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, 1998 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 93-0256820 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) 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 28, 1999: $0. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 28, 1999: 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 AFDC................................Allowance for Funds Used During Construction Beaver..............................Beaver Combustion Turbine Plant Bethel..............................Bethel 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 Authority 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.................................................. 13 Item 3. Legal Proceedings........................................... 15 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................................. 17 Item 6. Selected Financial Data..................................... 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......................... 18 Item 8. Financial Statements and Supplementary Data................. 34 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................... 53 PART III Item 10. Directors and Executive Officers of the Registrant.......... 54 Item 11. Executive Compensation...................................... 57 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 1998 its service area population was approximately 1.5 million, constituting approximately 44% of the state's population. At December 31, 1998 PGE served approximately 704,000 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. PGE is now a wholly owned subsidiary of Enron and subject to control by the Board of Directors of Enron. As of December 31, 1998, PGE had 2,728 employees. This compares to 2,729 and 2,587 PGE employees at December 31, 1997 and 1996, respectively. OPERATING REVENUES RETAIL PGE serves a diverse retail customer base. Residential customers constitute the largest customer class and account for approximately 48% of total retail revenues, with Commercial and Industrial customers accounting for 38% and 14%, respectively. Residential demand is highly sensitive to the effects of weather, with company revenues highest during the winter heating season. Electricity sales to both Commercial and Industrial customers declined somewhat in 1998 due to the effects of PGE's Customer Choice pilot program, which 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 22% of retail demand, they represent 10 different industrial groups, including paper manufacturing, high technology, metal fabrication, transportation equipment, and health services. No single customer represents more than 6% of PGE's total retail load. In late 1997 PGE filed a proposal before the OPUC which would give all its customers a choice of electricity providers as early as January 1, 1999. PGE's Customer Choice proposal included new price tariffs and a new structure for the company in which PGE would become a regulated transmission and distribution company focused on delivering, but not selling electricity. In January 1999, the OPUC issued an order recommending that PGE offer its customers a limited set of options, including the ability to continue to purchase rate-regulated electricity, with most commercial and industrial customers able to chose their electricity provider through direct access. The Commission's order further requires PGE to refile a new rate case should it choose to adopt the plan recommended by the order, which is also contingent upon the adoption of certain statutory changes by the Oregon Legislature. Until such changes are made and agreed upon among all parties, PGE will not be implementing its proposal or accompanying new rate structure.
WHOLESALE Wholesale electricity sales comprised about 20% of total operating revenues in 1998, down from about 35% in 1997. During the last several years PGE has actively marketed wholesale power throughout the western United States, with significant sales growth since 1994; most of such growth has come through sales to marketers and brokers 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. Long-term wholesale trading activities have been transferred to a non-regulated Enron affiliate, which participates more fully in a broader market. PGE expects that its future revenues from the wholesale marketplace will decline. The following table summarizes operating revenues and MWh sales for the years ended December 31: <TABLE> <CAPTION> 1998 1997 1996 <S> <C> <C> <C> Operating Revenues (Millions) Residential $ 432 $ 391 $ 427 Commercial (1) 345 354 357 Industrial 132 144 149 Tariff Revenues 909 889 933 Accrued (Collected) Revenues (8) 10 (27) Retail 901 899 906 Wholesale 234 497 194 Other 41 21 10 Total Operating Revenues $1,176 $1,417 $1,110 Megawatt-Hours Sold (Thousands) Residential 7,101 6,999 7,073 Commercial (1) 6,781 6,973 6,577 Industrial 3,562 4,247 3,909 Retail 17,444 18,219 17,559 Wholesale 10,869 26,934 10,188 Total MWh Sold 28,313 45,153 27,747 Energy Delivered to ESP Customers (2) 1,292 2 0 Total MWh Sold and Delivered 29,605 45,155 27,747 <FN> (1) Includes Public Street Lighting. (2) Represents energy delivered to customers of Energy Service Providers under PGE's Customer Choice Pilot Program (described further in "Regulatory Matters"). </FN> </TABLE> 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 The OPUC, a three-member commission appointed by the Governor, approves PGE's retail rates and establishes conditions of utility service. The OPUC ensures that prices are fair and equitable and provides PGE an opportunity to earn a fair return on its investment. In addition, the OPUC 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. Construction of new generating facilities requires a permit from the Energy Facility Siting Council (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. PGE received regulatory approval in 1998 to ship and dispose of the Trojan reactor vessel as a single package, called the Reactor Vessel And Internals Removal Project (RVAIR). In 1998 PGE applied for approval of the Independent Spent Fuel storage Installation (ISFSI) project, and expects full approval in 1999. Equipment removal and disposal activities will also continue in 1999. Trojan will be 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 CUSTOMER CHOICE PROPOSAL In late 1997 PGE filed a proposal before the OPUC to give all of its customers a choice of electricity providers as early as 1999. Under the proposal, PGE would become a regulated transmission and distribution company focused on delivering, but not selling, electricity. PGE would continue to operate and maintain the electricity delivery system and handle outage restoration, while other competitive companies would market power to customers over that system. To effect this restructuring, PGE asked for OPUC approval to sell all its generating assets, power supply and purchase contracts. In July 1998, the OPUC staff issued its position, disagreeing with PGE's proposal for full customer choice. On January 28, 1999, the OPUC issued an order recommending that PGE offer customers a limited set of options, including the ability to continue to purchase rate-regulated electricity. In addition, most commercial and industrial customers (those with demand exceeding 30 kW) would be able to choose their electricity provider through direct access. Although the order would allow PGE to sell its coal- and gas-fired generation plants, it rejected PGE's request to sell its hydroelectric assets. The Commission's order further requires PGE to refile a new rate case should it choose to adopt the plan recommended by the order, which is also contingent upon the adoption of certain statutory changes by the Oregon Legislature. Until such changes are made and agreed upon among all parties, PGE will not be implementing its proposal or accompanying new rate structure. The issue of restructuring will be further addressed by the 1999 Oregon Legislature; PGE is reviewing the OPUC order and will encourage legislation that creates a comprehensive approach to the electricity industry that helps develop a market that is truly competitive. INTRODUCTORY PROGRAM PGE initiated the Customer Choice Introductory Program as a one-year pilot to test deregulation readiness by allowing certain customers to buy their power from competing energy service providers. The program, approved by the OPUC, was made available to about 50,000 residential, small business and commercial customers in four cities and industrial customers throughout PGE's service territory. At its peak, over 8,700 - almost 17 percent of eligible retail customers - had selected from among eight participating energy service providers. The one-year pilot program terminated on December 31, 1998, and all participating customers returned to PGE. The Customer Choice Introductory Program provided valuable information to PGE, the OPUC, and legislators on the effects of retail competition on PGE and its customers. An extensive independent assessment of the program was completed and made available to interested parties, including the State Legislature. Such assessment indicated wide satisfaction by both customers and energy service providers, with lower prices and the ability to choose their electricity supplier cited as primary reasons for customer participation. 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 filed for formal approval of its 1998-1999 Integrated Resource Plan (IRP) with the OPUC. The plan recognizes fundamental changes occurring in the electric industry and establishes a transition strategy for the next two years. The plan will maintain PGE's delivery capability and provides a bridge to a competitive environment in which funding for public purposes is provided from a System Benefit Charge. 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 January 1998, rates for PGE's residential and small farm customers increased 11.9% due to the Bonneville Power Administration's (BPA) elimination of the Residential Exchange Credit. PGE contested this decision and in September 1998 signed a Residential Exchange Termination Agreement with BPA that provides for a total of $34.5 million in BPA payments through September 2000 and continues to provide benefits to PGE's residential and small farm customers through at least June 2001; the current customer credit under the Residential Exchange Program amounts to about 1% to 2% on the average monthly electricity bill. This new agreement with BPA allowed for a retail rate rollback in late 1998 to a net increase of 5.7%. 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. In order to do this, PGE is focusing on both commercial and industrial new construction and industrial process improvements, and continues to provide a weatherization program for eligible low-income families. PGE is also focusing on developing a regional solution to funding and delivering energy efficiency in a competitive environment. 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's deregulation strategy encompasses five key principles: bringing true market conditions to the industry, separating the regulated and non-regulated portions of utility services, removing the incumbent utility advantage, transferring commercial customer relationships to the energy service provider and allowing the market to determine the cost of transitioning from a regulated to a deregulated environment. The outcome of PGE's 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. WHOLESALE COMPETITION AND MARKETING The FERC has taken steps to provide a framework for increased competition in the electric industry. In 1996, it issued Order 888 requiring non- discriminatory open access transmission by all public utilities that own interstate transmission, requiring utilities to file tariffs that offer others the same transmission services they provide themselves under comparable terms and conditions. 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, as well as its wholesale trading activities, 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. Although wholesale activity has recently declined, PGE's retail demand is expected to continue its upward trend. PGE has relied increasingly on short-term purchases to supplement its existing base of generating resource and long-term power contracts to meet its energy needs. Short-term purchases include both secondary as well as firm purchases for periods less than one year in duration. The availability of short-term firm purchase agreements and PGE's ability to renew these contracts on a month-by-month basis 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 2,023 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. On November 1, 1998, PGE signed a definitive agreement to sell its 20 percent 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 322 megawatt interest in the plant to PP&L Global, a subsidiary of PP&L Resources, for $230.5 million. Regulatory approval of this agreement is expected to take about one year. It is not anticipated that the sale will have an adverse impact on the results of operations. PURCHASED POWER PGE has long-term power contracts with four hydro projects on the mid-Columbia River which provide PGE with 650 MW of firm capacity. PGE also has firm contracts, ranging in term from 1 to 30 years, to purchase 519 MW, primarily hydro-generated, from other Pacific Northwest utilities. In addition, PGE has a long-term exchange contract with a summer-peaking Southwest utility to help meet its winter-peaking requirements. These resources, along with short-term contracts, provide PGE with sufficient firm capacity to serve its peak loads. 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. The WSCC performs an essential role in developing and monitoring established reliability criteria guides and procedures to ensure continued reliability of the 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, is very diverse in climates. 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. Further, according to WSCC forecasts, the nearly 80 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 until the year 2006. January Reserve Margin WSCC Region (Megawatts) WSCC Reserve Margin % Margin 1993 22,997 0.217 1994 31,033 0.31 1995 28,693 0.288 1996 24,500 0.221 1997 36,246 0.325 1998 37,145 0.326 1999 33,240 0.286 2000 34,309 0.29 2001 34,056 0.284 2002 30,842 0.253
Favorable water conditions also contribute to increased energy supplies. During 1998, PGE's peak load was 4,073 MW, of which 14% was met through short- term purchases. PGE's firm resource capacity, including short-term purchase agreements, totaled approximately 4,492 MW as of December 31, 1998. 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 the 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 helped mitigate the effect of these actions in 1997 and 1998. PGE continues to evaluate the impact of these listings on the operation of hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette Rivers. We foresee no further operational changes to our hydroelectric projects during 1999 as a result of recovery measures for endangered salmon.
