-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, S5/ZKLvzsqV5In/p/Nx8QSwLdGmL/Hvx3y0/xOhoqi8/LkyMsA8h+ftawkdXgkV6 BKJa3nd/abWRLCBMKNfGrw== 0000784977-00-000008.txt : 20000307 0000784977-00-000008.hdr.sgml : 20000307 ACCESSION NUMBER: 0000784977-00-000008 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20000214 FILED AS OF DATE: 20000303 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PORTLAND GENERAL ELECTRIC CO /OR/ CENTRAL INDEX KEY: 0000784977 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 930256820 STATE OF INCORPORATION: OR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-05532-99 FILM NUMBER: 560491 BUSINESS ADDRESS: STREET 1: 121 SW SALMON ST CITY: PORTLAND STATE: OR ZIP: 97204 BUSINESS PHONE: 5034647439 MAIL ADDRESS: STREET 1: 121 SW SALMON STREET CITY: PORTLAND STATE: OR ZIP: 97204 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _______ TO _______ COMMISSION FILE NUMBER 1-5532-99 PORTLAND GENERAL ELECTRIC COMPANY (Exact name of registrant as specified in its charter) OREGON (State or other jurisdiction 93-0256820 ofincorporation or organization) (I.R.S. Employer Identification No.) 121 SW SALMON STREET, PORTLAND, OREGON 97204 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: (503) 464-8000 Securities registered pursuant to Section 12(b) of the Act: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED Portland General Electric Company 8.25% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series A) New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: TITLE OF CLASS Portland General Electric Company, 7.75% Series, Cumulative Preferred Stock, no par value None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ] State the aggregate market value of the voting stock held by non-affiliates of the registrant as of February 29, 2000: $0. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 29, 2000: 42,758,877 shares of Common Stock, $3.75 par value. (All shares are owned by Enron Corp.) DEFINITIONS The following abbreviations or acronyms used in the text and notes are defined below: Abbreviations OR ACRONYMS TERM Beaver .......................... Beaver Combustion Turbine Plant Boardman ........................ Boardman Coal Plant BPA ............................. Bonneville Power Administration Centralia ....................... Centralia Coal Plant Colstrip ........................ Colstrip Units 3 and 4 Coal Plant Coyote Springs .................. Coyote Springs Generation Plant CUB ............................. Citizens' Utility Board DEQ ............................ Oregon Department of Environmental Quality Enron ........................... Enron Corp. EFSC ............................ Energy Facility Siting Council EPA ............................. Environmental Protection Agency FERC ............................ Federal Energy Regulatory Commission Financial Statements ............ Refers to Financial Statements of Portland General Electric Company included in Part II, Item 8 of this report. KWh ............................. Kilowatt-Hour MW .............................. Megawatt MWa ............................. Average megawatts MWh ............................. Megawatt-hour NRC ............................. Nuclear Regulatory Commission NYMEX ........................... New York Mercantile Exchange OPUC or the Commission .......... Oregon Public Utility Commission PGE or the Company .............. Portland General Electric Company PUD ............................. Public Utility District Regional Power Act .............. Pacific Northwest Electric Power Planning and Conservation Act SFAS ............................ Statement of Financial Accounting Standards issued by the FASB Trojan .......................... Trojan Nuclear Plant USDOE ........................... United States Department of Energy WAPA ............................ Western Area Power Administration WNP-3 ........................... Washington Public Power Supply System Unit 3 Nuclear Project WSCC ............................ Western Systems Coordinating Council TABLE OF CONTENTS PAGE Definitions ............................................................. 2 PART I Item 1. Business ........................................................ 4 Item 2. Properties ..................................................... 16 Item 3. Legal Proceedings .............................................. 19 Item 4. Submission of Matters to a Vote of Security Holders ............ 20 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ................................... 21 Item 6. Selected Financial Data ....................................... 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ........................... 22 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ................................................... 32 Item 8. Financial Statements and Supplementary Data ................... 33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........................... 55 PART III Item 10. Directors and Executive Officers of the Registrant ............ 56 Item 11. Executive Compensation ........................................ 59 Item 12. Security Ownership of Certain Beneficial Owners and Management ................................................ 63 Item 13. Certain Relationships and Related Transactions ................ 63 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ........................................... 64 Signatures ............................................................. 65 Exhibit Index .......................................................... 66 PART I ITEM 1. BUSINESS GENERAL PGE, incorporated in 1930, is an electric utility engaged in the generation, purchase, transmission, distribution, and sale of electricity in the State of Oregon. PGE also sells energy to wholesale customers throughout the western United States. PGE's Oregon service area is 3,170 square miles, including 54 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of 4,070 square miles. PGE estimates that at the end of 1999 its service area population was approximately 1.5 million, comprising about 44% of the state's population. For the year 1999, the Company added approximately 15,000 customers, representing an annualized growth rate of about 2.5%. At December 31, 1999, PGE served approximately 719,000 customers. On July 1, 1997 Portland General Corporation (PGC), the former parent of PGE, merged with Enron Corp. (Enron) with Enron continuing in existence as the surviving corporation and PGE operating as a wholly owned subsidiary subject to control by Enron. On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion, comprised of $2.02 billion in cash and the assumption of Enron's approximately $80 million merger payment obligation. The proposed transaction, which is subject to regulatory approval, is expected to close in late 2000. On January 18, 2000, Sierra filed with the OPUC an application to acquire PGE. On February 3, 2000, Sierra filed with the SEC an application to acquire PGE and also to become a registered public utility holding company. As of December 31, 1999, PGE had 2,787 employees. This compares to 2,728 and 2,729 employees at December 31, 1998 and 1997, respectively. Currently, 1,072 employees are covered under a three-year agreement with Local Union No. 125 of the International Brotherhood of Electrical Workers that is effective from March 1, 1998 through March 1, 2001. OPERATING REVENUES RETAIL PGE serves a diverse retail customer base. Residential customers constitute the largest customer class and account for approximately 45% of total retail revenues, with commercial and industrial customers accounting for 38% and 17%, respectively. Residential demand is highly sensitive to the effects of weather, with company revenues highest during the winter heating season. Electricity sales increased somewhat in 1999 due to the effects of PGE's Customer Choice pilot program, which in 1998 allowed some customers to buy their power from competing energy service providers; this program terminated at the end of 1998. The commercial and industrial classes are not dominated by any single industry. While the 20 largest customers constitute about 18% of retail demand, they represent 8 different industrial groups, including paper manufacturing, high technology, metal fabrication, general merchandising and health services. No single customer represents more than 3% of PGE's total retail load. WHOLESALE Wholesale electricity sales comprised about 26% of total operating revenues in 1999, up from about 20% in 1998. Most of PGE's wholesale sales have been to utilities and power marketers and have been predominantly short- term. PGE will continue its participation 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; this allows PGE to secure power for its customers at the lowest cost available. The following table summarizes operating revenues and MWh sales for the years ended December 31: 1999 1998 1997 Operating Revenues (Millions) Residential $ 438 $ 432 $ 391 Commercial(1) 367 345 354 Industrial 173 132 143 Tariff Revenues 978 909 888 Accrued (Collected) Revenues 26 (8) 10 Retail 1,004 901 898 Wholesale 355 234 497 Other 19 41 21 Total Operating Revenues $ 1,378 $1,176 $1,416 Megawatt-Hours Sold (Thousands) Residential 7,404 7,101 6,999 Commercial(1) 7,392 6,781 6,973 Industrial 4,463 3,562 4,247 Retail 19,259 17,444 18,219 Wholesale 12,612 10,869 26,934 Total MWh Sold 31,871 28,313 45,153 Energy Delivered to ESP Customers (2) - 1,292 2 Total MWh Sold and Delivered 31,871 29,605 45,155 (1) Includes public street lighting. (2) Represents energy delivered to customers of Energy Service Providers (ESPs) under PGE's Customer Choice pilot program. For additional information on year-to-year revenue trends, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. REGULATION 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 Commission further ensures that prices are fair and equitable and provides PGE an opportunity to earn a fair return on its investment. In addition, the Commission regulates the issuance of securities and prescribes the system of accounts to be kept by Oregon utilities. 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, subject to regulation by the FERC as to accounting policies and practices, certain prices, 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, which are proceeding satisfactorily and within approved cost estimates. After receiving regulatory approval, PGE in 1999 shipped and disposed of the Trojan reactor vessel as a single package called the Reactor Vessel and Internals Removal Project (RVAIR). Equipment removal and disposal activities will also continue in 2000. Trojan is subject to NRC regulation until it is fully decommissioned, all nuclear fuel is removed from the site, and the license terminated. The Oregon Department of Energy also monitors Trojan. (For further information, see "Nuclear Decommissioning" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). REGULATORY MATTERS ELECTRIC POWER INDUSTRY RESTRUCTURING On July 23, 1999, Oregon's governor signed into law a State Senate Bill (SB1149) that provides all industrial and commercial customers of investor- owned utilities direct access to competing energy suppliers no later than October 1, 2001. Residential customers will be able to purchase electricity from a "portfolio" of rate options that will include a cost-of- service rate, a new renewable resource rate, and a market-based rate. SB1149 also provides for a 10-year public purposes 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. In addition, SB1149 provides for low-income electric bill assistance through proportionate collections by affected utilities, beginning in January 2000. Also included in SB1149 is a requirement that investor-owned utilities unbundle the costs of service into power generation, transmission, distribution, and retail services. The law also provides for "transition" charges and credits that would allow recovery on uneconomic utility investment or a refund of benefits from economic utility investment. Incentives for the divestiture of generation assets are authorized, provided any divestiture does not deprive customers of the benefit of the utility's or the region's low cost resources. SB1149 further requires that its implementation have no material adverse impact on the ability of investor-owned utilities to access cost-based power from the Bonneville Power Administration for its residential and small farm customers. In October 1999, the OPUC began a series of workshops designed to discuss the issues associated with SB1149 and to develop administrative rules for implementation of the law; PGE is participating fully in these workshops. In February 2000, the OPUC began its formal rulemaking process with the expectation that rules enabling utilities to develop tariffs will be adopted in June 2000. Additional rulemakings regarding non-tariff-related items are also expected. PGE expects to file its restructuring plan, including associated tariffs, in time to allow for direct access by October 1, 2001. LEAST COST ENERGY PLANNING The OPUC adopted Least Cost Energy Planning for all energy utilities in Oregon, with the goal of selecting the mix of resources that yields a reliable supply of energy at the least cost to customers. PGE has received acknowledgement of its 1998-1999 Integrated Resource Plan (IRP) from the OPUC. This plan recognized fundamental changes occurring in the electric industry and established a transition strategy for the next two years. It maintained PGE's delivery capability and provided a bridge to a competitive environment in which funding for public purposes is provided from a system benefit charge. PGE is currently holding a public process to obtain input from interested parties for its next IRP, which is scheduled for completion by the end of 2000. This Plan will help shape PGE's resource decisions under new state law adopted in 1999 that requires restructuring to be implemented by October 1, 2001. RESIDENTIAL EXCHANGE PROGRAM In 1980, the Regional Power Act (RPA) was passed by Congress in response to growing power supply and cost inequities between customers of government and publicly-owned utilities, who have priority access to low-cost power from the federal hydroelectric system, and the customers of investor-owned utilities ("IOUs"). The RPA created the Residential Exchange Program to ensure that all residential and small farm customers in the region, the majority of which are served by IOUs, receive similar benefits from the publicly funded federal power system. Exchange benefits are passed directly to PGE's customers in the form of price adjustments contained in OPUC-approved tariffs. In accordance with federal recommendations and the intent of both parties to replace the Residential Exchange Program with one providing more predictable and stable cash payments by BPA, PGE and BPA in September 1998 signed a Residential Exchange Termination Agreement that provides for a total of $34.5 million in BPA payments to PGE over two years. The agreement continues to provide benefits to PGE's residential and small farm customers through at least the June 2001 termination date of the agreement. BPA has prepared its initial wholesale electric power and transmission rate proposals for the period October 2001 through September 2006, reflecting its intent to share the benefits of the Federal Columbia River Power system, restore fish and wildlife, encourage conservation and renewables development, and manage costs and risks. The rate case process is governed by the Northwest Power Act and involves workshops and hearings that give interested parties and participants the opportunity to participate fully in the process. Although it is anticipated that customers of investor-owned utilities will continue to receive benefits from the publicly funded federal power system beyond the 2001 termination of the current agreement with BPA, it has not yet been determined how this will be accomplished. ENERGY EFFICIENCY PGE has long promoted the efficient use of electricity. Current Demand Side Management (DSM) programs provide a range of services to all classes of PGE customers and seek to maximize those opportunities in which efficiency measures are most cost-effective for both PGE ratepayers and customers. To accomplish this, PGE focuses on both commercial and industrial new construction, industrial process improvements, and residential weatherization measures, including a program for low-income families. In the past, the costs of DSM programs have been deferred and amortized to expense over future periods. In response to new legislation that encourages a competitive marketplace for energy services and provides for a public service charge to fund conservation measures, PGE has requested OPUC approval to immediately expense all future DSM expenditures. PGE's current unamortized DSM investment would be amortized