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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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 15

Item 3. Legal Proceedings 18

Item 4. Submission of Matters to a Vote of Security Holders 21

Item 5. Market for Registrant's Common Equity and

Related Stockholder Matters 22

Item 6. Selected Financial Data 22

Item 7. Management's Discussion and Analysis of Financial

Condition and Results of Operations 23

Item 7A. Quantitative and Qualitative Disclosures About

Market Risk 62

Item 8. Financial Statements and Supplementary Data 64

Item 9. Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure 113

Item 10. Directors and Executive Officers of the Registrant 114

Item 11. Executive Compensation 120

Item 12. Security Ownership of Certain Beneficial Owners

and Management and Related Stockholder Matters 123

Item 13. Certain Relationships and Related Transactions 123

Item 14. Controls and Procedures 124

Item 15. Exhibits, Financial Statement Schedules and

Reports on Form 8-K 125

Signature Page 127

Certifications 128

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 wholesale electric energy to utilities, brokers, and power marketers located throughout the western United States. PGE's service area is located entirely within Oregon and covers 3,150 square miles. It includes 51 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of 4,095 square miles. PGE estimates that at the end of 2002 its service area population was approximately 1.5 million, comprising about 44% of the state's population. The Company added approximately 7,700 customers during 2002, and at December 31, 2002 served approximately 743,000 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 is not included in the filing. 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, 2002, PGE had 2,757 employees. This compares to 2,790 and 2,781 employees at December 31, 2001 and 2000, respectively. A total of 902 employees are covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 885 employees for a three-year period effective from March 1, 2002 through February 29, 2004; negotiations on a new agreement are expected to begin in late 2003. In addition, 17 employees at Coyote Springs are covered under an agreement effective from September 1, 2001 through August 1, 2006.

PGE's diverse retail customer base has helped mitigate the effects of a significant downturn in Oregon's economy. Residential, the largest customer class, comprises about 88% of the Company's total number of customers, and in 2002 provided 38% of total retail MWh energy sales and 41% of retail tariff revenues. Residential demand is sensitive to the effects of weather, with revenues highest during the winter heating season. Commercial and industrial customers provided about 40% and 19%, respectively, of retail tariff revenues in 2002. While total retail MWh energy sales decreased somewhat from 2001, reflecting the continuing effect of Oregon's slow economy and conservation efforts, revenues increased approximately 35%, reflecting a general rate increase that became effective October 1, 2001 (see "Retail Rate Changes" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information).

Commercial and industrial customer classes are not dominated by any single industry. While the 20 largest customers constitute about 21% 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 3.4% of PGE's total retail load.

Non-trading wholesale electricity sales related to activities to serve retail load requirements comprised about 21% of total operating revenues in 2002, down from about 54% in 2001. The decrease was due to significantly lower wholesale market prices. 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 power for its customers at the lowest cost available.

Other operating revenues include net gains and losses from PGE's energy trading activities, which seek to take advantage of price movements in electricity, natural gas, and crude oil. 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 further ensures that prices are fair, equitable, 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.

PGE is also subject to the jurisdiction of the FERC with regard to the transmission and sale of wholesale electric energy, licensing of hydroelectric projects, and certain other matters. The Company is a "licensee" and a "public utility" as those terms are used in the Federal Power Act and is, therefore, also subject to regulation by the FERC as to accounting policies and practices, transmission and wholesale prices, issuance of short-term debt, and other matters.

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. In October 2002, the NRC approved the transfer of spent nuclear fuel from the Trojan spent fuel pool to the Trojan Independent Spent Fuel Storage Installation (ISFSI), using a separately licensed dry cask storage system. 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 Ene rgy also monitors Trojan. For further information, see "Nuclear Decommissioning" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 11, Trojan Nuclear Plant, in the Notes to Financial Statements.

PGE is a subsidiary of a holding company (Enron) exempt under PUHCA, except for Section 9(a)(2) with respect to the acquisition of the securities of other public utilities. In February 2002, Enron applied to the SEC to continue its exemption, which requires that PGE's utility activities be predominantly intrastate in nature. In February 2003, an administrative law judge issued an Initial Decision that denied Enron's application for exemption, holding that PGE does not meet the criteria to be predominantly intrastate in character. On February 27, 2003, Enron filed a Petition for Review with the SEC requesting that the SEC review the Administrative Law Judge's Initial Decision, reverse such Initial Decision, and find that Enron is entitled to exemption from PUHCA. Filing of the Petition for Review stays the effect of the Initial Decision until such time as the SEC may act on the Petition for Review. The SEC could act on the Petition for Review at any time. Possible responses of the SEC to th e Petition for Review include setting the matter down for further hearings before the full Commission or summarily affirming the Initial Decision. In the event that the Initial Decision is affirmed by the SEC, either summarily or after further hearings, Enron could be required to register as a holding company under PUHCA, and PGE would become a subsidiary of a registered holding company. If PGE were be become a subsidiary of a registered holding company, it would become subject to additional regulation by the SEC with respect to certain matters, including transactions with Enron. For further information, see "Public Utility Holding Company Act of 1935" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

On March 1, 2002, Oregon's electric energy industry restructuring plan was implemented. Signed into law as State Senate Bill 1149 by the state's governor, the restructuring plan provides all commercial and industrial customers of investor-owned utilities direct access to competing energy suppliers. Residential and small business 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. For further information, see "Regulation and Competition" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

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

In August 2002, PGE filed a new Integrated Resource Plan. In its Plan, PGE describes its strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. The Plan, which considers resource actions over the next two to three years, includes reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, long-term power purchases, and meeting seasonal peaking requirements through seasonal exchanges, demand-side management, capacity tolling contracts, and combustion turbine development.

PGE filed a supplement to the Plan on February 28, 2003. The OPUC has initiated a schedule for input and review, with an acknowledgement of the Company's Plan, as supplemented, anticipated by mid-2003. PGE then anticipates issuing a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of additional generation (including the Port Westward gas turbine project), and the availability of reasonably priced medium to long-term power purchases from the market. PGE will continue to monitor changes in economic conditions and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.

Based upon results of the RFP process, PGE will update its action plan with specific resource recommendations and request acknowledgement that the Company's final action plan is consistent with least cost planning principles established by the OPUC.

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 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 be on a single network transmission tariff, and operational control of the transmission network would be administered by the RTO. The FERC is expected to issue further clarification on the implementation of Standard Market Design in April 2003.

In September 2002, the formation plan of RTO West received preliminary FERC approval, with some modification and further development of certain details. In its approval ruling, the FERC stated that the RTO West proposal, with some modification and further development of certain details, will satisfy Order No. 2000 requirements and provide a basic framework for a Standard Market Design for the West.

Also in September 2002, the FERC granted preliminary approval of a proposed rate structure for TransConnect, a new company proposed by PGE and two other regional utilities. Conditional approval from the FERC was received in 2001. As proposed, TransConnect would be an independent, jointly owned, for-profit transmission company that will participate in RTO West and which could own or lease the high-voltage transmission facilities currently held by PGE and its other participants. 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.

Decisions to move forward with 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 (NW Natural), 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 electric power restructuring law, related regulations, and PGE's tariff. For additional information, see "Regulation and Competition" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

Competition has transformed the electric utility industry at the wholesale level. The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers, and power marketers, and provided 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, requiring investor-owned utilities to allow others access to their transmission systems for wholesale power sales. This access must be provided at the same price and terms the utilities would apply to their own wholesale customers. It also requires reciprocity from municipals, cooperatives, and federal power marketers receiving service under the tariff and allows public utilities to recover stranded costs in accordance with the terms, conditions, and procedures set forth in the order.

The Company'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.

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 take advantage of price movements in electricity, natural gas, and crude oil.

In addition to the potential loss of revenues from those commercial and industrial customers that may choose to purchase energy directly from competing energy suppliers, there is also 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 examined by ratepayer activists and by certain local governments. 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 electric power 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 the Company's cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases. In the last half of 2000 and first half of 2001, both the cost and availability of power were adversely affected by a reduction in the availability of surplus generation and weather conditions in California and the Southwest that resulted in high demand. In addition, higher natural gas prices and very poor Northwest hydro conditions (accentuated by fish protection spill requirements) further resulted in increased costs and reduced supply. From mid-2001 through the end of 2002, however, additional generation from both new plants and from those returning to service, moderating weather conditions, near-average hydro conditions, additional natural gas supplies, federal price mitigation, and a reduction in demand from both a significa nt downturn in Oregon's economy and conservation efforts have resulted in significantly lower market prices for both electricity and natural gas. These events have affected the balance of market supply and demand, and several independent power producers have delayed or cancelled plans for new generating plants.