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 a portion of total requirements through the year 2000. Coal purchases in 1998, 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, was subject to federal, state and local regulations. Coal is delivered to Boardman by rail under a contract which expires in 2003. 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. PGE has reached an agreement to sell its 20 percent interest in Colstrip Units 3 and 4 (for additional information, see "Power Supply"). CENTRALIA Coal for Centralia Units 1 and 2, located in Southwestern Washington, is provided under contract with PacifiCorp, doing business as PacifiCorp Electric Operations. Most of Centralia's coal requirements are expected to be provided under this contract for the foreseeable future. SULFUR TYPE OF POLLUTION PLANT CONTENT CONTROL EQUIPMENT Boardman, OR 0.4% Electrostatic precipitators Centralia, WA 0.7% 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. 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 1998, PGE had access to 76,000 MMBtu/day of firm transportation capacity, enough to operate Beaver at a 70% load factor. 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. PGE remarkets any natural gas and transportation capacity that are excess to its needs.
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. AIR/WATER QUALITY The Clean Air Act (Act) requires significant reductions in emissions of sulfur dioxide, nitrogen oxide and other contaminants. Coal-fired plant operations will be affected by these emission limitations. State governments are also charged with monitoring and administering certain portions of the Act. Each state is required to set guidelines that at least equal federal standards. Boardman was assigned sufficient sulfur emission allowances by the EPA to operate after the year 2000 at a 60% to 67% capacity factor without having to further reduce emissions. If needed, PGE will purchase additional allowances to meet excess capacity needs. Centralia will be required to reduce emissions by the year 2001, with the owner-operator utility considering the installation of scrubbers. As it already utilizes scrubbers, it is not anticipated that Colstrip will be required to reduce emissions. However, future legislation, if adopted, could affect plant operations and increase operating costs or reduce coal-fired capacity. Federal operating permits, issued by the DEQ, have been obtained for all of PGE's fossil fuel generating facilities.
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 generating facilities: OREGON
Generating facilities owned by PGE are set forth in the following table: <TABLE> <CAPTION> PGE Net MW Capability FACILITY Location Fuel <S> <C> <C> <C> <C> 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 @ 65.8% Centralia Centralia, WA Coal 33 @ 2.5% Colstrip 3 & 4 Colstrip, MT Coal 288 @ 20.0% Total 2,023 </TABLE> PGE holds licenses under the Federal Power Act for its hydroelectric generating plants. All of its licenses expire during the years 2001 to 2006. 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 is actively pursuing the renewal of all other licenses. The State of Oregon also has licensed all or portions of five hydro plants. For further information see the Hydro Relicensing discussion 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 Combustion turbine generators at Beaver operate under a 25-year lease agreement. In February 1999, PGE exercised its option to purchase the generators for $37 million at the August 1999 termination of the lease. The lease of combustion turbine generators at Bethel terminated at the end of 1998. PGE leases its headquarters complex in downtown Portland and the coal-handling facilities and certain railroad cars for Boardman.
ITEM 3. LEGAL PROCEEDINGS UTILITY UTILITY REFORM PROJECT V. OPUC, MULTNOMAH COUNTY CIRCUIT COURT On February 18, 1992 the Utility Reform Project (URP) filed a complaint in Multnomah County Oregon Circuit Court asking the court to set aside and rescind OPUC Order No. 91-1781 that authorized PGE a temporary rate increase to recover a portion (approximately $22 million) of the excess power costs incurred during the 1991 Trojan outage. URP's challenge was stayed pending the outcome of a similar jurisdictional issue in another case already on appeal. That other case was decided, the stay lifted, and the URP challenge proceeded. PGE filed a motion, which was granted, to intervene as a participant in the case, and both PGE and the OPUC moved to have the case dismissed. The case was dismissed in December 1998 by the Multnomah County Circuit Court Judge. 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 Citizens' Utility Board (CUB) appealed a 1994 ruling from the Marion County Circuit Court which 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 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 back 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. 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. 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 has also filed such a petition for review. If the Supreme Court declines to hear the case, it would be referred back to the OPUC.
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. LLOYD K. MARBET AND LAURENCE TUTTLE V OREGON WATER RESOURCES DEPT AND OREGON PUC On November 9, 1998, two individuals filed suit in Multnomah County, Oregon Circuit Court against two agencies of the State of Oregon (the Oregon Water Resources Dept and the OPUC) seeking a declaration that the State of Oregon possesses certain contractual rights to current or future ownership of hydroelectric generating facilities licensed by the State of Oregon. The suit alleges certain state statutes, which were repealed in 1995, were incorporated into state licenses for some hydroelectric facilities licensed or permitted by the state prior to that date, and that the State of Oregon therefore has the right to assume ownership of such hydroelectric facilities when they have been fully depreciated. The relief requested includes an order that the state agencies perform an accounting to determine the depreciation status of the various projects. The complaint alleges that PGE's Round Butte generating facility is one of the projects that incorporated such statutes into a state license; the complaint does not allege specifically what other hydroelectric facilities in Oregon, owned by PGE or otherwise, would be affected. PGE's motion to intervene in this proceeding was granted. PGE cannot predict the outcome of this matter at this time. 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 which seeks to overturn a 1984 Judgment and Acquisition Agreement that confirmed PGE's exclusive right to serve Boise Cascade Corporation ("Boise"). The complaint seeks a declaration that the provision of such agreement establishing the amount to be paid by CRPUD to PGE if CRPUD condemns PGE's facilities necessary to serve Boise be declared invalid and unenforceable; it also seeks an injunction barring PGE from enforcing such agreement and judgment related to this matter. Attorney fees and costs are sought but no claim has been made for monetary damages. PGE cannot predict the outcome of this matter at this time.
