share of the power costs through December 31, 2003 was $40 million. Principally because of adverse hydro conditions and escalating gas costs for electric generation in 2003, PSE reached the $40 million cumulative cap under the PCA mechanism in 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 gave PSE the financial flexibility to rebuild its common equity ratio to at least 39% over a three-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
        In June 2001, PSE and Bonneville Power Administration (BPA) entered into an amended settlement agreement regarding the Residential Purchase and Sale 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 a Residential and Farm Energy Exchange Benefit 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.
        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 BPA, which modified 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. Under the modified agreement, BPA deferred paying a portion of the benefits it would have otherwise paid. The amount of benefits deferred was $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 entered into other agreements similar to the agreement with PSE through which other investor-owned utilities and BPA agreed to BPA’s deferral of payments in its fiscal year 2003. The total cumulative amount deferred under the agreement with PSE and other such agreements equals $55 million. Absent certain adjustments tied to a BPA rate adjustment clause, BPA will begin paying back the amount deferred with interest over the 60-month period beginning October 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 accepted the tariff changes and the Residential 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. On June 30, 2003, BPA adopted its final Record of Decision in the February 2003 rate case, which established a formula under the BPA rate adjustment clause to be used in adjusting the rate that will affect the level of residential exchange benefits for PSE’s customers. 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 was $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 2003 and 2002, respectively. The difference between the customers’ credit and the amount received from BPA either increases or decreases the previously deferred amount owed to customers. The aggregated deferred amount is recorded on PSE’s balance sheet as restricted cash. Absent certain adjustments tied to the BPA rate adjustment clause described above, the modified amended 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 customers.
        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 adjustment 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 under certain conditions under the 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 amended settlement agreement and the conditional settlement agreements between BPA and PSE described above. 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 and the above-described District Court and U.S. Ninth Circuit Court of Appeals actions may have on 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:

        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 services to customers. The increase was intended to provide approximately $35.6 million annually in revenues. This rate increase became effective September 1, 2002.
        PSE is currently preparing to file 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 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 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 sales.

ELECTRIC OPERATING STATISTICS

¹ Operating revenues in 2003, 2002 and 2001 were reduced by $7.7 million, $12.7 million and $31.0 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, 2003, PSE’s peak electric power resources were approximately 4,537,495 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-related hedges and exchange agreements. During 2003, PSE’s total electric energy production was supplied 26.7% by its own resources, 19.9% through long-term contracts with several of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River and 22.3% from other firm purchases. Short-term wholesale purchases, net of sales to other utilities and marketers, accounted for 14.1% of energy purchases in 2003.
        The following table shows PSE’s electric energy supply resources at December 31, 2003 and 2002, and energy production during the year:

        PSE filed its electric Least Cost Plan on April 30, 2003 with the Washington Commission. 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 2003. An all-source RFP was issued in February 2004.

         COMPANY-CONTROLLED ELECTRIC GENERATION RESOURCES
        At December 31, 2003, PSE has the following plants with an aggregate net generating capacity of 1,801,200 KW:

¹ Power 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.
² Short-term wholesale purchases net of resales of 5,170,564 MWh and 6,063,076 MWh for 2003 and 2002, respectively, account for 14.1% and 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.

        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 the Colstrip Units 3 & 4 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.

         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. 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 license jurisdictional hydropower projects. FERC licenses are generally issued for a term of 30-50 years. The Baker River and Snoqualmie Falls Projects are currently in FERC relicensing 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 FERC license. The Electron Project is not subject to FERC jurisdiction. The White River Project was shut down on January 15, 2004 as a result of PSE’s rejection of the FERC license that made the project uneconomical to operate.
        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 current authorized capacity of 170.0 MW. The project was licensed for 50 years, effective May 1, 1956. The project’s current license expires on April 30, 2006, and PSE will issue its Notice of Intent to file a new license application in April 2004. 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 acting 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 of a “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 agreement 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 project. PSE appealed the 1997 license because it contained terms and conditions that would render ongoing operations of the project uneconomic relative to alternative resources. In November 2003, PSE determined that it could no longer continue to 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 costs and directs PSE to operate the diversion dam in accordance with measures determined by federal agencies to be necessary to protect listed species and habitat. 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 matter 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 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 currently evaluating responses to this 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 2003, approximately 19.9% of PSE’s energy output was obtained at an average cost of approximately $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 repairs or replacements or license 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, 2003, PSE’s aggregate capacity from all units of the Rock Island Project was 413,900 KW. PSE’s share of output of the additional Rock Island units may be reduced by up to 10% per year. Chelan began withdrawing 5% of the power from the additional Rock Island units for use in meeting its local 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:

        PSE has contracted to purchase from Chelan 38.9% (505,000 KW of peak capacity as of December 31, 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, 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, 2003) of the annual output of the Priest Rapids Development and 10.8% (98,000 KW of peak capacity as of December 31, 2003) of the annual output of the Wanapum Development, which percentages remain unchanged for the remainder of the original 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 contracts' 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 PUD’s new contracts unreasonably restrain trade and violate various sections of the FPA 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, FERC 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 was 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 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, 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 56 MW of exchange energy to BPA in all months except May, July and August for contract year 2003 — 2004.
        On October 31, 2003, a 15-year contract for the purchase of firm power and energy between PacifiCorp and PSE expired under the terms of the agreement. The contract provided for 120 average MW of energy and 200 MW of peak capacity annually.
        On October 1, 1989, PSE signed a contract with The Montana Power Company, which subsequently sold its utility assets to NorthWestern Corporation (NorthWestern) in 2002. Under the contract, NorthWestern provides PSE 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 each year. No payments are made under this agreement. PG&E is a summer peaking utility and provides power during the months of November through February. PSE is a

winter peaking utility and provides power during the months of June through September. Each party may terminate the contract 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 May 2002, PG&E responded and stated its view that PSE’s notice was void due to PG&E’s bankruptcy. PSE has not responded to the PG&E letter.

         ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITY GENERATORS
        As required by the federal Public Utility Regulatory Policies Act, 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, 2003 was $216.7 million, which will be recovered in electric rates through 2011. In the power 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 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. 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

GAS SUPPLY
        PSE currently purchases a blended portfolio of gas supplies ranging from long-term firm to 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 serve its customers. All of PSE’s gas supply is ultimately transported through the facilities of Williams Northwest Pipeline Corporation (NWP), the sole interstate pipeline delivering directly into the Western Washington area.

        For baseload and peak-shaving purposes, PSE supplements its firm gas supply portfolio by purchasing natural 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-owned gas held in NWP’s liquefied natural gas (LNG) facility at Plymouth, Washington, by producing propane-air gas at a plant owned by PSE and located on its distribution 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 Dth per day 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 the replacement costs of the distillate fuel for such 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 2003-2004 winter heating season, PSE contracted for approximately 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 seasonal purchase agreements. Long-term gas supplies from Alberta represent approximately 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 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 NWP’s Plymouth facility and propane-air resources, which represent approximately 38.2%, 8.6% and 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 2003, approximately 35% of gas supplies purchased by PSE originated in British Columbia while 22% originated in Alberta and 43% originated in the United States. The current firm, long-term gas supply portfolio consists of arrangements with 22 producers and gas marketers, with no single supplier representing more than 12% of expected peak-day requirements. Contracts have remaining terms ranging from less than one year to eight years.
        PSE’s firm gas supply portfolio is structured to capitalize on regional price differentials when they 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 some 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 NWP, Gas Transmission Northwest and Duke Energy Gas 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 and WNG CAP I, a wholly-owned subsidiary of PSE, hold firm year-round capacity on NWP through various contracts. PSE and WNG CAP I participate in the secondary pipeline capacity market to achieve savings for PSE’s customers. As a result, PSE and WNG CAP I hold approximately 465,000 Dth per day 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 NWP have remaining terms ranging from less than 1 year to 13 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 Gas Transmission Northwest’s pipeline, totaling approximately 90,000 Dth per day, has a remaining term of 20 years. PSE’s firm transportation capacity on Duke Energy Gas Transmission’s pipeline, totaling approximately 40,000 Dth per day, has 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 contract obligations to PSE, which may include new pipeline construction or purchase of firm capacity from customers of NWP who have excess capacity. PSE does not expect the line to 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 NWP’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 NWP’s one-third stake in Jackson Prairie, PSE has peak firm delivery capacity of over 349,000 Dth per day and total firm storage capacity exceeding 7,900,000 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 also used for system reliability. After the release of capacity, PSE retains maximum firm withdrawal capacity of over 55,000 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 10 and 16 years. The capacity release contracts PSE has with multiple parties at the Clay Basin storage facility have remaining terms of 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 contract for storage of 241,700 Dth of PSE-owned gas as LNG at NWP’s Plymouth facility, which equates to approximately three and one-half days’ supply at a maximum daily deliverability of 70,500 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 NWP pipeline capacity not utilized during off-peak periods through capacity release. WNG CAP I 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-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 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 18 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 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 measures 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 to 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 processes 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. Consultation with federal agencies is ongoing.

