Back to GetFilings.com

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

The following abbreviations or acronyms used in the text and notes to the financial statements are defined below:

Abbreviations or Acronyms

AFDC

Allowance For Funds Used During Construction

Bankruptcy Court

United States Bankruptcy Court For The Southern District

of New York

Beaver

Beaver Combustion Turbine Plant

Boardman

Boardman Coal Plant

BPA

Bonneville Power Administration

COBRA

Consolidated Omnibus Budget Reconciliation Act

Colstrip

Colstrip Units 3 and 4 Coal Plant

Coyote Springs

Coyote Springs Generation Plant

CUB

Citizens' Utility Board

DEQ

Oregon Department of Environmental Quality

Dth

Decatherm = 10 therms = 1,000 cubic feet of natural gas

EFSC

Energy Facility Siting Council

EITF

Emerging Issues Task Force of the Financial Accounting

Standards Board

Enron

Enron Corp., as Debtor and Debtor in Possession in Chapter

11, Case No. 01-16034 pending in the US Bankruptcy Court For The Southern District of New York

EPA

Environmental Protection Agency

ERISA

Employee Retirement Income Security Act of 1974

ESA

Endangered Species Act

FERC

Federal Energy Regulatory Commission

Financial Statements

Financial Statements of Portland General Electric Company

included in Part II, Item 8 of this report

IRS

Internal Revenue Service

kWh

Kilowatt-hour

MW

Megawatt

MWa

Average megawatts

MWh

Megawatt-hour

NRC

Nuclear Regulatory Commission

NW Natural

Northwest Natural Gas Company

NYMEX

New York Mercantile Exchange

OPUC or the Commission

Public Utility Commission of Oregon

PBGC

Pension Benefit Guaranty Corporation

PGE or the Company

Portland General Electric Company

PUHCA

Public Utility Holding Company Act of 1935

SEC

Securities and Exchange Commission

SFAS

Statement of Financial Accounting Standards issued by the

Financial Accounting Standards Board

Tribes

Confederated Tribes of the Warm Springs Reservation

of Oregon

Trojan

Trojan Nuclear Plant

URP

Utility Reform Project

USDOE

United States Department of Energy

VEBA

Voluntary Employee Beneficiary Association

WECC

Western Electricity Coordinating Council

Definitions 2

Item 1. Business 4

Item 2. Properties 18

Item 3. Legal Proceedings 21

Item 4. Submission of Matters to a Vote of Security Holders 25

Item 5. Market for Registrant's Common Equity and

Related Stockholder Matters 26

Item 6. Selected Financial Data 26

Item 7. Management's Discussion and Analysis of Financial

Condition and Results of Operations 27

Item 7A. Quantitative and Qualitative Disclosures About

Market Risk 66

Item 8. Financial Statements and Supplementary Data 69

Item 9. Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure 122

Item 9A. Controls and Procedures 123

Item 10. Directors and Executive Officers of the Registrant 124

Item 11. Executive Compensation 130

Item 12. Security Ownership of Certain Beneficial Owners

and Management 133

Item 13. Certain Relationships and Related Transactions 133

Item 14. Principal Accounting Fees and Services 134

Item 15. Exhibits, Financial Statement Schedules, and

Reports on Form 8-K 136

Signatures 138

PGE, incorporated in 1930, is a single integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. PGE also sells electricity and natural gas in the wholesale market to utilities and power marketers located throughout the western United States. PGE's service area is located entirely within Oregon and includes 51 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. PGE estimates that at the end of 2003 its service area population was approximately 1.5 million, comprising about 43% of the state's population. The Company added approximately 10,600 retail customers during 2003, and at December 31, 2003 served approximately 754,000 retail customers.

On July 2, 1997, Portland General Corporation (PGC), the former parent of PGE, merged with Enron Corp., with Enron continuing in existence as the surviving corporation and PGE operating as a wholly owned subsidiary of Enron.

On December 2, 2001, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. PGE was not included in the filing.

On November 18, 2003, Enron and Oregon Electric Utility Company, LLC (Oregon Electric), a newly-formed Oregon limited liability company financially backed by investment funds managed by Texas Pacific Group, entered into a definitive agreement under which Enron will sell all of the issued and outstanding common stock of PGE to Oregon Electric. The transaction, which was approved on February 5, 2004 by the Bankruptcy Court in Enron's Chapter 11 bankruptcy proceedings, requires approval of the OPUC, the FERC, and certain other regulatory agencies. For further information, see "Enron Bankruptcy" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

As of December 31, 2003, PGE had 2,687 employees. This compares to 2,757 and 2,790 employees at December 31, 2002 and 2001, respectively. A total of 890 employees are represented by Local Union No. 125 (Local 125) of the International Brotherhood of Electrical Workers. Seventeen employees at Coyote Springs are covered under an agreement effective from September 1, 2001 through August 1, 2006. The Company and Local 125 have reached agreement on a new five-year agreement covering the other 873 employees. The new agreement is subject to approval by a vote of the covered employees.

PGE serves a diverse retail customer base. Residential, the largest customer class, comprises about 88% of the Company's total number of customers, with the remainder comprised largely of commercial customers. At year-end 2003, PGE served 246 industrial customers. Residential demand is sensitive to the effects of weather, with revenues highest during the winter heating season. Commercial and industrial customer classes are not dominated by any single industry. While the 20 largest customers constitute about 20% of retail demand, they represent 9 different commercial and industrial groups, including paper manufacturing, high technology, metal fabrication, food merchandising, and health services. No single customer represents more than 3.9% of PGE's total retail load.

Total retail MWh energy sales decreased somewhat from 2002 due to a 10% decline in industrial sales, most of which was attributable to a single large customer which began generating its own power requirements in the second quarter of 2003. An increase in residential and commercial customers served in 2003 resulted in higher MWh energy sales, partially offsetting the decrease in industrial sales. Total retail revenue declined 10% from 2002 primarily as the result of a rate decrease (related to lower power costs) that became effective January 1, 2003 (see "Retail Rate Changes" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information).

Non-trading wholesale electricity sales related to activities to serve retail load requirements comprised about 22% and 21% of total operating revenues in 2003 and 2002, respectively. Non-trading wholesale revenues and energy sales for the fourth quarter of 2003 were reduced by approximately $90 million and 2,116 thousand MWhs, respectively, to reflect the October 1, 2003 adoption of Emerging Issues Task Force No. 03-11 (EITF 03-11), Reporting Gains and Losses on Derivative Instruments That are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes. EITF 03-11 requires that realized gains and losses associated with non-trading derivative activities that are not physically settled be reported on a net basis. Accordingly, such activities, formerly recorded on a "gross" basis in both Operating Revenues and Purchased Power and Fuel expense, are now recorded on a "net" basis in Purchased Power and Fuel expense. Prior period amounts have not been reclassified. See New Accounting Standards in Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements.

Most of PGE's non-trading wholesale sales have been to utilities and power marketers and have been predominantly short-term. PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such participation includes power purchases and sales resulting from daily economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions are also referred to as "book outs". Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations are physically settled.

Other operating revenues include net gains and losses from PGE's participation in energy trading activities in electricity, natural gas, and crude oil markets. Such activities are not reflected in the Company's retail rates. Also included are sales of natural gas in excess of generating plant requirements, and revenues from transmission services, pole contact rentals, and certain other electric services to customers.

The following table summarizes total Operating Revenues and Energy Sales for the year ended December 31:

For additional information on year-to-year revenue trends, see Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

PGE is subject to the jurisdiction of the OPUC, comprised of three members appointed by Oregon's governor to serve non-concurrent four-year terms. The Commission approves the Company's retail rates and establishes conditions of utility service. The OPUC ensures that the prices and terms of service are fair, non-discriminatory, and provide PGE an opportunity to earn a fair return on its investment. In addition, the Commission regulates the issuance of stock and long-term debt, prescribes the system of accounts to be kept by Oregon utilities, and reviews applications to sell utility assets and engage in transactions with affiliated companies.

Certain activities of PGE are also subject to the jurisdiction of the FERC. The Company is a "licensee" and a "public utility", as those terms are used in the Federal Power Act, and is subject to regulation by the FERC as to accounting policies and practices, licensing of hydroelectric projects, transmission services, wholesale sales, issuance of short-term debt, and other matters. In addition, PGE's interest in a natural gas pipeline is subject to the FERC's jurisdiction. Under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, the FERC's authority includes matters related to extension, enlargement, and abandonment of jurisdictional pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce.

Construction of new thermal generating facilities requires a permit from the EFSC.

The NRC regulates the licensing and decommissioning of nuclear power plants. In 1993, the NRC issued a possession-only license amendment to PGE's Trojan operating license and in early 1996 approved the Trojan Decommissioning Plan. Approval of the Trojan Decommissioning Plan by the NRC and EFSC has allowed PGE to begin decommissioning activities. In 2001, the NRC approved PGE's License Termination Plan (LTP). The LTP outlines the process by which PGE will complete the decommissioning of the Trojan site and meet regulatory requirements for decommissioned nuclear facilities. The NRC approved the completed transfer of spent nuclear fuel from the Trojan spent fuel pool to a separately licensed dry cask storage system to house the nuclear fuel until permanent storage is available. Trojan is subject to NRC regulation until it is fully decommissioned, all nuclear fuel is removed from the site, decontamination is completed, and NRC licenses are terminated. The Oregon Department of Energy also monit ors Trojan. For further information, see "Nuclear Decommissioning" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 12, Trojan Nuclear Plant, in the Notes to Financial Statements.

All of the common stock of PGE is owned by Enron. As the owner of PGE's common stock, Enron is a holding company for purposes of the Public Utility Holding Company Act of 1935 (PUHCA). Following Enron's acquisition of PGE in 1997, Enron annually filed for an exemption from all provisions of PUHCA (except Section 9(a)(2) thereof) under Section 3(a)(1), in accordance with Rule 2 promulgated thereunder. Due to Enron's bankruptcy filing in December 2001, Enron is no longer able to provide necessary financial information needed to file under Rule 2. As a result, in February 2002, Enron filed an application seeking exemption under Section 3(a)(1). To be eligible for the Section 3(a)(1) exemption, it is necessary, among other things, that PGE's utility activities be predominantly intrastate in character.

The SEC issued an order on December 29, 2003, denying Enron's exemption application under Section 3(a)(1) of PUHCA, holding that PGE's utility activities were not predominantly and substantially intrastate in character. On December 31, 2003, Enron filed an application for an exemption as a public utility holding company under Section 3(a)(4) of PUHCA, based on the temporary nature of the applicants' interest in PGE under the Chapter 11 plan filed by Enron and certain of its subsidiaries. The hearing scheduled on the Section 3(a)(4) application was postponed to consider a settlement offer proposed by Enron. In accordance with the settlement offer, on March 9, 2004, Enron registered as a holding company under PUHCA. Immediately after Enron registered, the SEC issued two orders, one granting Enron and its subsidiaries authority to undertake certain transactions without further authorization from the SEC under PUHCA (the "Omnibus Order") and the other approving Enron's Fifth Amended Bankruptcy Plan, except the sale of PGE to Oregon Electric, which sale will require additional approval from the SEC. On the same day, Enron withdrew the Section 3(a)(4) application.

The Omnibus Order authorizes, among other items, certain transactions specific to PGE and its subsidiaries, including authority for PGE to issue certain short-term debt. In addition, the Omnibus Order authorizes PGE to continue providing cash management services to its subsidiaries and participate in certain transactions among associate companies within Enron's registered holding company system. The authorizations are effective until the earlier of the deregistration of Enron under PUHCA or July 31, 2005. The authority granted to PGE and its subsidiaries in the Omnibus Order minimizes the likelihood that PGE's business will be adversely impacted by Enron's registration under PUHCA.

However, PUHCA imposes a number of restrictions on the operations of a registered holding company and its subsidiaries within the registered holding company system. As a subsidiary of a registered holding company, PGE is subject to regulation by the SEC with respect to the acquisition of the securities of other public utilities; the acquisition of assets and interests in any other business; the declaration and payment of certain cash distributions; intra-system borrowings or indemnifications; sales, services or construction transactions with other holding company system companies; and the issuance of debt or equity securities, among other matters. To the extent those regulated activities are not approved under the Omnibus Order or otherwise exempt under various rules and the regulations promulgated under PUHCA, PGE would be required to seek additional approvals from the SEC.

PGE does not believe that becoming a subsidiary of a registered holding company will have a material adverse affect on its financial condition, results of operations, or cash flows. However, the finding in the SEC's December 29, 2003 order that PGE is not an intrastate utility could make it more difficult for any future owner of PGE to obtain a Section 3(a)(1) exemption from PUHCA.

The electric power industry continues to experience change. The impetus for this change is public, regulatory, and governmental support for replacing the traditional cost-of-service regulatory framework with a market system under which customers have a choice of energy supplier. Federal laws and regulations now provide for open access to transmission systems. Several states, including Oregon, have adopted or are considering new regulations to allow direct access to retail energy suppliers.

Oregon's electricity restructuring law was implemented on March 1, 2002. It provides all commercial and industrial customers of investor-owned utilities direct access to competing Energy Service Suppliers (ESS) as well as cost-of-service and market price options. Residential and small commercial and industrial customers can purchase electricity from a "portfolio" of rate options that include a basic service rate, a time-of-use rate, and renewable resource rates. The law also requires that investor-owned utilities unbundle and separately identify the costs of electric service on a functional basis, including energy resources, delivery, and other services. It further provides for a "transition adjustment" for non-residential customers that choose to purchase energy at market rates from investor-owned utilities or from electricity service suppliers. Such charges or credits reflect the above-market or below-market cost, respectively, of energy resources owned or purchased by the utility an d are designed to ensure that such costs or benefits do not unfairly shift to the utility's remaining energy customers.

The law also provides for a 10-year Public Purpose Charge, equal to 3% of retail revenues, designed to fund cost-effective conservation measures, new renewable energy resources, and weatherization measures for low-income housing (see "Energy Efficiency" in this section for further information). In addition, the law provides for low-income electric bill assistance.

Early results indicate a measured response to Oregon's electricity restructuring law. There are four ESS's registered to transact business with PGE in 2004, with two currently serving a total of seven customers (119 separate accounts) with an average load of approximately 86 MW. No customers were served by ESS's in 2003. A total of 66 commercial and industrial customers (approximately 100 separate accounts) received service from PGE under market-based pricing options in 2003. The Company has also offered an option under which certain large nonresidential customers may, for a minimum five-year term, elect to be removed from cost of service pricing, with energy supplied at a daily market rate or by an ESS; four customer accounts have chosen this option. Approximately 27,000 customers have chosen renewable energy options and approximately 1,600 customers have chosen the time of use option.

In accordance with the law and an order from the OPUC, PGE is deferring certain costs related to implementation of the restructuring plan for recovery in electricity rates. Recovery of these costs has begun, with unrecovered costs totaling approximately $23 million at December 31, 2003. The OPUC staff conducted an audit and prudency review of such costs and issued a report finding them to be prudently incurred.

PGE continues to operate as a cost-based regulated electric utility, for which revenue requirements are determined based upon the cost to serve customers, including an appropriate rate of return to the Company, and remains obligated to provide full ("bundled") service to all of its customers. PGE's 2001 general rate filing with the OPUC was based upon this cost-of-service model. At this time, the large majority of PGE's customers continue to be served under rate tariff schedules determined by the cost of service.

While PGE continues to meet the criteria of SFAS No. 71 and currently applies its provisions to reflect the effects of rate regulation in its financial statements, the Company periodically assesses the applicability of the statement to its business, or separable portions thereof. These assessments consider both the current and anticipated future rate environment and related accounting guidance, as outlined in SFAS No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS No. 71, and EITF Issue 97-4, Deregulation of the Pricing of Electricity - Issues Related to the Application of SFAS No. 71 and SFAS No. 101.

The Energy Policy Act of 1992 (Energy Act) enabled changes in federal regulations to increase wholesale competition in the electric industry. The Energy Act eased restrictions on independent power production and granted authority to the FERC to mandate open access for the wholesale transmission of electricity.