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS PGE is a wholly owned subsidiary of Enron. PGE's common stock is not publicly traded. Aggregate cash dividends declared on common stock were as follows (millions of dollars): QUARTER 1998 1997 First $ - $ 14 Second 16 16 Third 16 17 Fourth 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 1998 1997 1996 1995 1994 (millions of dollars) Operating Revenues $1,176 $1,416 $1,110 $982 $959 Net Operating Income 200 208 230 201 159 Net Income 137 126 156 93{1} 106 Total Assets $3,162 $3,256 $3,398 $3,246 $3,354 Long-Term Obligations{2} 981 1,038 963 931 856 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 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 one of the faster growing service territories in the U.S. Retail revenues increased $2 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 $21 million for the year and caused the increase in Other operating revenues. NET INCOME $ Millions 1994 106 1995 93 1996 156 1997 126 1998 137 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. OPERATING REVENUES $Millions RETAIL WHOLESALE 1994 845 106 1995 877 95 1996 906 194 1997 899 497 1998 901 234 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. RETAIL ENERGY SALES Million MWhs 1994 16.802 1995 17.065 1996 17.559 1997 18.221 1998 18.736 1997/1998 include energy delivered to ESP customers
<TABLE> <CAPTION> MEGAWATT-HOURS/VARIABLE POWER COSTS <S> <C> <C> <C> <C> Megawatt-Hours Average Variable (thousands) Power Cost (Mills/KWh) 1998 1997 1998 1997 Generation 10,854 7,326 8.6 6.3 Firm Purchases 16,595 36,014 17.3 16.5 Spot Purchases 2,180 2,958 23.6 12.2 Total Send-Out 29,629 46,298 * 15.6 * 15.1 (* includes wheeling costs) </TABLE> 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 $7 million increase in depreciation expense due to capital additions to PGE's distribution system. OPERATING EXPENSES ($ Millions) Depreciation Operating Costs Variable Power 1994 128 334 338 1995 140 356 285 1996 162 410 308 1997 155 378 675 1998 149 386 441 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. 1997 COMPARED TO 1996 Portland General Electric's net income for 1997 was $126 million, including a $14 million non-recurring loss provision associated with non-utility property. Excluding this provision, 1997 net income would have been $140 million compared to $156 million in 1996. PGE's strong operating performance reflected the addition of over 17,000 new customers in one of the faster growing service territories in the U.S. Continued customer growth helped mitigate the impact of a December 1996 rate settlement which resulted in a $70 million annual rate reduction for PGE's regulated retail customers. Retail revenues decreased $8 million primarily due to the decrease in rates mentioned above. Wholesale revenues totaled $497 million in 1997, an all-time record for PGE and an increase of over $300 million from 1996 levels. Favorable market conditions prompted PGE to increase its participation in the short-term wholesale marketplace. Purchased power and fuel costs rose $367 million, or 119%, due largely to increased wholesales sales volume. Energy purchases were up 79%, with prices averaging 16.2 mills compared to 13.8 mills for 1996. Increased winter gas prices followed by tight market conditions in the southwestern United States were the major contributors to the price increase. Company generation provided 16% of total power needs. Operating expense (excluding purchased power, fuel, depreciation and taxes) were comparable to 1996.
Depreciation expense increased $6 million or 5% due to recent capital additions to PGE's distribution system. Amortization expense decreased $13 million, due largely to the $17 million amortization of the gain associated with termination of a power sales agreement in 1996; this was partially offset by the amortization of bondable conservation investments. Other Income decreased due to loss provisions recorded for the future removal of non-utility property. 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 1998, monthly balances ranged from $96 million to $167 million. PGE has committed borrowing facilities through July 2000 totaling $200 million, which are used as backup for PGE's commercial paper facility. A significant portion of cash provided by operations comes from depreciation and amortization of utility plant, charges which are recovered in customer revenues but require no current period cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash. CAPITAL EXPENDITURES ($ Millions) 1994 246 1995 234 1996 200 1997 180 1998 144 Decreased cash flow in 1998 was due to a significant reduction in accounts payable. In addition, 1997 includes a non-cash loss provision of $24 million related to future costs associated with non-utility property (in "Other non- cash expenses") and deferred income taxes of $48 million on a capital gain associated with the termination of the SCE Power Sales Agreement (in "Deferred income taxes"). "Other - net" includes a $35 million net change in deferred charges and credits. INVESTING ACTIVITIES consist primarily of improvements to PGE's distribution, transmission, and generation facilities, as well as continued energy efficiency program expenditures. Capital expenditures of $144 million in 1998 were primarily for the expansion and upgrade of PGE's distribution system. Capital expenditures are expected to approximate $200 million in 1999, including the $37 million purchase of previously-leased combustion turbines at Beaver. 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 the addition of new customers. 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 1998, PGE issued long term debt maturing through 2033 and in turn redeemed $142 million of its variable rate pollution control bonds. In addition, PGE repaid $72 million in other long term debt, funded primarily through commercial paper borrowings. In April 1999, PGE plans to file a $200 million shelf registration statement with the Securities and Exchange Commission for the purpose of issuing new long-term debt. During 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 1997, PGE's dividend payments totaled $65 million, consisting of common stock dividends of $46 million to public shareholders and $17 million to its parent, and $2 million in preferred stock dividends.
In September 1998, Moody's Investor Services reaffirmed PGE's debt ratings, with senior secured debt rated A2, and commercial paper rated P1. In November 1998, Standard & Poor's reaffirmed PGE's debt ratings, with senior secured debt rated A and commercial paper rated A-1. These ratings enable PGE to access public debt markets at favorable borrowing costs. 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, 1998, PGE had 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 REGULATION AND COMPETITION State Since the passage of the federal Energy Policy Act of 1992, various state utility commissions and legislatures have considered allowing retail customers direct access to generation suppliers, marketers, brokers and other service providers in a competitive marketplace for energy services (retail wheeling). A statement of principles for restructuring the electric utility industry was issued by Oregon's governor in 1996 that included access to electricity service at a reasonable price, the option of customers to choose their electricity provider, and the opportunity for utilities to recover the costs of previous commitments, including stranded costs. In late 1997, PGE filed its "Customer Choice" proposal before the OPUC, designed to give all of its customers a choice of electricity providers as early as 1999. Under the proposal, PGE would become a regulated transmission and distribution company focused on delivering, but not selling, electricity. PGE would continue to operate and maintain the electricity delivery system and handle outage restoration, while other competitive companies would market power to customers over that system. To effect this restructuring, PGE asked for OPUC approval to sell all its generating assets, power supply and purchase contracts. In conjunction with its proposal, PGE initiated the Customer Choice Introductory Program as a one-year pilot to test deregulation readiness by allowing certain PGE customers to buy their power from competing energy service providers. The program, approved by the OPUC, was made available to about 50,000 residential, small business and commercial customers in four cities and industrial customers throughout PGE's service territory. At its peak, over 8,700 - almost 17 percent of eligible retail customers - had selected from among eight participating energy service providers. The program terminated as scheduled on December 31, 1998, and all participating customers returned to PGE. The Customer Choice Introductory Program provided valuable information to PGE, the OPUC, and legislators on the effects of retail competition on PGE and its customers. An extensive independent assessment of the program was completed and made available to interested parties, including the State Legislature. Such assessment indicated wide satisfaction by both customers and energy service providers, with lower prices and the ability to choose their electricity supplier cited as primary reasons for customer participation. In July 1998, the OPUC staff issued its position on PGE's Customer Choice proposal, disagreeing with PGE's proposal for full implementation. On January 28, 1999, the OPUC issued an order recommending that PGE offer customers a limited set of options, including the ability to continue to purchase rate- regulated electricity; most commercial and industrial customers (those with demand exceeding 30 kW) would be able to choose their electricity provider through direct access. Although the order would allow PGE to sell its coal- and gas-fired generation plants, it rejected PGE's request to sell its hydroelectric assets. The Commission's order further requires PGE to refile a new rate case should it choose to adopt the plan recommended by the order, which is also contingent upon the adoption of certain statutory changes by the Oregon Legislature. Until such changes are made and agreed upon among all parties, PGE will not seek to implement either its Customer Choice proposal or the recent Commission order. The issue of restructuring will be further addressed by the 1999 Oregon Legislature. PGE is reviewing the OPUC order and will support a deregulation plan that includes the following: 1) creation of a comprehensive approach to restructuring the electricity industry that benefits all customers; 2) development of a truly competitive market; 3) avoidance of cost shifts that benefit one group at the expense of another; 4) assurance that customers continue to receive benefits of federal hydropower; and, 5) implementation of a Systems Benefit Charge (SBC) to ensure adequate funds for public purpose investments (renewable energy projects, low-income weatherization, etc).