by the October 1, 2001 implementation of SB1149. These proposed changes, which would result in an approximate 2.3% average rate increase, are currently under review by the OPUC. COMPETITION AND MARKETING GENERAL As electricity deregulation moves forward nationally, PGE continues to maintain its commitment to service excellence while assisting in the formation of a competitive electricity market in the Northwest. Its Customer Choice pilot program was successfully implemented in 1998 and provided valuable information on the effects of retail competition on PGE and its customers. PGE will continue its efforts to bring market conditions to the industry, working closely with customers and regulators to achieve the state's policy goals. The outcome of these efforts to help create a more competitive electricity market will depend in large part on both statutory and regulatory changes. RETAIL COMPETITION AND MARKETING PGE operates within a state-approved service area and under current regulation is substantially free from direct retail competition with other electric utilities. PGE's competitors within its Oregon service territory include other fuel suppliers, such as the local natural gas company, which compete with PGE for the residential and commercial space and water heating market. In addition, there is the potential for the loss of PGE service territory from the creation of public utility districts or municipal utilities by voters. In September 1999, voters within the Columbia County cities of St. Helens, Scappoose, and Columbia City approved annexation to the Columbia River People's Utility District (CRPUD); voters within the Columbia County City of Rainier approved annexation to the Clatskanie Public Utility District. These annexations would provide for the transfer of approximately 7,300 PGE customers to these two utility districts. In January 2000, a memorandum of understanding was agreed upon by the parties that provides for the payment of approximately $10 million to PGE from the utility districts in exchange for the service territories of the four cities. The proposed sale is subject to approval by the OPUC. WHOLESALE COMPETITION AND MARKETING 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 low-cost hydroelectric generation, with summer-peaking wholesale customers in California and the Southwest, which have higher-cost fossil fuel generation. PGE has used 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. POWER SUPPLY Growth within PGE's service territory has underscored the Company's need for sources of reliable, low-cost energy supplies. The demand for energy within PGE's service territory has experienced an average annual growth rate of approximately 2.5% over the last 10 years and retail demand is expected to continue this upward trend. PGE has relied increasingly on short-term purchases to supplement its existing base of generating resources and long-term power contracts to meet its energy needs. Short- term purchases include both secondary as well as firm purchases for periods of less than one year in duration. The availability of short-term firm purchase agreements and PGE's ability to renew these contracts have enabled PGE to minimize risk and enhance its ability to provide reliable low-cost energy to retail customers. Increased competition has placed pressure on the price of short-term power as well as enhanced its availability. Northwest hydro conditions also have a significant impact on regional power supply. Plentiful water conditions can lead to surplus power and the economic displacement of more expensive thermal generation. GENERATING CAPABILITY PGE's existing hydroelectric, coal-fired, and gas-fired plants are important resources for the Company, providing 1,998 MW of generating capability (see Item 2. Properties, for a full listing of PGE's generating facilities). PGE's lowest-cost producers are its eight hydroelectric projects on the Clackamas, Sandy, Deschutes, and Willamette rivers in Oregon. These facilities operate under federal licenses, which will be up for renewal between the years 2001 and 2006. For further discussion of hydroelectric project relicensing, see "Hydro Relicensing" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. In conjunction with its federal relicensing process, PGE has reached a tentative agreement with the City of Portland, the State of Oregon, and the National Marine Fisheries Service to decommission its 22-MW Bull Run Hydroelectric Project, removing the Marmot and Little Sandy dams. The purpose of the agreement is to improve habitat for salmon, steelhead, and the other fish protected by the Endangered Species Act in the Little Sandy/Bull Run watersheds. The cost of removing the dams, constructed in the early 1900's, is estimated at $8 million. The regulatory approval process and dam decommissioning are expected to take approximately three years. In November 1999, PGE filed with the FERC a "Notice of Intent Not to File Application for New License", providing formal notice that it does not intend to relicense the Bull Run Project when its existing federal license expires in November 2004. The retirement of the Bull Run Project is not expected to have a material effect on the financial condition or results of operations of the Company. There are no current plans to remove any other of the Company's hydroelectric projects. On November 1, 1998, PGE signed a definitive agreement to sell its 20% interest in coal-fired generating Units 3 and 4 of the Colstrip power plant, located in eastern Montana. The agreement, subject to both state and federal approval, would transfer ownership of PGE's 296 MW interest in the plant to PP&L Global, a subsidiary of PP&L Resources, for $230.4 million. On April 7, 1999, PGE filed an application for approval of the sale with the OPUC; such application, as subsequently amended, included a $26.6 million (excluding transition costs) retail rate reduction, to become effective upon approval and sale. OPUC Staff recommended that approval of the proposed sale be denied absent both a higher sales price and further retail rate reduction. On February 29, 2000, the OPUC issued an order that denied PGE's application to sell its interest in Units 3 and 4 of the Colstrip power plant. SYSTEM RELIABILITY AND THE WSCC PGE relies on wholesale market purchases within the WSCC in conjunction with its base of generating resources to supply its resource needs and maintain system reliability. The WSCC is the largest and most diverse of the 10 regional electric reliability councils. Organized in 1967, it provides coordination for operating and planning a reliable and adequate electric power system for the western part of the continental United States, Canada, and Mexico. It provides the forum for its member systems to enhance communication, coordination, and cooperation in planing and operating a reliable interconnected electric system. During the last few years, the area covered by WSCC has become a dynamic marketplace for the trading of electricity. This area, which extends from Canada to Mexico and includes 14 Western states, has great diversity in climates and peak loads occur at different times of the year in the different regions within the WSCC area. Energy loads in the Southwest peak in summer due to air conditioning; northern loads peak during winter heating months. According to WSCC forecasts, the nearly 104 electric organizations participating in the WSCC, which include utilities, independent power producers and transmission utilities, have sufficient generating capacity to meet forecast demand and energy requirements through the year 2009. JANUARY RESERVE MARGIN WSCC REGION MEGAWATTS 2000 34,467 2001 34,133 2002 33,822 2003 32,940 2004 31,662 2005 31,496 2006 28,539 2007 27,834 2008 27,747 2009 26,320 During 1999, PGE's peak load was 3,544 MW, of which 31% was met through short-term purchases. PGE's firm resource capacity, including short-term purchase agreements, totaled approximately 5,333 MW as of December 31, 1999. RESTORATION OF SALMON RUNS The 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). 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. This change in water releases has resulted in decreased energy generation in the fall and winter. Favorable hydro conditions continued to help mitigate the effect of these actions in 1999. In 1999, nine federal agencies involved in the management of the Columbia River system formed a Federal Caucus to develop specific options for salmon recovery. The Federal Caucus will continue its efforts throughout 2000, coordinating with other regional efforts and forums to examine opportunities for recovering listed salmon. PGE continues to evaluate the impact of current and potential listings on the operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette Rivers. PGE's ongoing hydroelectric relicensing efforts, in addition to discussions with the listing agency, have begun addressing issues associated with endangered salmon. Based on this, and review of the proposed rules that have been issued thus far, PGE does not anticipate any significant operational changes to its hydroelectric projects during 2000 as a result of endangered salmon recovery measures. FUEL SUPPLY Fuel supply contracts are negotiated to support annual planned plant operations. Flexibility in contract terms is sought to allow for the most economic dispatch of PGE's thermal resources in conjunction with the current market price of wholesale power. COAL BOARDMAN PGE has agreements to purchase coal for Boardman that cover requirements through the year 2000. Ample supplies exist to fuel Boardman's requirements in future years. Coal purchases in 1999, totaling about 2 million tons, contained less than 0.4% of sulfur by weight and emitted less than the EPA allowable limit of 1.2 pounds of sulfur dioxide per MMBtu when burned. The coal, from surface mining operations in Wyoming and Utah, was subject to federal, state and local regulations. Coal is delivered to Boardman by rail under contracts with the Burlington Northern, Santa Fe, and Union Pacific Railroads. COLSTRIP Coal for Colstrip Units 3 and 4, located in southeastern Montana, is provided under contract with Western Energy Company, a wholly owned subsidiary of Montana Power Company. The contract provides that the coal delivered will not exceed a maximum sulfur content of 1.5% by weight. The Colstrip plant has sulfur dioxide removal equipment to allow operation in compliance with EPA's source-performance emission standards. SULFUR TYPE OF POLLUTION PLANT CONTENT CONTROL EQUIPMENT Boardman, OR 0.4% Electrostatic precipitators Colstrip, MT 0.7% Scrubbers and precipitators NATURAL GAS In addition to the agreements discussed below, the Company utilizes short-term and spot market purchases to secure transportation capacity and gas supplies sufficient to fuel plant operations. PGE remarkets any natural gas and transportation capacity that are excess to its needs. BEAVER PGE owns 90% 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. During 1999, PGE had access to 76,000 MMBtu/day of firm transportation capacity, enough to operate Beaver at a 70% load factor. In May 1999, PGE and B-R Pipeline Co., a wholly owned subsidiary of U.S. Gypsum Co, filed a joint application with the FERC for the sale by PGE of 12% of its interest (representing a 10.5% tenancy-in-common share) in the Kelso-Beaver Pipeline to B-R Pipeline for approximately $2.5 million; the sale represents pipeline capacity in excess of PGE's current or foreseeable needs. The sale has been approved by the OPUC and has received preliminary approval, subject to environmental review, by the FERC. COYOTE SPRINGS The Coyote Springs generating station utilizes 41,000 MMBtu/day of firm transportation capacity on three interconnecting pipeline systems accessing the gas fields in Alberta, Canada. Firm gas supplies for Coyote Springs are purchased at market based prices up to two years prior to delivery based on the anticipated operation of the plant. PGE believes that sufficient gas is available in the marketplace to meet the full fuel requirements of the plant. ENVIRONMENTAL MATTERS PGE operates in a state recognized for environmental leadership. PGE's environmental stewardship policy emphasizes minimizing waste in its operations, minimizing environmental risk, and promoting the wise use of energy. REGULATION PGE's current and historical 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 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. CLEANUP PGE is involved with others in the environmental cleanup of PCB contaminants at various sites as a potentially responsible party (PRP). The cleanup effort is considered complete at several sites, which are awaiting consent orders from the appropriate regulatory agencies. These and future cleanup costs are not expected to be material. HARBORTON PGE received a letter dated September 27, 1999, from the Oregon Department of Environmental Quality (DEQ) requesting that PGE perform a voluntary remedial investigation of its Harborton Substation Site to confirm whether any regulated hazardous substances have been released from the substation property into a portion of the Willamette River known as the Portland Harbor. A 1997 investigation of the Portland Harbor conducted by an U.S. Environmental Protection Agency (EPA) contractor purportedly revealed significant contamination of sediments within the harbor. The DEQ has advised PGE that, based on analytical results from the 1997 study, the EPA is considering Portland Harbor for inclusion on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act. The DEQ directed that PGE perform a remedial investigation pursuant to a DEQ approved Voluntary Agreement, and that the work be coordinated with other Portland Harbor sediment investigations currently being pursued by the DEQ that involve more than 50 PRPs. While PGE does not believe that it is responsible for any contamination in Portland Harbor, PGE entered into the Voluntary Agreement and will conduct an initial set of investigatory activities. Subsequent investigations will almost certainly be required if any significant soil or groundwater contamination is discovered during the course of the initial investigation being conducted by PGE. Remedial activities, if any, that PGE may ultimately perform with respect to this matter will depend on the results of its investigations. PGE does not expect this to have a material adverse impact on the financial condition or results of operations of the Company. AIR/WATER QUALITY 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 at least equal federal standards. Oregon has air quality standards that are more stringent than federal standards. The air pollutants addressed under the Act that primarily affect PGE are sulfur dioxide ("SO{2}"), nitrogen oxides ("NO{x}"), and particulate matter. PGE manages its emissions through burning low sulfur fuel, emission controls, emission monitoring and through good combustion controls. The SO{2} emission allowances awarded under the Act, and those allowances expected to be awarded annually in the future, are sufficient to operate Boardman at a 60% to 67% capacity factor without having to further reduce emissions. In addition, the number of emission allowances are sufficient to operate Colstrip, which utilizes scrubbers. If necessary, PGE intends to acquire a relatively small number of additional allowances in order to meet excess capacity needs. PGE sold its share of Centralia to Avista Corp. as of December 31, 1999, so PGE is no longer a party in meeting the emission requirements for this plant. It is not yet known what impacts the federal Ozone Transport, Regional Haze, or PM{2.5} regulations may have on future plant operations, operating costs, or generating capacity. Federal operating air permits, issued by the DEQ, have been obtained for all of PGE's fossil fuel generating facilities, which includes its combustion turbine plants. Two of these air permits (for the Beaver and Boardman Plants) will require renewal applications due in July 2000. The current permits are in effect until the renewal process is completed. ITEM 2. PROPERTIES PGE's principal plants and appurtenant generating facilities and storage reservoirs are situated on land owned by PGE in fee or land under the control of PGE pursuant to valid existing leases, federal or state licenses, easements, or other agreements. In some cases meters and transformers are located upon the premises of customers. 