The FERC has taken steps to provide a framework for increased competition in the electric industry. In 1996, the FERC issued Order 888 requiring non-discriminatory open access transmission by all public utilities that own interstate transmission. The final rule requires utilities to file tariffs that offer others the same transmission services they provide themselves under comparable terms and conditions. This rule also allows public utilities to recover stranded costs in accordance with the terms, conditions and procedures set forth in Order 888. The ruling requires reciprocity from municipals, cooperatives and federal power marketers receiving service under the tariff. The new rules became effective in July 1996 and have resulted in increased competition and more choices to wholesale energy customers. Other FERC policies allow qualifying entities to sell power at rates based on the market, rather than cost.

Restructuring of the electric industry has slowed at the federal level. Congressional committee hearings are expected to continue, although there remains considerable uncertainty regarding their ultimate outcome. PGE continues to formulate strategies to meet the challenges of wholesale competition.

Pursuant to PGE's 2001 general rate filing, the OPUC authorized retail price increases, effective October 1, 2001. The Commission also approved a power cost adjustment mechanism covering the period October 2001 through December 2002. As actual power costs during this period exceeded those costs used in rate determination, the power cost adjustment mechanism allowed the Company to defer for later recovery from retail customers actual net variable power costs in excess of certain baseline amounts. Pursuant to PGE's updated 2003 power cost forecast that estimated a reduction in power costs utilized in the Company's 2001 general rate filing, the OPUC authorized reductions in the Company's retail prices, effective January 1, 2003. PGE did not have a power cost adjustment mechanism in place for 2003.

For further information, see "Retail Rate Changes" and "Power Cost Adjustment Mechanisms" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

PGE filed an Integrated Resource Plan (IRP) with the OPUC in 2002, with a supplement filed in February 2003. The IRP describes the Company's strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. It details resource actions over the next two to three years that provide for reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. The IRP also addresses future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, longer-term power purchases, the use of seasonal exchanges to meet peaking requirements, demand-side management, and capacity tolling contracts.

In June 2003, following approval by the OPUC, PGE issued a request for proposals (RFP) to prospective suppliers (including power generators, wholesalers, and developers) to acquire resources to meet the electricity needs of its customers. In January 2004, PGE filed a Proposed Action Plan with the Commission on how to best meet its customers' future power supply requirements, beginning as early as 2006. PGE's recommendations to acquire 635 average MW in mid-term and long-term resources include three primary components: 1) construction of a natural gas-fired power plant at its Port Westward site in Columbia County, producing 240 or 350 average MW (depending on technology selected), beginning in late 2006; 2) acquisition of up to 65 average MW (195 MW capacity) of wind generation; and 3) acquisition of up to 300 average MW in gas tolling and fixed price power purchase agreements with durations of 5 to 10 years. In addition to the increased capacity resulting from these recommendations, the Proposed Action Plan includes approximately 485 MW of additional capacity from plant upgrades, extension of a current contract with the Tribes to 2012, standby generation, and peak tolling and seasonal exchange agreements.

PGE has consistently promoted the efficient use of electricity. Prior to the March 1, 2002 enactment of Oregon's electricity restructuring law, PGE utilized Demand Side Management programs to provide a range of energy efficiency services to all customer classes. Since the restructuring law's enactment, PGE has promoted energy efficiency through information tips on its web site, newsletters to customers, and information provided by customer service representatives and account managers. PGE also refers customers to the Energy Trust of Oregon (see below) for conservation and energy efficiency services.

Beginning March 1, 2002, as provided by Oregon's electricity restructuring law, PGE began collecting a 3% Public Purpose Charge from retail customers to fund cost-effective conservation measures, renewable energy resources, school district conservation, and weatherization measures for low-income housing. Amounts collected are distributed monthly to organizations responsible for the administration of these programs. The Energy Trust of Oregon, a non-profit organization, administers the conservation and renewable resources portions of the public purpose funds, contracting with PGE and other companies to provide energy conservation and efficiency services to customers.

In 1999, the FERC issued Order No. 2000 in a continued effort to more efficiently manage transmission, create fair pricing policies, and encourage competition by providing equal access to the nation's electric power grids. The order requires all owners of electricity transmission facilities to file a proposal to join a Regional Transmission Organization (RTO) or, alternatively, to file an explanation of reasons preventing them from making such filing. In response to this order, BPA and nine western utilities, including PGE, filed an initial proposal with the FERC to form RTO West, a regional non-profit transmission organization that would operate the transmission system and manage pricing in the Pacific Northwest, Nevada, and small portions of California and Wyoming.

In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) to standardize the structure and operation of competitive wholesale markets. If the NOPR is implemented as proposed, it will significantly change how wholesale energy and transmission markets operate. Wholesale companies and retail load serving companies would use a single network transmission tariff, and operational control of the transmission network would be administered by the RTO.

In September 2002, the formation plan of RTO West received preliminary approval of the FERC, with some modification and further development of certain details. In its approval ruling, the FERC stated that the RTO West proposal would satisfy Order No. 2000 requirements and provide a basic framework for an SMD for the West. Also in September 2002, the FERC granted preliminary approval of a proposed structure for TransConnect, a new company proposed by PGE and two other regional utilities, that would own or lease the high-voltage transmission facilities currently held by PGE and its other participants. As proposed, TransConnect would be an independent, jointly owned, for-profit transmission company that would participate in RTO West. Combining transmission resources into one independent entity could create new opportunities to attract capital for system improvements and expansion while improving transmission infrastructure and reducing regional transmission constraints.

In April 2003, the FERC outlined intended changes to its proposed rule on SMD. The proposed changes provide for a "phased-in" implementation schedule specific to each region and market power mitigation and monitoring requirements.

Decisions regarding the formation of RTO West and TransConnect will ultimately depend on the conditions imposed during the regulatory approval process, as well as economic considerations. Such decisions will be subject to approvals by state and federal agencies and individual company boards of directors.

Restructuring of the electric industry has slowed at both the national level and in the Pacific Northwest. PGE continues to maintain its commitment to service excellence while accommodating the formation of a competitive electricity market in Oregon.

PGE conducts retail electric operations exclusively in Oregon within a state-approved service area. Competitors within the Company's service territory include the local natural gas company, which competes for the residential and commercial space and water heating market, and fuel oil suppliers that compete primarily for residential space heating customers. In addition, effective March 1, 2002, commercial and industrial customers are allowed direct access to competing electricity service suppliers in accordance with Oregon's electricity restructuring law, related regulations, and PGE's tariff. PGE currently offers eligible customers regulated cost of service and market-based prices. The Company does not operate as an electricity service supplier.

The amount of surplus electric generating capability in the western United States, the amount of annual snow pack and its impact on hydro generation, the number and credit quality of wholesale marketers and brokers participating in the energy trading markets, the availability and price of natural gas as well as other fuels, and the availability and pricing of electric and gas transmission all contributed to and have an impact on the wholesale price and availability of electricity. PGE will continue its participation in the wholesale energy marketplace in order to manage its power supply risks and acquire the necessary electricity and fuel to meet the needs of its retail customers and administer its current long-term wholesale contracts. In addition, the Company will continue its trading activities to participate in electricity, natural gas, and crude oil markets. Although PGE has authority under its FERC tariff to charge market-based rates for wholesale energy sales, the Company is operating under a cost-based cap through December 18, 2004, under terms of a 2003 settlement agreement between PGE, the FERC, and other parties (for further information, see Item 3. - Legal Proceedings).

PGE's transmission system connects winter-peaking utilities in the Northwest and Canada, which have access to lower variable cost hydroelectric generation, with summer-peaking wholesale customers in California and the Southwest, which have higher variable cost fossil fuel generation. PGE uses this system to purchase and sell in both markets depending upon the relative price and availability of power, water conditions, and seasonal demand from each market.

In addition to the potential loss of energy related revenues from those commercial and industrial customers that may choose to purchase energy directly from competing energy suppliers, there is the potential for the loss of service territory from the creation of people's utility districts or municipal utilities in PGE's service territory. Public ownership of PGE is currently being pursued by certain parties. For additional information, see "Public Ownership Initiatives" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

To meet its customers' energy needs, PGE relies upon its existing base of generating resources, long-term power contracts, and short-term purchases that together provide flexibility to respond to consumption changes and Oregon's electricity restructuring law. Short-term purchases include both spot and firm purchases for periods of less than one year in duration.

Northwest hydro conditions have a significant impact on the region's power supply, with water conditions significantly impacting PGE's cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases. Current forecasts indicate continued below-normal hydro conditions in 2004. In addition, natural gas, used to fuel the Company's combustion turbine plants, is subject to price volatility. PGE continues to monitor its exposure to natural gas.

For further information, see "Power and Fuel Supply" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

PGE's existing hydroelectric, coal-fired, and gas-fired plants are important resources for the Company, providing 1,957 MW of generating capability (see Item 2. - "Properties" for a full listing of PGE's generating facilities). PGE's lowest-cost producers are its five FERC licensed hydroelectric projects incorporating eight powerhouses on the Clackamas, Sandy, Deschutes, and Willamette rivers in Oregon. These facilities operate under federal licenses, which will be up for renewal through 2006. PGE will not relicense its Bull Run hydroelectric project on the Sandy River.

PGE's Proposed Action Plan, filed with the OPUC in January 2004 pursuant to the Integrated Resource Plan process, proposes construction of a new natural gas-fired power plant at the Company's Port Westward site in Columbia County, Oregon, adjacent to the existing Beaver plant site. PGE has obtained all necessary permits required to construct a two-unit combined cycle combustion turbine facility with up to 650 MW of production capacity. In consideration of other resource strategies outlined in its Proposed Action Plan, the Company has recommended construction of a single unit natural gas-fired power plant producing 240 or 350 average MW (depending on technology selected), with the unit placed in service in late 2006.

In 2001, PGE terminated its plans for a 49 MW combustion turbine facility located on leased property at Port of Morrow, Oregon, due to both reduced demand and lower power prices. The Company is currently marketing the gas turbine unit purchased for this facility.

PGE supplements its own generation with long-term and short-term contracts as needed to meet its retail load requirements or provide the most economic mix of resources on a variable cost basis. The Company has long-term power contracts with four hydroelectric projects on the mid-Columbia River, which provide approximately 510 MW of firm capacity. PGE also has firm contracts, ranging from one to twenty-five years, to purchase 740 MW of power from BPA, other Pacific Northwest utilities, and the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). In addition, PGE has an exchange contract with a summer-peaking California utility to help meet the Company's winter-peaking requirements, and an exchange contract with a Northwest utility to help meet the Company's summer-peaking requirements. These resources, along with short-term contracts, provide the Company with sufficient firm capacity to serve its peak loads. For further information, see "Power and Fuel Supply" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

System Reliability and the WECC

PGE relies on wholesale market purchases within the WECC in conjunction with its base of generating resources to supply its resource needs and maintain system reliability. The WECC is the largest and most diverse of the 10 regional electric reliability councils. It provides coordination for operating and planning a reliable and adequate electric power system for the western continental United States, Canada, and Mexico. It further supports competitive power markets, helps assure open and non-discriminatory transmission access among members, provides a forum for resolving transmission access disputes, and provides an environment for coordinating the operating and planning activities of its 156 members. The WECC area, which extends from Canada to Mexico and includes 14 western states, has great diversity in climate and peak loads that occur at different times of the year. Energy loads in California and the Southwest peak in the summer due to air conditioning use, while northern loads peak during winter heating months. According to WECC forecasts, its members, which serve about 71 million people, will have sufficient capacity margin to meet forecast demand and energy requirements through the year 2013, assuming the timely completion of planned new generation.

PGE's peak load in 2003 was 3,351 MW, of which approximately 44% was met through short-term purchases. At December 31, 2003, PGE's total firm resource capacity, including short-term purchase agreements, was approximately 3,883 MW (net of short-term sales agreements of 3,910 MW).

The Pacific Northwest peak season continues to be in winter months, when home and business heating and lighting cause the highest demand. PGE's all-time peak of 4,073 MW occurred in December 1998.

Populations of many salmon species in the Pacific Northwest have shown significant decline over the last several decades. A significant number of these species have either been granted, or are being evaluated for, protection under the federal Endangered Species Act (ESA), which was initially enacted in 1966. Passage of the ESA, and the subsequent listing of various species of fish, wildlife, and plants as threatened or endangered species, has resulted in potentially significant changes to federally-authorized activities, such as hydroelectric project operations, and to potential civil or criminal liability for unauthorized "take" of listed species. Long-term recovery plans for these species may include major operational changes to the region's hydroelectric projects, including PGE's, with potentially significant impacts. The biggest change thus far has been a modification in the timing of stored water releases from dams located in the upper parts of the Columbia River and Snake Riv er basins.

PGE continues to evaluate the impact of current and potential ESA listings on the operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette rivers. The Company's consultation with the National Oceanographic and Atmospheric Administration and the United States Fish and Wildlife Service (USFWS) has identified opportunities for the protection of fish runs on those rivers where PGE operates. The agencies have completed an ESA consultation on the Company's Pelton Round Butte Project (Deschutes River) and Willamette Falls Project (Willamette River), which will be in effect until new licenses are granted by the FERC. In 2003, the Company received the biological opinion for the Bull Run Project (Sandy River) which will cover the project's operations and decommissioning. Completion of ESA consultation by the National Marine Fisheries Service, the FERC, and USFWS is required to obtain a FERC license or license amendment for hydroelectric projects, and provides author ization for take of listed species consistent with the terms and conditions identified through the consultation.

PGE acquires fuel supply contracts to support planned operation of thermal generating plants. Flexibility in contract terms allows for the most economic dispatch of PGE's thermal resources relative to the market price of wholesale power.

PGE negotiates agreements each year to purchase coal for Boardman in the following calendar year, and currently has agreements that cover the plant's requirements through 2004. Available coal supplies are sufficient to meet future requirements of the plant. The coal, obtained from surface mining operations in Wyoming and Montana and subject to federal, state, and local regulations, is delivered by rail under two separate 10-year contracts, the terms of which began January 1, 2004. Coal purchases in 2003, totaling about 2.6 million tons, contained approximately 0.3% of sulfur by weight. Utilizing electrostatic precipitators, the plant emitted less than the EPA-allowed limit of 1.2 pounds of sulfur dioxide per MMBtu.

Coal for Colstrip Units 3 and 4, located in southeastern Montana, is obtained from an adjacent mine under a contract that provides for coal to not exceed a maximum sulfur content of 1.5% by weight. Utilizing wet scrubbers to minimize sulfur dioxide emissions, the plant operated in compliance with EPA's source-performance standards.

PGE makes long-term, short-term, and spot market purchases to secure transportation capacity and short-term and spot market purchases to secure natural gas supplies sufficient to fuel plant operations. PGE re-markets natural gas and transportation capacity in excess of its needs.

PGE owns 79% of the Kelso-Beaver Pipeline, which directly connects its Beaver generating station to Northwest Pipeline, an interstate gas pipeline operating between British Columbia and New Mexico. In 2003, PGE was granted a blanket transportation certificate by the FERC that authorizes the Company to transport natural gas for others under a Part 284 blanket transportation certificate. Currently, PGE transports gas for its own use under a firm transportation service agreement for all of its pipeline capacity, with capacity offered on an interruptible basis to the extent not utilized by the Company.

Firm gas supplies for Beaver, based on anticipated operation of the plant, are typically purchased up to 24 months in advance. PGE has access to 76,000 Dth/day of firm transportation capacity, sufficient to operate Beaver at a 70% load factor. In addition, PGE has contractual access, through October 2004, to natural gas storage in Mist, Oregon, from which it can draw natural gas in the event the plant's supply is interrupted or if economic factors indicate its use. The Company also has contractual access, through November 2005, to 20,000 Dth/day of transportation capacity from a pipeline connection to a natural gas production area in British Columbia, Canada. PGE believes that sufficient market supplies of gas are available to fully meet anticipated requirements of the plant in 2004.

The Coyote Springs generating station utilizes 41,000 Dth/day of firm transportation capacity on three interconnecting pipeline systems accessing gas fields in Alberta, Canada. Firm gas supplies for Coyote Springs, based on anticipated operation of the plant, are typically purchased up to 24 months in advance. PGE believes that sufficient market supplies of gas are available to fully meet requirements of the plant in 2004.