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 1,945 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. For further information, see "Hydro Relicensing" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

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.

On January 1, 2002, PGE sold a 33.33% undivided interest in its 450-MW Pelton Round Butte hydroelectric project to the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). PGE has entered into contracts to purchase the Tribes' share of the power from the project for approximately five years, beginning January 2002. For further information, see Note 15, Sale of Pelton Round Butte Hydroelectric Project, in the Notes to Financial Statements.

In early 2001, PGE filed a "Notice of Intent" with Oregon's EFSC to build the Port Westward Generating Project, a new 650-MW gas turbine plant adjacent to the Beaver plant site. An air contamination discharge permit application has been approved, with a site certificate issued on November 8, 2002. All other required permits have either been obtained or are anticipated in the first half of 2003. PGE has not made a decision whether to develop this project at this time.

Assuming OPUC acknowledgement of PGE's Integrated Resource Plan, the Company anticipates issuance of a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of Port Westward (as well as other additional generation), considering the results of the RFP process, changes in economic conditions and resultant demand, and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers. Further decisions regarding the Port Westward project are subject to both of these processes as well as required corporate approvals.

PGE supplements its own generation with long-term and short-term contracts as needed to meet its retail load requirements. Under the provisions of state electricity restructuring legislation, the Company remains obligated to serve all of its customers. Under terms of a separate tariff schedule, certain non-residential customers may provide the Company notice 12 months prior to the start of a calendar year that they do not want PGE to include their loads in Company power purchases for the noticed year. Customers providing such notice may either obtain their power supply directly from an electricity service supplier or they may purchase power from PGE at then prevailing market rates (with price terms of one day to one year in length) for delivery in the noticed year. These customers are also required by the tariff to provide a year's advance notice should they choose to return to PGE for cost of service rates for a subsequent calendar year. For further information, see "Regulation an d Competition" ("State") in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

PGE has long-term power contracts with four hydroelectric projects on the mid-Columbia River, which provide approximately 652 MW of firm capacity. PGE also has firm contracts, ranging from one to twenty-six years, to purchase 828 MW of power from BPA, other Pacific Northwest utilities, and the Tribes. In addition, PGE has an exchange contract with a summer-peaking Southwest 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 145 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 the Southwest peak in the summer due to air conditioning use, while northern loads peak during wi nter 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 2012, assuming the timely completion of planned new generation.

PGE's peak load in 2002 was 3,408 MW, reached on August 13^th; this exceeded the Company's previous summer peak consumption of 3,341 MW in July 1998. Approximately 43% of the Company's 2002 peak load was met with short-term purchases. At December 31, 2002, PGE's total firm resource capacity, including short-term purchase agreements, was approximately 4,434 MW (net of short-term sales agreements of 3,927 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 given rise to 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. While long-term recovery plans for these species may include major operational changes to the region's hydroelectric projects, including PGE's, the impacts to date have been minimal. The biggest change has been modifying the timing of releases of water stored behind the dams in the upper part of the Columbia and Snake River 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 hydroelectric relicensing efforts, in combination with endangered species consultations among the FERC, National Marine Fisheries Service (NMFS) and the United States Fish and Wildlife Service (USFWS), address issues associated with the protection of fish runs on those rivers where PGE operates, including authorization of "take" of listed species. The agencies have completed an ESA consultation on the Deschutes River, the location of the Company's Pelton Round Butte Project, that will be in effect until a new license is granted by the FERC; no significant operational changes to the project have been indicated. The Company awaits conclusion by the federal agencies of consultation with respect to its hydroelectric project on the Sandy River. The Company currently is supporting the federal agencies' E SA consultation activities regarding the Company's projects on the Clackamas and Willamette rivers, with minor operational changes implemented in February 2003 on the Clackamas and planned for 2004 on the Willamette. Completion by the FERC, NMFS, and USFWS of ESA consultation is required to obtain a FERC license or license amendment for hydroelectric projects and provides authorization for take of listed species consistent with the terms and conditions identified through the consultation.

Fuel supply contracts are negotiated to support annual planned plant operations. Flexibility in contract terms allows for the most economic dispatch of PGE's thermal resources in conjunction with the current 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 2003. 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 contracts with the Burlington Northern Santa Fe and Union Pacific Railroads. Coal purchases in 2002, totaling about 2.1 million tons, contained approximately 0.4% 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 provided under contract with Western Energy Company, a wholly owned subsidiary of Westmoreland Mining LLC. The contract provides for delivered 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 utilizes long-term, short-term, and spot market purchases to secure transportation capacity and 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. Firm gas supplies for Beaver, based on anticipated operation of the plant, are purchased at fixed prices for 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. PGE believes that sufficient market supplies of gas are available to fully meet requirements of the plant in 2003 and beyond.

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 purchased at fixed prices for up to 24 months in advance. PGE believes that sufficient market supplies of gas are available to fully meet requirements of the plant in 2003 and beyond.

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 19-day supply of oil at the plant site at December 31, 2002.

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 Note 10, Legal and Environmental Matters, in the Notes to Financial Statements.

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 are also charged with monitoring and administering certain portions of the Act and are required to 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 emission 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. In addition, current emission allowances are sufficient to operate Colstrip, which utilizes wet scrubbers. If necessary, PGE intends to acquire sufficient additional allowances in order to meet excess capacity needs. 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 five of the plants. Licenses for the Sullivan and Bull Run projects expire in 2004 and licenses for all projects on the Clackamas River expire in 2006. 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 FERC requires that a notice of intent to relicense hydroelectric projects be filed approximately five years prior to license expiration. The Company has filed notice to relicense and is actively pursuing renewal of licenses for all of its hydroelectric generating plants except Bull Run, which will not be relicensed. For further information, see "Hydro Relicensing" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

On January 1, 2002, PGE sold a 33.33% undivided interest in its Pelton Round Butte hydroelectric project to the Tribes. For further information, see Note 15, Sale of Pelton Round Butte Hydroelectric Project, in the Notes to Financial Statements.

The rated generating capability at Beaver increased 5 MW based upon revised measurements of the plant's performance in 2002. The generating capability at Faraday increased 4 MW in 2002 due to turbine replacement and rehabilitation.

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.

PGE leases its Portland headquarters complex and 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 regarding recovery of the Trojan investment and decommissioning costs. In August 1993, the OPUC issued the 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, 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. 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 Oregon Court of Appeals 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 decision relating to PGE's recovery of its undepreciated investment in Trojan.

In June 1999, Oregon's governor signed into law Oregon House Bill 3220 authorizing the OPUC to allow recovery of a return on the undepreciated investment in utility property that the utility retires from service. The law retroactively affirmed the OPUC's authority to allow PGE's recovery of a return on its undepreciated investment in Trojan.

Relying on the new legislation, in July 1999, PGE requested the Oregon Supreme Court to vacate the 1998 ruling of the Oregon Court of Appeals denying a return on its undepreciated investment in Trojan and affirm the validity of the OPUC's order allowing such recovery. The URP and CUB opposed the request on the ground that an effort was underway to gather sufficient signatures to place on the ballot a referendum to negate the new legislation. Sufficient signatures were gathered, and in the November 7, 2000 election, the voters approved the referendum rejecting House Bill 3220.

In September 2000, PGE, CUB, and the OPUC Staff settled proceedings related to PGE's recovery of its investment in the Trojan plant (Settlement). Under the agreements, CUB agreed to withdraw from the litigation and support the settlement as the means to resolve the Trojan litigation. 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. Following the Settlement, PGE requested the Oregon Supreme Court to hold in abeyance the PGE and URP Petitions for Review of the 1998 Court of Appeals decision, pending resolution of URP's complaint 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, 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 July 1, 2002, PGE filed a notice and motion to dismiss and vacate with the Oregon Supreme Court seeking to dismiss the pending review of the 1998 decision of the Oregon Court of Appeals and to vacate that decision. On November 19, 2002, the Oregon Supreme Court denied PGE's motion to dismiss and vacate and also dismissed PGE's and URP's Petitions for Review of the 1998 Oregon Court of Appeals decision. As a result, the 1998 Oregon Court of Appeals opinion stands and the remand to the OPUC became effective.

On December 31, 2002, PGE was granted intervention in the Marion County proceeding filed by URP challenging the March 2002 Settlement Order approving PGE's application of the accounting and ratemaking elements of the Settlement.

On January 17, 2003, URP filed a Petition to Reconsider and Motion to Recall Appellate Judgment and Modify with the Court of Appeals. This pleading requests the Court of Appeals to remand the matter to the Marion County Circuit Court and not to the OPUC as required in the Court of Appeal's 1998 ruling. PGE and the OPUC filed in opposition to this request. A decision from the Court is pending.