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 anticipated in 1999, although there remains considerable uncertainty regarding their ultimate outcome. On July 16, 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. RETAIL CUSTOMER GROWTH AND ENERGY SALES During 1998, weather adjusted retail energy sales grew 3.0%. Commercial and industrial sales increased by 3.8% and 2.7% respectively due to continued growth in most industry segments. The addition of over 19,000 customers resulted in residential sales growth of 2.4%. PGE forecasts retail energy sales growth of approximately 3% in 1999 and comparable growth in the next few years. In January 1998, rates for PGE's residential and small farm customers increased 11.9% due to the Bonneville Power Administration's (BPA) elimination of the Residential Exchange Credit. PGE contested this decision and reached a new agreement with BPA in September 1998 that provides for a retail rate rollback to a net increase of 5.7%. Exchange benefits are passed directly to PGE's customers in the form of price decreases. 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 and NYMEX electricity contract trading has led to enhanced price discovery available for market participants, further adding to the downward pressure on wholesale prices and margins. During 1998, PGE's wholesale sales accounted for about 19% of total revenues and 38% 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. Long-term wholesale trading activities have been transferred to a non-regulated Enron affiliate, which participates more fully in a broader market. PGE expects that its future revenues from wholesale activities will continue to decline. 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 1999, 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 1998, PGE generated approximately 37% of its total load requirement, compared to approximately 16% in 1997; short-term purchases were utilized to meet the remaining load. Purchases, which are expected to decline further in 1999, were also used to support PGE's wholesale sales activity. On November 1, 1998, PGE signed a definitive agreement to sell its 20 percent 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 322 megawatt interest in the plant to PP&L Global, a subsidiary of PP&L Resources, for $230.5 million. Regulatory approval of this agreement is expected to take about one year. It is not anticipated that the sale will have an adverse impact on the results of operations. 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, operated under terms of a 25-year lease expiring in August 1999, produce a net output of approximately 500 MW in combined-cycle configuration. The lease of combustion turbine generators at Bethel terminated at the end of 1998. 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 to date has been modifying the timing of the 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 helped mitigate the effect of these actions in 1997 and 1998. PGE continues to evaluate the impact of these listings on the operation of hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette Rivers. The company foresees no further operational changes to its hydroelectric projects during 1999 as a result of recovery measures for endangered salmon. HYDRO RELICENSING PGE HYDRO - PGE's eight hydroelectric plants provide economical generation and flexible load following capabilities; in 1998, they produced 2.6 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. PGE continued the relicensing process for its 408-MW Pelton Round Butte Project throughout 1998, culminating with issuance of a draft license application in December. The Confederated Tribes of Warm Springs, currently the licensee for a powerhouse located at the reregulating dam (one of three dams within the Pelton Round-Butte Project), also proceeded with their competing relicensing process for the entire project. Several meetings with federal and state agencies, as well as members of the public and non-governmental organizations, were conducted during the year 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 license, 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. The relicensing process includes the involvement of numerous interested parties such as governmental agencies, public interest groups and communities, with much of the focus on environmental concerns. PGE has already
performed many pre-filing activities, including numerous public meetings with such groups. The cost of relicensing includes legal and filing fees as well as the cost of environmental studies, possible fish passage measures, and wildlife habitat enhancements. Relicensing cost may be a significant factor in determining whether a project remains cost-effective after a new license is obtained, especially for smaller projects. Although the FERC has rarely denied an application and has never issued a license to anyone other than the incumbent licensee, there is no assurance that new licenses will be granted to PGE. Refer to Item 3. Legal Proceedings for additional information. 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. This matter is now on appeal to the Circuit Court of Appeals. 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 $73 million expended through 1998. The total estimate assumes that the majority of decommissioning activities will be completed by 2002, after the spent fuel has been transferred to a temporary dry spent fuel storage facility. 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, for further discussion of the decommissioning plan and other Trojan issues). In 1998 PGE continued to make progress in decommissioning Trojan. Over 68 thousand cubic feet of contaminated equipment and material were removed, packaged, and shipped to the disposal site. Also in 1998, Trojan received regulatory approval to ship and dispose of the Trojan reactor vessel as a single package, called the Reactor Vessel And Internals Removal Project. This precedent-setting project will save millions of dollars from the conventional segmentation approach. In 1999, PGE will continue moving forward on this project. PGE expects remaining transition activities to be completed in 1999, with total costs estimated at $8 million paid from current operating funds. Transition activities are comprised of operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage as part of the Independent Spent Fuel Storage Installation (ISFSI) project. Equipment removal and disposal activities will also continue. PGE anticipates total 1999 decommissioning costs of approximately $59 million, compared to about $30 million in 1998. 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 on schedule and within approved cost estimates. PGE expects the final site survey to be completed by the end of 2002. YEAR 2000 The Year 2000 problem results 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. These errors or failures may have limited effects, or the effects may be widespread, depending on the computer chip, system or software, and its location and function. The effects of the Year 2000 problem are exacerbated because of the interdependence of computer and telecommunications systems in the United States and throughout the world. This interdependence certainly is true for PGE and PGE's suppliers, trading partners, and customers.
STATE OF READINESS PGE's Board of Directors has adopted the Enron Year 2000 plan (the "Plan"), which covers all of PGE's and other Enron subsidiaries' activities. The aim of the plan is to take reasonable steps to prevent Enron's mission-critical functions from being impaired due to the Year 2000 problem. "Mission-critical" functions are those critical functions whose loss would cause an immediate stoppage of or significant impairment to major business areas (a major business area is one of material importance to Enron's business). PGE's Year 2000 plan has been assigned to a centralized staff under the direction of a Year 2000 Project Manager, who coordinates the implementation of the Plan within all affected areas of the company. PGE has also engaged outside consultants, technicians and other external resources to aid in implementing the Plan. PGE is implementing the Plan, which will be modified as events warrant. Under the Plan, PGE will continue to inventory its mission-critical computer hardware and software systems and embedded chips (computer chips with date-related functions, contained in a wide variety of devices); assess the effects of Year 2000 problems on the mission-critical functions of PGE's business; remedy systems, software and embedded chips in an effort to avoid material disruptions or other material adverse effects on mission-critical functions, processes and systems; verify and test the mission-critical systems to which remediation efforts have been applied; and attempt to mitigate those mission-critical aspects of the Year 2000 problem that are not remediated by January 1, 2000, including the development of contingency plans to cope with the mission- critical consequences of Year 2000 problems that have not been identified or remediated by that date. The Plan recognizes that the computer, telecommunications, and other systems ("Outside Systems") of outside entities ("Outside Entities") have the potential for major, mission-critical, adverse effects on the conduct of PGE's business. PGE does not have control of these Outside Entities or Outside Systems. However, the Plan includes an ongoing process of identifying and contacting Outside Entities whose systems in PGE's judgment have, or may have, a substantial effect on PGE's ability to continue to conduct the mission-critical aspects of its business without disruption from Year 2000 problems. The Plan envisions PGE's attempting to inventory and assess the extent to which these Outside Systems may not be "Year 2000 ready" or "Year 2000 compatible." PGE will attempt reasonably to coordinate with these Outside Entities in an ongoing effort to obtain assurance that the Outside Systems that are mission-critical to PGE will be Year 2000 compatible well before January 1, 2000. Consequently, PGE will work prudently with Outside Entities in a reasonable attempt to inventory, assess, analyze, convert (where necessary), test, and develop contingency plans for PGE's connections to these mission-critical Outside Systems and to ascertain the extent to which they are, or can be made to be, Year 2000 ready and compatible with PGE's mission-critical systems. It is important to recognize that the processes of inventorying, assessing, analyzing, converting (where necessary), testing, and developing contingency plans for mission-critical items in anticipation of the Year 2000 event are necessarily iterative processes. That is, the steps are repeated as PGE learns more about the Year 2000 problem and its effects on PGE's internal systems and on Outside Systems, and about the effects that embedded chips may have on PGE's systems and Outside Systems. As the steps are repeated, it is likely that new problems will be identified and addressed. PGE anticipates that it will continue with these processes through January 1, 2000 and, if necessary based on experience, into the Year 2000 in order to assess and remediate problems that reasonably can be identified only after the start of the new century. As of March 1999, PGE is at various stages in implementation of the Plan, as shown in the following table, which lists the status of both mission-critical internal systems (including embedded chips) and Outside Systems. Any notation of "complete" or reference to a "completion date" conveys the fact only that the initial iteration of this phase has been substantially completed. PGE will continue closely to monitor work under the Plan and to revise estimated completion dates for the initial iteration of each listed process.