The Beaver generating station has the capability to operate at full capacity on No. 2 diesel fuel oil when it is economic or if the plant's natural gas supply is interrupted. To ensure the plant's continued operability under such circumstances, PGE had an approximate 15-day supply of oil at the plant site at December 31, 2003.

The Coyote Springs plant has the capability to operate on oil if needed, with sufficient fuel maintained on-site to run the plant for 40-50 hours.

PGE operates in a state recognized for environmental leadership. The Company's policy of environmental stewardship emphasizes minimizing both waste and environmental risk in its operations, along with promoting the wise use of energy.

PGE's operations are subject to a wide range of environmental protection laws covering air and water quality, noise, waste disposal, and other environmental issues. The EPA regulates the proper use, transportation, cleanup and disposal of polychlorinated biphenyls (PCBs). State agencies or departments, which have direct jurisdiction over environmental matters, include the Environmental Quality Commission, the DEQ, the Oregon Office of Energy, and the EFSC. Environmental matters regulated by these agencies include the siting and operation of generating facilities and the accumulation, cleanup, and disposal of toxic and hazardous wastes.

A 1997 investigation of a portion of the Willamette River known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor. Subsequently, the EPA has included Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund). In December 2000, PGE, along with sixty-eight other companies on the Portland Harbor Initial General Notice List, received a "Notice of Potential Liability" with respect to the Portland Harbor Superfund Site. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the potential liability of responsible companies, including PGE. Management believes that the Company's contribution to the sediment contamination, if any, would qualify it as a de minimis Potentially Responsible Party.

For further information, see "Environmental Matters" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund Site.

PGE's operations, principally its fossil-fuel electric generation plants, are subject to the federal Clean Air Act (Act) and other federal regulatory requirements. State governments also monitor and administer certain portions of the Act and must set guidelines that are at least equal to federal standards; Oregon's air quality standards exceed federal standards. Primary pollutants addressed by the Act that affect PGE are sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon monoxide (CO), and particulate matter. PGE manages its emissions by the use of low sulfur fuel, emission controls, emission monitoring, and combustion controls.

The SO₂ emissions allowances awarded under the Act, along with expected future annual allowances, are sufficient to operate Boardman at a 60% to 67% capacity without emissions reductions. PGE has acquired additional emissions allowances to operate the Boardman plant at forecasted capacity through mid-2007 without the need to purchase additional emissions allowances. In addition, current emissions allowances are sufficient to operate Colstrip, which utilizes wet scrubbers. It is not yet known what impacts federal regulations on mercury transport, regional haze, or particulate matter standards may have on future plant operations, operating costs, or generating capacity.

Federal operating air permits, issued by DEQ, have been obtained for all of PGE's thermal generating facilities.

PGE's principal plants and appurtenant generating facilities and storage reservoirs are situated on land owned by the Company in fee or land under the control of PGE pursuant to existing leases, federal or state licenses, easements, or other agreements. In some cases, meters and transformers are located on customer property. The Indenture securing PGE's First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property. PGE's service territory and generating facilities are indicated on the map below:

The following are generating facilities owned by PGE:

PGE holds licenses under the Federal Power Act for its hydroelectric generating plants, as well as licenses from the State of Oregon for all or portions of the five projects. The Company filed a 30-year license application with the FERC in December 2002 for its 16 MW Willamette River project, the current license for which expires on December 31, 2004. In 2003, the Company and participants in the relicensing process completed a settlement process that resulted in an agreement that was filed with the FERC in January 2004. The agreement includes several improvements to assist downstream passage of juvenile fish, reduce maintenance costs, and enhance production capacity through the replacement of most of the plant's turbines. The federal agencies responsible for salmon protection and ESA issues were participants in the settlement process. A decision from the FERC is expected by the end of 2004.

The license for the Clackamas River projects expires in 2006, and PGE will file a license application with the FERC in 2004.

The license for the Pelton Round Butte project expired at the end of 2001. In June 2001, PGE and the Tribes jointly filed a 50-year license application, which is pending with the FERC. The project has been operating on annual licenses since the license expired. Participants in the relicensing process will continue settlement discussions in 2004 to seek agreement on the terms and conditions of the new license.

It is anticipated that mandatory conditions, including facility modifications and operational changes, will be imposed on PGE's hydroelectric projects during the relicensing process to improve the passage, and enhance the survival, of adult and juvenile salmon.

In October 2002, PGE entered into an agreement with state and federal agencies, conservation groups, and others regarding removal of the Company's 22 MW Bull Run hydroelectric project located in the Sandy River basin, including the Marmot and Little Sandy Dams. The agreement also provides for the protection of threatened fish species and the transfer of 1,500 acres of PGE-owned land to a nonprofit organization toward the creation of a 5,000-acre wildlife and public recreation area. The agreement provides for the removal of the Marmot Dam in 2007 and the Little Sandy Dam in 2008. PGE has requested that the existing license, which expires in November 2004, be extended to allow the project to operate until the removal of Little Sandy Dam. The FERC is expected to issue its amended license and surrender order in 2004. PGE's current rates include recovery of its remaining plant investment through the end of the project's existing license period and recovery, over a ten-year period beginning Octo ber 2001, of about $16 million in estimated decommissioning costs.

PGE owns transmission lines that deliver electricity from its Oregon plants to its distribution system in its service territory and also to the Northwest grid. The Company also has ownership in, and contractual access to, transmission lines that deliver electricity from the Colstrip plant in Montana to PGE. In addition, PGE owns approximately 16% of the Pacific Northwest Intertie, a 4,800 MW transmission facility between John Day, in northern Oregon, and Malin, in southern Oregon near the California border. This line is used primarily for interstate purchases and sales of electricity among utilities, including PGE.

The rated generating capabilities of both Faraday and Round Butte were reduced by 2 MW based upon measurement testing completed during 2003. The generating capability at Beaver increased 16 MW due to improved efficiency resulting from evaporator re-tubing and replacement of economizer heat exchangers on the heat recovery steam generators.

PGE leases its Portland headquarters complex and the coal-handling facilities at the Boardman plant.

Following the closing of the Trojan Nuclear Plant, PGE, in its 1993 general rate filing, sought OPUC approval to recover through rates future decommissioning costs and full recovery of, and a rate of return on, its Trojan investment. PGE's request was challenged and PGE requested from the OPUC a Declaratory Ruling (Docket DR 10) regarding recovery of the Trojan investment and decommissioning costs. In August 1993, the OPUC issued a Declaratory Ruling in PGE's favor, citing an opinion issued by the Oregon Department of Justice (Attorney General) that current law gave the OPUC authority to allow recovery of, and a return on, its Trojan investment and future decommissioning costs. The Declaratory Ruling was appealed to the Marion County Circuit Court, which upheld the OPUC in November 1994. The Citizens' Utility Board (CUB) appealed the decision to the Oregon Court of Appeals.

In PGE's 1995 general rate case (Docket UE 88), the OPUC issued an order (1995 Order) granting PGE full recovery of Trojan decommissioning costs and 87% of its remaining undepreciated investment in the plant. The Utility Reform Project (URP) filed an appeal of the 1995 Order to the Marion County Circuit Court, alleging that the OPUC lacked authority to allow PGE to recover Trojan costs through its rates. The CUB also filed an appeal to the Marion County Circuit Court challenging the portion of the 1995 Order that authorized PGE to recover a return on its remaining undepreciated investment in Trojan.

In April 1996, the Marion County Circuit Court issued a decision that contradicted the Court's November 1994 ruling. The 1996 decision found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan. The 1996 decision was appealed to the Oregon Court of Appeals, where it was consolidated with the earlier appeal of the 1994 decision.

In June 1998, the Oregon Court of Appeals ruled that the OPUC does not have the authority to allow PGE to recover a rate of return on its undepreciated investment in Trojan, but upheld the OPUC's authority to allow PGE's recovery of its undepreciated investment in Trojan and its costs to decommission Trojan (1998 Decision). The court remanded the matter to the OPUC for reconsideration of its 1995 Order in light of the court's decision.

In August 1998, PGE filed a Petition for Review with the Oregon Supreme Court seeking review of that portion of the 1998 Decision relating to PGE's return on its undepreciated investment in Trojan. The URP filed a Petition for Review with the Oregon Supreme Court seeking review of that portion of the 1998 Decision relating to PGE's recovery of its undepreciated investment in Trojan.

In September 2000, PGE, CUB, and the OPUC Staff settled proceedings related to PGE's recovery of its investment in the Trojan plant (Settlement). The URP did not participate in the Settlement and filed a complaint and requested a hearing with the OPUC, challenging PGE's application for approval of the accounting and ratemaking elements of the Settlement.

In March 2002, after a full contested case hearing (Docket UM 989), the OPUC issued an order (Settlement Order) denying all of URP's challenges and approving PGE's application for the accounting and ratemaking elements of the Settlement. URP appealed the Settlement Order to the Marion County Circuit Court.

On November 19, 2002, the Oregon Supreme Court dismissed PGE's and URP's Petitions for Review of the 1998 Decision. As a result, the 1998 Decision stands and the remand of the 1995 Order to the OPUC became effective.

In regards to the URP's appeal of the March 2002 Settlement Order, on November 7, 2003, the Marion County Circuit Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. On February 9, 2004, PGE appealed this opinion to the Oregon Court of Appeals. The OPUC has also appealed.

On March 3, 2004, the OPUC reopened Dockets DR 10, UE 88, and UM 989 and issued a notice of a consolidated procedural conference before an administrative law judge to determine what proceedings are necessary to comply with the Court of Appeals and Marion County Circuit Court orders remanding this matter to the OPUC.

On January 17, 2003, two class action suits were filed in Marion County Circuit Court against PGE on behalf of two classes of electric service customers. The Dreyer case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the Morgan case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers.

On March 24, 2003, PGE was served with two class action suits in Multnomah County Circuit Court, identical to the Marion County cases. On October 24, 2003, the Multnomah County suits were dismissed.

On December 24, 2001, numerous individuals, businesses, and California cities, counties, and other governmental entities filed a consolidated Master Complaint in their class action law suits (Wholesale Electricity Antitrust Cases) in California state court against various individuals, utilities, generators, traders, and other entities, including Duke Energy Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke Parties), and Reliant Energy Services, Inc., Reliant Ormond Beach, Inc., Reliant Energy Etiwanda, Inc., Reliant Energy Ellwood, Inc., Reliant Energy Mandalay, Inc., and Reliant Energy Coolwater, Inc. (Reliant Parties), alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest, and penalties.

On April 23, 2002, the Duke Parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases (Cross-defendants), alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. The Reliant Parties have filed a similar cross complaint against PGE and the other Cross-defendants. The cases were removed to Federal Court by certain parties. The Duke Parties, Reliant Parties, and Cross-defendants have stipulated to place the cross complaints in abeyance until 30 days after a ruling on their motions to dismiss the Master Complaint by either the California state courts or the fe deral courts.

On December 13, 2002, the United States District Court signed an order granting the plaintiff's motions to remand the cases to the California state court. The Duke and Reliant Parties filed an appeal to the United States Ninth Circuit Court of Appeals. On February 20, 2003, the United States Court of Appeals for the Ninth Circuit issued an Order deciding it had jurisdiction to hear the appeals from the District Court's December 13, 2002 remand order. The Ninth Circuit also issued a stay of the remand order pending the outcome of the appeals. As stated above, the cross complaint against PGE will be continued in abeyance until 30 days after a ruling is entered on the motions to dismiss the Master Complaint.

On May 30, 2002, the Attorney General of California filed a complaint alleging failure of PGE to comply with the Federal Power Act and with FERC requirements for its market based sales of power in California. On September 26, 2003, PGE and the California Attorney General agreed to settle this case. The agreement is part of a larger settlement (Settlement) with the Staff of the FERC and other parties related to trading activities by PGE during the California energy crisis in 2000-2001 in FERC Docket Nos. EL02-114-000 and EL02-115-000. The Settlement resolves this case and related non-public investigations, except that the California Attorney General is not precluded from pursuing any willfully fraudulent acts or omissions not known at the time of the settlement or any criminal acts or omissions.

Under the Settlement, PGE agreed to pay $8.5 million, of which $6.1 million was paid to California. PGE also agreed to file an amendment to its FERC market-based rates tariff that imposes a cost-based cap on prices charged for new wholesale electricity sales transactions for a prospective period of twelve months. In addition, PGE agreed to conduct annual training for its trading floor employees on code of conduct, standards of conduct, antitrust and ethics, and to retain for five years recordings of affiliate trading transactions, affiliate postings and related accounting records. The Settlement provides that it will not be deemed an admission of fault or liability by PGE for any reason and implies no admission or fault by PGE.

On December 17, 2003, the FERC approved the Settlement, which was uncontested. There is no further appeal.

On May 21, 2003, the Port of Seattle, Washington (Port) filed a complaint in the U.S. District Court for the Western District of Washington against PGE and sixteen other companies (Defendants) alleging violation of both the Sherman Act and the Racketeer Influenced and Corrupt Organization Act, fraud, and, with respect to Puget Energy, Inc. and Puget Sound Energy, Inc., breach of contract. The complaint alleges that the price of electric energy purchased by the Port between November 1997 and June 2001 under a contract with Puget Sound Energy, Inc. was unlawfully fixed and artificially increased through various actions alleged to have been undertaken in the Pacific Northwest power markets among Defendants and Enron Corp., Enron Energy Services, Inc., Enron North America Corp., Enron Power Marketing, Inc., and others. The complaint alleges actual damages of $30.5 million suffered by the Port and seeks recovery of that amount, plus punitive damages and reasonable attorney fees. On December  4, 2003, this case was transferred to the Southern District of California for consolidation with the Wholesale Electricity Antitrust Cases I and II (Case No. CV02-990, 1000, 1001) discussed above.

On June 30, 2003, the Montana Attorney General filed a complaint in Montana state court against PGE and numerous named and unnamed generators, suppliers, traders, and marketers of electricity and natural gas in Montana. The Complaint alleges unfair and deceptive trade practices in violation of the Montana Unfair Trade and Practices and Consumer Protection Act, deception, fraud and intentional infliction of harm arising from various actions alleged to have been undertaken in the western wholesale electricity and natural gas markets during 2000 and 2001. The relief sought includes injunctive relief to prohibit the unlawful practices alleged, treble damages, general damages, interest, and attorney fees. No monetary amount is specified.

On November 26, 2003, PGE filed a complaint for Declaratory Relief in U.S. District Court for the District of Oregon seeking to end the Oregon Attorney General's investigation into the Company's participation in wholesale power trading markets related to the California energy crisis of 2000-2001. The complaint is based on Federal preemption grounds and judicial estoppel because the State of Oregon, through the OPUC, has settled with the Company on these issues.

On December 16, 2003, the Oregon Attorney General filed in the Multnomah County Oregon Circuit Court a Motion for Order to Show Cause why the Company should not comply with the Oregon Attorney General's investigation. The motion was removed to the U.S. District Court for the District of Oregon.

On May 5, 2003, Robert and Julie Remington and forty-eight other individuals, unions and businesses filed a suit against PGE and the other owners, designers and operators of the Colstrip coal-fired electric generation plants (Colstrip Project) in Montana alleging that holding and settling ponds at the Colstrip Project have leaked and contaminated groundwater. The plaintiffs allege nuisance, trespass, unjust enrichment, fraud, and negligence, and seek a declaratory judgment of nuisance and trespass, an order that the nuisance be abated, and an unspecified amount for damages, disgorgement of profits, and punitive damages.

In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allege that the losses were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. On May 24, 2002, PGE filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA, and that the conduct complained of is directed against Enro n, not PGE.

On May 28, 2003, PGE filed a motion for summary judgment. On August 14, 2003, the Court granted PGE's motion for summary judgment. On October 22, 2003, the IBEW filed an appeal to the Oregon Court of Appeals.

None.

PGE is a wholly owned subsidiary of Enron, which owns all 42,758,877 shares of PGE's outstanding common stock. No cash dividends were declared on common stock in 2003 or 2002. PGE declared a non-cash dividend of $27 million in July 2002. For further information, see Note 13, Related Party Transactions, in the Notes to Financial Statements.