For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements.

On January 17, 2003, two class actions suits were filed 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. PGE intends to vigorously defend these cases.

For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements.

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 but the order was not immediately implemented. The Duke and Reliant Parties filed an appeal to the United States Ninth Circuit Court of Appeals and applied to the District Court for a stay of the remand to the California state court. On January 24, 2003, the District Court denied the application for a stay and deferred certain motions for reconsideration. 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 and set a briefing schedule that will not be completed until mid-September 2003. As stated above, the cross complaint against PGE will be continued in abeyance until 30 days after a ruling is entere d 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. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price" or a reasonable price and for each alleged regulatory violation. No specific damage claim is stated. On July 10, 2002, PGE filed a Notice of Removal to the U.S. District Court. On July 17, 2002, PGE filed a Motion to Dismiss on preemption grounds with the U.S. District Court.

Following PGE's filing to remove the case to the U.S. District Court, the Attorney General filed a motion with U.S. District Court to remand the case to the state court. The motion has been denied. The Attorney General filed an appeal to the Ninth Circuit Court of Appeals of the denial of the motion to remand, and a motion to stay with the U.S. District Court. The U.S. District Court, finding the appeal to the Court of Appeals frivolous, denied the motion to stay the case. The motion to dismiss filed by PGE was argued on September 26, 2002 and is currently under advisement by the U.S. District Court.

On December 20, 2002, a class action suit on behalf of consumers in the State of Washington was filed against participants in the Pacific Northwest electric power markets, including PGE. The suit alleges violation of the Washington Consumer Protection Act, fraud by concealment, and negligence. The relief sought includes treble damages, attorney fees, and injunctive relief to prohibit the unlawful practices alleged. No monetary amount is specified. Plaintiff has agreed to extend the time for PGE to respond until after April 2, 2003.

Grievances have been 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. PGE has 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 Enron, not PGE. The IBEW filed an answer and counterclaim that the issue is arbitrable, and PGE filed a reply that denied the counterclaim and raised four affirmative defenses. The Circuit Court has set a trial date of May 22, 2003. See Note 10, Legal and Environmental Matters, in the Notes to Financial Statements for further information.

None.

PGE is a wholly owned subsidiary of Enron, which owns all 42,758,877 shares of PGE's outstanding common stock. Cash dividends declared on common stock were as follows (in millions):

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 facilities prohibit the payment of common stock dividends to Enron (excluding the non-cash dividend described above). For further information, see "Dividends" in the "Liquidity and Capital Resources" section of Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 4, Common and Preferred Stock, in the Notes to Financial Statements.

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 replaced 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. For further information regarding trading activities, see Note 8, Price Risk Management, in the Notes to Financial Statements.

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 was 60% of last year (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 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 2002, it was neces sary 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 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) for the last two years (excludes energy trading activities). Average variable power costs indicated exclude the effect of credits to purchased power and fuel costs related to PGE's power cost 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. Based on ratemaking history, the Company believes that this deferred tax relates to the flow through of tax benefits to customers in periods prior to 1993, which were to be recovered by the Company in a future period. Management assessed the potential for recovering this amount from customers and based on the available evidence is unable to represent that recovery is probable. Management does not believe the related charge is significant to 2002 results of operations. 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 and its subsidiaries. The Company also reversed a $3 million credit reserve established in 2001 related to receivables from Enron. (For additional information, see Note 12, Related Party Transactions, in the Notes to Financial Statements). 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 mechanism. Reserves of $3 million and $5 million were recorded in 2002 and 2001, respectively, related to the ca ncellation of a proposed gas turbine generation project. Losses of $5 million were incurred 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.

PGE's net income in 2001 was $34 million compared to $141 million in 2000. Significantly higher power costs and lower energy loads in 2001, partially offset by a general rate increase that became effective at the beginning of the fourth quarter, contributed to an approximate 35% decrease in net operating income. Results for 2001 also include 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, the Company recorded after tax provisions of approximately $13 million in 2001 related to amounts receivable for energy sales in the California wholesale market, a franchise fee audit, and costs associated with the cancellation of a proposed gas turbine generation project.

The following table summarizes Operating Revenues and Energy Sales for 2001 and 2000:

The increase in total Operating Revenues in 2001 was due primarily to higher prices for wholesale energy sales. The increase in wholesale (non-trading) revenues was attributable to prices that more than doubled due to the combined effect of higher natural gas prices, below normal hydro conditions, and market forces within the region. Wholesale sales volume decreased 24% as power activities slowed due to uncertainty and volatility in energy markets during the year.

The increase in retail revenues was due to a general rate increase that became effective October 1, 2001. Retail energy sales decreased 4% as a slowing economy, mild weather, conservation, and PGE's Demand Buyback program more than offset an approximate 11,000 (1.5%) increase in total customers from the end of 2000. A total of $42 million in retail revenues was deferred to 2002 to reflect amounts collected in excess of net variable power costs.

Other operating revenues decreased $38 million, primarily as the result of losses incurred in the Company's electricity and fuel trading activities. In 2001, PGE sustained losses in its trading activities as the Company sold higher-cost wholesale purchases at prevailing market prices that had moderated significantly from the prior year. Conversely, in 2000 PGE achieved gains on such activities as the Company's cost of power and fuel sold in the wholesale market was significantly exceeded by prevailing market prices. For further information regarding trading activities, see Note 8, Price Risk Management, in the Notes to Financial Statements.

Purchased power and fuel costs increased $639 million (58%), as PGE's average variable power cost increased 91% from 2000. During the fourth quarter of 2000 and through the first quarter of 2001, PGE entered into electricity and natural gas forward contracts for the last half of 2001 at forward prices reflecting the higher prevailing market prices. Western wholesale power prices moderated significantly in the last half of 2001 due to the combined effects of mild weather, additional generation capacity in the West, increased natural gas supplies, lower retail loads, and conservation. As prices declined, PGE was unable to sell excess wholesale power at prices covering the cost of such power, resulting in historically high net variable power costs in the last half of 2001. Conversely, in 2000, PGE achieved significantly lower net variable power costs in the last half of the year as the Company sold on the wholesale market excess power purchases, made in anticipation of higher retail demand, a t prices significantly higher than cost. The Company also recorded additional provisions in 2001 related to the collectibility of receivable balances associated with certain energy sales in the California wholesale market. For further information, see Note 13, Receivables - California Wholesale Market, in the Notes to Financial Statements.

Partially offsetting the effect of increased prices was a 12% decrease in total system load, as both wholesale and retail energy sales decreased from 2000. PGE's Demand Buyback program, by which certain large customers voluntarily reduced their electricity usage during certain peak periods during the first nine months of 2001, reduced manufacturing sector sales by 6.4% and partially offset the Company's increased cost of power. In addition, Purchased power and fuel costs in 2001 include an approximate $84 million credit related to the Company's power cost mechanism, in which a portion of net variable power costs exceeding a baseline amount were deferred for future recovery from customers. (See "Power Cost Mechanisms" in the Financial and Operating Outlook section for further information).

Company generation increased 8% in 2001, with a 15% increase in combustion turbine and coal generation partially offset by reduced hydro production. Total generation met approximately 61% of PGE's retail load during 2001, compared to 54% in 2000.

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 indicated exclude the effect of credits to purchased power and fuel costs related to PGE's power cost mechanisms, as discussed above.

Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) increased $16 million (6%). Increased energy efficiency expenditures and customer service and support activities were the primary causes of the increase. (Energy efficiency expenditures were deferred and amortized prior to October 1, 2000, but in 2001 were expensed and recovered by additional revenues). Partially offsetting these increases were lower employee benefit costs and the effect of a nonrecurring 2000 provision made against deferred costs related to the proposed sale of the Company's 20% interest in Units 3 and 4 of the Colstrip power plant. (The sale was denied by the OPUC and the Company was granted rate recovery of a portion of such costs in its 2001 general rate proceeding).

Depreciation and amortization expense increased $6 million (4%), due primarily to the effect of normal capital additions and to the removal of certain regulatory liabilities from the balance sheet as part of 2000's Trojan settlement agreement. (For additional information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements). Partially offsetting these increases were decreases in regulatory amortization, including that related to the Company's SAVE program promoting energy efficiency.

Income taxes decreased $56 million (60%) primarily due to lower taxable income, $5 million in adjustments to deferred income taxes, and the utilization of $2 million in state energy tax credits.