<TABLE> <CAPTION> YEAR 2000 READINESS PLAN <S> <C> <C> <C> <C> MISSION-CRITICAL INTERNAL ITEMS MISSION-CRITICAL OUTSIDE ENTITIES STATUS COMPLETION DATE STATUS COMPLETION DATE* Inventory Complete December 1997 Complete October 1998 Assessment Complete October 1998 Complete November 1998 Analysis Complete October 1998 Complete November 1998 Conversion In Process June 1999 In Process June 1999 Testing In Process June 1999 In Process June 1999 Y2K-Ready In Process June 1999 In Process June 1999 Contingency Plan In Process June 1999 In Process June 1999 </TABLE> * The June 1999 completion date for Mission-Critical Outside Entities conveys only the date when PGE anticipates it will have evaluated the progress of Outside Entities with respect to Conversion, Testing, Y2K-Ready, and Contingency Plans. COSTS TO ADDRESS YEAR 2000 ISSUES Under the Plan, PGE currently estimates that it will spend approximately $20-25 million relating to Year 2000 issues, about one-third of which has been spent to date; 1999 expenditures are currently estimated at approximately $15 million. Most costs incurred to address the Year 2000 issue are charged to operating expenses as incurred and are expected to be funded by cash provided by operations. PGE anticipates that its costs relating to Year 2000 issues will not have a material adverse effect on its financial condition or results of operations. Although management believes that its estimates are reasonable, there can be no assurance, for the reasons stated in the "Outlook" section, below, that the actual costs of implementing the plan will not differ materially from the estimated costs or that PGE will not be materially adversely affected by Year 2000 issues. YEAR 2000 RISK FACTORS REGULATORY REQUIREMENTS - PGE expects to satisfy all requirements of regulatory authorities for achieving Year 2000 readiness. If its reasonable expectations in this regard are in error, the adverse effect on PGE could be material. Outside Entities could force temporary cessation of operations that materially adversely affect PGE. SHORTAGE OF RESOURCES - Between now and 2000 there will be increased competition for people skilled in the technical and managerial skills necessary to deal with the Year 2000 problem. While PGE is taking substantial precautions to recruit and retain sufficient people skilled in dealing with the Year 2000 problem and has hired consultants who bring additional skilled people to deal with the Year 2000 problem as it affects PGE, PGE could face shortages of skilled personnel or other resources, such as Year 2000 ready computer chips, and these shortages might delay or otherwise impair PGE's ability to assure that its mission-critical systems are Year 2000 ready. Outside Entities could force temporary cessation of operations that materially adversely affect PGE. PGE believes that the possible import of the shortage of skilled people is not, and will not be, unique to PGE. POTENTIAL SHORTCOMING - PGE estimates that its mission-critical systems will be Year 2000-ready substantially before January 1, 2000. However, there is no assurance that the Plan will succeed in accomplishing its purposes or that unforeseen circumstances will not arise during implementation of the Plan that would materially and adversely affect PGE. CASCADING EFFECT - PGE is taking reasonable steps to identify, assess, and where appropriate, replace devices that contain embedded chips. Despite these reasonable efforts, there is no assurance that PGE will be able to find and remediate all embedded chips in its systems. Further, there is no assurance that Outside Entities on
which PGE depends will be able to find and remediate all embedded chips in their systems. Some of the embedded chips that fail to operate or that produce anomalous results may create system disruptions or failures. Some of these disruptions or failures may spread from the systems in which they are located to other systems in a cascade. These cascading failures may have adverse effects upon PGE's ability to maintain safe operations and may also have adverse effects upon PGE's ability to serve its customers and otherwise to fulfill certain contractual and other legal obligations. The embedded chip problem is widely recognized as one of the more difficult aspects of the Year 2000 problem across industries and throughout the world. PGE believes that the possible adverse impact of the embedded chip problem is not, and will not be, unique to PGE. THIRD PARTIES - PGE cannot assure that suppliers upon which it depends for essential goods and services will convert and test their mission-critical systems and processes in a timely manner. Failure or delay by all or some of these entities, including U.S. federal, state or local governments, could create substantial disruptions having a material adverse effect on PGE's business. CONTINGENCY PLANS As part of the Plan, PGE is developing contingency plans that deal with two aspects of the Year 2000 problem: (1) that PGE, despite its good-faith, reasonable efforts, may not have satisfactorily remediated all of its internal mission-critical systems; and (2) that Outside Systems may not be Year 2000 ready, despite PGE's good-faith, reasonable efforts to work with Outside Entities. PGE's contingency plans are being designed to minimize the disruptions or other adverse effects resulting from Year 2000 incompatibilities regarding these mission-critical functions or systems, and to facilitate the early identification and remediation of mission-critical Year 2000 problems that first manifest themselves after January 1, 2000. PGE's contingency plans will contemplate an assessment of all its mission- critical internal information technology systems and its internal operational systems that use computer-based controls. This process will commence in the early minutes of January 1, 2000, and continue for hours, days, or weeks as circumstances require. Further, PGE will in that time frame assess any mission-critical disruptions due to Year 2000-related failures that are external to PGE. The assessment process will cover, for example, loss of electrical power from other utilities; telecommunications services from carriers; or building access, security, or elevator service in facilities occupied by PGE. PGE plans to file with the Western Systems Coordinating Council by June 15, 1999 its contingency plan related to Mission-Critical Internal Systems (including embedded chips) and Outside Systems. PGE plans to perform additional contingency planning relating to other systems both before and after its June 15, 1999 filing. PGE's contingency plans will include the creation of teams that will be standing by on the eve of the new millennium, prepared to respond rapidly and otherwise as necessary to mission-critical Year 2000-related problems as soon as they become known. The composition of teams that are assigned to deal with Year 2000 problems will vary according to the nature, mission-criticality, and location of the problem. WORST CASE SCENARIO The Securities and Exchange Commission requires that companies must forecast the most reasonably likely worst case Year 2000 scenario. Analysis of the most reasonably likely worst case Year 2000 scenarios PGE may face leads to contemplation of the following possibilities which, though unlikely in some or many cases, must be included in any consideration of worst cases: widespread failure of electrical, gas, and similar supplies by utilities serving PGE; widespread disruption of the services of communications common carriers; similar disruption to means and modes of transportation for PGE and its employees, contractors, suppliers, and customers; significant disruption to PGE's ability to gain access to, and remain working in, office buildings and other facilities; the failure of substantial numbers of PGE's mission-critical information (computer) hardware and software systems, including both internal business systems and systems (such as those with embedded chips) controlling operational facilities such as electrical generation, transmission, and distribution systems; and the failure of Outside Systems, the effects of which would have a cumulative material adverse impact on PGE's mission-critical systems. Among other things, PGE could face substantial claims by customers or loss of revenues due to service interruptions, inability to fulfill contractual obligations, inability to account for
certain revenues or obligations or to bill customers accurately and on a timely basis, and increased expenses associated with litigation, stabilization of operations following mission- critical failures, and the execution of contingency plans. PGE could also experience an inability by customers, traders, and others to pay, on a timely basis or at all, obligations owed to PGE. Under these circumstances, the adverse effect on PGE, and the diminution of PGE's revenues, would be material, although not quantifiable at this time. Further in this scenario, the cumulative effect of these failures could have a substantial adverse effect on the economy, domestically and internationally. The adverse effect on PGE, and the diminution of its revenues, from a domestic or global recession or depression also is likely to be material, although not quantifiable at this time. PGE will continue to monitor business conditions with the aim of assessing and quantifying material adverse effects, if any, that result from the Year 2000 problem. SUMMARY PGE has a Plan to deal with the Year 2000 challenge and believes that it will be able to achieve substantial Year 2000 readiness with respect to the mission critical systems that it controls. From a forward-looking perspective, the extent and magnitude of the Year 2000 problem as it will affect PGE, both before and for some period after January 1, 2000, are difficult to predict or quantify for a number of reasons. Among these are: the difficulty of locating "embedded" chips that may be in a great variety of mission-critical hardware used for process or flow control, environmental, transportation, access, communications and other systems; the difficulty of inventorying, assessing, remediating, verifying and testing Outside Systems; the difficulty in locating all mission-critical software (computer code) internal to PGE that is not Year 2000 compatible; and the unavailability of certain necessary internal or external resources, including but not limited to trained hardware and software engineers, technicians and other personnel to perform adequate remediation, verification and testing of PGE systems or Outside Systems. Accordingly, there can be no assurance that all of PGE's systems and all Outside Systems will be adequately remediated so that they are Year 2000 ready by January 1, 2000, or by some earlier date, so as not to create a material disruption to PGE's business. If, despite PGE's reasonable efforts under the Plan, there are mission-critical Year 2000-related failures that create substantial disruptions to PGE's business, the adverse impact on PGE's business could be material. Additionally, Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of Outside Systems and similar events. Moreover, the estimated costs of implementing the Plan do not take into account the costs, if any, that might be incurred as a result of Year 2000-related failures that occur despite PGE's implementation of the Plan. NEW ACCOUNTING STANDARDS In 1998, the AICPA issued Statement of Position 98-1 (SOP 98-1), "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use", and Statement of Position 98-5 (SOP 98-5), "Reporting on the Costs of Start-Up Activities". Also in 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", and the Emerging Issues Task Force reached a consensus on Issue No. 98-10, "Accounting for Contracts involved in Energy Trading and Risk Management Activities". PGE has analyzed the potential effects of the application of SOP 98-1 and SOP 98-5 in 1999 and has determined that their application will not have a material effect on its financial position or results of operations for the year. SFAS No. 133, to be effective January 1, 2000, establishes 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. PGE has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the method of its adoption of SFAS No. 133 nor the effect on the accounting for its hedging activities or physical contracts.