PGE is restricted, without prior OPUC approval, from making dividend distributions to Enron that would reduce PGE's common equity capital below 48% of total capitalization (excluding short-term borrowings). In addition, terms of PGE's revolving credit facility prohibit the payment of any cash dividends or any other distribution by PGE on its common stock.

PGE is a single integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon, as well as the wholesale sale of electricity and natural gas throughout the western states. PGE's mission is to be a company that customers depend on to provide electric service in a safe and reliable manner with excellent customer service at a reasonable price. The OPUC establishes tariffs and retail revenue requirements based upon the cost to serve retail customers and a fair return on investment, using a forecasted test year and an original cost rate base. Wholesale prices are regulated by the FERC.

Although Oregon's recent electricity restructuring law provides for both direct access to competing energy suppliers and for market price options, the Company remains obligated to provide service to all of its retail customers, the large majority of which buy electricity under rates determined by the cost of service. Subject to regulatory review and timing, PGE expects the OPUC to recognize all prudently-incurred costs in setting rates, although there can be no assurance that the Company will have an opportunity to fully recover its costs through rates set in the regulatory process. While customer rates applicable to projected power costs are adjusted on an annual basis, rates applicable to non-power costs are adjusted only in a general rate proceeding. As electricity rates are fixed during the year, fluctuations in both energy sales and power and fuel prices can significantly impact the Company's earnings.

Enron Bankruptcy - Uncertainties associated with potential liabilities and risks resulting from Enron's bankruptcy are diminishing as Enron progresses through its bankruptcy process. Enron has agreed to sell PGE to Oregon Electric Utility Company, LLC (Oregon Electric) and the process of securing approvals for the sale has begun, with a decision expected by year-end 2004. However, if PGE is not sold, under Enron's plan of reorganization, PGE's stock will be distributed to Enron's creditors and it will become an independent company. Whether PGE is sold or its stock is distributed, control of employee benefit and retirement savings plans will be returned to PGE by the end of 2004.

Economy - Typical of electric utilities, PGE's business is affected by the general economy and by population growth in its service territory. The Company continues to experience customer growth, adding approximately 35,000 retail customers in the first four years of this decade (2000-2003), and now serves over 754,000 customers as the largest supplier of electricity in the state. The Company's diverse retail customer base has helped mitigate the effects of a downturn in Oregon's economy, notably impacting the high tech industry and other manufacturing sectors, where sales dropped sharply in 2002 and remained depressed in 2003. Oregon is slowly recovering from the recession, with seasonally-adjusted unemployment falling from a high of 8.5% in June 2003 to 7.2% in December 2003.

Retail energy sales during the last half of 2003 reflect the economic improvement, with gains in the residential and commercial markets offsetting a continued slow manufacturing sector. A key driver of sales growth in the residential and commercial markets remains population growth. An improving job market in the service sector and a softening of mortgage interest rates have sustained the local housing market. The Company plays an active role in supporting growth in its service territory, engaging in regional economic development strategies that promote job creation and load growth, and encouraging retention and expansion actions of its major industrial customers.

Operations - Despite a challenging economic environment, PGE continues to operate well and is financially sound. PGE's earnings in 2003 were not reflective of the Company's historical operations and cash flows. As in 2001 and 2002, financial reserves and a decline in retail energy sales resulting from the slow economy contributed significantly to a decline from normal earnings levels. The 2000-2001 West Coast energy crisis, centered largely on the supply of electricity and significantly affected by events in California's deregulated power markets, continued to have an effect on the Company, with 2003 reserves related primarily to investigations into wholesale power market activities during 2000 and 2001. In addition, adverse hydro conditions, the lack of a power cost adjustment mechanism, and the disallowance of certain power purchase contracts in customer rates had a negative impact on 2003 earnings. The OPUC has denied PGE's application to defer energy costs incurred to offset adv erse hydro conditions in 2003.

The Company continues to meet regulatory standards for safety and service quality related to outage frequency and duration. The Company's customer satisfaction index has remained strong over the past several years among both residential and business customers, with reliability, restoration response, and customer service significant factors. PGE continues to invest in its transmission, distribution, and customer service systems and in upgrades to its generating plants. Decommissioning of the Company's closed Trojan nuclear plant is proceeding well, with transfer of spent fuel to a temporary storage facility completed ahead of schedule in 2003 and license termination anticipated in 2005. PGE and its employees continue their long-established commitment to the community through corporate support of local non-profit groups and employee volunteer efforts.

Voters in 2003 rejected a PUD initiative in Multnomah County, where a majority of PGE's customers reside. On March 9, 2004, Yamhill County voters also rejected a PUD initiative. The Company faces another PUD initiative in Clackamas County on May 18, 2004.

Financial Condition - Although PGE's earnings have been below expectations due to both a slow economy and financial reserves related to wholesale market activities, the Company has maintained a strong financial position and stable cash flow. As a financially sound utility, PGE has succeeded in securing financing, enabling it to effectively invest in its systems, serve customers, and improve operational efficiency.

The Company maintains investment-grade ratings on its secured debt with all the major credit rating agencies and successfully issued new debt and refinanced high coupon debt in 2002 and 2003. PGE maintains adequate liquidity through its revolving credit facility, cash from operations, and access to short-term debt markets, and continues to meet all financial covenants and requirements of its debt and financing agreements. The Company expects to meet the majority of its operating and capital requirements in the next few years with cash from operations and short-term borrowings. Long-term financing of $75 million to $100 million is anticipated in both 2004 and 2005.

Both regulatory "ring fencing" provisions and the establishment of a bankruptcy remote structure have effectively insulated PGE and its customers from adverse affects of Enron's bankruptcy. PGE has not paid a cash dividend since the second quarter of 2001, increasing the Company's equity position and strengthening its balance sheet. The added protection helps secure financing and positions the Company for investment in any new power supply resources.

Power Supply - PGE manages its power supply to secure reasonably priced power for customers by effectively using the Company's assets and position in the marketplace. PGE can meet approximately 75% of its estimated 2004 retail peak load requirement with output from its generating plants and long-term hydro contracts, with the remaining 25% met with short-term and other long-term power purchases in the wholesale market. The portion of retail load met with power purchases can increase if it becomes more economic to purchase electricity than to generate it with natural gas or other thermal sources. The Company remains active in wholesale energy markets, which are integral to PGE's retail business, providing for the efficient use of its generating capacity. Wholesale energy market prices in the western states were relatively stable during the last year compared to 2002 and 2001. The Company took several actions to maintain a balanced net energy position through the winter peak period an d the remainder of the year through a combination of existing physical resources, electricity purchases, and peaking generation facilities.

PGE's twelve diversified generating plants (40% gas/oil, 34% coal, and 26% hydro) have both base-load and peaking capabilities, with fuel for thermal plants supplied under short-term agreements and spot-market purchases, allowing the Company to dispatch its thermal resources based upon the market price of wholesale power relative to the market price of natural gas or coal.

Below average water conditions in 2003 reduced generation from PGE's hydroelectric projects by 35,000 MWh from 2002. Although hydro conditions in both the Clackamas and Deschutes river systems, where the Company's facilities are located, are projected at somewhat above normal in 2004, it is anticipated that regional water conditions will continue at below normal levels during 2004. This could require increased output from the Company's thermal generating plants and energy purchases in the wholesale market, which would result in increased power costs. Natural gas, used to fuel the Company's combustion turbine plants, is subject to price volatility resulting from supply issues, which can negatively affect generation and purchased power costs.

Recent regulatory activities include the implementation of a "Resource Valuation Mechanism" (RVM) process that provides for customer rate adjustments based upon changes in projected power costs. This process resulted in a rate decrease for 2003 and a small average increase for 2004. In addition, power cost adjustment mechanisms have allowed the deferral and subsequent recovery of increases in net variable power costs that exceed established baseline amounts. The Company continues to recover power costs deferred under those mechanisms in effect during 2001 and 2002. As the cost of power, driven by variability in hydro conditions, remains a major risk to PGE, the Company will continue to work with Oregon's commission to develop a multi-year power cost adjustment mechanism focused on variations in hydro conditions.

PGE also continues to work with the Oregon commission in developing and implementing an Integrated Resource Plan that addresses resource actions required to meet the future electricity needs of its customers, with an emphasis on both price stability and flexibility. Regulatory acknowledgement of the plan would support Company actions in rate decisions related to future resource acquisitions.

PGE's net income in 2003 was $58 million compared to $66 million in 2002. Results for 2003 included after tax provisions totaling approximately $19 million related to investigations into wholesale power market activities during 2000 and 2001, consisting of $14 million related to amounts due the Company for wholesale electricity sales made in California and $5 million related to a settlement agreement between PGE, the FERC, and other parties. Earnings in 2003 were unfavorably impacted by poor hydro conditions and lack of a power cost adjustment mechanism. A 1.8% decline in retail energy sales, resulting primarily from warmer weather in the year's first quarter, also reduced earnings for the year. A power cost adjustment mechanism in place during 2002 partially offset the negative earnings impact of energy sales that fell 8% lower than levels used in PGE's general rate case implemented in the fourth quarter of 2001. Although Oregon's economy is improving, retail energy sales in 2003 remained approximately 8% lower than projected in the Company's rate case. Higher income from non-qualified benefit plan trust assets, a reduction in nonutility expenses, and gains on energy trading activities were offset by increased amortization and interest charges. Results for 2003 also include a $2 million gain from a cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations.

The following table summarizes Operating Revenues and Energy Sales for 2003 and 2002:

The decrease in Retail Revenues in 2003 was caused by both lower prices and energy sales. As provided in the OPUC's 2001 general rate order, PGE reduced its retail customer rates by an average of approximately 7% on January 1, 2003 to reflect a decrease in projected 2003 variable power costs (see "Retail Rate Changes" in the Financial and Operating Outlook section for further information). Retail energy sales decreased from 2002 due to a 10% decline in industrial sales, most of which was attributable to a single large customer that began generating its own power requirements in the second quarter of 2003. Combined residential and commercial energy sales increased approximately 1% from last year, as an approximate 10,600 (1.4%) increase in the number of customers served was partially offset by warmer temperatures in the first quarter of 2003 and conservation efforts. Average wholesale power prices increased 28%, reflecting higher summer temperatures as well as increased natural gas prices and adverse hydro conditions in the region. Lower wholesale energy sales resulted primarily from the adoption of EITF 03-11 in the fourth quarter of 2003. Beginning October 1, 2003, revenues and expenses related to non-trading energy activities that are not physically settled, formerly included on a "gross" basis within both Operating Revenues and Purchased Power and Fuel expense, are recorded on a "net" basis in Purchased Power and Fuel expense. This change results in a decrease in reported non-trading wholesale energy sales and purchases and related amounts in comparative financial statements. Although determination of the effect of the change on prior years' reported revenues and expenses is not practicable, the change has no impact on reported net income. The increase in Other Operating Revenues was primarily related to sales of natural gas in excess of generating plant requirements, as power purchases in the wholesale market economically displaced more expensive gas-fired thermal generation. Such sales in 2003 resulted in a $13 million gain, compared to an $18 million loss in 2002 caused by low natural gas prices.

Purchased Power and Fuel expense decreased $129 million (11%). The decrease was due to both a $90 million reduction resulting from the adoption of EITF 03-11 (described above) and to lower purchased power costs, attributable to lower term prices in 2002 for power delivered in 2003. Such reductions, combined with decreased fuel costs and an approximate 2% reduction in total system load, more than offset the combined effects of the discontinuance of the Company's power cost adjustment mechanism and 2003 provisions for uncollectible accounts receivable for wholesale electricity sales. Lower term power prices for power delivered in 2003 more than offset higher spot power prices during the year. Combined with a decrease in the cost of coal-fired generation, PGE's average variable power cost decreased 10% from that of 2002 (for further information, see "Power Supply" in the Financial and Operating Outlook section). Purchased Power and Fuel costs in 2003 include a $62 million charge for the amort ization of costs deferred under the power cost adjustment mechanisms in 2001 and 2002, which were recovered from customers in 2003. Purchased Power and Fuel costs in 2002 included a net credit of $13 million related to the Company's power cost adjustment mechanisms, consisting of a $36 million credit for the deferral of 2002 power costs and a $23 million charge for amortization of 2001 deferred costs recovered from customers in 2002. There was no power cost adjustment mechanism in place in 2003. Also included in 2003 are $22.5 million of provisions for uncollectible accounts receivable for wholesale electricity sales related to sales made in the California market during 2000 and 2001. (For further information, see "Receivables and Refunds on Wholesale Market Transactions" in the Financial and Operating Outlook section). Total Company generation increased 4% from 2002, with increased coal-fired generation partially offset by both reduced hydro production (due to low stream flows) and combustion turbine genera tion, resulting from the forced outage of the Coyote Springs plant during the second quarter of 2003. Total generation met approximately 40% of PGE's retail load during the year, compared to 38% in 2002, due to last year's planned maintenance and economic displacement of combustion turbine generation, and planned maintenance and repair outages at the Company's coal-fired generating plants.

Due to anticipated adverse hydro conditions in the region, PGE filed an application with the OPUC seeking deferral, for future recovery from customers, of approximately $25 million in hydro replacement power costs for the period February 11, 2003 (application date) through December 31, 2003. This application was denied by the Commission on March 2, 2004.

The following table indicates PGE's total system load (including both retail and wholesale) for the last two years (excludes energy trading activities). Average variable power costs exclude the effect of credits to purchased power and fuel costs related to PGE's power cost adjustment mechanisms, as discussed above.

Production, distribution, administrative and other expenses were unchanged from 2002. Increased pension and medical benefit costs were offset by a reduction in major maintenance expenses at the Company's generating plants and reduced costs related to implementation of Oregon's electricity restructuring law (fully offset within Depreciation and Amortization).

Depreciation and Amortization expense increased $52 million (32%), primarily due to decreased amortization of regulatory liabilities, the effects of which are offset within Operating Revenues. This includes $23 million in credits given to customers in 2002 related to a distribution received by PGE in 2000 from Nuclear Electric Insurance Limited. Other reductions in regulatory liabilities include a combined $17 million in credits related to merger-related cost savings and gains on certain major property sales provided to customers in 2002. Amortization of computer software, including the Company's new customer information and billing system, increased by $4 million. The remaining increase was caused by a nonrecurring $4 million credit in 2002 related to the sale of the Pelton Round Butte hydroelectric project (offset in Income tax expense) and a $4 million increase related to the deferral and amortization of costs related to implementation of Oregon's electricity restructuring law.

Income taxes decreased $18 million primarily due to lower taxable income. Included in 2002 is an adjustment that increased income tax expense by $4.5 million to establish deferred income taxes related to a property tax temporary difference that was not identified at the time the Company implemented SFAS No. 109, Accounting for Income Taxes, in 1993.

Other Income increased $13 million, resulting primarily from a $10 million increase in income from non-qualified benefit plan trust assets and a reduction in nonutility expenses, including costs related to the cancellation of a proposed gas turbine generation project. Partially offsetting these items was an $8.5 million charge related to a settlement agreement between PGE, the FERC, and other parties related to wholesale power market activities in 2000 and 2001. The increase in Other Income resulted in a $4 million reduction in tax benefits from 2002.

Interest Charges increased $8 million due primarily to an increase in outstanding long-term debt, including first mortgage bonds issued from October 2002 through August 2003.

PGE's net income in 2002 was $66 million compared to $34 million in 2001. Results for 2001 included a $48 million after tax provision for uncollectible accounts receivable from Enron and affiliated companies due to uncertainties surrounding Enron's bankruptcy proceedings. In addition, 2001 results included an $11 million gain from a cumulative effect of a change in accounting principle resulting from the adoption of SFAS No. 133 where certain non-trading derivatives were recorded at fair value. Earnings in 2002 were unfavorably impacted by a 1.4% decline in retail energy sales from 2001, resulting from the combined effects of Oregon's poor economy and conservation efforts. In addition, retail energy sales in 2002 were approximately 8% lower than levels used in the Company's general rate case implemented in the fourth quarter of 2001. A power cost adjustment mechanism in place during 2002, in which $41 million was deferred for future collection from customers, partially offset the negative earnings impact of lower energy sales. Settlement of issues associated with 2003 estimated power costs also resulted in the Company recording a $4.6 million pre-tax charge to 2002 earnings by reducing amounts recoverable under the power cost adjustment mechanism. The impact of lower retail energy sales in 2002 was partially offset by reduced losses on energy trading activities and the effect of non-recurring provisions recorded in 2001 related to amounts owed the Company for certain prior year wholesale electricity sales made in California.