Other income decreased $85 million primarily due to a $79 million provision for uncollectible accounts receivable from Enron and affiliated companies recorded in December 2001 due to uncertainties surrounding Enron's bankruptcy proceedings. (For additional information, see Note 12, Related Party Transactions, in the Notes to Financial Statements). In addition, in 2000, PGE received $15 million related to the termination of its membership in Nuclear Electric Insurance Limited (NEIL) and also wrote off $5 million of its remaining investment in the Trojan plant as part of a settlement agreement. In 2001, PGE incurred a $5 million loss in the value of trust owned life insurance (compared to a $1 million loss in 2000). These were partially offset in 2001 by a $7 million increase in interest income, including $6 million related to the Enron merger credit and SCE contract termination, both of which were offset in the Trojan settlement agreement, with related interest reflected in income. Taxes on other income provided a $39 million benefit resulting from the decrease in taxable income.

Interest charges remained the same for both 2000 and 2001. An increase in interest on long-term debt and other, due to both interest on wholesale trading deposits and to the March 2000 issuance of $150 million in unsecured notes, was offset by reduced interest on a lower average level of commercial paper outstanding during 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 depreciation and amortization of utility plant charges which are recovered in customer revenues but require no current period cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash.

Cash provided by operating activities totaled $298 million in 2002 compared to $67 million of cash used in such activities in 2001. The increase was due primarily to a $312 million reduction in cash collateral deposit requirements with wholesale customers related to the settlement of certain energy contracts, and to increased receipts from wholesale and retail energy sales.

Cash from operations and remaining proceeds from the October 2002 issuance of long-term debt and early retirement of first mortgage bonds (described below) were invested primarily in government money market funds at December 31, 2002.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. A $38 million reduction in capital expenditures in 2002 is primarily attributable to reduced expenditures for generation construction and intangible plant, consisting primarily of computer software development costs. Capital expenditures in 2001 included $14 million related to construction of a new 24.5 megawatt combustion turbine unit at the Company's Beaver plant site, as well as certain large transmission substation and production plant improvements. Capital expenditures are expected to approximate $180 million in 2003, with the majority of expenditures expected to consist of improvements to, and expansion of, PGE's distribution system to support both new and existing customers within the Company's service territory.

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

Short-term - During 2002, PGE repaid $174 million of short-term borrowings. Cash collateral deposits returned by wholesale customers and cash from operations were used to repay $129 million in commercial paper, with proceeds from the issuance of long-term debt used to retire $45 million of short-term bank loans.

Although PGE has traditionally utilized commercial paper borrowings in meeting its day-to-day cash requirements, the Company has been unable to access the commercial paper market due to ratings reductions by credit rating agencies.

In June 2002, PGE entered into a new $72 million 364-day revolving credit facility with a group of commercial banks, replacing a $200 million credit facility that expired in June 2002. Under this facility, PGE has the option to use letters of credit, in addition to borrowings, totaling up to the $72 million. The Company also has a three-year $150 million revolving credit facility that expires in July 2003. Together, the two credit facilities provide available liquidity to PGE of $222 million.

Each facility contains rating sensitive pricing, though neither facility contains rating triggers that would cause acceleration, default, or puts. The facilities have material adverse change clauses and covenants that limit consolidated indebtedness, as such term is defined in the facilities, to 60% of total capitalization, and that require a minimum 2.25:1 ratio of earnings before interest and taxes (EBIT) to consolidated interest expense. PGE's indebtedness to total capitalization and interest coverage ratios at December 31, 2002 were 45.5% and 2.67:1, respectively. Both facilities are secured by First Mortgage Bonds. Borrowings under these credit facilities, along with cash provided by operations, have replaced the use of commercial paper in meeting PGE's day-to-day cash requirements.

PGE is evaluating alternatives for the replacement of its credit lines expiring in June and July 2003, including the issuance of First Mortgage Bonds and/or new revolving credit facilities. As of December 31, 2002, the Company has sufficient capacity under its Indenture of Mortgage to issue additional First Mortgage Bonds for this purpose.

For additional information, see Note 5, Credit Facilities and Debt, in the Notes to Financial Statements.

Long-term - In October 2002, PGE issued $250 million in First Mortgage Bonds, consisting of $150 million of 8 1/8% bonds maturing February 2010 and $100 million of 5.6675% bonds maturing October 2012. The Company purchased a policy insuring the principal and interest payments on the latter issue, which adds approximately 1.5% to annual interest costs. Both bond issues were private placements, with net proceeds from both issues used to reduce short-term debt, refinance current maturities of long-term debt, and for other general corporate purposes. In October 2002, PGE utilized a portion of the proceeds of these two bond issues for the early retirement of $150 million in First Mortgage Bonds due in December 2002. Also in 2002, PGE retired $15 million in matured First Mortgage Bonds and $9 million of conservation bonds and other long-term debt, and retired $2 million of preferred stock.

In 2001, PGE issued $150 million of variable rate First Mortgage Bonds, which were used to reduce commercial paper borrowings and bank loans under the Company's revolving credit facilities. The bonds were retired early in October 2002, as described above. In addition, PGE repaid $58 million in matured First Mortgage Bonds, pollution control bonds, and conservation bonds during 2001.

PGE has $49 million in long-term debt maturing in 2003, consisting of $40 million in First Mortgage Bonds that mature in August and $9 million of conservation bonds maturing throughout the year. The Company anticipates meeting these obligations through the sale of other long-term debt, the use of its existing credit facilities, or from cash from operations. In addition, PGE expects to re-market $142 million of tax-exempt pollution control bonds that will be put back to the Company in May 2003. If the bonds are not re-marketed, PGE anticipates using cash from operations and proceeds from the sale of other long-term debt to repurchase the bonds.

PGE currently plans to utilize letters of credit to provide funding assurance for certain future decommissioning activities at Trojan. Decommissioning funding assurance is required by the NRC for the amount by which total estimated future radiological decommissioning costs exceed actual balances in decommissioning trust accounts. It is currently anticipated that such funding assurance, for an estimated initial amount of $25 million, will be required upon completion of the transfer of spent nuclear fuel to an on-site dry storage facility in late 2003. Such amount would decrease through late 2005, as radiological decommissioning is completed. The timing and amount of actual funding assurance requirements are subject to change. PGE does not expect that such obligation will have a material effect on its financing requirements.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Articles of Incorporation and the Indenture securing the bonds. As of December 31, 2002, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital requirements.

Dividends - In 2002, PGE paid $2 million in preferred stock dividends. In July 2002, upon approval of the Company's board of directors, PGE made a non-cash dividend of $27 million to Enron related to the transfer of a receivable balance due from PGH (for further information, see Note 12, Related Party Transactions, in the Notes to Financial Statements). No other common stock dividends were declared in 2002. In 2001, PGE paid $40 million in common stock dividends to Enron and $2 million in preferred stock dividends.

Management continues to evaluate the future declaration of common stock dividends in light of expected cash requirements and other considerations. 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, the Company's revolving credit facilities prohibit the declaration or payment of dividends on PGE's capital stock except for regularly scheduled dividends on its preferred stock and the $27 million non-cash dividend to Enron described above.

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), with Fitch Ratings (Fitch) currently carrying a below investment grade rating on the Company. In their 2002 reviews of PGE ratings, credit agencies cited PGE's reduced financial flexibility resulting from its status as a subsidiary of an insolvent parent (Enron), a difficult capital market environment, and uncertainty regarding ongoing federal investigations into the Company's energy trading activities in the western U.S. power markets. Also cited in such reviews was the expectation that PGE would be sold, the significant credit enhancement and strengthened liquidity resulting from PGE's creation of a ring fence structure (described in the following paragraph), as well as the Company's fundamentally sound operations, healthy capitalization ratios, and levels of earnings and cash flows.

PGE 's current credit ratings are as follows:

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.

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, 2003, PGE had posted, in the form of letters of credit, $16 million of collateral. Based on the Company's non-trading and trading portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of January 31, 2003, the approximate amount of additional collateral that could be requested upon such a downgrade event is $36 million and decreases to approximately $29 million by year-end 2003. In addition to collateral calls, such a credit rating reduction would likely have an adverse effect on the terms and conditions of future long-term debt. In addition, any such rating reductions would increase interest rates on PGE's two revolving credit facilities, increasing the cost of funding its day-to-day work ing capital requirements.

PGE's ability to access the commercial paper market has been adversely affected by the May 2002 ratings reduction for commercial paper by Moody's and Fitch. Management believes that it has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

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, it does believe 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 the OPUC in conn ection 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 proceeding 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, 2002 (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. For further information, see "Purchased Power" in Note 7, Commitments, in the Notes to Financial Statements.