EXECUTIVE OFFICERS OF THE REGISTRANTS
        The executive officers of Puget Energy as of January 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.

        The executive officers of Puget Sound Energy as of January 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.

ITEM 2. PROPERTIES

        The principal electric generating plants and underground gas storage facilities owned by PSE are described under Item 1, “Business – Electric Supply and Gas 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.
        InfrastruX operates a fleet of vehicles and equipment that it uses in its utility construction business. Its fleet is composed 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 Condition and Results of Operations.” 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.

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.” At December 31, 2003, there were approximately 43,200 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 2003 and 2002. Puget Energy and its predecessor companies have paid dividends on common stock each year since 1943 when such stock first became publicly held.

        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 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 $235.9 million at December 31, 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.

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 2003 was $121.3 million on operating revenues of $2.5 billion, compared to $117.9 million on operating revenues of $2.4 billion in 2002 and $106.8 million on operating revenues of $2.9 billion in 2001. Income for common stock was $116.2 million in 2003, compared to $110.1 million in 2002 and $98.4 million in 2001.
        Basic earnings per share in 2003 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 in 2002 and $1.14 on 86.4 million weighted average common shares outstanding in 2001. Diluted earnings per share were $1.22 on 95.3 million weighted average common shares outstanding compared to $1.24 on 88.8 million weighted average common shares outstanding in 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 $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 $10.3 million of federal tax refunds in 2002. Net income in 2002 was negatively impacted by a decrease in non-utility net income of $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 an $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 kWh energy sales to retail consumers in 2003 were 19.6 billion compared with 19.3 billion in 2002 and 19.9 billion in 2001. Kilowatt-hour sales to wholesale customers were 5.1 billion in 2003, 3.5 billion in 2002 and 5.0 billion in 2001. Kilowatt-hours transported to transportation customers were 2.0 billion in 2003, 2.3 billion in 2002 and 0.4 billion in 2001.
        Total gas sales to retail consumers in 2003 were 815.7 million therms compared with 839.6 million therms in 2002 and 850.4 million therms in 2001. Total gas sales to transportation customers in 2003 were 209.5 million therms compared to 207.9 million therms in 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.

        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:

        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:

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 electricity expenses 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 credits associated 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 gas expenses 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 fuel expense 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 instruments increased $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 settled 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 maintenance costs decreased $2.0 million 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’s Personal Energy Management^TM energy-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.
        The Low-Income Program approved 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 maintenance costs 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 amortization expense 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 amortization increased $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 taxes decreased $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 taxes increased $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
        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
        The table below sets forth changes in the results of operations for InfrastruX, net of minority interest.

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

INFRASTRUX
2003 COMPARED TO 2002
        InfrastruX revenue increased $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 maintenance expenses 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 amortization increased 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 taxes decreased $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 $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.
        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 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-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 and establishing a PCA mechanism in the rate case settlement. The mechanism will 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.

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.