The following table summarizes Operating Revenues and Energy Sales for 2002 and 2001:

The decrease in total Operating Revenues in 2002 was due to significantly lower wholesale prices for sales of energy in excess of retail customer requirements. The decrease in Wholesale (Non-Trading) revenues is attributable to a 77% average price decrease from 2001 due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to a slowing economy. Wholesale (Non-Trading) sales volume increased 30% as energy marketing activity returned from lower levels in 2001 caused by price volatility and uncertainty related to the cost and availability of power in western markets. In addition, power in excess of retail requirements, from forward contracts entered into in 2000 and 2001, was sold in the wholesale market in 2002; in 2001, power from such contracts was used to replace low hydro generation to meet retail load. The increase in retail revenues was due primarily to a general rate increase that b ecame effective October 1, 2001; energy sales decreased 1.4% as a slow economy more than offset an approximate 7,700 (1.0%) increase in total customers from the end of 2001. (See "Retail Growth and Energy Sales" in the Financial and Operating Outlook section for further information). Included in the increase in retail revenues is the effect of the recognition in 2002 of $42 million in revenues deferred in 2001 related to differences between the timing of such revenues and related variable power costs over the 15-month period ending December 31, 2002.

Other Operating Revenues decreased $21 million due largely to lower prices on sales of natural gas in excess of generating requirements, as power purchases economically displaced higher cost gas-fired thermal generation. This was partially offset by the effect of lower losses on the Company's energy trading activities in 2002, as the Company's cost of power and fuel sold in the wholesale market significantly exceeded wholesale market prices in 2001.

Purchased Power and Fuel costs decreased $577 million (33%) due to lower prices for power purchases, lower fuel costs, and reduced thermal generation. Due to lower regional power and natural gas prices, the average cost of firm power purchases was approximately half that of 2001. Combined with lower prices for spot market purchases and a 43% decrease in thermal generation, PGE's average variable power cost for 2002 was 60% of 2001 (for further information, see "Power Supply" in the Financial and Operating Outlook section). Purchased Power and Fuel costs in 2002 and 2001 include credits of $36 million and $84 million, respectively, under the two separate power cost adjustment mechanisms in effect during the two years. Although PGE was able to defer substantial power costs in 2001 for future recovery from customers, it was necessary for the Company to absorb approximately $54 million in costs exceeding the power cost baseline established by the OPUC under the mechanism then in effect. In 200 2, it was necessary for the Company to absorb $42 million under the mechanism in effect during the year, the majority of which was attributable to lower retail loads. (See "Power Cost Adjustment Mechanisms" in the Financial and Operating Outlook section for further information).

Energy generation from PGE's plants decreased 38% from 2001 due to planned maintenance and economic displacement of combustion turbine generation, and planned maintenance and forced repair outages at the Company's coal fired generating plants. Hydro energy production decreased 13%, with the loss in generation attributable to the January 1, 2002 sale of a 33.33% interest in the Company's Pelton Round Butte project partially offset by improved stream flows during the year. Total generation met approximately 38% of PGE's retail load during the year, compared to 61% in 2001.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for 2002 and 2001. Average variable power costs exclude the effect of credits to purchased power and fuel costs related to PGE's power cost adjustment mechanisms, as discussed above.

Operating Expenses (excluding Purchased Power and Fuel, Depreciation and Amortization, and taxes) decreased $14 million (5%). Production and Distribution expenses decreased $10 million due to the termination of flowage easement fees to the Tribes related to the operation of PGE's Pelton Round Butte hydroelectric project, a 33.33% interest in which was sold to the Tribes in January 2002. Reduced maintenance costs at the Company's thermal generating plants were offset by higher delivery system costs, including tree trimming and other distribution-related work. Administrative and other expenses decreased due to reduced energy efficiency expenditures, including the discontinuance of the Compact Fluorescent Lighting program; this was partially offset by increased provisions for uncollectible customer accounts, costs related to the implementation of a new customer information and billing system, and employee severance expenses.

Depreciation and Amortization expense decreased $9 million (5%). A $30 million decrease due to regulatory amortization, including the amortization of regulatory liabilities related to various refunds to customers, was partially offset by a $21 million increase in depreciation of utility plant, due to both normal property additions and to higher depreciation rates established in the Company's 2001 general rate case implemented October 1, 2001.

Income taxes increased $30 million primarily due to higher taxable income. Year 2002 also included an adjustment that increased income tax expense by $4.5 million to establish deferred income taxes related to a property tax temporary difference that was not identified at the time the Company implemented SFAS No. 109, Accounting for Income Taxes, in 1993. In 2001, there were certain nonrecurring credit adjustments totaling $5 million recorded related to prior years' amended tax returns and deferred tax and audit adjustments.

Other Income increased $67 million primarily due to the effect of a $79 million provision for uncollectible accounts receivable from Enron and affiliated companies recorded in December 2001 to reflect uncertainties surrounding Enron's bankruptcy proceedings. In 2002, PGE reserved an additional $7 million for interest accrued during the year on the Merger Receivable from Enron and $2 million for receivable amounts due from Portland General Holdings, Inc. (PGH) and its subsidiaries. The Company also reversed a $3 million credit reserve established in 2001 related to receivables from Enron. The write-off of certain non-utility investments in 2002 was partially offset by higher interest income on regulatory assets, including interest on the unrecovered balance of the Company's power cost adjustment mechanism. Reserves of $3 million and $5 million were recorded in 2002 and 2001, respectively, related to the cancellation of a proposed gas turbine generation project. Losses of $5 million were inc urred in both 2002 and 2001 on investments in trust owned life insurance policies as a result of the downturn in the financial markets. The increase in Other Income resulted in a $26 million reduction in tax benefits from 2001.

Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE. Supplemental cash is obtained from external borrowings, as needed.

A significant portion of cash provided by operations consists of charges that are recovered in customer revenues for depreciation and amortization of utility plant that require no current period cash outlay. The recovery from customers of prior capital expenditures through depreciation and amortization provides a source of funding for current and future cash requirements. Cash flows from operations can also be affected by weather conditions. Temperatures outside the normal range during the year can result in increased or decreased electricity usage, causing an increase or decrease in operating cash flows, and a resulting impact on the need for short-term borrowings to meet current cash requirements.

PGE generated cash from operations in amounts considerably greater than net income in each of the last three years (excluding the effect of net margin deposit activity in 2001). An increase in 2001 margin deposit requirements on energy trading activities, related to changes in power and natural gas prices, reduced cash flow by $223 million.

Cash provided by operating activities totaled $307 million in 2003 compared to $305 million in 2002. Increased cash receipts resulted from an increase in wholesale energy sales and prices and recovery from retail customers of amounts related to power cost adjustment mechanisms in effect during 2001 and 2002. Such increases were largely offset by decreased refunds of margin deposits from wholesale customers, related to the settlement of certain energy contracts, and by a decrease in cash received from retail electricity sales, due to lower energy sales and a January 1, 2003 rate decrease.

Cash from operations and remaining proceeds from the issuance of long-term debt (described below) were invested primarily in government money market funds at December 31, 2003. Such investments are consistent with PGE's investment objectives to preserve principal, maintain liquidity, and diversify risk. Company investments are limited to investment grade securities maturing within one year, as approved by PGE's board of directors.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. Capital expenditures of $167 million in 2003 approximated those of 2002. The $30 million change in "Other - net" includes the effect of the termination of a 1996 power sale termination agreement, under which the Company received $28 million in 2002. For additional information regarding future investing activities, see "Cash Requirements" in this section.

Financing Activities provide supplemental cash for both day-to-day operations and capital requirements as needed. PGE relies on cash from operations, borrowings under its revolving credit facility, and long-term financing activities to support such requirements.

During 2003, PGE issued $200 million in First Mortgage Bonds at interest rates ranging from 5.279% to 6.875%. These Bonds were issued as private placements, maturing from 2013 through 2033. Net proceeds from these issues and cash provided from operations were used to redeem $180 million of First Mortgage Bonds, bearing interest rates ranging from 6.47% to 9.46%, and $70 million of 8.25% Junior Subordinated Deferrable Interest Debentures. Bonds issued in 2003 provided funds for debt maturing during the year and reduced PGE's borrowing costs by replacing higher rate debt.

PGE also repurchased $142 million in Pollution Control Bonds that were subsequently remarketed for a term of six years at fixed rates of 5.20% (for $121 million of the bonds) and 5.45% (for $21 million). The bonds are secured by First Mortgage Bonds issued by the Company. The Pollution Control Bonds were required to be repurchased during 2003 and were remarketed to take advantage of cost savings associated with secured, tax-exempt debt.

In addition, the Company repaid $9 million of conservation bonds, retired $3 million of preferred stock, and paid $2 million in preferred stock dividends. As required by SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, $1 million of dividends paid after June 30, 2003 are classified as interest expense on the income statement. No cash dividends on common stock were declared or paid in 2002 or 2003.

In May 2003, PGE completed a new $150 million 364-day revolving credit facility with a group of commercial banks that replaced two separate facilities that were terminated upon execution of the new agreement. Under the new credit facility, PGE has the option to issue up to $100 million of the $150 million credit line in letters of credit. The letter of credit provisions of the revolving credit facility accommodate PGE's collateral requirements related to its wholesale trading activities and other operating needs. At December 31, 2003, the Company had utilized approximately $18 million in letters of credit. The facility contains a material adverse change clause and financial covenants that limit consolidated indebtedness, as defined in the facility, to 60% of total capitalization; it also requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less than 3.75:1. At December 31, 2003, the Company's indebtedness to total capit alization and interest coverage ratios, as calculated under the facility, were 47.1% and 4.85:1, respectively. The new facility is secured by First Mortgage Bonds issued by the Company and requires annual facility fees of 0.25%. The new facility prohibits the payment of any cash dividends or any other distributions by PGE on its common stock.

In 2003, existing cash and short-term investments, along with cash provided by operations, replaced the use of commercial paper in meeting the Company's day-to-day requirements.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Company's Articles of Incorporation and the Indenture securing the bonds. As of December 31, 2003, PGE has the capability to issue additional preferred stock and First Mortgage Bonds in amounts sufficient to meet its anticipated capital and operating requirements.

Access to short-term debt markets provides necessary liquidity to support PGE's current operating activities, including the purchase of electricity and fuel. Long-term capital requirements are driven largely by debt refinancing activities and capital expenditures for distribution, transmission, and generation facilities supporting both new and existing customers.

PGE's liquidity and capital requirements are significantly affected by operating, capital expenditure, debt service, and working capital needs, including margin deposits related to wholesale trading activity. PGE's revolving credit facility supplements operating cash flow and provides a primary source of liquidity. PGE's ability to secure sufficient long-term capital at reasonable cost is determined by its financial performance and outlook, capital expenditure requirements (including the effects of these factors on the Company's credit ratings), and alternatives available to investors. The Company's ability to obtain and renew such financing depends on its credit ratings as well as on bank credit markets, both generally and for electric utilities in particular.

PGE's financial policies have been established by the Company's management and approved by its board of directors. Such policies include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company's financial obligations. PGE's objective is to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of 50% to 55%. Achievement of this objective while sustaining sufficient cash flow are necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE's common equity ratios were 54.5% and 51.9% at December 31, 2003 and 2002, respectively.

As previously indicated, a significant portion of cash provided by operations consists of depreciation and amortization of utility plant which are recovered in rates but require no current cash outlay. PGE estimates recovery of such charges to approximate $160 million to $190 million annually over the period 2004-2006. Combined with all other sources, total cash provided by operations is estimated to range from $300 million to $360 million during the 2004-2006 period.

The following table indicates PGE's projected primary cash requirements for the years indicated (in millions):

1. System improvements to support both new and existing customers, excluding the proposed construction of Port Westward.

Projected cash flow from operations in excess of cash requirements may be used to fund costs associated with securing new energy resources, including the proposed construction of the Port Westward combustion turbine plant. Construction of Port Westward is contingent upon OPUC review and acknowledgment of PGE's Integrated Resource Plan (for further information, see "Integrated Resource Plan" in Part I, Item 1. Business - Regulatory Matters). Under the Company's proposal, it is anticipated that the Port Westward plant would be operational in late 2006 and cost approximately $210 million to $260 million, excluding Allowance for Funds Used During Construction, ($80 million to $100 million in 2004, $110 million to $130 million in 2005, and $20 million to $30 million in 2006). To the extent necessary, long-term debt may be considered to fund any potential shortfall. Additional liquidity is available under the Company's revolving credit facility, which is expected to be replaced with a sim ilar facility upon its May 27, 2004 expiration date. PGE anticipates long-term financing activity of $75 million to $100 million in both 2004 and 2005.

PGE's secured and unsecured debt ratings continue to be investment grade from both Moody's Investors Service (Moody's) and Standard and Poor's (S&P). Fitch Ratings (Fitch) rates PGE's secured debt at investment grade and unsecured debt at below investment grade.

PGE 's current credit ratings are as follows:

In March 2004, S&P placed PGE's credit ratings on CreditWatch with negative implications following Oregon Electric's filing with the OPUC to purchase PGE from Enron. S&P's Outlook change is based on their view of the consolidated leverage from the proposed acquisition of PGE by Oregon Electric. Should Moody's and S&P reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On January 31, 2004, PGE had posted, in the form of letters of credit, approximately $7 million of collateral. Based on the Company's non-trading and trading portfolios, estimates of current energy market prices, and the current level of collateral outstanding, as of January 31, 2004, the approximate amount of additional collateral that could be requested upon such a downgrade event is $30 million and decreases to approximately $23 million by yea r-end 2004. In addition to collateral calls, such a credit rating reduction could impact the terms and conditions of long-term debt issued in the future. Any rating reductions could also increase interest rates and fees on PGE's revolving credit facility, increasing the cost of funding the Company's day-to-day working capital requirements.

Due to the Company's increased liquidity and financial flexibility, PGE has regained its ability to access the commercial paper market, to which it had temporarily lost access due to ratings reductions for commercial paper by Moody's and Fitch in May 2002. As discussed in "Cash Requirements" above, management believes that the Company's existing line of credit and cash from operations provide it with sufficient liquidity to meet its day-to-day cash requirements.

In order to increase the degree of insulation between PGE and its insolvent parent company, PGE, in September 2002, created a new class of Limited Voting Junior Preferred Stock and issued a single share of such stock to an independent party. The stock has voting rights which limit PGE's right to commence a voluntary bankruptcy proceeding without the consent of the holder of the share. For further information, see Note 4, Common and Preferred Stock, in the Notes to Financial Statements.

Although measures of PGE's financial performance, including financial ratios, remain strong, due to continuing uncertainty regarding the impact of Enron's bankruptcy on PGE, management is unable to predict what actions, if any, will be taken by the rating agencies in the future. However, PGE management believes there are sufficient structural and regulatory mechanisms to protect the Company's assets from Enron and its creditors and there are no economic incentives for Enron to cause PGE to file for bankruptcy protection. PGE, as a separate corporation, owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis. Neither PGE nor Enron have guaranteed the obligations of the other and there are no loans between them. Under Oregon law and specific conditions imposed on Enron and PGE by t he OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997, Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. PGE is a solvent enterprise whose greatest value is as a going concern. In a bankruptcy, Enron would lose most, if not all, control over PGE. It would merely continue to be the holder of PGE's common stock, and PGE, as a Debtor in Possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. Any plan of reorganization would be devised by PGE management and approved by PGE's creditors, not Enron or its creditors. No dividends could be paid to Enron, no assets could be sold, and no other transfer of funds could be made except with the approval of the PGE creditors and the Bankruptcy Court. PGE believes that the OPUC would challenge any attempt in the bankruptcy proceedings to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party without OPUC approval.