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 2003, is approximately $250 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 are in compliance with the requirements and ratemaking practices of regulatory authorities having jurisdiction. For certain transactions where revenues, costs, and gains would otherwise be recorded in income under GAAP, they are deferred for future ratemaking treatment under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to reflect the effects of regulation. (These assets and liabilities, titled Unamortized regulatory assets and Unamortized regulatory liabilities on the Consolidated Balance Sheets, total $544 million and $16 million, respectively, at December 31, 2002). 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.

The preparation of the financial statements requires management to use estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related contingency disclosures. PGE evaluates its estimates on a continuing basis and makes revisions based upon historical experience, new information, and other assumptions that are reasonable under the circumstances. Actual results could differ from such estimates.

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; gain contingencies are recognized upon realization and are disclosed when material. Reserves established reflect management's assessment of inherent risks, credit worthiness, and complexities involved in the collection process.

Revenues are recognized when customers are billed for electricity sold. In addition, unbilled revenues are recorded for services provided to retail customers from the meter read date to month-end. In certain situations, PGE defers the recognition of revenues until the period in which costs are incurred, in accordance with the provisions of SFAS No. 71.

PGE engages in price risk management activities for both non-trading and trading purposes, utilizing derivative instruments such as electricity forward and option, and natural gas forward, swap and futures contracts. Derivative contracts entered into for non-trading 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 to manage power and fuel costs for retail customers. PGE enters into derivative contracts for trading purposes to take advantage of price movements in electricity, natural gas, and crude oil; 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 and SFAS No. 138. (Prior to 2001, trading contracts were recorded at fair value pursuant to Emerging Issues Task Forc e (EITF) Issue 98-10, Accounting for Energy Trading and Risk Management Activities). For non-trading activities, certain derivative instruments are recorded at fair value on the balance sheet, with changes in fair value reflected as 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 the changes in fair value in current earnings.

Accounts receivable are evaluated for collectibility based upon past experience and the best available information. Management continues to assess PGE's exposure to all accounts receivable balances and establishes an appropriate allowance for doubtful accounts for amounts due.

For additional information, see Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements.

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 OPUC regulation. Most affiliated interest transactions are made under a Master Service Agreement (MSA) approved by the Commission. Any transactions not covered by the MSA must be separately approved by the Commission. 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. In addition to affiliated services, PGE provides transmission services under an existing contract for an Enron subsidiary, which is part of Enron's bankruptcy proceedings. The ultimate disposition of the intercompany receivable and payable balances with Enron and its subsidiaries at December 31, 2002 is uncertain due to Enron's bankr uptcy proceedings. The Company has recorded provisions against certain receivable balances due from Enron companies in bankruptcy. For further information, see Note 12, Related Party Transactions, and Note 16, Enron Bankruptcy, in the Notes to Financial Statements.

PGE trading activities utilize electricity forward and option contracts, natural gas forward, swap and futures contracts, and crude oil futures contracts to take advantage of price movements in electricity, natural gas, and crude oil. Valuation of these instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value, and volatility factors underlying the commitments. At December 31, 2002, 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 2002 and 2001, as well as the source of the fair value of the unrealized loss at December 31, 2002 and unrealized gain at December 31, 2001 (in millions):

Commencing in December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. 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. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.

Although PGE is not included in the Enron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating. PGE was also included among those Enron subsidiaries suspended from contracting with the federal government. PGE believes it does not merit suspension and has initiated the process to have the suspension removed. No federal, state, or local governmental entity has ceased to transact business with PGE, and the BPA has stated that the suspension does not affect its sales and purchases of electricity with the Company. Management believes the suspension will not have a material adverse effect on PGE business and operations.

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:

PGE management cannot predict with certainty what impact Enron's bankruptcy 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 Portland General Corporation 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 equity capital to fall below 48% of tot al 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. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely 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. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) 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 Bankruptcy Court after notice to PGE's creditors. 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 state 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 years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. 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 Pref erred 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. See Note 4, Common and Preferred Stock, in the Notes to Financial Statements for further information.

Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 16, Enron Bankruptcy, in the Notes to Financial Statements.

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. 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 PG E unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

On May 3, 2002, Enron presented to its Unsecured Creditors' Committee a proposal under which certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operated prospectively as a new integrated power and pipeline company. If Enron's proposal were to be adopted, the inclusion of PGE in the new company would be subject to potential sale to a different buyer under a bankruptcy code Section 363 auction process, which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the Unsecured Creditors' Committee and is one of many options Enron may pursue.

On August 27, 2002, Enron announced that it has commenced a formal sales process for its interests in certain major assets, including PGE. In its announcement, Enron indicated that it is extending invitations to visit electronic data rooms containing information on 12 of its most valuable businesses to a broad universe of potential bidders with whom Enron has executed confidentiality agreements.

Enron's announcement stated that the sales process continues Enron's efforts to maximize value and enhance recovery for its creditors. Enron and its advisors, in consultation with the Unsecured Creditors' Committee and its advisors, will evaluate all offers received to determine the combination of bids that maximizes the value of all assets.

PGE has been informed by Enron management that Enron and its advisors are continuing to review bids received on certain of its North American properties, including PGE. However, Enron has stated that it reserves the right not to sell any assets if the bids received are not deemed fully reflective of the aggregate value of such assets. A sale of PGE would require the consideration and approval of regulatory agencies, including the OPUC. Until there is a filing with the Bankruptcy Court, management cannot assess the impact of a sale or other arrangement on PGE's business and operations.

In August 2002, the City Council of Portland, Oregon passed a resolution authorizing the expenditure of up to $500,000 for professional advice regarding the City's potential acquisition of PGE, including possible condemnation of the Company's assets. The City has signed a confidentiality agreement with Enron to permit it to participate in the Enron auction process relating to PGE.

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. Under this mechanism, PGE shared with its retail customers differences 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. (See "Power Cost Mechanisms" 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. During the initial power cost 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, 2002, the remaining balance to be collected was approximately $73 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 for recovery from customers both 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 balance is being collected from large industrial customers over a one-year period (2003) and over a two-year period (2003-2004) from all other customer classes. At December 31, 2002, the balance to be collected, which is subject to a prudence review and audit by the OPUC, was approximately $36 million.

Although PGE does not currently have a power cost mechanism in place in 2003, the Company has filed with the OPUC an application to defer for later ratemaking treatment increases in power costs related to adverse hydro conditions (see "Hydro Replacement Power Costs" for further information).

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. 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 its projected power costs change from those included in its 2001 general rate case. It provides for an adjustment, filed annually on November 15, 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 utilized in the Company's 2001 general rate case. Accordingly, the OPUC authorized reductions in the Company's retail prices, effective January 1, 2003. Price decreases range 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 have decreased in the 2003 forecast. The smaller decrease in residential rates reflects the higher cost of electricity from BPA, which increased its rates in October 2002, as well as PGE's cost of generation. Based upon projected energy sales, it is estimated that such price decreases will reduce PGE's 2003 revenues by approximately $100 million.

Included in the price reduction is the effect of the Commission's disallowance of approximately $15 million related to four power purchase contracts, entered into in the first half of 2001, providing 125 megawatts of on-peak delivery in 2003. The disallowance was based upon a prudency review that included an evaluation and comparison of average prices contained in such contracts, reflecting the volatile wholesale market that existed at the time of their inception, with current market prices.

The new prices also reflect a resolution regarding the recovery period for the approximate $36 million balance related to PGE's power cost mechanism covering the period October 2001 through December 2002. This amount includes the effect of a settlement stipulation related to estimated 2003 power costs, in which PGE agreed to reduce its recovery under the power cost mechanism by approximately $4.6 million; such reduction was recorded by the Company in 2002.

In August 2002, PGE filed a new Integrated Resource Plan. In its Plan, PGE describes its strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. The Plan, which considers resource actions over the next two to three years, includes reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, long-term power purchases, and meeting seasonal peaking requirements through seasonal exchanges, demand-side management, capacity tolling contracts, and combustion turbine development.

PGE filed a supplement to the Plan on February 28, 2003. The OPUC has initiated a schedule for input and review, with an acknowledgement of the Company's Plan, as supplemented, anticipated by mid-2003. PGE then anticipates issuing a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of additional generation (including the Port Westward gas turbine project), and the availability of reasonably priced medium to long-term power purchases from the market. PGE will continue to monitor changes in economic conditions and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.

Based upon results of the RFP process, PGE will update its action plan with specific resource recommendations and request acknowledgement that the Company's final action plan is consistent with least cost planning principles established by the OPUC.

As of December 31, 2002, PGE has net accounts receivable totaling approximately $62 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) that may be affected by the financial condition of two major California utilities. 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). Both the PX and PG&E have filed for bankruptcy. PGE is pursuing collection through the PX and PG&E bankruptcies. A credit reserve has been established by PGE for a portion of the total amount due under its wholesale electricity contracts. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables. Management believes that the outcome of this matter 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. For further information, see Note 13, Receivables-California Wholesale Market, in the Notes to Financial Statements.