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. The map below shows PGE's Oregon service territory and location of its generating facilities: Generating facilities owned by PGE are set forth in the following table: PGE NET MW FACILITY LOCATION FUEL CAPABILITY WHOLLY OWNED: Faraday Clackamas River Hydro 44 North Fork Clackamas River Hydro 54 Oak Grove Clackamas River Hydro 44 River Mill Clackamas River Hydro 25 Pelton Deschutes River Hydro 108 Round Butte Deschutes River Hydro 300 Bull Run Sandy River Hydro 22 Sullivan Willamette River Hydro 16 Beaver Clatskanie, OR Gas/Oil 500 Coyote Springs Boardman, OR Gas/Oil 241 PGE JOINTLY OWNED: INTEREST Boardman Boardman, OR Coal 348 @ 65.0% Colstrip 3 & 4 Colstrip, MT Coal 296 @ 20.0% Total 1,998 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. All of its licenses expire during the years 2001 to 2006. The FERC requires that a notice of intent to relicense these projects be filed approximately five years prior to expiration of the license. PGE filed for relicensing of the Pelton Round Butte Project in December 1998 and in December 1999 reached a preliminary agreement that would result in shared ownership and control of the Project with the Confederated Tribes of Warm Springs over a proposed 50-year license period. PGE would remain as the operator of the Project. PGE has reached a tentative agreement with the City of Portland, the State of Oregon, and the National Marine Fisheries Service to decommission the Bull Run Hydroelectric Project, removing the Marmot and Little Sandy Dams. The purpose of the agreement is to improve habitat for salmon, steelhead, and other fish protected by the Endangered Species Act in the Little Sandy/Bull Run watersheds. In November 1999, PGE filed with the FERC a "Notice of Intent Not to File Application for New License" when its existing federal license expires in November 2004. The regulatory approval process and dam decommissioning are expected to take approximately three years. PGE is actively pursuing the renewal of all other licenses for its hydroelectric generating plants. For further information see "Hydro Relicensing" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Following the 1993 Trojan closure, PGE was granted a possession-only license amendment by the NRC. In early 1996 PGE received NRC approval of its Trojan decommissioning plan. See Note 11, Trojan Nuclear Plant, in the Notes to the Financial Statements for further information. LEASED PROPERTIES PGE leases its headquarters complex in downtown Portland and the coal- handling facilities and certain railroad cars for Boardman. ITEM 3. LEGAL PROCEEDINGS UTILITY CITIZENS' UTILITY BOARD OF OREGON V. PUBLIC UTILITY COMMISSION OF OREGON AND UTILITY REFORM PROJECT AND COLLEEN O'NEILL V. PUBLIC UTILITY COMMISSION OF OREGON, Marion County Oregon Circuit Court, the Court of Appeals of the State of Oregon, the Oregon Supreme Court. The Citizens' Utility Board (CUB) appealed a 1994 ruling from the Marion County Circuit Court that upheld the order of the OPUC in its Declaratory Ruling proceeding (DR-10). In the DR-10 proceeding, PGE filed an Application with the OPUC requesting a Declaratory Ruling regarding recovery of the Trojan investment and decommissioning costs. On August 9, 1993 the OPUC issued the declaratory ruling. In its ruling, the OPUC agreed with an opinion issued by the Oregon Department of Justice (Attorney General) stating that under current law, the OPUC has authority to allow recovery of and a return on Trojan investment and future decommissioning costs. In PGE's 1995 general rate case, the OPUC issued an order granting PGE full recovery of Trojan decommissioning costs and 87% of its remaining investment in the plant. The Utility Reform Project (URP) filed an appeal of the OPUC's order. URP alleged that the OPUC lacked authority to allow PGE to recover Trojan costs through its rates. The complaint sought to remand the case to the OPUC and have all costs related to Trojan immediately removed from PGE's rates. The CUB also filed an appeal challenging the portion of the OPUC's order issued in PGE's 1995 general rate case that authorized PGE to recover a return on its remaining investment in Trojan. The CUB alleged that the OPUC's decision was not based upon evidence received in the rate case, is not supported by substantial evidence in the record of the case, was based on an erroneous interpretation of law and is outside the scope of the OPUC's discretion, and otherwise violates constitutional or statutory provisions. The CUB sought to have the order modified, vacated, set aside or reversed. On April 4, 1996, a circuit court judge in Marion County, Oregon rendered a decision that contradicted a November 1994 ruling from the same court. The 1996 decision found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan currently in PGE's rate base. The 1994 and 1996 circuit court decisions were consolidated and appealed to the Oregon Court of Appeals. On June 24, 1998, the Court of Appeals of the State of Oregon ruled that the OPUC does not have the authority to allow PGE to recover a rate of return on its undepreciated investment in Trojan. The court upheld the OPUC's authorization of PGE's recovery of its undepreciated investment in Trojan and its costs to decommission Trojan. On August 26, 1998, PGE filed a Petition for Review with the Oregon Supreme Court, supported by amicus briefs filed by three other major utilities seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's return on its undepreciated investment in Trojan. The OPUC also filed such a petition for review. Also on August 26, 1998, the Utility Reform Project 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 recovery of its undepreciated investment in Trojan. On April 29, 1999, the Oregon Supreme Court accepted the petitions for review of the June 24, 1998, Oregon Court of Appeals decision. On June 16, 1999, Oregon's governor signed Oregon House Bill 3220 authorizing the OPUC to allow recovery of a return on the undepreciated investment in property retired from service. One of the effects of the bill is to affirm retroactively the OPUC's authority to allow PGE's recovery of a return on its undepreciated investment in the Trojan generating facility. Relying on the new legislation, on July 2, 1999, the Company requested the Oregon Supreme Court to vacate the June 24, 1998, adverse ruling of the Oregon Court of Appeals and affirm the validity of the OPUC's order allowing PGE to recover a return on its undepreciated investment in Trojan. The Utility Reform Project and the Citizens Utility Board, another party to the proceeding, opposed such 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; such effort by the referendum's sponsors was successful and the referendum will appear on the November 2000 ballot. The Oregon Supreme Court has stated it will hold its review of the Court of Appeals decision in abeyance until after the election. COLUMBIA RIVER PEOPLE'S UTILITY DISTRICT V. PORTLAND GENERAL ELECTRIC COMPANY On December 1, 1998, the Columbia River People's Utility District (CRPUD) filed an anti-trust complaint in Federal District Court that seeks to overturn a 1984 Judgment and Acquisition Agreement that confirmed PGE's exclusive right to serve Boise Cascade Corporation. The complaint seeks to declare as invalid and unenforceable a provision establishing the amount to be paid by CRPUD upon its condemnation of PGE facilities serving Boise Cascade; the complaint also seeks an injunction barring PGE from enforcing earlier agreements and judgments related to this matter. Attorney fees and costs were sought but no claim was made for monetary damages. On March 24, 1999, the Court entered Summary Judgment in favor of PGE. On April 21, 1999, CRPUD filed a Notice of Appeal, with briefing and oral argument to follow. A decision from the Ninth Circuit Court of Appeals may be rendered in 2000. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS PGE is a wholly owned subsidiary of Enron, which owns all 42,758,877 shares of PGE's outstanding stock. Aggregate cash dividends declared on common stock were as follows (millions of dollars): QUARTER 1999 1998 First $ 20 $ - Second 20 16 Third 20 16 Fourth 21 17 PGE is restricted, without prior OPUC approval, from making any dividend distributions to Enron that would reduce PGE's common equity capital below 48% of total capitalization. ITEM 6. SELECTED FINANCIAL DATA FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997 1996 1995 (millions of dollars) Operating Revenues $1,378 $1,176 $1,416 $1,110 $ 982 Net Operating Income 190 200 208 230 201 Net Income 128 137 126 156 93{1} Total Assets $3,167 $3,162 $3,256 $3,398 $3,246 Long-Term Obligations{2} 763 876 1,038 963 931 NOTES TO THE TABLE ABOVE: {1} Includes a loss of $50 million from regulatory disallowances. {2} Includes long-term debt, preferred stock subject to mandatory redemption requirements, long-term capital lease obligations, and commercial paper to be refinanced. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS GENERAL 1999 COMPARED TO 1998 Portland General Electric's net income for 1999 was $128 million compared to $137 million for 1998. Increased property, franchise, and income taxes, as well as a reduction from 1998's gains on the sale of Company land were primarily responsible for the decrease. These were partially offset by an increased margin on higher electricity sales and by reduced interest charges. Retail revenues increased $103 million primarily due to higher energy sales resulting from both the addition of 15,000 new customers as well as the termination of 1998's Customer Choice pilot program which enabled participating customers to purchase their electricity from other energy service providers. Revenues from power delivery services to energy service providers totaled $21 million last year; termination of the pilot program in 1999 caused the decrease in Other operating revenues. NET INCOME (Millions) 1999 128 1998 137 1997 126 1996 156 1995 93 Wholesale revenues increased $121 million (52%) due to both higher energy sales volume and prices. Increased energy sales resulted largely from sales in the wholesale market of excess power obtained to meet higher anticipated retail demand. Demand was lower than expected due to mild temperatures in 1999. OPERATING REVENUES (Millions) Retail Wholesale 1999 1004 355 1998 901 234 1997 898 497 1996 906 194 1995 877 95 Purchased power and fuel costs increased $197 million (45%) due to higher prices for increased energy purchases. Higher regional power and gas market prices increased the cost of firm power purchases, resulting in a 25% increase in average power prices. Purchases were made to supply expected higher retail demand caused by weather volatility and customer growth, including the return of those customers participating in 1998's Customer Choice pilot program. Increased purchases also reflect PGE's ability to purchase power at a price more economical than generation. Company generation decreased from 37% to 32% of total power needs, primarily due to the economic displacement of gas powered generation, which declined about 21%. Coal and hydro generation approximated that of last year. RETAIL ENERGY SALES Million MWh 1999 19.259 1998 18.736 1997 18.221 1996 17.559 1995 17.065 MEGAWATT-HOURS/VARIABLE POWER COSTS Megawatt-Hours Average Variable (thousands) Power Cost (Mills/KWh) 1999 1998 1999 1998 Generation 10,515 10,854 9.8 8.6 Firm Purchases 18,897 16,595 23.2 17.3 Spot Purchases 3,712 2,180 19.7 23.6 Total Send-Out 33,124 29,629 *19.5 *15.6 (* includes wheeling costs) Operating expenses (excluding purchased power and fuel, depreciation and taxes) increased $2 million, or less than 1%, as increased administrative and delivery system costs were largely offset by reduced generating plant expenses. Depreciation and amortization expense increased $6 million (4%) primarily due to the effect of 1998's non-recurring $4 million gain on the sale of land formerly occupied by PGE's Western Division offices. OPERATING EXPENSES (Millions) DEPRECIATION OPERATING COSTS VARIABLE POWER 1999 155 395 638 1998 149 386 441 1997 155 378 675 1996 162 410 308 1995 135 357 294 Taxes other than income taxes increased $4 million (7%) primarily due to higher state property taxes, caused by increases in taxable values, and city franchise fees that increased with higher electricity sales. Income taxes increased $3 million (4%) primarily because of the reversal of pre- 1981 tax benefits related to the depreciation of certain regulatory assets; this was partially offset by a small decrease in net taxable income for the year. Interest charges decreased $6 million (8%) due to a reduction in outstanding debt. 1998 COMPARED TO 1997 Portland General Electric's net income for 1998 was $137 million compared to $126 million for 1997. Net income in 1997 included the effect of a $14 million non-recurring loss provision associated with non-utility property. PGE's operating performance reflected the addition of over 19,000 new customers in a growing service territory. Retail revenues increased $3 million, as the effects of warmer winter weather and the move of about 8,700 customers to other energy service providers under PGE's Customer Choice pilot program largely offset the increase in customers served. Revenues from power delivery services to energy service providers totaled $20 million for the year and caused the increase in Other operating revenues. Wholesale revenues decreased $263 million, or 53%, reflecting PGE's decision to limit wholesale activities to transactions related to the management of system power supplies and generation. Purchased power and fuel costs decreased $234 million, or 35%, due almost entirely to reduced wholesale trading activity. A 52% decrease in energy purchases was offset somewhat by higher average prices (16.2 mills in 1997, 18.0 mills in 1998) caused largely by increased winter gas prices and tight market conditions in the southwestern United States. Company generation provided 37% of total power needs, up from 16% in 1997; coal and gas powered generation almost tripled with average production costs significantly less than the cost to purchase. Operating expenses (excluding purchased power and fuel, depreciation and taxes) increased $9 million, or 4%. The increase was due largely to the payment of $12 million in Enron overhead costs and a $2 million increase in production and distribution expenses; these were partially offset by a $5 million decrease in customer support, marketing, and sales expenses. Depreciation and amortization expense decreased $6 million, or 4%. A $13 million decrease caused by the amortization of regulatory credits and the gain on the sale of land formerly occupied by PGE's Western Division offices was partially offset by a $7 million increase in depreciation expense due to capital additions to PGE's distribution system. Other Income increased $20 million, due largely to a $14 million after tax loss provision recorded in 1997 for the future removal of non-utility property. Also contributing to the 1998 increase were gains on sales of non-utility land and timber. CASH FLOW 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. PGE maintains varying levels of short-term debt, primarily in the form of commercial paper, which serves as the primary form of daily liquidity. In 1999, monthly balances ranged from $124 million to $266 million. PGE has two committed borrowing facilities: a $200 million facility maturing in July 2000 and a $100 million facility maturing in August 2000. Both facilities are used as backup for PGE's commercial paper facility. A significant portion of cash provided by operations comes from 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 $236 million in 1999, compared to $265 million in 1998. The decrease is due primarily to a reduction from the amount received in 1998 from the Bonneville Power Administration under terms of the Residential Exchange Termination agreement. INVESTING ACTIVITIES consist primarily of improvements to PGE's distribution, transmission, and generation facilities, as well as energy efficiency program expenditures. Capital expenditures of $188 million in 1999 were primarily for the expansion and upgrade of PGE's distribution system and also include the $37 million purchase of previously leased combustion turbine generators at the Beaver generating plant. Capital expenditures are expected to approximate $180 million in 2000. Over the next few years, anticipated expenditures are expected to approximate current levels, with the majority of expenditures comprised of improvements to the Company's expanding distribution system to support both new and existing customers within PGE's service territory. FINANCING ACTIVITIES provide supplemental cash for day-to-day operations and capital requirements as needed. PGE relies on commercial paper borrowings and cash from operations to manage its day-to-day financing requirements. In 1999, PGE repaid $113 million in long-term debt, including $94 million in matured First Mortgage Bonds, $9 million in other long-term debt, and the early redemption of $10 million in 7 3/4 % First Mortgage Bonds due in the year 2023, funded primarily through commercial paper borrowings. The Company also repaid $30 million ($32 million less $2 million prepaid interest) in