EITF 98-10 is effective for fiscal years beginning after December 15, 1998 and requires energy trading contracts to be recorded at fair value on the balance sheet, with any changes in fair value included in earnings. The effect of initial application of EITF 98-10 will be reported as a cumulative effect of a change in accounting principle. Because an insignificant portion of PGE's electricity trades are entered into for trading purposes, PGE believes that the adoption of EITF 98-10 will not have a materially adverse impact on its financial position or results of operations. 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.
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, 1998, 1997 and 1996, 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 Shareholder 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, 1998, 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. 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, 1998, 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 March 5, 1999
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholder 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, 1998 and 1997, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. Arthur Andersen LLP Portland, Oregon, March 5, 1999
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME <TABLE> <CAPTION> For the Years Ended December 31 1998 1997 1996 <S> <C> <C> <C> (MILLIONS OF DOLLARS) Operating Revenues $ 1,176 $ 1,416 $ 1,110 Operating Expenses Purchased power and fuel 441 675 308 Production and distribution 134 132 138 Administrative and other 114 107 104 Depreciation and amortization 149 155 162 Taxes other than income taxes 57 56 52 Income taxes 81 83 116 976 1,208 880 Net Operating Income 200 208 230 Other Income (Deductions) Miscellaneous 13 (21) (3) Income taxes (1) 13 5 12 (8) 2 Interest Charges Interest on long-term debt and other 68 69 67 Interest on short-term borrowings 7 5 9 75 74 76 Net Income 137 126 156 Preferred Dividend Requirement 2 2 3 Income Available for Common Stock $ 135 $ 124 $ 153 Portland General Electric Company and Subsidiaries Consolidated Statements of Retained Earnings For the Years Ended December 31 1998 1997 1996 (MILLIONS OF DOLLARS) Balance at Beginning of Year $ 270 $ 292 $ 246 Net Income 137 126 156 Miscellaneous 0 (2) (2) 407 416 400 Dividends Declared Common stock - cash 49 47 105 Common stock - property 0 97 0 Preferred stock 2 2 3 51 146 108 Balance at End of Year $ 356 $ 270 $ 292 The accompanying notes are an integral part of these consolidated financial statements. </TABLE>
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> AT DECEMBER 31 1998 1997 <S> <C> <C> (MILLIONS OF DOLLARS) ASSETS ELECTRIC UTILITY PLANT - ORIGINAL COST Utility plant (includes Construction Work in Progress of $35 and $27) $ 3,182 $ 3,078 Accumulated depreciation (1,363) (1,260) 1,819 1,818 OTHER PROPERTY AND INVESTMENTS Contract termination receivable 95 104 Receivable from parent 97 106 Nuclear decommissioning trust, at market value 72 84 Corporate Owned Life Insurance, less loans of 63 58 $32 and $30 Miscellaneous 15 17 342 369 CURRENT ASSETS Cash and cash equivalents 4 3 Accounts and notes receivable 135 125 Unbilled and accrued revenues 45 46 Inventories, at average cost 28 30 Prepayments and other 31 21 243 225 DEFERRED CHARGES Unamortized regulatory assets 731 819 Miscellaneous 27 25 758 844 $ 3,162 $ 3,256 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 356 270 Cumulative preferred stock Subject to mandatory redemption 30 30 Long-term obligations 951 1,008 1,977 1,948 CURRENT LIABILITIES Accounts payable and other accruals 145 167 Accrued interest 11 11 Dividends payable 1 1 Accrued taxes 35 63 192 242 OTHER Deferred income taxes 351 363 Deferred investment tax credits 39 43 Trojan decommissioning and transition costs 274 313 Unamortized regulatory liabilities 237 258 Miscellaneous 92 89 993 1,066 $ 3,162 $ 3,256 The accompanying notes are an integral part of these consolidated financial statements. </TABLE>
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW <TABLE> <CAPTION> For the Years Ended December 31 1998 1997 1996 <S> <C> <C> <C> (MILLIONS OF DOLLARS) Cash flows from Operating Activities: Reconciliation of net income to net cash provided by (used in) operating activities Net Income $ 137 $ 126 $ 156 Non-cash items included in net income: Depreciation and amortization 149 155 162 Deferred income taxes (5) (58) (9) Other non-cash expenses 0 24 0 Changes in working capital: (Increase) Decrease in receivables (8) 27 (32) Increase (Decrease) in payables (47) 51 38 Other working capital items - net (4) (1) 4 Other - net 43 35 50 Net Cash Provided by Operating Activities 265 359 369 Cash flows from Investing Activities: Capital expenditures (144) (180) (200) Other - net (4) (28) (21) Net Cash Used in Investing Activities (148) (208) (221) Cash Flows from Financing Activities: Repayment of long-term debt (214) (115) (176) Issuance of long-term debt 148 8 171 Retirement of preferred stock 0 0 (20) Dividends paid (51) (65) (106) Other - net 1 5 0 Net Cash Used in Financing Activities (116) (167) (131) Increase (Decrease) in Cash and Cash Equivalents 1 (16) 17 Cash and Cash Equivalents, the Beginning of Year 3 19 2 Cash and Cash Equivalents, End of Year $ 4 $ 3 $ 19 Supplemental disclosures of cash flow information Cash paid during the year: Interest, net of amounts capitalized $ 63 $ 71 $ 73 Income taxes 133 96 108 The accompanying notes are an integral part of these consolidated financial statements. </TABLE>
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 now 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 1998, PGE's service area population was approximately 1.5 million, constituting approximately 44% of the state's population and serving approximately 704,000 customers. 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 generally accepted accounting principles. 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 4.3% in 1998, 1997 and 1996. 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's capital leases are amortized over the life of the lease. As of December 31, 1998 and 1997, accumulated amortization for capital leases totaled $28 million and $33 million, respectively. 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 5.5%. 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. DERIVATIVE FINANCIAL INSTRUMENTS PGE uses financial instruments to hedge against exposure to interest rate risks. The objective of PGE's hedging program is to mitigate risks due to market fluctuations associated with external financings. Gains and losses on financial instruments that reduce interest rate risk of future debt issuances are deferred and amortized over the life of the related debt as an adjustment to interest expense. 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: <TABLE> <CAPTION> 1998 1997 <S> <C> <C> (millions of dollars) Regulatory Assets Trojan-related $438 $488 Income taxes recoverable 165 174 Debt reacquisition and other 44 47 Conservation investments - secured 64 72 Energy efficiency programs 21 19 Regional Power Act (1) 19 Total Regulatory Assets $731 $819 Regulatory Liabilities Deferred gain on SCE termination $92 $103 Merger payment obligation 96 103 Miscellaneous 49 52 Total Regulatory Liabilities 237 $ 258 </TABLE>
As of December 31, 1998, 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 1998, the Company estimates that it will collect substantially all of its regulatory assets within the next 13 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, 1998, the outstanding balance on the bonds was $68 million. DEFERRED GAIN ON 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. TRANSACTIONS WITH RELATED PARTIES As part of its ongoing operations, PGE receives management services from Enron and provides incidental services to Enron and its affiliated companies. In 1998, approximately $12 million was paid to Enron for allocated overhead costs, including PGE's $5 million share of the Employee Stock Option Plan.