The FERC has issued an order to consider refunds for sales by electricity suppliers, including PGE, in the California spot market between October 2, 2000 and June 20, 2001. Hearings were held during 2002 to determine the amount of these refunds and also to determine amounts still owed to sellers. The presiding administrative law judge issued a certification of facts and the matter is now pending decision by the FERC. FERC hearings were also held in 2001 to determine whether there may have been unjust and unreasonable charges, and whether refunds may be due, for spot market sales of electricity in the Pacific Northwest by PGE and other suppliers from December 25, 2000 through June 20, 2001. An administrative law judge recommendation that no refunds be ordered is also pending before the FERC.

In late 2002, the FERC reopened the records in both the California case and the Pacific Northwest case to allow the parties to conduct additional discovery and to submit additional evidence regarding possible manipulation of the two markets. On March 3, 2003, numerous parties filed documents in both refund dockets addressing that issue. The most comprehensive filings were by the City of Tacoma in the Pacific Northwest case and by the California Parties in the California case. In addition to alleging that the markets were manipulated and that the refund cases should thus be expanded, those two parties alleged that numerous sellers, including PGE, participated in various strategies that adversely affected the market. PGE will be filing responses to the allegations in both dockets in late-March 2003.

The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California. In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism in effect during 2001-2002, which could further mitigate the financial effect of any refunds made or received by the Company.

Management cannot predict the ultimate outcome of these matters. However, it believes that 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. See Note 13, Receivables - California Wholesale Market, and Note 14, Refunds on Wholesale Transactions, in the Notes to Financial Statements for further information.

In June 2001, the FERC adopted a price mitigation program for the power system serving 11 Western states, adopting a new benchmark formula limiting prices for electricity sold in the spot markets at all times throughout the region through September 2002. The program applied to power generators, marketers, and investor-owned utilities under FERC jurisdiction, as well as public power providers, municipal utilities, and electric cooperatives that use FERC-regulated transmission lines.

Under the program, a ceiling price was set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator (ISO) and in markets in the other Western states. Such price, initially set at $91.87/MWh, reflected specified fuel, operations, and maintenance costs, and was based upon the bid submitted by the highest cost gas-fired generating unit supplying power during a Stage 1 supply emergency.

In December 2001, the FERC temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the ISO, recognizing differences between Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. The changes, including a ceiling price of $108/MWh, were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.

In July 2002, the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 31, 2002. The new ceiling price applies to all sales of electricity in the WECC. In addition to the new price ceiling, the FERC order established conditions and rules guiding participation in Western wholesale electricity markets, including automatic price mitigation procedures to be implemented during periods of tight supplies.

On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WECC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. In April 2002, the Company submitted the requested information. Additionally, on March 15, 2002 the FERC enforcement staff issued a subpoena to Enron, which Enron then forwarded to the Company. In response to this subpoena, the Company provided information related to its trading organization, its trading policies and procedures, its price curves and their derivation, and its trading position reports.

As a result of an internal investigation, PGE discovered that it had failed to properly post on a public web site information about a number of energy transactions with an affiliate, Enron Power Marketing, Inc. The preliminary results of this investigation were disclosed to FERC Staff on April 15, 2002 and final results on August 1, 2002. This issue was subsequently included in the investigation in Docket No. EL02-114-000 described below.

In early May 2002, the FERC received information contained in memos released by Enron, indicating that Enron, through its subsidiary Enron Power Marketing, Inc. (EPMI), may have engaged in several types of trading strategies that raised questions regarding potential manipulation of electricity and natural gas prices in California in 2000-2001. On May 8, 2002, the FERC ordered all sellers of wholesale electricity or ancillary services into the California markets during 2000-2001 to respond to the FERC whether they engaged in any transactions falling within any of the enumerated types of trading strategies, and, if they did, to provide information about the transactions. Although PGE was not specifically named in the FERC order, on May 22, 2002, PGE voluntarily submitted the results of its investigation to the FERC. The material submitted to FERC did not show any instances where the Company engaged in or knowingly aided deceptive or misleading trading strategies. However, PGE reporte d that it was among other intermediaries in a series of trading activities that occurred on 15 days from April through June 2000 where EPMI was found to be at both ends of the transaction chain. The trading transactions identified during the 15-day period moved about 2,300 megawatt hours (0.12%) of the total 2 million megawatt hours traded by PGE on those days, and about 0.02% of the total 13 million megawatt hours traded by PGE during the three-month period. The services provided by PGE may have been used by EPMI as a step in one of the enumerated strategies. In addition, it is conceivable that in the normal course of business, PGE could have provided services to third parties that may have resulted in PGE being used, unknowingly, as an intermediary in partial execution of one or more of the enumerated strategies.

On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. The order stated that the companies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. On June 14, 2002, PGE filed a response indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE. PGE believes that it has fully cooperated with the FERC's inquiry.

On August 13, 2002, the FERC issued two orders initiating investigations into instances of possible misconduct by PGE and certain other companies. In the first order (Docket No. EL02-114-000), the FERC ordered investigation of PGE and EPMI related to possible violations of their codes of conduct, the FERC's standards of conduct, and the companies' market-based rate tariffs, and whether PGE has cooperated by providing all relevant information related to the FERC's May 8, 2002 data request and June 4 Show Cause Order. In the second order (Docket No. EL02-115-000), the FERC ordered investigation of Avista Corporation and Avista Energy, Inc. (collectively, Avista) with respect to, among other things, transactions in which Avista engaged in or facilitated the trading strategies identified in the Enron memoranda or acted as a middleman with respect to sales of electric energy between PGE and EPMI. PGE and EPMI are included as parties in that Docket. In the orders, the FERC established October 15 , 2002 as the "refund effective date." Issues involving PGE and EPMI in Docket No. EL02-115-000 have now been consolidated into Docket No. EL02-114-000. If PGE were to lose its market-based rate authority, purchasers of electric energy from PGE at market-based rates after that date could be entitled to a refund of the difference between the market-based rates and cost-based rates deemed just and reasonable by the FERC.

On December 10, 2002, the FERC trial staff released a Revised Statement of Asserted Violations (Revised Statement) and its initial testimony in its investigation of PGE (Docket No. EL02-114-000). The assertions in the Revised Statement and testimony are limited to PGE's self-reported failure to properly post information about energy transactions with EPMI, and alleged violations for affiliate dealings with EPMI relating to a series of transactions that occurred on certain days in April-June 2000, involving PGE, EPMI, and Avista Corporation. The latter transactions were previously reported by PGE to FERC on May 22, 2002 in response to the FERC's May 8, 2002 data request. The trial staff recommended a remedy of revocation of PGE's market-based rate authority for two years, and a requirement that PGE's application for reinstatement of market-based rates include documentation supporting revised procedures to ensure that posting errors and violations of affiliate rules do not occur again. The C ity of Tacoma, Washington filed testimony seeking a refund from PGE of $3.2 million. The California Attorney General and the California Public Utilities Commission (California Parties) have filed testimony that PGE should refund amounts to compensate market participants for PGE's alleged unlawful conduct, but the testimony specifies no amount of refunds.

PGE's initial response testimony was filed on February 24, 2003. In its testimony, PGE describes the posting errors it self-reported, most of which were technical in nature, and the cooperation it has extended to the FERC, the investigative staff, and the trial staff to furnish all requested information to aid the investigation. PGE also provided testimony that the April-June 2000 transactions with EPMI did not involve violations of affiliate rules, except for certain posting errors.

The hearing in Docket No. EL02-114-000 is scheduled to begin on June 2, 2003, with an initial decision from the presiding FERC judge scheduled for July 17, 2003. The schedule in Docket No. EL02-115-000 is currently suspended pending the disposition of a settlement proposal submitted between Avista and the FERC trial staff.

PGE will continue to cooperate with the investigations. PGE continues to believe that it has fully complied with the FERC investigation initiated on February 13, 2002, and that it has not engaged in deception or market manipulation.

On May 21, 2002, the FERC issued a data request and request for admissions to all sellers of wholesale electricity and/or ancillary services in the U.S. portion of the WECC during the years 2000-2001. Such request ordered sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. Although PGE was not listed in the data request, PGE conducted an investigation and submitted the results in a response to the FERC on May 31, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request to the extent that such activities artificially inflated trading volumes, revenues or market prices. PGE's response also noted that it had no reason or incentive to artificially inflate trading volumes or revenues, as the primary purpose of its wholesale trading operations is to manage risk and reduce costs for its retail customers by balancing load requirements and maximizing the value of owned generat ion and purchase contracts to the extent that available supply exceeds the needs of the Company's firm customers.