policy loans on corporate owned life insurance. During 1999, PGE's dividend payments totaled $83 million, consisting of common stock dividends of $81 million paid to its parent and $2 million in preferred stock dividends. In 1998, PGE's dividend payments totaled $51 million, consisting of common stock dividends of $49 million paid to its parent and $2 million in preferred stock dividends. In April 1999, PGE filed a $200 million shelf registration statement with the Securities and Exchange Commission for the purpose of issuing long-term debt from time to time, as determined in light of market conditions and other factors, the proceeds from which will be used to refund fixed and variable rate securities, reduce commercial paper borrowings, and fund planned construction and other expenditures. Subject to the above factors, PGE expects to issue debt under this shelf filing in March 2000. In July 1999, PGE received approval from the Federal Energy Regulatory Commission to issue short-term debt, including commercial paper, credit facilities, and other evidences of indebtedness up to $350 million. This approval is effective for two years and replaces and supercedes PGE's prior approval from the FERC authorizing short-term borrowing of $250 million. On August 6, 1999, PGE entered into a $100 million revolving credit facility with two commercial banks. This facility, combined with the Company's existing $200 million revolving credit facility, effectively increases the total committed credit for PGE to $300 million. These facilities are used primarily as backup for commercial paper and borrowings from commercial banks under uncommitted lines of credit. In July 1999, Duff & Phelps Credit Rating Co. (DCR) assigned initial ratings to PGE's debt, with senior secured debt rated 'AA-', senior unsecured debt rated 'A+', preferred stock and junior subordinated debt rated 'A', and commercial paper rated 'D1'. Also in July, Moody's Investors Services (Moody's) changed PGE's rating outlook from 'stable' to 'positive'. On November 8, 1999, in response to the announced purchase and sale agreement for PGE and uncertainties regarding the future status of certain OPUC stipulations that were agreed to in its 1997 merger with Enron, credit rating agencies reviewed their ratings of the Company. DCR placed the Company on Rating Watch--Uncertain, Moody's placed PGE's ratings on review for possible downgrade, and Standard and Poor's placed the ratings of the Company on CreditWatch with negative implications. On November 11, 1999, Moody's confirmed the Prime-1 short-term debt rating for commercial paper issued by PGE. 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 its First Mortgage Bonds. As of December 31, 1999, PGE has the capability to issue preferred stock and additional First Mortgage Bonds in amounts sufficient to meet its capital requirements. FINANCIAL AND OPERATING OUTLOOK PORTLAND GENERAL ELECTRIC COMPANY - ELECTRIC UTILITY PROPOSED ACQUISITION On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion, comprised of $2.02 billion in cash and the assumption of Enron's approximately $80 million merger payment obligation. The proposed transaction, which is subject to regulatory approval, is expected to close in late 2000. On January 18, 2000, Sierra filed with the OPUC an application to acquire PGE. On February 3, 2000, Sierra filed with the SEC an application to acquire PGE and also to become a registered public utility holding company. REGULATION AND COMPETITION STATE 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 an open market competitive framework where customers have a choice of energy supplier. Federal laws and regulations now provide for open access to transmission systems and several states have adopted or are considering new regulations to allow open access for all energy suppliers. In 1999, Oregon's governor signed into law deregulation legislation giving industrial and commercial customers of investor-owned utilities direct access to energy suppliers and residential customers access to a portfolio of rate options. PGE recognizes that when a competitive marketplace exists, customers will make their energy purchasing decisions based upon many factors, including price, service and system reliability. To meet these competitive challenges, PGE is participating in restructuring processes that will determine the shape of future markets and is pursuing strategies that capitalize on its competitive position, including the development and delivery of innovative products and services. PGE continues to develop its competitive strategy as legislation, regulation and market opportunities continue to evolve. Federal 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, lower prices and more choices to wholesale energy customers. Further legislation to restructure the electric industry, including retail choice, is under active consideration at the federal level. Congressional committee hearings on electricity restructuring are expected to continue, although there remains considerable uncertainty regarding their ultimate outcome. In 1998, PGE filed an application with the FERC to increase its rates for transmission service, in accordance with the terms of FERC Order 888 requiring open-access transmission by public utilities. Revised rates were implemented on February 11, 1999, with final settlement and filing on March 1, 1999. PGE continues to formulate strategies to meet the challenges of wholesale competition. RETAIL CUSTOMER GROWTH AND ENERGY SALES During 1999, weather adjusted retail energy sales grew 2.1%. Commercial and manufacturing sales increased by 3.9% and 0.3% respectively. The addition of over 15,000 customers resulted in residential sales growth of 2.0%. PGE forecasts retail energy sales growth of approximately 3.5% in 2000 with the rebound in the manufacturing sector. WHOLESALE SALES The availability of electric generating capability in the Western U.S., the entrance of numerous wholesale marketers and brokers into the market, and open access transmission are contributing to increasing competitive pressure on the price of power. In addition, the development of financial markets, including the NYMEX electricity contract, has led to enhanced price discovery available for market participants, further adding to the downward pressure on wholesale prices and margins. During 1999, PGE's wholesale sales accounted for about 26% of total revenues and 40% of total energy sales. PGE will continue its participation 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. POWER & FUEL SUPPLY PGE's base of hydro and thermal generating capacity, supplemented by its existing firm power contracts and the availability of competitively-priced wholesale energy within the region, provide the Company with the flexibility needed to respond to seasonal fluctuations in the demand for electricity within its service territory. PGE has long-term power contracts with four hydro projects on the mid- Columbia River providing capability of 650 MW, and has also relied increasingly upon short-term purchases to meet its energy needs. The Company anticipates that an active wholesale market and a surplus of generating capacity within the WSCC should provide sufficient wholesale energy available at competitive prices to supplement its generation and purchases under existing firm power contracts. Though early forecasts indicate above-average water conditions for 2000, efforts to restore salmon runs on the Columbia and Snake rivers may somewhat reduce the amount of water available for generation, which could affect the availability and price of purchased power. Additional factors that could affect the availability and price of purchased power 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. During 1999, PGE generated approximately 32% of its total load requirement, compared to approximately 37% in 1998. Short-term and long-term purchases were utilized to meet the remaining load. In February 1999, PGE elected to exercise its option to purchase the six combustion turbine generators at Beaver for their $37 million fair market value. The generators, previously operated under terms of a 25-year lease that expired in August 1999, produce a net output of approximately 500 MW in combined-cycle configuration. RESTORATION OF SALMON RUNS - 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. ASSET SALES In November 1998, PGE signed an agreement to sell its 20% interest in coal- fired generating Units 3 and 4 of the Colstrip power plant to PP&L Global for $230.4 million, subject to approval of the OPUC. In late February 2000, the OPUC denied the Company's application to sell its interest in the plant. In September 1999, voters within four Columbia County cities approved annexation, and transfer of approximately 7,300 PGE customers, to two separate public utility districts. Upon OPUC approval, PGE would receive approximately $10 million in exchange for its service territory in these four cities. In December 1999, PGE sold its 2.5% interest in the Centralia Steam Electric Generating Plant to Avista Corp. for approximately $3.5 million; the Company has an agreement to purchase power from the plant during the first several months of 2000. In February 2000, PGE announced an agreement with the Confederated Tribes of the Warm Springs (Tribes) allowing the purchase of portions of the Pelton Round Butte hydroelectric project over a 50-year license period. PGE would remain as the operator of the project, which provides about 20% of the Company's power-generating capacity. HYDRO RELICENSING PGE HYDRO - PGE's eight hydroelectric plants provide economical generation and flexible load following capabilities; in 1999, they produced 2.8 million MWh of renewable energy, about 9% of PGE's total load. The plants operate under federal licenses, which will be up for renewal between the years 2001 and 2006. Numerous meetings were conducted in 1999 in support of relicensing PGE's hydroelectric projects on the Clackamas, Sandy, and Willamette Rivers; licenses on these plants, with combined generating capacity of 203 MW, expire in 2004 and 2006. Should relicensing not be completed prior to the expiration of the original licenses, it is anticipated that PGE will be issued annual licenses at substantially identical terms and conditions until such time as final relicensing has been completed. In May, PGE, with support of the City of Portland and state and federal agencies, decided to prepare a license surrender application for its 22-MW Bull Run Project on the Sandy River instead of continuing the process of preparing and filing a new operating license application. In November, PGE filed with the FERC a "Notice of Intent Not to File Application for New License", providing formal notice that it does not intend to relicense the Bull Run Project when its existing federal license expires in November 2004. Uncertainty in upcoming relicensing, mitigation, and operating and maintenance costs were key factors in deciding to retire the Bull Run Project. PGE continued the relicensing process for its 408-MW Pelton Round Butte Project throughout 1999, filing a final license application in December. The Confederated Tribes of Warm Springs, currently the licensee for a powerhouse located at a reregulating dam within the project, also proceeded with their competing relicensing process for the entire project and submitted a final license application. As a result of ongoing discussions in 1998 and 1999, PGE and the Tribes reached a preliminary agreement that would result in shared ownership and control of the project, which provides about 20% of the Company's power-generating capacity. 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. Certain Idaho Electric Utility Co-operatives have initiated proceedings with the FERC seeking to change the allocation of generation from the Priest Rapids and Wanapum dams between electric utilities in the region upon expiration of the current contracts. In early 1998, the FERC ruled that the portion of the output from these dams made available to purchasers such as PGE be reduced to 30%, and that such purchases be at market-based rather than cost-based prices. This decision could change both PGE's percentage share and the price of power from these facilities, although such changes are not yet determinable. 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. NUCLEAR DECOMMISSIONING PGE currently estimates the total cost to decommission Trojan at $339 million (nominal dollars), with approximately $114 million expended through 1999. The total estimate assumes that the majority of decommissioning activities will be completed after the spent fuel has been transferred to a temporary dry spent fuel storage facility in 2002. The plan anticipates final site restoration activities will begin in 2018 after PGE completes shipment of spent fuel to a USDOE facility (see Note 11, Trojan Nuclear Plant, in the Notes to Financial Statements, for further discussion of the decommissioning plan). In 1999, PGE made significant progress in decommissioning Trojan. In August, PGE shipped the Trojan reactor vessel as a single package, called the Reactor Vessel and Internals Removal Project, to be disposed of at the Hanford Nuclear Reservation. This precedent-setting project saved several million dollars compared to the conventional segmentation approach. PGE expects remaining transition activities to be extended through 2002 due to the continuing delay of the Independent Spent Fuel Storage Installation project. Transition activities are comprised of operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage. PGE anticipates total 2000 decommissioning costs of approximately $42 million, compared to about $41 million in 1999. 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 these hazards are no longer present. Decommissioning is proceeding within approved cost estimates. YEAR 2000 A Year 2000 problem was anticipated which could have resulted from the use in computer hardware and software of two digits rather than four digits to define the applicable year. The use of two digits was a common practice for decades when computer storage and processing was much more expensive than today. When computer systems must process dates both before and after January 1, 2000, two-digit year "fields" may create processing ambiguities that can cause errors and system failures. For example, computer programs that have date-sensitive features may recognize a date represented by "00" as the year 1900 instead of 2000.PGE estimates total expenditures related to Year 2000 issues will approximate $20-22 million, about 90% of which has been spent to date. Pursuant to an April 1999 accounting order from the OPUC, PGE has capitalized approximately $10 million of incremental Year 2000 costs, which will be amortized over a 5-year period beginning January 1, 2000. The order defers to a future proceeding whether PGE will be allowed to recover the balance of any unamortized costs in rates. PGE's efforts related to Year 2000 issues resulted in several company-wide system improvements that will benefit the Company and its customers in the future. These include an automated phone system capable of handling three times the number of phone calls as the older system, an upgrade Energy Management System, desktop computer upgrades that incorporate newest technologies, replacement of meter reading equipment, creation of contingency plans that can be used in the event of natural disasters, and a system of satellite phones for emergency communication between generating plants, load dispatchers, power marketing and substation operations. The year 2000 problem has caused no material disruption to PGE's mission- critical facilities or operations. PGE will remain vigilant for Year 2000 related problems that may yet occur, due to hidden defects in computer hardware or software at PGE or PGE's mission-critical external entities. PGE anticipates that the Year 2000 problem will not create material disruptions to its mission-critical facilities or operations, and will not create future material costs. NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. In June 1999, the FASB issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. A company may implement SFAS No. 133, as of the beginning of any fiscal quarter after issuance; however, the statement cannot be applied retroactively. PGE does not plan to adopt SFAS No. 133 early and believes that the statement will not have a material impact on its accounting for price risk management activities or physical based contracts. INFORMATION REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although PGE believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include political developments affecting federal and state regulatory agencies, the pace of electric industry deregulation in Oregon and in the United States, environmental regulations, changes in the cost of power, adverse weather conditions, and the effects of the Year 2000 date change during the periods covered by the forward-looking statements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risk arising from the need to purchase fuel for its generating units (both natural gas and coal) as well as the purchase of power to meet the needs of its retail customers. This price and location risk is mitigated by PGE's use of swaps, futures and options. The use of these instruments during the year and their estimated fair values at December 31, 1999 and 1998 were not material. In 1998, PGE entered into an interest rate swap agreement to manage interest rate exposure and cancelled these swap agreements in 1999 with an immaterial gain. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The following financial statements of Portland General Electric Company and 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 assessed its internal control system as of December 31, 1999, 1998 and 1997, relative to current standards of control criteria. Based upon this assessment, management believes that its system of internal controls was adequate during the periods to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition. Arthur Andersen LLP was engaged to audit the financial statements of PGE and issue reports 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 opinion on the financial statements. Arthur Andersen LLP was also engaged to examine and report on management's assertion about the effectiveness of PGE's system of internal controls over financial reporting and the protection of assets against unauthorized acquisition, use or disposition. The Reports of Independent Public Accountants appear in this Annual Report. The adequacy of PGE's financial controls and the accounting principles employed in financial reporting are under the general oversight of the Audit Committee of Enron's Board of Directors. No member of this committee is an officer or employee of Enron or PGE. The independent public 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. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholders of Portland General Electric Company: We have examined management's assertion that the system of internal control of Portland General Electric Company and its subsidiaries as of December 31, 1999, 1998 and 1997, was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition, included in the accompanying report on Management's Responsibility for Financial Reporting. Management is responsible for maintaining effective internal control over the reliability of the financial statements and the protection of assets against unauthorized acquisition, use or disposition. Our responsibility is to express an opinion on management's assertion based on our examination. Our examination was made in accordance with standards established by the American Institute of Certified Public Accountants and, accordingly, included obtaining an understanding of the system of internal control over financial reporting and the protection of assets against unauthorized acquisition, use or disposition, testing and evaluating the design and operating effectiveness of the system of internal control and such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion. Because of inherent limitations in any system of internal control, errors or irregularities may occur and not be detected. Also, projections of any evaluation of the system of internal control to future periods are subject to the risk that the system of internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assertion that the system of internal control of Portland General Electric Company and its subsidiaries as of December 31, 1999, 1998, and 1997 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition is fairly stated, in all material respects, based upon current standards of control criteria. Arthur Andersen LLP Portland, Oregon February 29, 2000 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholders of Portland General Electric Company: We have audited the accompanying consolidated balance sheets of Portland General Electric Company (an Oregon corporation), and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, retained earnings and cash flow for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Portland, Oregon February 29, 2000 PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997 (MILLIONS OF DOLLARS) OPERATING REVENUES $ 1,378 $ 1,176 $ 1,416 OPERATING EXPENSES Purchased power and fuel 638 441 675 Production and distribution 135 134 132 Administrative and other 115 114 107 Depreciation and amortization 155 149 155 Taxes other than income taxes 61 57 56 Income taxes 84 81 83 1,188 976 1,208 NET OPERATING INCOME 190 200 208 OTHER INCOME (DEDUCTIONS) Miscellaneous 13 13 (21) Income taxes (6) (1) 13 7 12 (8) INTEREST CHARGES Interest on long-term debt and 61 68 69 other Interest on short-term borrowings 8 7 5 69 75 74 NET INCOME 128 137 126 PREFERRED DIVIDEND REQUIREMENT 2 2 2 INCOME AVAILABLE FOR COMMON STOCK $ 126 $ 135 $ 124 PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997 (MILLIONS OF DOLLARS) BALANCE AT BEGINNING OF YEAR $ 356 $ 270 $ 292 NET INCOME 128 137 126 MISCELLANEOUS - - (2) 484 407 416 DIVIDENDS DECLARED Common stock - cash 81 49 47 Common stock - property - - 97 Preferred stock 2 2 2 83 51 146 BALANCE AT END OF YEAR $ 401 $ 356 $ 270 The accompanying notes are an integral part of these consolidated financial statements. PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS AT DECEMBER 31 1999 1998 (MILLIONS OF DOLLARS) ASSETS ELECTRIC UTILITY PLANT - ORIGINAL COST Utility plant (includes Construction work in progress of $44 and $35) $ 3,295 $ 3,182 Accumulated depreciation (1,430) (1,363) 1,865 1,819 OTHER PROPERTY AND INVESTMENTS Contract termination receivable 85 95 Receivable from parent 89 97 Nuclear decommissioning trust, at market value 42 72 Corporate owned life isurance, less loans of $0 and $32 85 63 Miscellaneous 17 15 318 342 CURRENT ASSETS Cash and cash equivalents - 4 Accounts and notes receivable 140 135 Unbilled and accrued revenues 49 45 Inventories, at average cost 37 28 Prepayments and other 41 31 267 243 DEFERRED CHARGES Unamortized regulatory assets 691 731 Miscellaneous 26 27 717 758 $ 3,167 $ 3,162 CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity Common stock, $3.75 par value per share, 100,000,000 shares authorized, 42,758,877 shares outstanding $ 160 $ 160 Other paid-in capital - net 480 480 Retained earnings 401 356 Cumulative preferred stock Subject to mandatory redemption 30 30 Long-term obligations 701 744 1,772 1,770 CURRENT LIABILITIES Long-term debt due within one year 32 102 Short-term borrowings 266 105 Accounts payable and other accruals 167 145 Accrued interest 11 11 Dividends payable 1 1 Accrued taxes 12 35 489 399 OTHER Deferred income taxes 351 351 Deferred investment tax credits 36 39 Trojan decommissioning and transition costs 234 274 Unamortized regulatory liabilities 197 237 Miscellaneous 88 92 906 993 $ 3,167 $ 3,162 The accompanying notes are an integral part of these consolidated financial statements. PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW FOR THE YEARS ENDED DECEMBER 31 1999 1998 1997 (MILLIONS OF DOLLARS) CASH FLOWS FROM OPERATING ACTIVITIES: Reconciliation of net income to net cash provided by (used in) operating activities Net income $ 128 $ 137 $ 126 Non-cash items included in net income: Depreciation and amortization 155 149 155 Deferred income taxes and investment tax credit (3) (5) (58) Other non-cash expenses 24 - 24 Changes in working capital: (Increase) decrease in receivables (9) (8) 27 Increase (decrease) in payables (1) (50) 51 Other working capital items - net (18) (1) (1) Other - net (16) 43 35 NET CASH PROVIDED BY OPERATING ACTIVITIES: 236 265 359 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (188) (144) (180) Other - net 14 (4) (28) NET CASH USED IN INVESTING ACTIVITIES (174) (148) (208) CASH FLOWS FROM FINANCING ACTIVITIES: Repayment of long-term debt (113) (214) (115) Issuance of long-term debt and commercial paper 161 148 8 Dividends paid (83) (51) (65) Repayment of loans on corporate owned life insurance (32) - - Other - net 1 1 5 (66) (116) (167) NET CASH USED IN FINANCING ACTIVITIES: INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (4) 1 (16) CASH AND CASH EQUIVALENTS, THE BEGINNING OF YEAR 4 3 19 CASH AND CASH EQUIVALENTS, END OF YEAR $ - $ 4 $ 3 Supplemental disclosures of cash flow information Cash paid during the year: Interest, net of amounts capitalized $ 60 $ 63 $ 71 Income taxes 139 133 96 The accompanying notes are an integral part of these consolidated financial statements. PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS NATURE OF OPERATIONS On July 1, 1997 Portland General Corporation (PGC), the former parent of PGE, merged with Enron Corp. (Enron) with Enron continuing in existence as the surviving corporation. PGE is currently a wholly owned subsidiary of Enron and subject to control by the Board of Directors of Enron. PGE is engaged in the generation, purchase, transmission, distribution, and sale of electricity in the State of Oregon. PGE also sells energy to wholesale customers, predominately utilities, marketers and brokers throughout the western United States. PGE's Oregon service area is 3,170 square miles, including 54 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of 4,070 square miles. At the end of 1999, PGE's service area population was approximately 1.5 million, comprising about 44% of the state's population and serving approximately 719,000 customers. On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion, comprised of $2.02 billion in cash and the assumption of Enron's approximately $80 million merger payment obligation. The proposed transaction, which is subject to regulatory approval, is expected to close in late 2000. On January 18, 2000, Sierra filed with the OPUC an application to acquire PGE. On February 3, 2000, Sierra filed with the SEC an application to acquire PGE and also to become a registered public utility holding company. NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CONSOLIDATION PRINCIPLES The consolidated financial statements include the accounts of PGE and its majority-owned subsidiaries. Intercompany balances and transactions have been eliminated. BASIS OF ACCOUNTING PGE and its subsidiaries' financial statements conform to accounting principles generally accepted in the United States. In addition, PGE's accounting policies are in accordance with the requirements and the rate making practices of regulatory authorities having jurisdiction. PGE's consolidated financial statements do not reflect an allocation of the purchase price that was recorded by Enron as a result of the PGC merger. USE OF ESTIMATES The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. RECLASSIFICATIONS Certain amounts in prior years have been reclassified for comparative purposes. REVENUES PGE accrues estimated unbilled revenues for services provided from the meter read date to month-end. PURCHASED POWER PGE credits purchased power costs for the benefits received through a power purchase and sale contract with the BPA. Reductions in purchased power costs that result from this exchange are passed directly to PGE's residential and small farm customers in the form of lower prices. PGE and the BPA reached a new agreement in September 1998, which will continue to provide benefits to PGE's residential and small farm customers through at least June 30, 2001. DEPRECIATION PGE's depreciation is computed on the straight-line method based on the estimated average service lives of the various classes of plant in service. Depreciation expense as a percent of the related average depreciable plant in service was approximately 4.2% in 1999 and 4.3% in 1998 and 1997. The cost of renewal and replacement of property units is charged to plant, while repairs and maintenance costs are charged to expense as incurred. The cost of utility property units retired, other than land, is charged to accumulated depreciation. PGE exercised its option to purchase six leased combustion turbine generators at the Beaver generating plant for approximately $37 million at the August 1999 termination of the lease. No gain or loss was recognized on this transaction. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) AFDC represents the pre tax cost of borrowed funds used for construction purposes and a reasonable rate for equity funds. AFDC is capitalized as part of the cost of plant and is credited to income but does not represent current cash earnings. The average rate used by PGE was 5.3%. INCOME TAXES PGE's federal income taxes are a part of its parent company's consolidated federal income tax return. PGE pays for its tax liabilities when it generates taxable income and is reimbursed for its tax benefits by the parent company on a stand-alone basis. Deferred income taxes are provided for temporary differences between financial and income tax reporting. Amounts recorded for Investment Tax Credits (ITC) have been deferred and are being amortized to income over the approximate lives of the related properties, not to exceed 25 years. See Note 3, Income Taxes, for more details. CASH AND CASH EQUIVALENTS Highly liquid investments with original maturities of three months or less are classified as cash equivalents. REGULATORY ASSETS AND LIABILITIES The Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". When the requirements of SFAS No. 71 are met, PGE defers certain costs, which would otherwise be charged to expense if it is probable that future prices will permit recovery of such costs. In addition, PGE defers certain revenues, gains, or cost reductions which would normally be reflected in income but through the rate making process ultimately will be refunded to customers. Regulatory assets and liabilities reflected as deferred charges and other liabilities in the financial statements are amortized over the period in which they are included in billings to customers. Amounts in the Consolidated Balance Sheets as of December 31 relate to the following: 1999 1998 (millions of dollars) Unamortized regulatory assets: Trojan-related $398 $438 Income taxes recoverable 165 165 Debt reacquisition costs 23 25 Conservation investments - secured 61 64 Energy efficiency programs 22 21 Miscellaneous 22 18 Total $691 $731 Unamortized regulatory liabilities: Deferred gain on SCE termination $ 81 $ 92 Merger payment obligation 88 96 Miscellaneous 28 49 Total $197 $237 As of December 31, 1999, a majority of the Company's regulatory assets and liabilities are being reflected in rates charged to customers. Based on rates in place at year-end 1999, the Company estimates that it will collect substantially all of its regulatory assets within the next 12 years. CONSERVATION INVESTMENTS - SECURED - In 1996, $81 million of PGE's energy efficiency investment was designated as Bondable Conservation Investment upon PGE's issuance of 10-year 6.91% Conservation Bonds collateralized by OPUC-assured future revenues. These bonds provide savings to customers while granting PGE immediate recovery of its prior energy efficiency program expenditures. Revenues collected from customers fund the debt service obligation on the conservation bonds. At December 31, 1999, the outstanding balance on the bonds was $61 million. DEFERRED GAIN ON SOUTHERN CALIFORNIA EDISON COMPANY (SCE) TERMINATION - In 1996, PGE and SCE entered into a termination agreement for the Power Sales Agreement between the two companies. The agreement requires that SCE pay PGE $141 million over 6 years ($15 million per year in 1997 through 1999 and $32 million per year in 2000 through 2002). The gain is being recognized in income consistent with current rate making treatment. MERGER PAYMENT OBLIGATION - Pursuant to the Enron/PGC merger agreement, PGE customers are guaranteed $105 million in compensation and benefits, payable over an eight-year period, in the form of reduced prices. These benefits are being paid by Enron, received by PGE, and passed on to PGE's retail customers. NOTE 2 - EMPLOYEE BENEFITS PENSION AND OTHER POST-RETIREMENT PLANS PGE participates in a non-contributory defined benefit pension plan (the Plan) with other affiliated companies. Substantially all of the plan members are current or former PGE employees. The plan's assets are held in a trust. PGE also participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" below). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. Contributions are made to a voluntary employee's beneficiary association to fund these plans. The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of plans' assets, a statement of the funded status, and components of net periodic pension expense (in millions): PENSION BENEFITS OTHER BENEFITS 1999 1998 1999 1998 RECONCILIATION OF BENEFIT OBLIGATION: Obligation at January 1 $284 $254 $ 29 $ 26 Service cost 8 7 1 0 Interest cost 20 18 2 2 Plan amendments 6 - - - Curtailments(a) (8) - - - Participants' contributions - - - 1 Actuarial loss (gain) (25) 18 (1) 2 Benefit payments (18) (13) (2) (2) Obligation at December 31 $267 $284 $ 29 $ 29 RECONCILIATION OF FAIR VALUE OF PLAN ASSETS: Fair value of plan assets at January 1 $401 $375 $ 33 $ 32 Actual return on plan assets 55 38 3 1 Participants' contributions - - 1 1 Company contributions 1 1 - 1 Benefit payments (18) (13) (2) (2) Fair value of plan assets at December 31 $439 $401 $ 35 $ 33 FUNDED STATUS: Funded status at December 31 $172 $117 $ 6 $ 4 Unrecognized transition (asset) (9) (11) 4 4 Unrecognized prior service cost 13 11 2 2 Unrecognized gain (162) (117) (13) (10) Prepaid Pension Cost $ 14 $ 0 $ (1) $ 0 ASSUMPTIONS: Discount rate used to calculate benefit obligation 7.75% 6.75% 7.75% 6.75% Rate of increase in future compensation levels 4.0 - 9.5% 4.0-9.5% 4.0-9.5% 4.0-9.5% Long-term rate of return on assets 9.00% 9.00% 9.50% 9.50% COMPONENTS OF NET PERIODIC PENSION EXPENSE: Service cost $ 8 $ 7 $ 1 $ 1 Interest cost on benefit obligation 20 18 2 2 Expected return on plan assets (31) (28) (2) (2) Amortization of transition asset (2) (2) - - Amortization of prior service cost 1 1 - - Recognized gain (3) (3) (1) (1) Effect of curtailment(a) (5) - - - Net periodic pension (benefit) $ (12) $ (7) $ 0 $ 0 (a). Represents one-time nonrecurring event associated with certain union employees ceasing participation in the pension plan as a result of union negotiations. Included in the above Pension Benefits amounts are the unfunded obligations for the supplemental executive retirement plan. At December 31, 1999 and 1998, respectively, the projected benefit obligation for this plan was $12 million and $13 million. For measurement purposes, a 10.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease .5% per year to 5.0% in 2010 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects (in millions): 1-Percentage 1-Percentage POINT POINT INCREASE DECREASE Effect on total of service and interest cost components $0.1 $(0.1) Effect on post-retirement benefit obligation $0.8 $(0.8) DEFERRED COMPENSATION PGE provides certain employees with benefits under an unfunded Management Deferred Compensation Plan (MDCP). Obligations for the MDCP were $34 million and $29 million at December 31, 1999 and 1998, respectively. EMPLOYEE STOCK OWNERSHIP PLAN PGE participated in the PGH Retirement Savings Plan through June 30, 1999. On July 1, 1999, the plan merged into the Enron Savings Plan and PGE continued participation. The successor plan includes an Employee Stock Ownership Plan (ESOP). One-half of employee contributions up to 6% of base pay are matched by employer contributions in the form of Enron common stock. ALL EMPLOYEE STOCK OPTION PLAN Enron stock options were granted to PGE employees on December 31, 1997. The options were granted at the fair value of the stock at the date of the grant. One-third of the options vested in 1998, one-third vested in 1999, and one-third will vest in 2000. PGE pays Enron the estimated value of the shares vesting each year. The fair value of shares that vested in 1999 and 1998 were $4 million and $5 million, respectively. It is estimated that shares valued at $4 million will vest in 2000. The value is calculated using the Black-Scholes option-pricing model. NOTE 3 - INCOME TAXES The following table shows the detail of taxes on income and the items used in computing the differences between the statutory federal income tax rate and PGE's effective tax rate (millions of dollars): 1999 1998 1997 Income Tax Expense Currently payable Federal $ 78 $ 75 $114 State and local 16 13 14 94 88 128 Deferred income taxes Federal (1) (1) (45) State and local 2 (1) (9) 1 (2) (54) Investment tax credit adjustments (4) (4) (4) $ 91 $ 82 $ 70 Provision Allocated to: Operations $ 84 $ 81 $ 83 Other income and deductions 7 1 (13) $ 91 $ 82 $ 70 Effective Tax Rate Computation: Computed tax based on statutory federal income tax ratesapplied to income before income taxes $ 77 $ 77 $ 69 Flow through depreciation 7 4 6 State and local taxes - net 11 7 13 State of Oregon refund - - (9) Investment tax credits (4) (4) (4) Excess deferred tax (1) (1) (1) Other 1 (1) (4) $ 91 $ 82 $ 70 Effective tax rate 41.5% 37.5% 35.7% As of December 31, 1999 and 1998, the significant components of PGE's deferred income tax assets and liabilities were as follows (millions of dollars): 1999 1998 DEFERRED TAX ASSETS Depreciation and amortization $ 24 $ 27 SCE termination payment 36 42 Other regulatory liabilities 15 14 Employee fringe benefits 15 15 Other 5 4 95 102 DEFERRED TAX LIABILITIES Depreciation and amortization $(356) $(378) Price risk management (9) (9) Trojan abandonment (55) (56) Other regulatory assets (16) (3) Other (10) (7) (446) (453) Total $(351) $(351) PGE has recorded deferred tax assets and liabilities for all temporary differences between the financial statement basis and tax basis of assets and liabilities. NOTE 4 - COMMON AND PREFERRED STOCK COMMON STOCK CUMULATIVE PREFERRED NUMBER $3.75 PAR NUMBER NO- PAR PAID-IN (millions of dollars OF SHARES VALUE OF SHARES VALUE CAPITAL except share amounts) December 31, 1997 42,758,877 $160 300,000 $30 $480 December 31, 1998 42,758,877 160 300,000 30 480 December 31, 1999 42,758,877 160 300,000 30 480 CUMULATIVE PREFERRED STOCK PGE has authorized 30 million shares of cumulative preferred stock, no par value; there are 300,000 shares of the 7.75% series outstanding. The 7.75% series preferred stock has an annual sinking fund requirement, which requires the redemption of 15,000 shares at $100 per share beginning in 2002. At its option, PGE may redeem, through the sinking fund, an additional 15,000 shares each year. All remaining shares shall be mandatorily redeemed by sinking fund in 2007. This series is only redeemable by operation of the sinking fund. No dividends may be paid on common stock or any class of stock over which the preferred stock has priority unless all amounts required to be paid for dividends and sinking fund payments have been paid or set aside, respectively. COMMON DIVIDEND RESTRICTION OF SUBSIDIARY Enron is the sole shareholder of PGE common stock. PGE is restricted from paying dividends or making other distributions to Enron without prior OPUC approval to the extent such payment or distribution would reduce PGE's common stock equity capital below 48% of its total capitalization. NOTE 5 - CREDIT FACILITIES AND DEBT At December 31, 1999, PGE had committed lines of credit totaling $300 million. Credit lines of $200 million, with an annual fee of 0.10%, expire in July 2000; credit lines of $100 million, with an annual fee of 0.125%, expire in August 2000. These lines of credit, which do not require compensating cash balances, are used primarily as backup for both commercial paper and borrowings from commercial banks under uncommitted lines of credit. Unused committed lines of credit must be at least equal to the amount of PGE's commercial paper outstanding. Commercial paper and lines of credit borrowings are at rates reflecting current market conditions. Short-term borrowings and related interest rates were as follows: 1999 1998 (millions of dollars) AS OF YEAR-END Aggregate short-term debt outstanding Commercial paper $266 $105 Weighted average interest rate* Commercial paper 6.1% 5.2% Committed lines of credit $300 $200 FOR THE YEAR ENDED: Average daily amounts of short-term debt outstanding Commercial paper $162 $113 Weighted daily average interest rate* Commercial paper 5.5% 5.4% Maximum amount outstanding during the year $266 $144 * Interest rates exclude the effect of commitment fees, facility fees and other financing fees. 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. Schedule of long-term debt at December 31 1999 1998 (millions of dollars) First Mortgage Bonds Maturing 1999 - 2004 6.47% - 8.88% $ 170 $ 219 Maturing 2005 - 2008 7.15% - 9.07% 68 113 Maturing 2021 - 2023 7.75% - 9.46% 160 170 398 502 Pollution Control Bonds Port of Morrow, Oregon, variable rate, due 2013 & 2031 (Average rate 3.4% for 1999, 3.5% for 1998) 6 6 Port of Morrow, Oregon, variable rate, due 2031 & 2033 (4.60% fixed rate to 2003) 23 23 City of Forsyth, Montana, variable rate, due 2033 (4.60%-4.75% fixed rate to 2003) 119 119 Port of St. Helens, Oregon, variable rate due 2010 & 2014 (4.80% - 5.25% fixed rate to 2003) 47 47 Port of St. Helens, Oregon, due 2014 (7.13% fixed rate) 5 5 200 200 Other 8.25% Junior Subordinated Deferrable Interest Debentures, due December 31, 2035 75 75 6.91% Conservation Bonds maturing monthly to 2006 61 68 Capital lease obligations - 1 Unamortized debt discounts (1) - 135 143 733 846 Long-term debt due within one year (32) (102) Total long-term debt $ 701 $ 744 The following principal amounts of long-term debt (excluding commercial paper) become due through regular maturities (millions of dollars): 2000 2001 2002 2003 2004 Maturities: PGE $32 $53 $23 $49 $55 NOTE 6 - OTHER FINANCIAL INSTRUMENTS FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practical to estimate that value. CASH AND CASH EQUIVALENTS - The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of those instruments. OTHER INVESTMENTS - Other investments approximate market value. REDEEMABLE PREFERRED STOCK - The fair value of redeemable preferred stock is based on quoted market prices. LONG-TERM DEBT - The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. INTEREST RATE SWAPS - At December 31, 1998, PGE had entered into interest rate swap agreements with a notional principal amount of $142 million to manage interest rate exposure. In March 1999, PGE cancelled these agreements; the amount received at cancellation was not material. The estimated fair values of debt and equity instruments are as follows (millions of dollars): 1999 1998 Carrying Fair Carrying Fair Amount Value Amount Value Preferred stock subject to mandatory redemption $ 30 $ 32 $ 30 $ 35 Long-term debt including current maturities $734 $714 $845 $892 Interest rate swaps in net receivable position $ - $ - $ - $ 1 NOTE 7 - COMMITMENTS NATURAL GAS AGREEMENTS PGE has long-term agreements for transmission of natural gas from domestic and Canadian sources to natural gas-fired generating facilities. The agreements provide firm pipeline capacity. Under the terms of these agreements, PGE is committed to paying capacity charges of approximately $15 million annually in 2000 through 2004 and $107 million over the remaining years of the contracts. PGE's capacity payments amounted to $16 million in 1999 and 1998, and $16 million in 1997. These contracts expire at varying dates from 2001 to 2015. PGE has the right to assign unused capacity to other parties. PURCHASE COMMITMENTS Certain commitments have been made related to capital expenditures planned for 2000. Obligations related to these expenditures totaled $8 million as of December 31, 1999. Cancellation of these purchase agreements could result in cancellation charges. In addition, PGE is committed to its hydro relicensing efforts, and has certain obligations related to these projects. PURCHASED POWER PGE has long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon. PGE is required to pay its proportionate share of the operating and debt service costs of the hydro projects whether or not they are operable. Selected information is summarized as follows (millions of dollars): ROCKY PRIEST PORTLAND REACH RAPIDS WANAPUM WELLS HYDRO Revenue bonds outstanding at December 31, 1999 $229 $169 $186 $183 $ 33 PGE's current share of: Output 12.0% 13.9% 18.7% 20.3% 100% Net capability (megawatts) 154 131 194 171 36 Annual cost, including debt service: 1999 $ 6 $ 4 $ 6 $ 6 $ 4 1998 6 4 6 6 4 1997 7 3 4 6 4 Contract expiration date 2011 2005 2009 2018 2017 PGE's share of debt service costs, excluding interest, will be approximately $6 million for 2000, $7 million for 2001 through 2002, $8 million for 2003, and $7 million for 2004. The minimum payments through the remainder of the contracts are estimated to total $66 million. PGE has entered into long-term contracts to purchase power from other utilities in the region. These contracts will require fixed payments of up to $20 million in 2000 and $19 million in 2001 through 2003. After that date, capacity contract charges will average $19 million annually until 2016. Long-term contract payments amounted to $22 million in 1999, $22 million in 1998, and $23 million in 1997. LEASES PGE has operating lease arrangements for its headquarters complex, coal-handling facilities and certain railroad cars for Boardman. PGE's aggregate rental payments charged to expense totaled $24 million in 1999, $23 million in 1998, and $24 million in 1997. Future minimum lease payments under non-cancelable leases are as follows (millions of dollars): YEAR ENDING OPERATING LEASES DECEMBER 31 (NET OF SUBLEASE RENTALS) 2000 $ 20 2001 20 2002 10 2003 10 2004 10 Remainder 157 Total $227 Included in the future minimum operating lease payments schedule above is approximately $109 million for PGE's headquarters complex. NOTE 8 - PROPERTY DIVIDEND During 1997, PGE transferred its rights and certain obligations under the WNP-3 Settlement Exchange Agreement (WSA) and the long-term power sale agreement with the Western Area Power Administration (WAPA) to Enron in the form of a special non-cash dividend. NOTE 9 - JOINTLY OWNED PLANT At December 31, 1999, PGE had the following investments in jointly owned generating plants (millions of dollars): MW PGE % PLANT ACCUMULATED FACILITY LOCATION FUEL CAPACITY INTEREST IN SERVICE DEPRECIATION Boardman Boardman,OR Coal 561 65.0 $381 $221 Colstrip 3&4 Colstrip,MT Coal 1,556 20.0 455 250 The dollar amounts in the table above represent PGE's share of each jointly owned plant. Each participant in the above generating plants has provided its own financing. PGE's share of the direct expenses of these plants is included in the corresponding operating expenses on PGE's consolidated income statements. NOTE 10 - LEGAL MATTERS TROJAN INVESTMENT RECOVERY - On June 24, 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 the Trojan generating facility. The court upheld the OPUC's authorization of PGE's recovery of its undepreciated investment in Trojan. The Court of Appeals decision was a result of combined appeals from earlier circuit court rulings. In April 1996, a Marion County Circuit Court judge ruled that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan, contradicting a November 1994 ruling from the same court upholding the OPUC's authority. The 1996 ruling was the result of an appeal of PGE's 1995 general rate order, which granted PGE recovery of, and a return on, 87% of its remaining investment in Trojan. On August 26, 1998, PGE and the OPUC filed a petition for review with the Oregon Supreme Court, supported by amicus briefs filed by three other major utilities seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's return on its undepreciated investment in Trojan Also on August 26, 1998, the Utility Reform Project 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 recovery of its undepreciated investment in Trojan. On April 29, 1999, the Oregon Supreme Court accepted the petitions for review of the June 24, 1998, Oregon Court of Appeals decision. On June 16, 1999, Oregon's governor signed Oregon House Bill 3220 authorizing the OPUC to allow recovery of a return on the undepreciated investment in property retired from service. One of the effects of the bill is to affirm retroactively the OPUC's authority to allow PGE's recovery of a return on its undepreciated investment in the Trojan generating facility. Relying on the new legislation, on July 2, 1999, the Company requested the Oregon Supreme Court to vacate the June 24, 1998, adverse ruling of the Oregon Court of Appeals and affirm the validity of the OPUC's order allowing PGE to recover a return on its undepreciated investment in Trojan. The Utility Reform Project and the Citizens Utility Board, another party to the proceeding, opposed such 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; such effort by the referendum's sponsors was successful and the referendum will appear on the November 2000 ballot. The Oregon Supreme Court has stated it will hold its review of the Court of Appeals decision in abeyance until after the election. At December 31, 1999, PGE's after-tax Trojan plant investment was $147 million. PGE is presently collecting annual revenues of approximately $18 million, representing a return on its undepreciated investment. Revenue amounts reflecting a recovery of a return on the Trojan investment decline through the recovery period, which ends in the year 2011. Management believes that the ultimate outcome of this matter will not have a material adverse impact on the financial condition of the Company. However, it may have a material impact on the results of operations for