The following indicates PGE's contractual obligations as of December 31, 2003 (in millions):

PGE has entered into long-term power purchase contracts with certain public utility districts in the state of Washington under which PGE has acquired a percentage of the output (Allocation) of four hydroelectric projects. The Company is required to pay its proportionate share of the operating and debt service costs of the projects whether or not they are operable. The contracts further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE will be allocated a pro rata share of both the output and the operating and debt service costs of the defaulting purchaser, up to a cumulative maximum of 25% of its percentage Allocation.

PGE entered into a sale transaction in 1985 in which it sold an undivided 15% interest in its Boardman coal plant (Plant) and a 10.714% undivided interest in the Pacific Northwest Intertie (Intertie) transmission line (jointly the Boardman Assets) to an unrelated third party (Purchaser). The Purchaser leased the Boardman Assets to a lessee (Lessee) unrelated to PGE or the Purchaser. Concurrently, PGE assigned to the Lessee certain agreements for the sale of power and transmission services from the Plant and the Intertie (P&T Agreements) to a regulated electric utility (Utility) unrelated to PGE, the Purchaser, or the Lessee. The payments by the Utility under the P&T Agreements exceed the payments to be made by the Lessee to the Purchaser under the lease. In exchange for PGE undertaking certain obligations of the Lessee under the lease, the Lessee reassigned to PGE certain rights, including the excess payments, under the P&T Agreements. However, in the event that the Utility def aults on the payments it owes under the P&T Agreements, PGE may be required to pay the damages owed by the Lessee to the lessor under the lease. Assuming no recovery from the Utility and no reduction in damages from mitigating sales or leases related to the Boardman Assets and P&T Agreements, the maximum amount that would be owed by PGE for the year 2004, is approximately $237 million. Management believes that circumstances that could result in such amount, or any lesser amount, being owed by the Company are remote.

PGE's consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (GAAP). In addition, the Company's accounting policies comply with requirements and rate making practices of jurisdictional regulatory authorities. To reflect the effect of regulation, certain revenues, costs, and gains, which would otherwise be recorded in income under GAAP, are deferred for future rate making treatment under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. As recoveries or refunds are reflected in future rates, the applicable regulatory asset or regulatory liability balances are amortized to income over the recovery or refund period. Such deferred assets and liabilities are titled "Regulatory assets" and "Regulatory liabilities" on the Consolidated Balance Sheets; balances were $387 million and $257 million, respectively, at December 31, 2003.

A critical accounting policy is one that is both important to results of operations and financial condition and requires management to make critical accounting estimates. An accounting estimate is an approximation made by management of a financial statement component or account. Accounting estimates reflected in PGE's financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. Accounting estimates included in the accounting policies described below require assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that could have been used, or changes in an accounting estimate that are reasonably likely to occur, could have a material impact on the financial statements. The inherent uncertainty of some matters can make judgments subjective and complex. The effects of estimates and assumptions related to future events cannot be made with certainty. PGE's estimat es are based upon historical experience and on assumptions that management believes to be reasonable in the circumstances. These estimates may change with changes in events, information, experience, and the Company's operating environment. The following critical accounting policies and estimates are those used in the preparation of PGE's consolidated financial statements.

SFAS No. 143 requires the recognition of Asset Retirement Obligations (AROs), measured at estimated fair value, for legal obligations related to dismantlement and restoration costs associated with the retirement of tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition of AROs that are measurable, the probability weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ARO liability classified as an operating expense on the Statement of Income. On the Statement of Income, AROs related to Utility plant are included in Depreciation and Amor tization expense, with those related to Other property included in Other Income (Deductions). In accordance with requirements of SFAS No. 143, accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from Accumulated depreciation to Regulatory liabilities on the Balance Sheet.

In early 1993, PGE ceased commercial operation of Trojan and began the decommissioning process. The original Trojan decommissioning cost estimate was prepared by an engineering firm with subsequent updates by PGE, due primarily to the effects of inflation and the timing of certain activities. The net estimated liability for Trojan decommissioning costs as of December 31, 2003 was $104 million, measured at estimated fair value. PGE collects $14 million annually from customers through 2011, which amount is based on the decommissioning cost estimate. Amounts collected from customers are deposited in an external trust fund, which reimburses PGE for costs expended under the decommissioning plan. The decommissioning estimate includes amounts for equipment removal, embedded pipe remediation, surface decontamination, non-radiological decontamination, and on-site spent nuclear fuel storage (until permanent storage is provided by the USDOE). Estimating the cost of decommissioning activ ities over a period extending to 2019 is inherently subjective and complex. Such estimates may vary because of changes in regulatory requirements, technology, labor and material costs, and waste burial. In addition, timing of actual activities may differ from that established in the decommissioning plan, which may also cause actual costs to vary from those estimated.

Management does not expect actual future decommissioning costs to change significantly from the current estimate. However, if actual costs significantly exceed the previously estimated amount, funds collected through rates may not be adequate to cover actual decommissioning costs and may require that PGE utilize available cash and a credit facility to advance funds to the trust to cover any near term shortfall. Recovery of any such shortfall from customers would require OPUC approval.

Contingencies are evaluated based on SFAS No. 5, Accounting for Contingencies, using the best information available. A material loss contingency is accrued and disclosed when it is probable that an asset has been impaired or a liability incurred and the amount of the loss can be reasonably estimated. If a range of possible loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency is disclosed to the effect that it cannot be reasonably estimated. Material loss contingencies are disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. Reserves established reflect management's assessment of inherent risks, credit worthiness, and complexities involved in the collection process.

As of December 31, 2003, PGE has net accounts receivable balances totaling approximately $61 million for wholesale electricity sales made to the California Independent System Operator (ISO) and the California Power Exchange (PX) from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E). In 2001, the PX filed for bankruptcy and PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code.

In 2002, the FERC ordered refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and PX. A methodology to calculate such refunds was also established by the FERC. The FERC has indicated that any potential refunds can be offset by accounts receivable, thereby mitigating the effect of potential refunds on PGE. Calculated interest on potential refunds will likewise be offset by interest on accounts receivable.

The FERC methodology for calculating potential refunds, initially established in July 2001, was revised in March 2003, significantly increasing the initially estimated refund amount. Reserves of $17.5 million were established at December 31, 2002 and increased to $40 million at December 31, 2003 due to changes in the FERC's methodology. As an unresolved legal and regulatory matter, both the refund methodology and potential refund estimate may vary significantly in the future, which could have a material impact on PGE's results of operations.

PGE engages in price risk management activities for both non-trading and trading purposes, utilizing derivative instruments such as electricity forward, swap and option contracts, natural gas forward, swap, option and futures contracts, and crude oil futures contracts. Derivative contracts entered into for non-trading electric utility purposes are anticipated to serve the Company's regulated retail load. Non-trading derivative contracts are utilized to protect the Company against variability in expected future cash flows due to associated price risk and endeavor to minimize net power costs for retail customers. PGE enters into derivative contracts for trading purposes to participate in electricity, natural gas, and crude oil markets; such activities are not reflected in PGE's retail rates. Derivative contracts are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138, and SFAS No. 149. For non-tradin g activities, certain derivative instruments are recorded at fair value on the balance sheet and, to the extent these instruments are included in the RVM, the changes in fair value are offset with a regulatory asset or regulatory liability under SFAS No. 71 to reflect the effects of regulation. As these contracts are settled, the regulatory asset or regulatory liability is reversed. For trading contracts, PGE records changes in fair value in current earnings. Changes in fair value of instruments not included in the RVM are reflected in either income or comprehensive income.

Marking a contract to market consists of reevaluating the market value over the entire term of the contract at the end of each reporting period and recording the resulting gain or loss of value in earnings or other comprehensive income for the period. This change in value represents the difference between the contract price and the current market value of the contract. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value of money, and volatility factors underlying the commitments.

Determining the fair value of these contracts requires the use of prices at which a buyer or seller could currently contract to purchase or sell a commodity at a future date (termed "forward prices"). Forward price "curves" are used to determine the current fair market price of a commodity to be delivered in the future. PGE's forward price curves are created by utilizing actively quoted market indications received from electronic and telephone brokers, industry publications, NYMEX, and other sources, and are validated using independent publications. The difference between PGE's forward price curves and four independently published price curves averages 1%. The difference at any single location, delivery date and commodity is less than 4%.

For purchases and sales of forward physical or financial contracts, the mark-to-market value is the present value of the difference between PGE's contracted price and the forward price multiplied by the total quantity of the contract. For option contracts, a theoretical value is computed using standard financial models that utilize price volatility, price correlation, time to expiration, interest rate and price curves. The mark-to-market of these options is the difference between the premium paid or received and the theoretical value.

These estimates change with market conditions. Unpredictable factors such as weather and the economy may materially affect the forward price curves. Each forward price curve is derived by various market factors.

Pension expense is dependent on several assumptions used in the actuarial valuation of the plan. Primary assumptions include the discount rate and the expected return on plan assets. These assumptions are evaluated by PGE, reviewed annually with the plan actuaries and trust investment consultants, and updated in light of market changes, trends, and future expectations. Significant differences between assumptions and actual experience could have a material impact on PGE's financial condition and results of operations.

PGE's pension discount rate is based on assumptions regarding rates of return on long-term high quality bonds. The Company reduced its discount rate to reflect a decrease in the rate of return on such bonds.

PGE's assumption regarding the expected rate of return on plan assets is based on historical and projected average rates of return for current asset classes in the plan investment portfolio. The expected rate of return reflects expected future returns for the portfolio, and was used in determining net periodic pension income for the year. At December 31, 2003, the plan's assets were comprised of approximately 71% equities and 29% other assets.

Assumption changes may materially affect net periodic pension income. Reducing the expected long-term rate of return on plan assets by 0.25% would have decreased 2003 pension income by approximately $1.1 million. Reducing the discount rate by 0.25% would have increased 2003 pension expense by approximately $0.3 million.

Revenues from retail electricity sales are recognized when monthly billings are made to customers for energy sold, based upon meter readings performed on a "cycle basis" during each month. In order to properly match revenue with related expenses (power costs, distribution expenses, etc), estimated "unbilled revenues" are accrued for electricity provided from meter read dates to each month-end. Such estimated unbilled revenues are based on PGE's net system load, the number of days from meter reading to the end of each calendar month, and current retail customer rates. Unbilled revenues, included within Current Assets on PGE's balance sheet, were $71 million and $84 million, respectively, at December 31, 2003 and 2002.

The calculation of unbilled revenues is affected by two estimates:

Net system load used to calculate unbilled revenues is adjusted for transmission and distribution line losses to estimate electricity delivered to retail customers. Historically, PGE has estimated line losses at approximately 2.6% for large industrial customers and 7% for other retail customers. To the extent that actual line losses differ from such estimates (due to temperature conditions, normal system aging, energy theft, etc), estimated unbilled revenues could be significantly different from actuals.

Estimates of unbilled electricity use assume daily consumption is constant throughout each month. The effects of sudden or severe weather/temperature changes or other circumstances that may cause variations in consumption during the month is not readily determinable. To the extent that actual energy use from meter read dates to each month-end differs from estimated use based upon a constant usage assumption, estimated unbilled revenues could be significantly different from actuals.

Estimated provisions for uncollectible accounts receivable from retail electricity sales are recorded in the same period as the related revenues. These estimates are based on management's assessment of the probable collection of customer accounts, aging of accounts receivable, bad debt write-offs, and other factors. Certain circumstances and events can cause actual bad debt write-offs to vary from assumptions used in estimating uncollectible account provisions; these include general economic conditions, industry trends, deterioration of major customer credit worthiness, and higher defaults. PGE's earnings would be affected should such circumstances require a material adjustment to the Company's provision for uncollectible accounts.

PGE's services to affiliated companies consist primarily of employee and corporate governance services. The Company also receives services from affiliated companies for employee benefit plans and corporate overheads. Transactions with affiliated companies are subject to regulation by the OPUC and, since Enron registered as a holding company, by the SEC. Most affiliated interest transactions are made under a Master Service Agreement (MSA) approved by the Commission and the SEC. Any transactions not covered by the MSA must be separately approved. Under OPUC regulations, services provided to affiliates by PGE are charged at the higher of cost or market, while affiliated services received by PGE are charged at the lower of cost or market. Under SEC regulations, affiliated services are charged at cost. Services will be provided at cost, unless there is a conflict between OPUC and SEC regulations, in which case PGE and Enron have agreed not to provide the services until the matter can be resolved.

The ultimate disposition of the intercompany receivable and payable balances with Enron and its subsidiaries at December 31, 2003 is uncertain due to the bankruptcy proceedings of Enron and certain of its subsidiaries. The Company has recorded provisions against certain receivable balances due from Enron companies in bankruptcy. For further information, see Note 13, Related Party Transactions, in the Notes to Financial Statements, and "Enron Bankruptcy" in the Financial and Operating Outlook section.

PGE trading activities utilize electricity forward, swap, and option contracts, natural gas forward, swap, option, and futures contracts, and crude oil futures contracts to participate in electricity, natural gas, and crude oil markets. Valuation of these instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value of money, and volatility factors underlying the commitments. At December 31, 2003, all energy trading contracts have a maturity of less than one year. The following tables indicate fair values, and changes in fair values, of PGE's trading contracts in 2003 and 2002, as well as the source of the fair value of the unrealized loss at December 31, 2002 (in millions):

Weather adjusted retail energy sales decreased 1.0% in 2003 compared to 2002. An 8.7% decrease in industrial energy sales was partially offset by 2.0% and 1.0% increases, respectively, in residential and commercial energy sales. Industrial sales declined primarily due to reduced energy use in the second half of 2003 by two large customers, one of which elected to obtain its electricity requirements through co-generation. These two large customers represented 2.7% and 5%, respectively, of weather adjusted retail energy sales in 2003 and 2002. The increase in residential sales was largely attributable to an approximate 1.6% increase in customers served. PGE forecasts retail energy sales growth of approximately 1% in 2004.

Wholesale power market products, along with PGE's base of thermal and hydroelectric generating capacity, currently provide the Company the flexibility to respond to seasonal fluctuations in the demand for electricity from its retail and wholesale customers. Although surplus generation has diminished in recent years due to economic and population growth in the western United States, the recent construction of new generating plants has increased the region's capacity to meet its power needs. The Company anticipates that an active wholesale market and generating capacity within the WECC will provide wholesale energy to supplement its generation and purchases under existing firm power contracts.

Early forecasts indicate that regional hydro conditions will continue at below normal levels in 2004. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, indicate the projected January-to-July 2004 runoff at 87% of normal, compared to 83% in 2003 and 97% in 2002. Hydro conditions in both the Clackamas and Deschutes river systems, where PGE's facilities are located, are projected to be near normal in 2004. Efforts to restore salmon runs on the Columbia and Snake rivers may reduce the amount of water available for generation, which could affect the availability and price of purchased power.

Additional factors that could affect the availability and price of purchased power and fuel include weather conditions in the Northwest during winter months and in the Southwest during summer months, as well as the performance of major generating facilities in both regions.

Commencing in December 2001, Enron and certain of its subsidiaries (Debtors) filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. PGE is not included in the bankruptcy, but the common stock of PGE held by Enron is part of the bankruptcy estate.

The Debtors have filed their proposed joint Chapter 11 plan (the Chapter 11 Plan) and related disclosure statement (the Disclosure Statement) with the Bankruptcy Court. The Chapter 11 Plan and Disclosure Statement, as amended, provide information about the assets that are in the bankruptcy estate, including the common stock of PGE, and how those assets will be distributed to the creditors. The Chapter 11 Plan and the Disclosure Statement are available at Enron's website located at www.enron.com/corp/por and the Bankruptcy Court's website located at "http://www.nysb.uscourts.gov/">www.nysb.uscourts.gov and at the website maintained at the direction of the Bankruptcy Court at www.elaw4enron.com.

Enron has entered into an agreement to sell PGE, which has been approved by the Bankruptcy Court. The sale requires certain regulatory approvals. If the sale does not close, shares of PGE's common stock will be distributed over time to the Debtors' creditors. It is anticipated that once a sufficient amount of the common stock is distributed to creditors, the shares would be publicly traded. The Chapter 11 Plan is subject to creditor approval and confirmation by the Bankruptcy Court.