On May 22, 2002, the FERC issued a data request and request for admissions to all sellers of natural gas in the U.S. portion of the WECC and in Texas during the years 2000-2001. Such request ordered such sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. PGE conducted an investigation and submitted the results in a response to the FERC on June 5, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request.

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, where briefing is now underway.

On June 17, 2002, the U.S. Commodity Futures Trading Commission (CFTC), which regulates futures contracts traded on U.S. exchanges, subpoenaed documents from PGE regarding the Company's electricity and natural gas trading, including any "wash" trading used to inflate revenue and trading volume. PGE forwarded documents previously prepared for the FERC investigation (described above). In addition, PGE has been requested to provide information and documents with respect to various federal and state actions and investigations of Enron. PGE will continue to cooperate to the fullest extent with these investigations.

In late 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) 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, inter est, and penalties.

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, 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 cross complaint against PGE and the other utilities, generators, traders and other entities similar to the cross complaint filed by the Duke Parties. The cases were remanded to Federal Court by certain parties. The parties have stipulated to place the cross complaints in abeyance until 30 days after a ruling on the motions to dismiss the Master Complaint.

On December 13, 2002, a United States District Court signed an order granting the plaintiff's motions to remand the cases to the California state court, but the order was not immediately implemented. The Duke and Reliant Parties filed an appeal to the United States Ninth Circuit Court of Appeals and applied to the District Court for a stay of the remand to the California state court. On January 24, 2003, the District Court denied the application for a stay and set for hearing certain motions for reconsideration. 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 and set a briefing schedule that will not be completed until mid-September 2003. 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.

At this time, management is unable to make any assessment of, or determination with respect to, these complaints.

In May 2002, the Attorney General of California filed a complaint in state court alleging failure of PGE to comply with the Federal Power Act (FPA) and with the FERC requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price" or a reasonable price and for each alleged regulatory violation. No specific damage claim is stated. In July 2002, PGE filed a Notice of Removal to U.S. District Court and a Motion to Dismiss on preemptive grounds. The Attorney General moved to remand to state court, which was denied. The Attorney General filed an appeal to the Ninth Circuit Court of Appeals of the denial of the motion to remand, and moved to stay action in the District Court pending the outcome of the appeal. The District Court, finding the appeal frivolous, refused to stay the case. Motions to dismiss the case were argued on September 26, 2002 and are currently under advisement by the District Court. At this time, management is unable to make any assessment of, or determination with respect to, this complaint. See Note 13, Receivables - California Wholesale Market, and Note 14, Refunds on Wholesale Transactions, in the Notes to Financial Statements for further information.

On December 20, 2002, a Class Action suit on behalf of consumers in the State of Washington was filed against participants in the Pacific Northwest electric power markets, including PGE. The suit alleges violation of the Washington Consumer Protection Act, fraud by concealment, and negligence. The relief sought includes treble damages, attorney fees, and injunctive relief to prohibit the unlawful practices alleged. No monetary amount is specified. Plaintiff has agreed to extend the time for all defendants to respond until after April 2, 2003.

Due to the closure of the Trojan Nuclear Plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals, and regulatory actions have taken place. As a result of a settlement agreement that was implemented in 2000, the recovery of the Trojan plant investment is no longer included in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant.

On January 17, 2003, two class actions suits were filed 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. PGE intends to vigorously defend these cases.

Although management cannot predict the ultimate outcome of the above legal challenges, it believes that they 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. For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements.

Grievances have been 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. For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements.

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 energy suppliers.

In 1999, Oregon's governor signed into law State Senate Bill 1149, which became effective March 1, 2002. It provides all commercial and industrial customers of investor-owned utilities direct access to energy suppliers 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 new 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 payment of "transition charges" by non-residential customers that choose to purchase energy at market rates from investor-owned utilities or from electricity service suppliers. Such charges reflect the above-market cost of energy resources owned or purchased by the utility and are designed to ensure that such costs do not unfairly shift to the utility's remaining energy customers.

The new 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 of Oregon's electric energy restructuring law indicate a measured response. Although numerous customers have chosen among available rate options, no customers have yet left PGE's system for competing electricity service suppliers.

PGE continues to operate as a cost-based regulated electric utility, where 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 bundled ("full") 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 will continue to periodically assess the applicability of the statement to its business, or separable portions thereof. Such assessment will 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.

In accordance with the new law and an order from the OPUC, PGE is deferring certain costs related to implementation of the restructuring plan for later recovery in electricity rates. At December 31, 2002, unrecovered costs totaled approximately $20 million. The OPUC staff recently completed an audit and prudency review of such costs, and in January 2003 issued a report that found these costs to be prudently incurred, with only minor adjustments proposed.

The Energy Policy Act of 1992 (Energy Act) set the stage for change in federal regulations aimed at increasing 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.

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.

Weather adjusted retail energy sales decreased 1.9% in 2002. Excluding the effects of the Demand Buyback program, in which PGE paid large customers to reduce their load during peak demand times in 2001, weather adjusted sales declined about 3.2%. Such decreases are attributable to the continuing effect of a significant downturn in Oregon's economy. Manufacturing sector sales decreased about 2.1%, as large paper, chemical, food, lumber and metals manufacturers reduced their energy use; excluding the effects of the Demand Buyback program, manufacturing sector sales declined about 7%. Commercial sales declined 3.0% compared to 2001. Sales to residential customers, adjusted for the effects of weather, decreased 0.8% as average use declined in response to conservation efforts; such decrease was partially offset by an approximate 1% increase in residential customers served. PGE forecasts minimal retail energy sales growth in 2003 due to Oregon's continued slow economy.

PGE has consistently promoted the efficient use of electricity, utilizing Demand Side Management programs that provide a range of services to all customer classes and that seek to maximize those opportunities in which energy efficiency measures are most cost-effective. To accomplish this, the Company focuses on both commercial and industrial new construction and retrofitting, industrial process improvements, and residential weatherization measures, including an expanded program that encouraged the use of compact fluorescent lighting and a program for low-income families.

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 (ETO), 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. As the ETO more fully develops its energy efficiency programs, it is utilizing transition contracts with utilities to assure energy efficiency programs are available to customers.

In 2002, PGE acquired total energy savings for residential, commercial, and industrial customers estimated at 11 average megawatts, including 6 average megawatts under the Company's transition contract with ETO. PGE will continue to offer customers general energy information to assist them in managing their energy costs.

The amount of surplus electric generating capability in the western United States, the amount of the 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. During 2002, PGE's wholesale sales accounted for about 21% of total revenues and 40% of total energy sales. 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 take advantage of price movements in electricity, natural gas, and crude oil.

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 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.

During 2002, PGE generated approximately 38% of its retail load requirement, compared to approximately 61% in 2001, as lower cost power purchases displaced the Company's thermal generation. Short-term and long-term purchases were utilized to meet the remaining load. PGE has long-term power contracts with four hydro projects on the mid-Columbia River providing capability of 652 MW, and has also relied increasingly upon short-term purchases to meet its energy 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 hydro conditions in 2003 will be significantly below normal. 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 2003 runoff at 73% of normal, compared to 97% in 2002 and 54% in 2001. Efforts to restore salmon runs on the Columbia and Snake rivers may additionally reduce the amount of water available for generation, which could affect the availability and price of purchased power. PGE continues to evaluate the impact of current and potential listings of salmon species for protection under the federal Endangered Species Act on its purchased power supply and the operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette Rivers.

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.

A region-wide drought throughout the Pacific Northwest has resulted in adverse hydro conditions for PGE and other utilities, with early forecasts indicating hydro conditions significantly below normal. In anticipation of the effects of such conditions, PGE has begun to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those contained in the Company's current energy rates.

On February 11, 2003, PGE filed with the OPUC an Application for Deferral of Hydro Replacement Power Costs, in which the Company requests authorization to defer for later ratemaking treatment increases in power costs incurred from the application date through December 31, 2003. The Company's application requests authorization for the deferral of 95% of the difference between actual net variable power costs and those allowed in current rates, with interest accrued at PGE's authorized rate of return. As proposed, the deferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Although the amount of the deferral is not yet determinable due to the effect of uncertain and unpredictable weather patterns for the remainder of the year, PGE estimates that the amount could range from $20 million to $60 million.

PGE and BPA have signed an agreement that provides cash benefits and power from BPA over a ten-year period beginning October 1, 2001. The benefits, which are passed directly to PGE's residential and small farm customers in the form of lower prices, are reflected within Purchased power and fuel expense.