NOTE 2 - EMPLOYEE BENEFITS PENSION PLAN 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. The following tables provide a reconciliation of the changes in the plan's benefit obligation, fair value of plan assets, a statement of the funded status, and components of net periodic pension expense (in millions): <TABLE> <CAPTION> 1998 1997 <S> <C> <C> Reconciliation of benefit obligation: Obligation at January 1 $ 240 $ 222 Service cost 7 6 Interest cost 17 17 Actuarial loss 17 5 Benefit payments (12) (10) Obligation at December 31 $ 269 $ 240 Reconciliation of fair value of plan assets Fair value of plan assets at January 1 $ 375 $ 315 Actual return on plan assets 38 71 Benefit payments (12) (11) Fair value of plan assets at December 31 $ 401 $ 375 Funded status Funded status at December 31 $ 132 $ 135 Unrecognized transition (asset) (12) (14) Unrecognized prior service cost 9 11 Unrecognized (gain) (117) (128) Prepaid Pension Cost $ 12 $ 4 </TABLE> <TABLE> <CAPTION> 1998 1997 <S> <C> <C> ASSUMPTIONS: Discount rate used to calculate PBO 6.75% 7.25% Rate of increase in future compensation levels 5.25 5.25 Long-term rate of return on assets 9.00 9.00 </TABLE> <TABLE> <CAPTION> COMPONENTS OF NET PERIODIC PENSION EXPENSE: <S> <C> <C> Service cost $ 7 $ 6 Interest cost on PBO 17 17 Expected return on plan assets (28) (25) Amortization of Transition Asset (2) (2) Amortization of Prior Service Cost 1 1 Recognized (gain) (3) (2) Net periodic pension (benefit) $ (8) $ (5) </TABLE>
OTHER POST-RETIREMENT BENEFIT PLANS PGE accrues for health, medical and life insurance costs during the employees' service years, in accordance with SFAS No. 106 ("Employers' Accounting for Post Retirement Benefits Other than Pensions"). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. The accumulated benefit obligation for post-retirement health and life insurance benefits at December 31, 1998, was $29 million, for which there were $33 million of assets held in trust. PGE also provides senior officers with additional benefits under an unfunded Supplemental Executive Retirement Plan (SERP). Projected benefit obligations for the SERP are $13 million and $12 million at December 31, 1998 and 1997, respectively. DEFERRED COMPENSATION PGE provides certain employees with benefits under an unfunded Management Deferred Compensation Plan (MDCP). Obligations for the MDCP were $30 million and $26 million at December 31, 1998 and 1997, respectively. EMPLOYEE STOCK OWNERSHIP PLAN PGE participates in an Employee Stock Ownership Plan (ESOP) which is a part of its 401(k) retirement savings plan. One-half of employee contributions up to 6% of base pay are matched by employer contributions in the form of ESOP common stock. Shares of common stock to be used to match contributions by PGE employees are purchased from Enron at current market prices. ALL EMPLOYEE STOCK OPTION PLAN Enron granted stock options 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 and one-third of the options will vest in 1999 and in 2000. PGE pays Enron the estimated value of the shares vesting each year. The fair value of shares that vested in 1998 was $5 million and is estimated to be $5 million in both 1999 and 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): <TABLE> <CAPTION> 1998 1997 1996 <S> <C> <C> <C> Income Tax Expense Currently payable Federal $ 75 $ 114 $ 98 State and local 13 14 22 88 128 120 Deferred income taxes Federal (1) (45) (4) State and local (1) (9) (1) (2) (54) (5) Investment tax credit adjustments (4) (4) (4) $ 82 $ 70 $ 111 Provision Allocated to: Operations $ 81 $ 83 $ 112 Other income and deductions 1 (13) (1) $ 82 $ 70 $ 111 Effective Tax Rate Computation: Computed tax based on statutory federal income tax rates applied $ 77 $ 69 $ 93 Flow through depreciation 4 6 9 State and local taxes - net 7 13 12 State of Oregon refund - (9) - Investment tax credits (4) (4) (3) Excess deferred tax (1) (1) (1) Other (1) (4) 1 $ 82 $ 70 $ 111 Effective tax rate 37.5% 35.7% 41.6% </TABLE>
As of December 31, 1998 and 1997, the significant components of PGE's deferred income tax assets and liabilities were as follows (millions of dollars): <TABLE> <CAPTION> 1998 1997 <S> <C> <C> DEFERRED TAX ASSETS Depreciation and amortization $ 27 $ 31 SCE termination payment 42 49 Other regulatory liabilities 14 12 Employee fringe benefits 15 15 Other 4 12 102 119 DEFERRED TAX LIABILITIES Depreciation and amortization $ (378) $ (393) Price risk management (9) (10) Trojan abandonment (56) (63) Other regulatory assets (3) (4) Other (7) (12) (453) (482) Total $ (351) $ (363) </TABLE> 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 <TABLE> <CAPTION> COMMON STOCK CUMULATIVE PREFERRED Other Number $3.75 Par Number $100 Par No-Par Paid-in Unearned OF SHARES VALUE OF SHARES VALUE VALUE CAPITAL COMPENSATION <S> <C> <C> <C> <C> <C> <C> <C> (millions of dollars except share amounts) December 31, 1995 42,758,877 $160 500,000 $ 20 $30 $473 $ (7) Redemption of preferred stock - - (200,000) (20) - 2 - Repayment of ESOP loan and other - - - - - 2 5 December 31, 1996 42,758,877 $160 300,000 - $30 $477 $ (2) Repayment of ESOP loan and other - - - - - 3 2 December 31, 1997 42,758,877 $160 300,000 $ - $30 $480 - December 31, 1998 42,758,877 $160 300,000 $ - $30 $480 $ - </TABLE> 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, 1998, PGE had committed lines of credit totaling $200 million, expiring in July 2000. These lines of credit have an annual fee of 0.10% and do not require compensating cash balances. These lines of credit are used primarily as backup for both commercial paper and borrowings from commercial banks under uncommitted lines of credit. At December 31, 1998, there were no outstanding borrowings under the committed lines of credit. PGE has a $200 million commercial paper facility. 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. PGE sells commercial paper to provide financing for various corporate purposes. As of December 31, 1998, commercial paper borrowings of $105 million have been classified as long-term debt based upon the availability of committed credit facilities with expiration dates exceeding one year and management's intent to maintain such amounts in excess of one year. Similarly, at December 31, 1998, $102 million of long-term debt due within one year is classified as long-term. Short-term borrowings and related interest rates were as follows: <TABLE> <CAPTION> 1998 1997 <S> <C> <C> AS OF YEAR-END: (millions of dollars) Aggregate short-term debt outstanding Commercial paper $105 $100 Weighted average interest rate* Commercial paper 5.2% 6.0% Committed lines of credit $200 $200 FOR THE YEAR ENDED: Average daily amounts of short-term debt outstanding Commercial paper $113 $ 89 Weighted daily average interest rate* Commercial paper 5.4% 5.6% Maximum amount outstanding during the year $144 $115 </TABLE> * 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. <TABLE> <CAPTION> 1998 1997 <S> <C> <C> Schedule of long-term debt at December 31 (millions of dollars) First Mortgage Bonds Maturing 1998 through 2003 5.65% - 8.88% $ 219 $ 241 Maturing 2004 - 2007 7.15% - 9.07% 113 153 Maturing 2021 - 2023 7.75% - 9.46% 170 170 502 564 Pollution Control Bonds Port of Morrow, Oregon, variable rate, due 2013 & 2031 (Average rate 3.5% for 1998) 6 29 Port of Morrow, Oregon, variable rate, due 2031 23 - & 2033 (4.60% fixed rate to 2033) City of Forsyth, Montana, variable rate, due - 119 2013 & 2016 Amount held by trustee - (8) City of Forsyth, Montana, variable rate, due 2033 (4.60% - 4.75% fixed rate to 2003) 119 - Port of St. Helens, Oregon, 4.80% - 7 1/8%, due 52 52 2010 & 200 192 Other 8.25% Junior Subordinated Deferrable Interest due December 31, 2035 75 75 6.91% Conservation Bonds maturing monthly to 68 73 2006 Capital lease obligations 1 4 Commercial Paper 105 100 249 252 Total long-term debt $ 951 $ 1,008 </TABLE> The following principal amounts of long-term debt (excluding Commercial Paper) become due through regular maturities (millions of dollars): <TABLE> <CAPTION> 1999 2000 2001 2002 2003 <S> <C> <C> <C> <C> <C> Maturities: PGE $102 $32 $53 $23 $49 </TABLE>
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 unwound these agreements. The estimated fair value of these agreements is based on the amount PGE would receive if the agreements were terminated. The estimated fair values of debt and equity instruments are as follows (millions of dollars): <TABLE> <CAPTION> 1998 1997 <S> <C> <C> <C> <C> Carrying Fair Carrying Fair Amount Value Amount Value Preferred stock subject to mandatory redemption $ 30 $ 35 $ 30 $ 34 Long-term debt $777 $822 $831 $861 Interest rate swaps in net receivable position $ - $ 1 $ - $ - </TABLE>