On November 18, 2003, Enron and Oregon Electric, a newly-formed Oregon limited liability company financially backed by investment funds managed by Texas Pacific Group, entered into an agreement under which Enron will sell all of the issued and outstanding common stock of PGE to Oregon Electric. The transaction is valued at approximately $2.35 billion, including the assumption of debt. The final amount of consideration will be determined on the basis of PGE's financial performance between January 1, 2003 and closing. The transaction, previously approved by the Enron Board of Directors and supported by the Official Unsecured Creditors' Committee, was approved by the Bankruptcy Court on February 5, 2004. The transaction also requires approval of the OPUC, the FERC, and certain other regulatory agencies. On March 8, 2004, application for approval of the acquisition of PGE by Oregon Electric was filed with the OPUC. Filings will be made with the other agencies over the ensuing wee ks. A decision is expected by year-end 2004.

If PGE is not sold, under the Chapter 11 Plan the shares of PGE's common stock will be distributed over time to the Debtors' creditors. Until shares are distributed to creditors, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of the creditors.

Until the Chapter 11 Plan or another filing related to the sale of PGE is approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's common stock to the Debtors' creditors.

Although PGE is not included in the Enron bankruptcy, it has been affected. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been de-listed from the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC and the State of Oregon. PGE has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating.

In addition to the general effects discussed above, PGE may have potential exposure to certain liabilities and asset impairments as a result of Enron's bankruptcy. These are:

1. Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS has completed an audit of the consolidated tax returns for 1996-2001.
2. For years 1996 through 1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries with substantial NOLs which may be used to offset additional income tax liabilities that may result from negotiation of the IRS audit for the taxable periods PGE was a member of Enron's consolidated federal income tax returns.
3. Enron's 2002 tax return was filed on September 12, 2003. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2002. Enron had 2002 NOLs sufficient to eliminate Enron's regular and alternative minimum income tax liabilities for 2002 and expects to have sufficient NOLs to offset its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.

PGE management cannot predict with certainty what impact Enron's bankruptcy, including the Chapter 11 Plan, may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Neither PGE nor Enron have guaranteed the obligations of the other. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and PGC in 1997 (Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's common equity capital to fa ll below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.

PGE management does not believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. As a solvent enterprise in bankruptcy, PGE would owe fiduciary obligations to its shareholders and creditors. If a bankruptcy were commenced, the United States Trustee would form a creditors' committee comprised of PGE's largest creditors, and any plan of reorganization would be subject to confirmation by the Bankruptcy Court. Prior to the effectiveness of such plan, no dividends could be paid to Enron, and no assets could be sold, or transfer of funds could be made, outside the ordinary course of business except with the approval of the Bankruptcy Court. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede sta te regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in litigation. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder.

PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor in possession credit agreement with Citicorp USA, Inc. and JPMorgan Chase Bank. The agreement was amended and restated in July 2002 and in May 2003. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control over PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

In 1983, PGE adopted certain non-qualified deferred compensation arrangements and associated "rabbi" trusts for the benefit of key employees, officers, and directors. In 1989, sponsorship of these arrangements was transferred to Portland General Corporation (which was subsequently merged into Enron in 1997) and in 1997 sponsorship was transferred to PGH. Although plan sponsorship was transferred, PGE continued to participate in these plans as a participating employer for the benefit of its own employees. Portland General Corporation, PGH, and certain of their subsidiary companies also had employees who participated in these plans. The plan documents specifically provide that: (1) a participating employer's obligation under the plans shall be that of an unfunded and unsecured promise to pay money in the future; and, (2) the payment of a participant's benefit pursuant to the plan shall be borne solely by the participating employer that employs the participant and reports the particip ant as being on its payroll during the accrual or increase of the plan benefit, and no liability for the payment of any plan benefit shall be incurred by reason of plan sponsorship or participation except for the plan benefits of a participating employer's own employees. Upon the bankruptcy filing by Enron and certain of its affiliates, and the subsequent bankruptcy filing of PGH, payment by those companies of participant benefits under these plans ceased. Since PGE is not in bankruptcy, benefit payments to participants due benefits from PGE have continued. Plan participants with benefits due from the bankrupt companies have sought to have the companies or the trusts commence payments without success. Certain of these Plan participants have indicated their intention to commence a lawsuit against PGE and other parties if they are unable to reach a resolution with respect to their benefit payments. If any lawsuit is filed, PGE intends to vigorously defend that case.

The City Council of Portland, Oregon received professional advice regarding the City's potential acquisition of PGE, including possible condemnation of PGE's assets, and signed a confidentiality agreement with Enron to permit it to participate in the Enron auction. The City did not participate in the overbid process following the Bankruptcy Court filing of Texas Pacific Group's agreement to purchase PGE. It is unclear at this time whether the City of Portland will continue to pursue the acquisition of PGE.

Proponents of the formation of Peoples' Utility Districts (PUDs) to acquire PGE's service territory obtained sufficient signatures on initiative petitions to place measures on election ballots in Multnomah, Yamhill, and Clackamas Counties. The formation initiative in Multnomah County, which appeared on the November 4, 2003 ballot, did not pass. On March 9, 2004, the voters in Yamhill County (which currently has approximately 24,000 PGE customers) also rejected a PUD initiative. In Clackamas County (which currently has approximately 158,000 PGE customers), the vote on formation of a PUD has been set for the May 18, 2004 ballot.

If PUDs are formed, they would have the authority to condemn PGE's distribution assets within the boundaries of the districts. Oregon law prohibits a PUD from condemning thermal generation plants. It is uncertain under Oregon law whether a PUD would be able to condemn PGE's hydro generation plants.

PGE opposes the formation of PUDs in its service territory and will oppose any efforts to condemn PGE's assets.

Pursuant to PGE's 2001 general rate filing, the OPUC authorized retail price increases, effective October 1, 2001. The increase provided approximately $440 million in additional annual revenues, primarily as the result of significant increases in the cost of wholesale power and fuel. In its rate order, the Commission established PGE's return on equity at 10.5% and approved price increases of approximately 31.6% for residential customers, 37.3% for smaller business customers, and 53.2% for commercial and industrial customers. In addition, the OPUC approved a power cost adjustment mechanism covering the period October 2001 through December 2002 (described below).

In order to protect both PGE and its customers from price volatility in the wholesale power and natural gas markets, the OPUC authorized the Company to defer for later recovery from retail customers actual net variable power costs which differed from certain baseline amounts approved by the Commission. Under the initial power cost adjustment mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received OPUC approval to recover the approximate $91 million balance (including interest) over a 3 1/2-year period (April 2002 - September 2005). At December 31, 2003, the remaining balance to be collected was approximately $48 million.

In its August 2001 general rate order, the OPUC approved a power cost adjustment mechanism for the period October 2001 through December 2002. Under this mechanism, PGE deferred approximately $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, as well as the difference between actual energy revenues and a pre-determined base. The deferred amount, which is subject to a prudence review and audit currently being conducted by the OPUC, is being collected over a two-year period (2003-2004). Recovery from large industrial customers was completed during 2003. At December 31, 2003, the balance to be collected was approximately $10 million. PGE did not have a power cost adjustment mechanism in place for 2003.

The OPUC's 2001 general rate order contains a Power Cost Stipulation that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines for Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, a Resource Valuation Mechanism (RVM) utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. The RVM process requires that PGE adjust its rates if projected power costs change from those included in the previous RVM rate process. It provides for an adjustment, filed annually in April and finalized in mid-November, which is effective January 1 of the following year.

PGE's first annual revision of its power supply costs under the RVM process forecast a reduction in the cost of power from that included in the Company's 2001 general rate case. Accordingly, the OPUC authorized an approximate 7% average reduction in the Company's retail prices, effective January 1, 2003. Price decreases ranged from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers are affected more by wholesale energy market prices, which decreased in the 2003 forecast. The smaller decrease in residential rates reflects both PGE's cost of generation as well as the higher cost of electricity from BPA, which increased its rates in October 2002. These price decreases reduced PGE's 2003 revenues by approximately $90 million.

Included in the 2003 price reduction was the effect of the Commission's disallowance of approximately $15 million related to four power purchase contracts, entered into in the first nine months of 2001, providing 125 megawatts of on-peak delivery in 2003. Also reflected in the price reduction was a resolution regarding the recovery period for PGE's power cost adjustment mechanism covering the period October 2001 through December 2002 and the effect of a settlement stipulation related to estimated 2003 power costs. Under the settlement, PGE agreed to reduce its recovery under the power cost adjustment mechanism by approximately $4.6 million, which was reflected as a reduction to the Company's earnings for 2002.

In August 2003, PGE, OPUC staff, and intervenors entered into a stipulation, approved by the Commission, related to the Company's forecast of 2004 net variable power costs. Forecast adjustments were made to the price of certain wholesale power purchase contracts, reflecting recent electricity forward prices and certain other modifications and adjustments to estimated variable power and fuel costs. The 2004 RVM was finalized in November 2003, with new rates effective January 1, 2004. The average price for all customers increased by approximately 0.4%. Price adjustments range from a 2.3% decrease for industrial customers to increases of 2.8% and 1.9% for small commercial and residential customers, respectively. Price adjustments varied between customer classes primarily due to different collection periods for PGE's 2001-2002 power cost adjustment mechanism (see "Power Cost Adjustment Mechanisms" in this section for further information). Based upon projected energy sales, it is estimated that the price adjustments will increase PGE's 2004 revenues by approximately $4 million.

The stipulation also provides that PGE withdraw a proposed power cost adjustment mechanism for 2004 and participate in a process to address the need for, and structure of, a cost recovery mechanism for variances in power costs from forecasted levels. PGE continues to work with customer groups and the OPUC staff on the development of a multi-year power cost adjustment mechanism, with particular focus on power cost variations caused by changes in hydro conditions.

In anticipation of the effects of adverse hydro conditions, PGE began in early 2003 to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those included in the Company's electric rates.

On February 11, 2003, PGE filed an Application for Deferral of Hydro Replacement Power Costs with the OPUC, in which the Company requested authorization to defer for later ratemaking treatment increases in power costs incurred from the application date through December 31, 2003. The Company's application requested authorization for the deferral of 95% of the difference between actual net variable power costs and those allowed in current rates. As proposed, the deferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Under the Company's proposed methodology, approximately $25 million in power costs would have been deferred for future ratemaking treatment in 2003. On March 2, 2004, the OPUC denied PGE's application for the deferral of hydro replacement power costs incurred in 2003.

On December 31, 2003, PGE filed an Application for Deferral of 2004 Hydro Related Costs with the OPUC covering the year 2004. The application, similar to the February 2003 filing, requests the deferral of excess power costs resulting from hydro conditions that vary from those assumed in the 2004 RVM process. PGE continues to work with parties to develop a multi-year power cost adjustment mechanism that focuses on power cost variations caused by changes in hydro conditions.

PGE's long-term power purchase contracts with certain public utility districts in the state of Washington expire between 2005 and 2018. PGE has executed new agreements with Grant County Public Utility District (Grant), operator of the Priest Rapids and Wanapum projects, for periods corresponding to Grant's new license term to be determined by the FERC. The new agreements are effective upon expiration of the current contracts in 2005 and 2009 and are subject to FERC approval. Under the agreements, Grant will annually determine the output required for its purposes, with PGE required to purchase approximately 25% of the output beyond Grant's needs over the term of the new license, for which PGE will pay a proportional share of the project's debt service and operating costs. PGE's share of the output will decline over time as Grant's needs increase, with the Company's share in the two projects reduced from the current 237 MW to an estimated 189 MW in 2009. Also under the agreements, PG E will purchase an additional 41 average megawatts of power during the period 2005 through 2011.

In March 2002, the Yakama Indian Nation filed a complaint with FERC, alleging that the Grant settlement contracts relating to the sale of power from the Project unreasonably restrain trade and violate various sections of the Federal Power Act and Public Law 83-544, and have harmed it monetarily and otherwise. FERC ruled on this complaint in November 2002, and while dismissing it, found that the non-compete clauses in the Grant settlement agreements violate section 10(h)(1) of the Federal Power Act. In December 2002, PGE filed a request for rehearing with FERC, and in April 2003, this request was denied. Both the Yakama Indian Nation and Grant appealed the November 2002 FERC decision and the appeals have been consolidated in the Ninth Circuit Court of Appeals.

In 2003, the Colville Confederated Tribes presented a claim to Douglas County PUD based upon alleged annual charges for the Wells Hydroelectric Project for the use of Colville tribal lands. The Colville Confederated Tribes claimed that annual charges would also be due for periods into the future. PGE purchases 20.3% of the power generated by the Wells Project. A settlement of this claim could affect the amount of energy PGE receives under the terms of the Company's purchased power contract or the price of the output of the Wells Hydroelectric Project purchased by PGE. Settlement discussions related to this matter are continuing.

For further information regarding the power purchase contracts on the mid-Columbia dams, see Note 7, Commitments, in the Notes to Financial Statements.

Approval of the Trojan Decommissioning Plan by the NRC and EFSC has allowed PGE to proceed with decommissioning activities, which are proceeding satisfactorily and within approved cost estimates. The steam generator, reactor containment vessel, and other major components have been removed and transported to the federal Hanford Nuclear Reservation in Washington State for permanent storage. A license amendment for the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that will house the nuclear fuel until permanent storage is available, was approved by the NRC in 2002. Fuel loading began in late 2002 and was completed in September 2003. PGE completed final radiological surveys of the Containment Building, Main Steam Support Structure, Electrical Penetration Area, Steam Generator Blow Down Building, and the majority of other building exteriors and supported the NRC's confirmatory surveys, with no significant findings or observations.

PGE has recorded an ARO for Trojan decommissioning of $104 million, measured at estimated fair value, as of December 31, 2003. The ARO estimate assumes the majority of decommissioning activities will be completed by 2005. The plan anticipates final site restoration activities will begin in 2018 after PGE completes shipment of spent fuel to a USDOE facility. Decommissioning expenditures are estimated at $15 million for 2004, compared to $21 million in 2003.

Transition activities, consisting of operating the spent fuel pool and securing the plant, ended in September 2003 when the fuel was transferred to dry storage, with remaining activities related primarily to decommissioning of the plant. These efforts position PGE to safely dispose of all radiological hazards, other than spent nuclear fuel, on the Trojan site and to initiate a final radiation survey to prove such hazards are no longer present.

In February 2002, the USDOE formally recommended that Yucca Mountain, Nevada become the nation's first long-term geologic (underground) repository for high-level radioactive waste produced in the United States. Lawsuits have been filed objecting to this recommendation. The proposed location is based on the conclusions of scientific studies of the site, conducted over 20 years, that support a finding of suitability as mandated by the Nuclear Waste Policy Act and various regulations of the NRC, USDOE, and the EPA. The House and Senate approved the site and President Bush signed the Yucca Mountain resolution into law on July 23, 2002 (P.L. 107-200). The USDOE must now apply to the NRC for an operating license. Further delays may create difficulties for PGE in disposing of its high-level radioactive waste by 2018. The availability of an off-site repository for the permanent storage of radioactive waste will allow PGE to remove spent nuclear fuel from the ISFSI, allowing final decommissioning a nd release of the Trojan site for unrestricted use. On January 6, 2004, the co-owners of Trojan, including PGE, filed a complaint against the USDOE in the U.S. Court of Federal Claims for failure to accept spent nuclear fuel by January 31, 1998, as required. Damages sought are in excess of $200 million.

In response to the terrorist attacks of September 11, 2001, the NRC issued interim compensatory security measures for a generalized high-level threat environment at closed nuclear reactors that are in the decommissioning process. The new requirements are expected to remain in effect until the NRC determines that the level of threat has diminished, or that other security changes are needed. The NRC issued additional security orders to all operating reactors in April 2003 that require operating plants to update their defensive strategies to counter a highly organized attack. It is expected that corresponding similar orders (limited in scope) will be issued to the Trojan ISFSI in late 2004 or in 2005. Until NRC requirements associated with the expected orders are determined, it is not known whether any related implementation costs will impact the Trojan decommissioning cost estimate and related funding requirements. However, as new security requirements are evaluated, any additional costs wil l be determined and decommissioning cost estimates revised as necessary.

For further information, see Note 12, Trojan Nuclear Plant, in the Notes to Financial Statements.