a future reporting period. OTHER LEGAL MATTERS - PGE is party to various other claims, legal actions and complaints arising in the ordinary course of business. These claims are not considered material. NOTE 11 - TROJAN NUCLEAR PLANT PLANT SHUTDOWN AND TRANSITION COSTS - PGE is a 67.5% owner of Trojan. In early 1993, PGE ceased commercial operation of the nuclear plant. Since plant closure, PGE has committed itself to a safe and economical transition toward a decommissioned plant. Transition costs associated with operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage will be paid from current operating funds. Delays have extended the expected completion date of transferring the fuel to dry storage through 2002. DECOMMISSIONING - In December 1997, PGE filed an updated decommissioning plan estimate with the OPUC. The plan estimates PGE's cost to decommission Trojan at $339 million reflected in nominal dollars (actual dollars expected to be spent in each year). The primary reason for the reduction from the $351 million estimated in 1994 is a lower inflation rate, coupled with the acceleration of certain decommissioning activities and partially offset by cost increases related to the spent fuel storage project. The current estimate assumes that the majority of decommissioning activities will occur between 1998 and 2004, while fuel management costs extend through the year 2018. The original plan represents a site-specific decommissioning estimate performed for Trojan by an engineering firm experienced in estimating the cost of decommissioning nuclear plants. Updates to the plan's original estimate have been prepared by PGE. Final site restoration activities are anticipated to begin in 2018 after PGE completes shipment of spent fuel to a USDOE facility (see the Nuclear Fuel Disposal discussion below). Stated in 1999 dollars, the decommissioning cost estimate is $297 million. TROJAN DECOMMISSIONING LIABILITY (millions of dollars) Estimate - 12/31/94 $351 Updates filed with NRC - 11/16/95 7 Updates filed with OPUC - 12/01/97 (19) 339 Expenditures through 12/31/99 (114) Liability - 12/31/99 225 Transition costs 9 Total Trojan obligations $234 PGE is collecting $14 million annually through 2011 from customers for decommissioning costs. These amounts are deposited in an external trust fund, which is limited to reimbursing PGE for activities covered in Trojan's decommissioning plan. Funds were withdrawn during 1999 to cover the costs of general decommissioning and activities in support of the independent spent fuel storage installation and the reactor vessel and internals removal project. Decommissioning funds are invested in investment-grade preferred stock, tax-exempt bonds, and U.S. Treasury bonds. Due to an increase in market interest rates during 1999, the market value of trust investments declined, resulting in no investment gain for the year. Year-end balances are valued at market. DECOMMISSIONING TRUST ACTIVITY (millions of dollars) 1999 1998 Beginning Balance $72 $84 Activity Contributions 14 14 Gain 0 4 Disbursements (44) (30) Ending Balance $42 $72 Earnings on the trust fund are used to reduce the amount of decommissioning costs to be collected from customers. PGE expects any future changes in estimated decommissioning costs to be incorporated in future revenues to be collected from customers. NUCLEAR FUEL DISPOSAL AND CLEANUP OF FEDERAL PLANTS - PGE contracted with the USDOE for permanent disposal of its spent nuclear fuel in federal facilities at a cost of 0.1 per net kilowatt-hour sold at Trojan which the Company paid during the period the plant operated. Significant delays are expected in the USDOE acceptance schedule of spent fuel from domestic utilities. The federal repository, which was originally scheduled to begin operations in 1998, is now estimated to commence operations no earlier than 2010. This may create difficulties for PGE in disposing of its high-level radioactive waste by 2018. However, federal legislation has been introduced which, if passed, would require USDOE to provide interim storage for high-level waste until a permanent site is established. PGE intends to build an interim storage facility at Trojan to house the nuclear fuel until a federal site is available. The Energy Policy Act of 1992 provided for the creation of a Decontamination and Decommissioning Fund to finance the cleanup of USDOE gas diffusion plants. Funding comes from domestic nuclear utilities and the federal government. Each utility contributes based on the ratio of the amount of enrichment services the utility purchased to the total amount of enrichment services purchased by all domestic utilities prior to the enactment of the legislation. Based on Trojan's 1.1% usage of total industry enrichment services, PGE's portion of the funding requirement is approximately $17 million. Amounts are funded over 15 years beginning with the USDOE's fiscal year 1993. Since enactment, PGE has made the first seven of the 15 annual payments with the first payment made in September 1993. NUCLEAR INSURANCE - The Price-Anderson Amendment of 1988 limits public liability claims that could arise from a nuclear incident and provides for loss sharing among all owners of nuclear reactor licenses. Because Trojan has been permanently defueled, the NRC has exempted PGE from participation in the secondary financial protection pool covering losses in excess of $200 million at other nuclear plants. In addition, the NRC has reduced the required primary nuclear insurance coverage for Trojan from $200 million to $100 million following a 3 year cool-down period of the nuclear fuel that is still on-site. The NRC has allowed PGE to self-insure for on-site decontamination. PGE continues to carry non-contamination property insurance on the Trojan plant at the $158 million level. NOTE 12 - RELATED PARTY TRANSACTIONS As part of its ongoing operations, PGE receives management services from Enron and provides incidental services to Enron and its affiliated companies. In 1999, approximately $23 million was paid to Enron for allocated overhead and other direct costs, including PGE's $4 million share of the Employee Stock Option Plan. In 1998, PGE paid $17 million to Enron for management services, including $5 million for employee stock options; in 1997, PGE paid $2 million to Enron for management services. In 1999, PGE entered into an agreement to transfer corporate owned life insurance investments, totaling $21 million, to an Enron affiliate. PGE accrues interest on the accounts receivable balance at 9.5 percent per annum. In 1998, PGE had $18 million in accounts receivable from affiliates related to income tax settlements. QUARTERLY COMPARISON FOR 1999 AND 1998 (UNAUDITED) MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 TOTAL (MILLIONS OF DOLLARS) 1999 Operating revenues $299 $294 $408 $377 $1,378 Net operating income 58 40 39 53 190 Net income 45 26 24 33 128 Income available for common stock 44 25 24 33 126 1998 Operating revenues $314 $260 $274 $328 $1,176 Net operating income 52 42 41 65 200 Net income 37 24 26 50 137 Income available for common stock 36 25 25 49 135 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS OF THE REGISTRANT (*) JAMES V. DERRICK, JR., age 55 Director since 1997 Mr. Derrick has served as Executive Vice President and General Counsel of Enron since July, 1999 and as Senior Vice President and General Counsel from June 1991 until July 1999. Prior to joining Enron in 1991, Mr. Derrick was a partner at the law firm of Vinson & Elkins L.L.P. for over 13 years. PEGGY Y. FOWLER, age 48 Director since 1998 Ms. Fowler has served as President of Portland General Electric Company since 1997. Served as Executive Vice President and Chief Operating Officer of Portland General Electric from November, 1996 until appointed to current position. Ms. Fowler also serves on the boards of George Fox University, Goodwill Industries, Legacy Health System, and Life Wise, A Premera Health Plan, Inc. KEN L. HARRISON, age 57 Director since 1987 Mr. Harrison serves as a Director of Enron and has served as Chairman and Chief Executive Officer of Portland General Electric Company since 1988. Mr. Harrison is also a Director of Enron Broadband Services. KENNETH L. LAY, age 57 Director since 1997 Mr. Lay has served as Chairman of the Board and Chief Executive Officer of Enron since February, 1986. Mr. Lay is also a Director of Eli Lilly and Company, Compaq Computer Corporation, EOTT Energy Corp. (the general partner of EOTT Energy Partners, L.P.), Azurix Corp., and Trust Company of the West. JEFFREY K. SKILLING, age 46 Director since 1997 Since January 1, 1997, Mr. Skilling has served as President and Chief Operating Officer of Enron. From June, 1995 until December, 1996, he served as Chief Executive Officer and Managing Director of Enron North America Corp. ("ENA"). From August, 1990 until June, 1995, Mr. Skilling served ENA in a variety of senior managerial positions. Mr. Skilling is also a director of Azurix Corp., Aquarion Company, TECO Energy, Inc., Hubbell, Inc., The Weir Group, PLC and Catalytica Inc. (*) Directors of PGE hold office until the next annual meeting of shareholders or until their respective successors are duly elected and qualified. EXECUTIVE OFFICERS OF THE REGISTRANT (*) NAME AGE Business Experience Ken L. Harrison 57 Appointed to current position of Chairman and Chief Chairman and Executive Officer on December 7, 1988. Chief Executive Officer Peggy Y. Fowler 48 Appointed to current position on June 24, 1997. Served President and as Executive Vice President and Chief Operating Officer, Chief Operating PGE from November, 1996 until appointed to current Officer position. Served as Senior Vice President, Customer Service and Delivery from September, 1995 until November, 1996. Served as Vice President, Distribution and Power Production from January, 1990 to September, 1995. Alvin L. Alexanderson Senior Vice 52 Appointed to current position on December 12, 1995. President, General Served as Vice President, Rates and Regulatory Affairs Counsel and from February, 1991 until appointed to current position. Secretary Frederick D. Miller Senior Vice 57 Appointed to current position on November 5, 1996. President Served as Vice President, Public Affairs and Corporate Public Policy and Services from October until November, 1996. Served as Administrative Director of Executive Department, State of Oregon, from Services 1987 until October, 1992. Walter E. Pollock Senior Vice 57 Appointed to current position on October 14, 1997. President Served as Vice President, Enron Capital and Trade and Power Supply Senior Vice President, First Point Utility Solutions from November, 1996 until appointed to current position. Served as Group Vice President, Marketing Conservation and Production at Bonneville Power Administration (BPA) from April, 1994 to November, 1996. Arleen N. Barnett Vice President 47 Appointed to current position on February 1, 1998. Human Resources Served as Manager, Generating Division from 1987 to 1989 and Manager, Human Resources Operations from 1989 until appointed to current position. David K. Carboneau Vice President 53 Appointed to current position in October, 1998. Served Retail Services as President of First Point Utility Solutions until appointed to current position. Served as Vice President, Utility Service and Telecommunications from January, 1997 until July, 1997. Served as Vice President, Information Technology from January, 1996 until January, 1997. Served as Vice President, Thermal and Power Operations from September, 1995 to January, 1996. Served as Vice President, PGE Administration from October, 1992 to September, 1995. Stephen R. Hawke Vice President 50 Appointed to current position on July 1, 1997. Served as Delivery System General Manager, System Planning and Engineering until Planning and appointed to current position. Served as Manager, Engineering Response and Restoration from May, 1993 until May, 1995. EXECUTIVE OFFICERS OF THE REGISTRANT (*) - CONTINUED NAME AGE Business Experience Ronald W. Johnson Vice President 49 Appointed to current position May 1, 1999. Joined PGE's Deputy General Legal Department in 1977. In 1989 became Deputy General Counsel and Counsel, managing the Legal Department. Assistant Secretary Pamela G. Lesh Vice President 43 Appointed to current position on December 31,1998. Served Rates and as Vice President, Strategy and Product Management with Regulatory ConneXt Corp. of Seattle since June, 1997. Previously Affairs served at PGE as Vice President, Rates and Regulatory Affairs from November, 1996 to June, 1997. Served as Director, Regulatory Policy, from August, 1989 to October, 1996. Joe A. McArthur Vice President 52 Appointed to current position on July 1, 1997. Served as Substation and Manager of Western Region from May, 1996 until appointed Line Crew to current position. Served as Manager, System Planning Operations from May, 1995 to May, 1996. Served as Commercial and Industrial Market Manager from 1993 to 1995. James J. Piro Vice President 47 Appointed to current position on February 23, 1998. Business Served as General Manager, Planning Support and Development Analysis from November, 1992 until appointed to current position. Stephen M. Quennoz Vice President 52 Appointed to current position in October, 1998. Joined Nuclear and PGE in 1991 and held the position of Trojan Site Thermal Executive and Plant General Manager since 1993. Operations Christopher D. Ryder Vice President 50 Appointed to current position on July 1, 1997. Served as Customer Service General Manager, Customer Services and Southern Region Delivery Operations from 1996 until appointed to current position. Served as General Manager, Customer Services, Marketing and Sales from 1992 to 1996. Carl B. Talton Vice President 55 Appointed to current position May 1, 1999. Joined PGE in Government July, 1998 as Director of Economic Development. Prior to Affairs and that worked 25 years for PacificCorp, where he held Economic several management positions. Development Mary K. Turina Vice President, 32 Appointed to current position on September 1,1999. Served Finance as Controller, Chief Accounting Officer, Treasurer, and Chief Financial Principal Financial Officer from May, 1999 to September, Officer and 1999. Served as Controller and Assistant Treasurer from Treasurer July, 1998 to May, 1999. Served as Manager of Risk Management, Reporting and Control from March, 1996 to July, 1998. Served as Senior Business Analyst from 1991 to 1996. (*) Officers are listed as of February 29, 2000, they are elected for one- year terms or until their successors are elected and qualified. ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The following indicates total compensation earned for the years ended December 31, 1999, 1998, 1997 by the Chief Executive Officer and the four most highly compensated executive officers of PGE. Long-Term Annual Compensation Compensation Restricted All Other Stock Name and Principal Position Year Salary(1) Bonus(2) Awards(3) Compensation(4) Ken L. Harrison (5) 1999 $244,163 $ - $ - $28,959 Chairman, 1998 206,799 183,200 705,483 12,050 Chief Executive 1997 243,570 236,592 204,755 68,051 Officer Peggy Y. Fowler 1999 267,502 400,000 - 16,646 President and Chief 1998 246,664 300,000 200,004 17,443 Operating Officer 1997 230,000 160,000 230,185 29,406 Walter E. Pollock (6) 1999 189,697 200,000 - 6,575 Senior Vice President, 1998 176,191 140,000 75,037 5,664 Power Supply 1997 37,500 24,000 - 826 Frederick D. Miller 1999 197,708 200,000 - 12,757 Senior Vice President, 1998 181,684 150,000 68,760 10,233 Public Policy and 1997 175,020 105,000 - 48,906 Administrative Services James J. Piro 1999 169,089 110,000 - 5,874 Vice President, 1998 157,535 128,063 50,043 5,081 Business Development 1997 131,352 140,000 - 7,743 (1) Amounts shown include cash compensation earned and received by the executive officer, as well as amounts earned but deferred at the election of the officer. (2) Bonuses include amounts, if any, converted to stock options and for phantom stock at the election of the officer. (3) Restricted stock awards are valued at the closing price of $20.7188 per share of Enron common stock for the July 1, 1997 grant, which vested 20% on July 1, 1998, and 20% on each of the following four anniversaries of the date of grant. Dividend equivalents for the July 1, 1997 grant accrue from the date of grant and are paid upon vesting. Restricted stock awarded to Mr. Harrison on October 12, 1998 is valued at the $25.4688 per share closing price of Enron common stock on that date; one-third of the shares vest on January 31 of each of the next three years, beginning in 1999. Restricted stock awarded to other officers was granted December 31, 1998, and is valued at the $28.5313 per share closing price of Enron common stock on that date. Aggregate restricted stock holdings listed below (including any annual bonus converted to Phantom stock) are valued at $44.3750 per share, the closing price of the Enron common stock on December 31, 1999. AGGREGATE RESTRICTED STOCK HOLDINGS AGGREGATE SHARES (#) VALUE Ken L. Harrison 103,886 $4,609,941 Peggy Y. Fowler 21,536 955,660 Walter E. Pollock 4,204 186,553 Frederick D. Miller 6,340 281,338 James J. Piro 2,244 99,578 (4) Other compensation includes: (i) company-paid split dollar insurance premiums; (ii) the dollar value of life insurance benefits as determined under the Commission's methodology for valuing such benefits; (iii) company contributions to the RSP and the MDCP; and (iv) earnings on amounts in the MDCP which are greater than 120 percent of the federal long-term rate which was in effect at the time the rate was set. The following are amounts for 1999: Split Dollar Dollar Value of Contributions Above Market Insurance Life to 401 (k) Interest on Premiums Insurance MDCP MDCP Total Ken L. Harrison $ 512 $ - $3,400 $25,047 $28,959 Peggy Y. Fowler 480 6,012 5,828 4,326 16,646 Walter E. Pollock - - 5,382 1,193 6,575 Frederick D. Miller 675 - 5,690 6,392 12,757 James J. Piro - - 4,797 1,077 5,874 (5) Mr. Harrison also served as an executive officer of Enron until July 1, 1999. The compensation shown represents the amount allocated to PGE. (6) Mr. Pollock became a PGE employee October 1997. The following lists information concerning options to purchase shares of Enron common stock that were exercised by the officers named above during 1999 and the total options and their value held by each at December 31, 1999.