PGE Hydro - PGE's five FERC-licensed hydroelectric projects consist of eight facilities which provide economical generation and flexible load following capabilities. In 2002, they produced approximately 1.8 million MWh of renewable energy, about 9% of PGE's total retail customer load. The plants operate under federal licenses, which will be up for renewal through 2006. Costs of relicensing the Company's hydroelectric projects are being capitalized for future rate recovery.

The Clackamas River hydroelectric projects have a combined output of 175 MW. PGE continues to involve resource agencies, environmental groups, tribal governments, and members of the public in the design and implementation of studies that will help PGE and the parties understand the projects' impacts and opportunities for mitigation and enhancements in the new license. The existing license expires in August 2006 and a draft application will be filed with the FERC in 2003.

PGE filed a license application with the FERC in December 2002 for its 16-MW Willamette River hydroelectric project, whose current license expires in December 2004. In 2003, the Company and participants in the relicensing process will continue to develop a plan for the timing and monitoring of proposed modifications to the generating project and facilities. Biological evaluation, to be used in ESA consultation undertaken by the FERC, will continue in 2003.

PGE and the Tribes filed their final joint application amendment for the Pelton Round Butte project on the Deschutes River in June 2001. PGE has a 300-MW ownership share in the 450-MW project following the January 2002 sale of a portion of the project to the Tribes. During 2003, participants in the relicensing process will continue in settlement discussions to seek agreement on the terms and conditions of the new license. The project has been operating on annual licenses since its FERC license expired in December 2001.

Mid-Columbia Hydro - 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. The new agreements are effective upon expiration of the current contracts 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 output will decline over time as Grant's needs increase, with an expected share of about 15 average megawatts in 2009.

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. PGE filed a request for rehearing with FERC on December 23, 2002 and expects an order by FERC on the merits in the spring of 2003.

For further information regarding the power purchase contracts on the mid-Columbia dams, including Priest Rapids and Wanapum, see Note 7, Commitments, in the Notes to Financial Statements

In October 2002, PGE entered into an agreement with state and federal agencies, conservation groups, and others regarding the removal of the Company's 22-MW Bull Run hydroelectric project on the Sandy River, 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.

Under the terms of the agreement, PGE has requested that the term of the existing license, which expires in November 2004, be extended to allow the project to operate until the removal of Little Sandy Dam. 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 October 2001, of about $16 million in estimated decommissioning costs.

The decision and agreement were based upon a comparison of projected future operating costs of the project, including required environmental measures necessary to protect several runs of endangered salmon, with the future value of the project's energy output. PGE has filed an application to amend the project license and an application to surrender the Bull Run license. A FERC decision on the amendment application and surrender application is expected in 2003.

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 is expected to be completed by the end of 2003. PGE also completed the final radiological survey of the containment building and areas impacted by the completed ISFSI. The Company supported the NRC's collection of confirmatory surveys of containment and ISFSI impacted areas with no significant findings or observations.

PGE currently estimates the total cost to decommission Trojan at $345 million (nominal dollars), with approximately $169 million expended through 2002. The total estimate assumes that the majority of decommissioning activities will be completed by 2005 after the spent fuel has been transferred to dry storage. The plan anticipates final site restoration activities will begin in 2018 after PGE completes shipment of spent fuel to a USDOE facility. Total decommissioning costs are currently estimated at approximately $25 million for 2003, compared to $18 million expended in 2002.

PGE expects remaining transition activities to extend through 2003; such activities consist of operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage. 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.

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 such time as the NRC determines that the level of threat has diminished, or that other security changes are needed. The NRC has begun a comprehensive re-evaluation of current safeguards and security programs, and PGE anticipates formal regulations to be issued in late 2003. Until NRC requirements are determined, it is not known whether the costs associated with their implementation will impact the Trojan decommissioning cost estimate and related funding requirements. However, as new security requirements are evaluated, any additional costs will be determined and decommissioning cost estimates revised as necessary.

For further information, see Note 11, Trojan Nuclear Plant, in the Notes to Financial Statements.

A 1997 investigation of a 5.5 mile segment of the Willamette River known as the Portland Harbor, conducted by the EPA, 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 2000.

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated 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 accordance with the Voluntary Agreement, in March 2001, 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 a final investigation report to the DEQ summarizing its investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations 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.

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. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, 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. Nonetheless, management cannot predict the ultimate outcome of this matter or estimate any possible loss.

For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements.

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 FERC issued an order in 1999 that requires all owners of electricity transmission facilities to file a proposal to join a Regional Transmission Organization (RTO). For further information, see "Regulatory Matters" in Part I, Item 1. - Business.

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 PUHCA. Following Enron's acquisition of PGE in 1997, Enron annually filed on Form U-3A-2 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 on Form U-3A-2. As a result, in February 2002, Enron filed an application on Form U-1 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.

Following the submission of testimony by the parties to the proceeding, a hearing on Enron's application was held on December 5, 2002. On February 6, 2003, the administrative law judge issued an Initial Decision holding that PGE does not meet the criteria to be predominantly intrastate in character, and denying Enron's application for exemption under 3(a)(1). On February 27, 2003, Enron filed a Petition for Review with the SEC requesting that the SEC review the Administrative Law Judge's Initial Decision, reverse such Initial Decision, and find that Enron is entitled to exemption from PUHCA. Filing of the Petition for Review stays the effect of the Initial Decision until such time as the SEC may act on the Petition for Review. The SEC could act on the Petition for Review at any time. Possible responses of the SEC to the Petition for Review include setting the matter down for further hearings before the full Commission or summarily affirming the Initial Decision. In the event that the Initi al Decision is affirmed by the SEC, either summarily or after further hearings, Enron could be required to register as a holding company under PUHCA and PGE would become a subsidiary of a registered holding company.

PUHCA imposes a number of restrictions on the operations of a registered holding company and its subsidiaries, including SEC approval of securities issuances (including those by utility subsidiaries that have not been authorized by the relevant state utility commissions) and engaging directly or indirectly in non-utility businesses. PUHCA also regulates transactions between the affiliates within the holding company system, including the provision of services by holding company affiliates to the system's utilities. If PGE were to become a subsidiary of a registered holding company, it would become subject to regulation by the SEC not only with respect to the acquisition of the securities of other public utilities, but also with respect to, among other things, payment of dividends out of capital and surplus, certain affiliate transactions, issuance of securities, and the acquisition of assets and interests in any other business.

Although PGE is unable to predict whether Enron will retain its status as an exempt holding company, PGE does not believe that becoming a subsidiary of a registered holding company would have a material adverse affect on its financial condition or results of operations. However, the finding that PGE is not an intrastate utility could make it more difficult for any future owner of PGE to obtain a 3(a)(1) exemption from PUHCA.

See Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements for information regarding new accounting standards.

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;
• effects of electric industry restructuring in Oregon and in the United States, including 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 which include changes in commodity prices, foreign exchange rates and interest rates. These changes may affect the Company's future financial results.

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 seasonal 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, 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 2002 was $0.1 million, $0.4 million, and zero, respectively, in 2001 was $0.8 million, $3.6 million, and zero, respectively, and in 2000 w as $0.3 million, $0.5 million, and zero, respectively. The instances of zero value at risk occur when there are no open positions in the trading portfolio. For 2002 and 2001, the value at risk on the non-trading portfolio is not meaningful since the majority of the portfolio is effectively accounted for on an accrual or settlements basis. Additionally, PGE had power cost mechanisms in 2001-2002 that allowed the Company to defer, for future ratemaking treatment, actual net variable power costs that differed from certain baseline amounts approved by the OPUC (see "Power Cost Mechanisms" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). In 2002 and 2001, PGE did not reduce its non-trading value at risk by the amount of potential deferrals. For 2000, the average, high, and low value at risk on the non-trading portfolio was $2.0 million, $4.6 million, and $1.1 million, respectively.

PGE faces exposure 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, 2002, a 10% change in the value of the Canadian dollar would result in a change in pre-tax income of approximately $4 million at the time the transactions settle over the next 22 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, 2002, the Company is typically exposed to risk resulting from changes in interest rates on variable rate short-term borrowings. The Company has also had exposure to interest rate changes on variable rate commercial paper, which it has recently been unable to issue due to reductions in its credit ratings. 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 Facilities 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. Due to the settlement of power contracts in 2002, the Company's exposure to credit risk has decreased significantly.

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 1, Summary of Significant Accounting Policies, and 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.

The system of internal controls of PGE is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system is augmented by written policies and guidelines and 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 internal control system 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.

PricewaterhouseCoopers LLP was engaged to audit the 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 Report of Independent Accountants appears 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 accountants 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.

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 2001, and the results of their operations and their cash flows for each of the three 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 manage ment; our responsibility 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