As of December 31, 2003, PGE has net accounts receivable balances totaling approximately $61 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).

In March 2001, the PX filed for bankruptcy and in April 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code. PGE is pursuing collection of all past due amounts through the PX and PG&E bankruptcy proceedings and has filed a proof of claim in each of the proceedings. Management continues to assess PGE's exposure relative to these receivables. Based upon FERC orders regarding the methodology to be used to calculate refunds and the FERC's indication that potential refunds related to California wholesale sales (see "Refunds on Wholesale Transactions" below) can be offset with accounts receivable related to such sales, PGE has established reserves totaling $40 million related to this receivable amount, including $22.5 million in 2003. The Company is examining numerous options, including legal, regulatory, and other means, to pursue collection of any amounts ultimately not received through the bankruptcy process.

California - In a June 2001 order adopting a price mitigation program for 11 states within the WECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and the PX.

On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering evidentiary hearings to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

Also in August 2002, the FERC Staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in PGE's potential refund obligation.

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. Although no final dollar amounts were included in the certification, the recommended methodology indicated a potential refund by PGE of $20 million to $30 million.

On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge, issued in December 2002, but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimated that the modified methodology could increase the amount of the potential refunds by approximately $20 million, with the Company's potential liability estimated at between $20 million and $50 million.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the pricing methodology. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds, and on December 20, 2003, the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals. Several other parties have also appealed the October 16, 2003 order.

The FERC has indicated that any refunds PGE may be required to pay related to California wholesale sales (plus interest from collection date) can be offset by accounts receivable (plus interest from due date) related to sales in California (see "Receivables - California Wholesale Market" above). Interest has not yet been recorded by the Company. In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost adjustment mechanism in effect at that time. This could further mitigate the financial effect of any refunds made or received by the Company.

Pacific Northwest - In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceedings and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders.

Management cannot predict the ultimate outcome of the above matters related to wholesale transactions in California and the Pacific Northwest. However, it believes the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

On June 25, 2003, the FERC ordered numerous entities, including PGE, that participated in the Western wholesale power market between January 1, 2000 and June 20, 2001 to show cause why their participation in specific behaviors and activities during that time period did not constitute gaming in violation of tariffs issued by the ISO and the PX. On August 27, 2003, prior to the due date for the show cause response, PGE and FERC Trial Staff settled Docket No. EL03-165-000 for a payment of $12,730, and with no admission of wrongdoing or liability on the part of PGE. This settlement, and numerous similar settlements involving other of the show cause respondents, have been contested by certain parties to the proceedings. By order issued March 8, 2004, FERC approved this settlement.

Also on June 25, 2003, the FERC initiated a generic investigation into bids by market participants in ISO and PX markets between May 1, 2000 and October 2, 2000 at levels above $250/Mwh. Entities submitting such bids were required to demonstrate why such bids did not constitute anomalous market behavior under the ISO and PX Market Monitoring and Information Protocols and the extent to which they constituted legitimate business behavior. The FERC indicated that monetary remedies will be the disgorgement of unjust profits associated with violations, and that non-monetary remedies, such as revocation of market-based rates or revisions to codes of conduct, will also be considered. During the indicated time period, PGE made bids that exceeded $250/Mwh in both the ISO and PX markets. PGE submitted responses to FERC data requests in July and August 2003. Following additional analysis, PGE submitted a further response on March 5, 2004.

On March 20, 2002, the California Attorney General filed a complaint with FERC against various sellers in the wholesale power market, alleging that the FERC's market-based rates violate the Federal Power Act (FPA), and, even if market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to refile their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals.

In 1993, following the closure of Trojan, PGE sought full recovery of, and a rate of return on, its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. The filing was a result of PGE's decision earlier in the year to cease commercial operation of Trojan as a part of its least cost planning process. In 1995, the OPUC issued a general rate order which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals, and requested reviews were filed in Marion County Circuit Court, the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and URP each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. On November 19, 2002, the Oregon Supreme Court dismissed the petitions for review. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

In 2000, while the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into settlement agreements, approved by the OPUC in September 2000, which allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, the OPUC issued an order denying all of URP's challenges and approving the accounting and rate making elements of the settlement. URP appealed the decision to the Marion County Circuit Court and on November 7, 2003, the Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have appea led to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On March 24, 2003, PGE was served with two class action suits in Multnomah County Circuit Court, identical to the Marion County cases. On October 24, 2003, the Multnomah County suits were dismissed.

On March 3, 2004, the OPUC re-opened three dockets in which it had addressed the issue of a return on PGE's investment in Trojan, including the 1995 rate order and settlement order, and issued a notice of a consolidated procedural conference before an administrative law judge to determine what proceedings are necessary to comply with the court orders remanding this matter to the OPUC.

Management cannot predict the ultimate outcome of these challenges. However, it believes that the resolution will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for a future reporting period.

A 1997 EPA investigation of a 5.5-mile segment of the Willamette River known as the Portland Harbor revealed significant contamination of sediments within the harbor. Based upon analytical results of the investigation, the EPA included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund).

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any hazardous substances had been released from the substation property into the Portland Harbor sediments. In May 2000, the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (the Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement.

In December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. The notice included a "Portland Harbor Initial General Notice List" containing sixty-eight other companies that the EPA believes may be Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

In March 2001, in accordance with the Voluntary Agreement, PGE submitted a final investigation plan to the DEQ for approval. DEQ approved the plan and in June 2001 PGE performed initial investigations and remedial activities based upon the approved investigation plan. The investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

In February 2002, PGE submitted its final investigative report to the DEQ summarizing its investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such voluntary investigation demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site. Further, the voluntary investigation demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement. Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis Potentially Responsible Party.

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign, nor has it signed, such an order.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE. Management cannot predict the ultimate outcome of this matter or estimate any potential loss. However, it believes this matter will not have a material adverse impact on its financial statements.

In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund Site. Sufficient information is currently not available to determine the total costs related to this matter. However, PGE believes this matter will not have a material adverse impact on its financial statements.

FASB Interpretation No. 46 (FIN 46) Revised December 2003, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, was issued on December 24, 2003. FIN 46 provides guidance on the identification and consolidation of entities (termed "variable interest entities") for which control is achieved by means other than through voting rights. The application of FIN 46 is required in financial statements of entities that have interests in structures commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application of FIN 46 for all other types of variable interest entities is required in financial statements for periods ending after March 15, 2004. Management does not believe that the application of FIN 46 will have a material impact on the Company's financial statements.

On January 12, 2004, the Financial Accounting Standards Board released FASB Staff Position No. FAS 106-1 (FSP 106-1), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law on December 8, 2003 and introduces a prescription drug benefit under Medicare and provides a federal subsidy to sponsors of certain retiree health care benefit plans. Uncertainties exist regarding the effects of the Medicare Act on PGE's accumulated postretirement benefit obligation and net postretirement benefit costs and the accounting for those effects, if any. Under FSP 106-1, plan sponsors are allowed to elect a one-time deferral of the accounting for the Medicare Act. Amounts and disclosures related to PGE's accumulated postretirement benefit obligation and net postretirement benefit costs in the financial statements a nd accompanying notes do not reflect the effects of the Medicare Act on the plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require PGE to change previously reported information.

This report contains statements that are forward-looking within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or 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 are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by PGE, 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 PGE'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 PGE to differ materially from those discussed in forward-looking statements include:

• matters related to Enron and certain of its subsidiaries' filings to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);
• events related to Enron's bankruptcy proceedings;
• events related to Enron's proposed sale of PGE to Oregon Electric;
• effects of electric industry restructuring in Oregon and in the United States, including retail and wholesale competition;
• governmental policies and regulatory investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and rate structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of net variable power costs and other capital investments, and present or prospective wholesale and retail competition;
• changes in weather, hydroelectric, and energy market conditions, which could affect PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;
• wholesale energy prices (including the effect of FERC price controls) and their effect on the availability and price of wholesale power purchases and sales in the western United States;
• the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;
• operational factors affecting PGE's power generation facilities;
• changes in, and compliance with, environmental and endangered species laws and policies;
• financial or regulatory accounting principles or policies imposed by governing bodies;
• residential, commercial, and industrial growth and demographic patterns in PGE's service territory;
• the loss of any significant customer, or changes in the business of a major customer, that may result in changes in demand for PGE services;
• the ability of PGE to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;
• capital market conditions, including interest rate fluctuations and capital availability;
• changes in PGE's credit ratings, which could have an impact on the availability and cost of capital;
• legal and regulatory proceedings and issues;
• employee workforce factors, including strikes, work stoppages, and the loss of key executives; and,
• general political, economic, and financial market conditions.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

PGE is exposed to various forms of market risk, including changes in commodity prices, foreign exchange rates, and interest rates. These changes may affect the Company's future financial results, as discussed below.

PGE's primary business is to provide electricity to its retail customers. The Company uses both long- and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to fluctuations in the demand for electricity and variability in generating plant operations. In meeting these needs, PGE is exposed to market risk arising from the need to purchase power and to purchase fuel for its natural gas and coal fired generating units. The Company uses instruments such as forward contracts, which may involve physical delivery of an energy commodity, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options, and futures contracts to mitigate risk that arises from market fluctuations of commodity prices.

Gains and losses from non-trading instruments that reduce commodity price risks are recognized when settled in Purchased Power and Fuel expense, or in wholesale revenue. In addition, Company policy allows the use of these instruments for trading purposes, which may expose the Company to market risks resulting from adverse changes in commodity prices. Under EITF 02-3, gains and losses on such instruments are recognized on a net basis within Operating revenues on PGE's income statement. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value of money, and volatility factors underlying the commitments.

PGE actively manages its risk to ensure compliance with its risk management policies. The Company monitors open commodity positions in its energy portfolios using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 months, including estimates of retail load and plant generation in the non-trading portfolio. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology, the average, high, and low value at risk on the trading portfolio in 2003 were $0.1 million, $0.4 million, and zero, respectively, in 2002 were $0.1 million, $0.4 million, and zero, respectively, and in 200 1 were $0.8 million, $3.6 million, and zero, respectively. The instances of zero value at risk occur when there are no open positions in the trading portfolio. The average, high, and low value at risk on the non-trading portfolio in 2003 were $2.0 million, $3.7 million, and $1.0 million, respectively. For 2002 and 2001, the value at risk on the non-trading portfolio is not meaningful since the majority of the portfolio was effectively accounted for on an accrual or settlements basis. Additionally, PGE had power cost adjustment mechanisms in 2001-2002 that allowed the Company to defer, for future rate making treatment, actual net variable power costs that differed from certain baseline amounts approved by the OPUC (see "Power Cost Adjustment Mechanisms" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). In 2003, 2002, and 2001, PGE did not reduce its non-trading value at risk by the amount of potential deferrals.

PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars, primarily in its non-trading portfolio. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE monitors its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy. Beginning in 2003, PGE implemented a strategy that utilizes forward contracts to acquire Canadian dollars in order to mitigate its currency exposure.

At December 31, 2003, a 10% change in the value of the Canadian dollar would result in an immaterial change in pre-tax income for transactions that will settle over the next 10 months. Foreign currency risk in PGE's trading portfolio is immaterial to the Company's consolidated financial statements and is not expected to change materially in the near future.

Although PGE has no short-term debt outstanding at December 31, 2003, the Company is typically exposed to risk resulting from changes in interest rates on variable rate short-term borrowings. Although PGE currently has no financial instruments to mitigate such risk, it will consider such instruments in the future as necessary.

The total fair value and carrying amounts (including current maturities) of PGE's long-term debt are as follows (in millions):

For detail of debt by category, see Note 5, Credit Facility and Debt, in the Notes to Financial Statements.

PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. PGE manages the risk of counterparty default according to its credit policies by performing financial credit reviews and setting limits and monitoring exposures, requiring collateral when needed, and using standardized enabling agreements which allow for the netting of positive and negative exposures associated with a counterparty. Despite such mitigation efforts, defaults by counterparties may periodically occur. Valuation allowances are provided for credit risk.

Credit risk with respect to trade accounts receivable from retail electricity sales is limited. The large number of customers and diversified customer base of residential, commercial, and industrial customers, combined with the Company's ability to discontinue service, significantly reduces credit risk. Estimated provisions for uncollectible accounts receivable related to retail electricity sales are provided for credit risk. At December 31, 2003, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following tables present PGE's credit exposure for commodity non-trading and trading activities and their subsequent maturity as of December 31, 2003. The tables reflect credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. The netting of counterparty balances is reflected only to the extent PGE has the contractual right of offset.

Investment grade includes counterparties with a minimum senior unsecured debt credit rating of Baa3 assigned by Moody's Investor Service (Moody's) and BBB- assigned by Standard & Poor's Rating Group (S&P). Non-investment grade includes counterparties with credit ratings that are below investment grade. The credit exposure includes activity for electricity and natural gas forward, swap and option contracts. Credit collateral posted may be in the form of cash or letters of credit and may represent prepayment or credit exposure assurance.

Omitted from the non-trading market risk exposures above are long-term power purchase contracts with certain public utility districts in the State of Washington and with the City of Portland, Oregon. These contracts provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2018. Management believes that circumstances that could result in the nonperformance by these counterparties are remote.

PGE has a Risk Management Committee, which is responsible for the oversight of commodity position and price risk, foreign currency risk, and credit risk related to wholesale energy marketing activities. PGE's Risk Management Committee consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The Risk Management Committee approves trading and credit policies and procedures, establishes limits subject to Enron approval, and monitors compliance and risk exposure on a regular basis through reports and meetings.

For further information, including accounting policies for price risk management activities, see Note 8, Price Risk Management, in the Notes to Financial Statements.

The following financial statements of Portland General Electric Company and its subsidiaries (collectively, PGE) were prepared by management, which is responsible for their integrity and objectivity. The statements have been prepared in conformity with generally accepted accounting principles and necessarily include some amounts that are based on the best estimates and judgments of management.

PGE maintains a system of internal control over financial reporting, which encompasses policies, procedures, and controls designed to provide reasonable assurance as to the reliability of the financial statements and for the protection of assets from unauthorized acquisition, use or disposition. This system is augmented by the careful selection and training of qualified personnel. It should be recognized, however, that there are inherent limitations in the effectiveness of any system of internal control. Accordingly, even an effective system of internal control over financial reporting can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Further, because of changes in conditions, internal control system effectiveness may vary over time.

PGE also has disclosure controls and procedures that are designed to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (SEC). The disclosure controls and procedures are also designed to ensure that information required to be disclosed is accumulated and communicated to PGE management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Deloitte & Touche LLP was engaged to audit the 2003 financial statements of PGE and issue a report thereon. PricewaterhouseCoopers LLP was engaged to audit the 2002 and 2001 financial statements of PGE and issue a report thereon. Their audits included developing an overall understanding of PGE's accounting systems, procedures, and internal controls, and conducting tests and other auditing procedures sufficient to support their opinions on the financial statements. The independent auditors' reports appear in this report.

The adequacy of PGE's internal controls, disclosure controls and procedures, and the accounting principles applied in financial reporting are under the general oversight of the Audit Committee of PGE's Board of Directors. The independent auditors have direct access to the Audit Committee, and they meet with the committee from time to time, with and without financial management present, to discuss accounting, auditing and financial reporting matters.

We have audited the accompanying consolidated balance sheet of Portland General Electric Company and subsidiaries as of December 31, 2003, and the related consolidated statements of income, retained earnings, comprehensive income, and cash flows for the year then ended. Our audit also included the financial statement schedule for the year ended December 31, 2003 listed in Item 15 (a). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule for the year ended December 31, 2003, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Notes 1 and 11 to the consolidated financial statements, in 2003 the Company changed its method of accounting for asset retirement obligations and its presentation of operating revenues and operating expenses associated with non-trading electric derivative activities.

Deloitte & Touche LLP

Portland, Oregon

March 18, 2004

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) present fairly, in all material respects, the financial position of Portland General Electric Company and its subsidiaries at December 31, 2002 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management; our re sponsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of reporting for contracts involved in energy trading and risk management activities in the third quarter of 2002.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments as of January 1, 2001.

PricewaterhouseCoopers LLP

Portland, Oregon

March 11, 2003