Aggregate Stock Options/SAR Exercised During 1999 and Stock Options/SAR Values at December 31, 1999 Shares Acquired Value Exercisable Unexercisable Exercisable Unexercisable on Exercise Realized Shares Shares Amount Amount Ken L. Harrison 154,000 $4,370,894 660,272 1,098,628 $9,680,058 $13,623,195 Peggy Y. Fowler 21,274 500,211 19,316 40,586 337,843 840,649 Walter E. Pollock 25,520 477,126 28,476 11,224 603,915 220,610 Frederick D. Miller 20,234 264,676 16,425 22,461 347,479 490,202 James J. Piro - - 78,774 17,640 2,139,891 415,443
Estimated annual retirement benefits payable upon normal retirement at age 65 for the named executive officers are shown in the table below. Amounts in the table reflect payments from the Portland General Holdings, Inc. Pension Plan and Supplemental Executive Retirement Plan ("SERP") combined. Pension Plan Table Estimated Annual Retirement Benefit Straight-Life Annuity, Age 65 Final Average Years of Service Earnings 15 20 25+ $ 175,000 $ 78,750 $ 91,875 $ 105,000 200,000 90,000 105,000 120,000 225,000 101,250 118,125 135,000 250,000 112,500 131,250 150,000 300,000 135,000 157,500 180,000 400,000 180,000 210,000 240,000 500,000 225,000 262,500 300,000 600,000 270,000 315,000 360,000 1,000,000 450,000 525,000 600,000 Compensation used to calculate benefits under the combined Pension Plan and SERP is based on a three-year average of base salary and bonus amounts earned (the highest 36 consecutive months within the last 10 years), as reported in the Summary Compensation Table. SERP participants may retire without age-based reductions in benefits when their age plus years of service equals 85. Surviving spouses receive one half the participant's retirement benefit from the SERP, plus the joint and survivor benefit, if any, from the Pension Plan. In addition to the aforementioned annual retirement benefits, an additional temporary Social Security Supplement is paid until the participant is eligible for social security retirement benefits. Retirement benefits are not subject to any deduction for social security. The following executive officers named in the table are participants in both plans and have had the following number of service years with the Company: Ken L. Harrison, 24; Peggy Y. Fowler, 25; Frederick D. Miller, 7. James J. Piro and Walter E. Pollock are not participants in the SERP, but do participate in the Pension Plan. Under the Company's SERP, the named executives are eligible to retire without a reduction in benefits upon attainment of the following ages: Ken L. Harrison, 59, Peggy Y. Fowler, 55; Frederick D. Miller, 62. Mr. Pollock and Mr. Piro are not participants in the SERP. EMPLOYMENT CONTRACTS Ms. Fowler and Mr. Miller entered into employment agreements on July 1, 1997, the effective date of the merger between Enron and PGC, the former parent of PGE. The employment agreements generally provide as follows: (i) each agreement has a term of three years and expires on June 30, 2000; (ii) each agreement provides for severance pay in the event of involuntary termination by PGE based on the greater of two years or the remainder of the term; (iii) the minimum salary for Ms. Fowler is $230,000 and the minimum salary for Mr. Miller is $175,000 per year; the minimum guaranteed annual cash incentive per year under such agreements is $115,000 for Ms. Fowler and $52,500 for Mr. Miller; (iv) Mr. Miller's agreements provide for the grant of 50,000 options to purchase shares of Enron common stock while Ms. Fowler's provides for 60,000 options; (v) Mr. Fowler's agreement provides for the grant of a number of restricted shares of Enron common stock having a market value equal to such employee's annual base pay which will vest over a five year period; (vi) Ms. Fowler's and Mr. Miller's agreements provide that the failure of PGE and the employee to extend or enter into a new agreement for two years will be treated as involuntary termination; (vii) each agreement provides for a supplemental retirement benefit; (viii) each agreement provides that in the event that the severance or other payments payable under the agreement for involuntary termination constitute "excess parachute payments" within the meaning of Section 280G of the code and the employee becomes liable for any tax penalties, PGE will pay in cash to the employee an amount equal to such tax penalties until the amount of the last gross up is less than one hundred dollars; and (ix) each agreement includes a non-competition covenant. Mr. Pollock entered into an employment agreement effective November 1, 1996. The agreement extended from the effective date until November 1, 1999, and provides for the following: 1. An initial base pay of $150,000. 2. A guaranteed bonus of 33% of base pay paid in 1996 and 1997, and a bonus opportunity of 75% in 1998. 3. A grant of 39,300 shares of PGC stock under the Portland General Corporation amended and restated 1990 Long-Term Master Plan which converted to Enron common stock upon the merger and vested 100% on November 4, 1999. 4. Remedy for breach clause, which provides for a payment of one times Mr. Pollock's salary plus target incentive award if his employment is terminated plus equivalent medical and dental coverage for 12 months for Mr. Pollock and his dependents. 5. Noncompete and confidentiality clauses. Mr. Piro entered into a retention agreement effective January 7, 1997. The agreement extended two years from the date of the merger between PGC and Enron and provided for the following: 1. No reduction of base pay during the agreement. 2. 12 months written notification prior to involuntary termination. 3. $10,000 plus one times Mr. Piro's base pay and target incentive in the event of a breach of the agreement, where a breach is defined as involuntary termination, diminishment of status, base pay or bonus opportunity position and/or responsibilities or a requirement that Mr. Piro relocate outside the Portland, Oregon geographic area without his written consent. In addition to the payment, the company will provide Mr. Piro and his dependents with equivalent medical and dental coverage for up to 12 months. 4. Noncompete and confidentiality clauses. COMPENSATION OF DIRECTORS There are no compensation arrangements for or fees paid to Directors of PGE. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION The Compensation and Management Development Committee of the Enron Board of Directors is responsible for developing and administering compensation philosophy. Salary increases, annual incentive awards and long-term incentive grants are reviewed annually to ensure consistency with Enron's total compensation philosophy. In 1999, PGE's Chairman and Chief Executive Officer, Ken L. Harrison, participated in those deliberations affecting the Company's executive officer compensation. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT PGE is a wholly owned subsidiary of Enron. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS There are no relationships or transactions involving PGE's directors and executive officers. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (A) INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES FINANCIAL STATEMENTS Report of Independent Public Accountants Consolidated Statements of Income for each of the three years in the period ended December 31, 1999 Consolidated Statements of Retained Earnings for each of the three years in the period ended December 31, 1999 Consolidated Balance Sheets at December 31, 1999 and 1998 Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 1999 Notes to Financial Statements FINANCIAL STATEMENT SCHEDULES Schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto. EXHIBITS See Exhibit Index on Page 66 of this report. (B) REPORT ON FORM 8-K None SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Portland General Electric Company March 2, 2000 By /s/ Ken L. Harrison Ken L. Harrison Chairman and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. /s/ Ken L. Harrison Chairman and Ken L. Harrison Chief Executive Officer March 2, 2000 Vice President, Finance /s/ Mary K. Turina Chief Financial Officer March 2, 2000 Mary K. Turina and Treasurer /s/ Kirk M. Stevens Controller and March 2, 2000 Kirk M. Stevens Assistant Treasurer *James V. Derrick *Peggy Y. Fowler *Ken L. Harrison Directors March 2, 2000 *Kenneth L. Lay *Jeffrey K. Skilling *By /s/ Mary K. Turina (Mary K. Turina, Attorney-in-Fact) PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES EXHIBIT INDEX Number Exhibit (2) PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION OR SUCCESSION * Amended and Restated Agreement and Plan of Merger, dated as of July 20, 1996 and amended and restated as of September 24, 1996 among Enron Corp, Enron Oregon Corp and Portland General Corporation [Amendment 1 to S4 Registration Nos. 333-13791 and 333-13791-1, dated October 10, 1996, Exhibit No. 2.1]. (3) ARTICLES OF INCORPORATION AND BYLAWS * Copy of Articles of Incorporation of Portland General Electric Company [Registration No. 2-85001, Exhibit (4)]. * Certificate of Amendment, dated July 2, 1987, to the Articles of Incorporation limiting the personal liability of directors of Portland General Electric Company [Form 10-K for the fiscal year ended December 31, 1987, Exhibit (3)]. * Bylaws of Portland General Electric Company as amended on October 1, 1991 [Form 10-K for the fiscal year ended December 31, 1991, Exhibit (3)]. * Bylaws of Portland General Electric Company as amended on May 1, 1998 [Form 10-K for the fiscal year ended December 31, 1998, Exhibit (3)]. (4) INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES * Portland General Electric Company Indenture of Mortgage and Deed of Trust dated July 1, 1945. * Fortieth Supplemental Indenture dated October 1, 1990 [Form 10-K for the fiscal year ended December 31, 1990, Exhibit (4)]. * Forty-First Supplemental Indenture dated December 1, 1991 [Form 10-K for the fiscal year ended December 31, 1991, Exhibit (4)]. * Forty-Second Supplemental Indenture dated April 1, 1993 [Form 10-Q for the quarter ended March 31,1993, Exhibit (4)]. * Forty-Third Supplemental Indenture dated July 1, 1993 [Form 10-Q for the quarter ended September 30, 1993, Exhibit (4)]. * Forty-Fifth Supplemental Indenture dated May 1, 1995 [Form 10-Q for the quarter ended June 30, 1995, Exhibit (4)]. PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES EXHIBIT INDEX (4) CONT Other instruments, which define the rights of holders of long-term debt not required to be filed, herein, will be furnished upon written request. (10) MATERIAL CONTRACTS * Residential Purchase and Sale Agreement with the Bonneville Power Administration [Form 10-K forthe fiscal year ended December 31, 1981, Exhibit (10)]. * Power Sales Contract and Amendatory Agreement Nos. 1 and 2 with Bonneville Power Administration [Form 10-K for the fiscal year ended December 31, 1982, Exhibit (10)]. The following 12 exhibits were filed in conjunction with the 1985 Boardman/Intertie Sale: * Long-term Power Sale Agreement dated November 5, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Long-term Transmission Service Agreement dated November 5, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Participation Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Lease Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31,1985, Exhibit (10)]. * PGE-Lessee Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Asset Sales Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Bargain and Sale Deed, Bill of Sale, and Grant of Easements and Licenses, dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Supplemental Bill of Sale dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Trust Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES EXHIBIT INDEX Number Exhibit (10) CONT * Tax Indemnification Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Trust Indenture, Mortgage and Security Agreement dated December 30,1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)]. * Restated and Amended Trust Indenture, Mortgage and Security Agreement dated February 27, 1986 [Form 10-K for the fiscal year ended December 31, 1997, Exhibit (10)]. * Portland General Holdings, Inc. Outside Directors' Deferred Compensation Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10]. * Portland General Holdings, Inc. Retirement Plan for Outside Directors, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10]. * Portland General Holdings, Inc. Outside Directors' Life Insurance Benefit Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10]. EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS * Portland General Holdings, Inc. Management Deferred Compensation Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10]. * Portland General Holdings, Inc. Senior Officers Life Insurance Benefit Plan, 1997 Restatement Amendment No. 1 dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10]. * Portland General Electric Company Annual Incentive MasterPlan [Form 10-K for the fiscal year ended December 31, 1987, Exhibit (10)]. * Portland General Electric Company Annual Incentive Master Plan, Amendments No. 1 and No. 2 dated March 5, 1990 [Form 10-K for the fiscal year ended December 31, 1989, Exhibit (10)]. * Portland General Holdings, Inc. Supplemental Executive Retirement Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10]. PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES EXHIBIT INDEX Number Exhibit (24) POWER OF ATTORNEY Portland General Electric Company Power of Attorney (filed herewith). (27) FINANCIAL DATA SCHEDULE UT (Electronic Filing Only). * Incorporated by reference as indicated. Note: The Exhibits furnished to the Securities and Exchange Commission with the Form 10-K will be supplied upon written request and payment of a reasonable fee for reproduction costs. Requests should be sent to: Kirk M. Stevens Controller and Assistant Treasurer Portland General Electric Company 121 SW Salmon Street, 1WTC0501 Portland, OR 97204 EX-27 2
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS FILED ON FORM 10-K FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1999, FOR PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES (PGE) AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000,000 JAN-01-1999 YEAR DEC-31-1999 DEC-31-1999 PER-BOOK 1,865 318 267 717 0 3,167 160 480 401 1,041 30 0 701 0 0 266 32 0 0 0 1,097 3,167 1,378 84 1,104 1,188 190 7 197 69 128 2 126 81 54 236 0 0
EX-24 3 POWER OF ATTORNEY PORTLAND GENERAL ELECTRIC COMPANY KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by the Company of its Annual Report on Form 10-K for the year ended December 31, 1999, with the Securities and Exchange Commission, the undersigned director(s) of the Company hereby constitute and appoint Alvin L. Alexanderson and Mary K. Turina, and each of them with full power (any one of them acting alone), as true and lawful attorneys-in- fact and agents, for and on behalf and in the name, place, and stead of the undersigned, in any and all capacities, to sign, execute, and file such Annual Report on Form 10-K, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto each above-mentioned individual the full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in or to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. Effective as of February 28, 2000. _/S/ JAMES V. DERRICK, JR. ______ _/S/ PEGGY Y. FOWLER_____________ James V. Der -----END PRIVACY-ENHANCED MESSAGE-----