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 1999 through 2003 and $122 million over the remaining years of the contracts. PGE's capacity payments amounted to $16 million in 1998 and 1997, and $15 million in 1996. These contracts expire at varying dates from 2001 to 2015. PGE has the right to assign unused capacity to other parties. PURCHASE COMMITMENTS Purchase commitments outstanding, which include construction, coal, and railroad service agreements, totaled approximately $51 million at December 31, 1998. Cancellation of these purchase agreements could result in cancellation charges. FUEL CONTRACTS PGE has coal and transportation contracts with take-or-pay obligations totaling $7 million for 1999 and $1 million for 2000. Coal purchases under unconditional purchase obligations in 1998, 1997, and 1996 respectively, were $5 million, $2 million, and $3 million. 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): <TABLE> <CAPTION> ROCKY PRIEST PORTLAND REACH RAPIDS WANAPUM WELLS HYDRO <S> <C> <C> <C> <C> <C> Revenue bonds outstanding at December 31, 1998 $238 $ 171 $ 157 $173 $ 34 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: 1998 6 4 6 6 4 1997 7 3 4 6 4 1996 5 4 5 6 4 Contract expiration date 2011 2005 2009 2018 2017 </TABLE> PGE's share of debt service costs, excluding interest, will be approximately $5 million for 1999, $7 million for 2000 thru 2002, and $8 million for 2003. The minimum payments through the remainder of the contracts are estimated to total $70 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 $23 million in 1999, $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 1998, $23 million in 1997, and $28 million in 1996. LEASES PGE has operating and capital leasing arrangements for its headquarters complex, combustion turbines and the coal-handling facilities and certain railroad cars for Boardman. PGE's aggregate rental payments charged to
expense totaled $23 million in 1998, $24 million in 1997, and $22 million in 1996. PGE has capitalized its combustion turbine leases; however, these leases are considered operating leases for rate making purposes. Future minimum lease payments under non-cancelable leases are as follows (millions of dollars): <TABLE> <CAPTION> YEAR ENDING OPERATING LEASES DECEMBER 31 CAPITAL LEASES (NET OF SUBLEASE RENTALS) TOTAL <S> <C> <C> <C> 1999 $1 $ 21 $ 22 2000 - 22 22 2001 - 21 21 2002 - 11 11 2003 - 11 11 Remainder - 162 162 Total $1 $248 $249 Imputed Interest - Present Value of Minimum Future Net Lease Payments $1 </TABLE> Included in the future minimum operating lease payments schedule above is approximately $114 million for PGE's headquarters complex. The lease of combustion turbine generators at Bethel terminated at the end of 1998. In February 1999, PGE exercised its option to purchase the combustion turbine generators at Beaver for $37 million at the August 1999 termination of the lease. NOTE 8 - WNP-3 SETTLEMENT EXCHANGE AGREEMENT 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, 1998, PGE had the following investments in jointly owned generating plants (millions of dollars): <TABLE> <CAPTION> MW PGE % PLANT ACCUMULATED FACILITY LOCATION FUEL CAPACITY INTEREST IN SERVICE DEPRECIATION <S> <C> <C> <C> <C> <C> <C> Boardman Boardman, OR Coal 529 65.8 $380 $208 Colstrip 3&4 Colstrip, MT Coal 1,440 20.0 454 235 Centralia Centralia, WA Coal 1,310 2.5 10 6 </TABLE> 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 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 percent 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. If the Supreme Court declines to hear the case, it would be referred back to the OPUC. Due to uncertainties in the regulatory process, management cannot predict, with certainty, what ultimate rate making action the OPUC will take regarding PGE's recovery of a rate of return on its Trojan investment. 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. At December 31, 1998, PGE's after-tax Trojan plant investment was $170 Million. PGE is presently collecting annual revenues of approximately $21 million, representing the 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 will not have a material adverse impact on the financial position of the Company. However, it may have a material impact on the results of operations for future reporting periods. 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. Remaining transition costs associated with operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage in 1999 are estimated at $8 million and will be paid from current operating funds. 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 2002, 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 1998 dollars, the decommissioning cost estimate is $290 million. TROJAN DECOMMISSIONING LIABILITY (millions of dollars) Estimated - 12/31/94 $351 Updates filed with NRC - 11/16/95 7 Updates filed with OPUC - 12/01/97 (19) 339 Expenditures through 12/31/98 (73) Liability - 12/31/98 266 Transition costs 8 Total Trojan obligation $274 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 1998 to cover the costs of planning and licensing activities in support of the independent spent fuel storage installation and the reactor vessel and internals removal project. Decommissioning funds are invested primarily in investment-grade, tax-exempt and U.S. Treasury bonds. Year-end balances are valued at market. 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. DECOMMISSIONING TRUST ACTIVITY (Millions of dollars) 1998 1997 Beginnning Balance $84 $78 Activity Contributions 14 14 Gain 4 6 Disbursements (30) (14) Ending Balance $72 $84 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<cent> 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.
QUARTERLY COMPARISON FOR 1998 AND 1997 (UNAUDITED) <TABLE> <CAPTION> MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 TOTAL (MILLIONS OF DOLLARS) <S> <C> <C> <C> <C> <C> 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 1997 Operating revenues $368 $308 $391 $349 $ 1,416 Net operating income 65 46 46 51 208 Net income 48 28 15 35 126 Income available for common stock 47 28 14 35 124 </TABLE> ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS OF THE REGISTRANT (*) JAMES V. DERRICK, JR., age 54 Director since 1997 Mr. Derrick has served as Senior Vice President and General Counsel of Enron since June 1991. 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 47 Director since 1998 Ms. Fowler has served as President of Portland General Electric Company since 1997. Ms. Fowler 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 Lifewise, a Premera Health Plan Inc. KEN L. HARRISON, age 56 Director since 1987 Mr. Harrison serves as a Director and Vice Chairman of Enron and has served as Chairman and Chief Executive Officer of Portland General Electric Company since 1987. Mr. Harrison is also a Director of Enron Oil & Gas Company, Enron Communications Inc, and Rythyms Net Connections. JOSEPH M. HIRKO, age 42 Director since 1997 Mr. Hirko serves as Senior Vice President of Enron and also serves as President and Chief Executive Officer of Enron Communications. From 1991 to 1998 he served as Vice President-Finance, Chief Financial Officer, Chief Accounting Officer and Treasurer of Portland General Electric Company. KENNETH L. LAY, age 56 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, Enron Oil & Gas Company, EOTT Energy Corp. (the general partner of EOTT Energy Partners, L.P.) and Trust Company of the West. JEFFREY K. SKILLING, age 45 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 Capital & Trade Resources Corp. ("ECT"). From August 1990 until June 1995, Mr. Skilling served ECT in a variety of senior managerial positions. (*)Directors of PGE hold office until the next annual meeting of shareholders or until their respective successors are duly elected and qualified.
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW EXECUTIVE OFFICERS OF THE REGISTRANT (*) <TABLE> <CAPTION> NAME AGE BUSINESS EXPERIENCE <S> <C> <C> Ken L. Harrison 56 Appointed to current position of Chairman Chairman and Chief and Chief Executive Officer on December 1, Executive Officer 1988. Peggy Y. Fowler 47 Appointed to current position on June 24, President and Chief 1997. Served as Executive Vice President Operating Officer and Chief Operating Officer, PGE from November 1996 until appointed to current position. Served as Senior Vice President, Energy Services from September 1995 until November 1996. Served as Vice President, Distribution and Power Production from January 1990 to September 1995. Alvin L. Alexanderson 51 Appointed to current position on December Senior Vice President 12, 1995. Served as Vice President, General Counsel and Rates and Regulatory Affairs from Secretary February 1991 until appointed to current position. Frederick D. Miller 56 Appointed to current position on June 24, Senior Vice President 1997. Served as Senior Vice President, Public Policy and Public Affairs and Corporate Services Administrative Services from November 1996 until appointed to current position. Served as Director of Executive Department, State of Oregon, from 1987 until appointed to Vice President, Public Affairs and Corporate Services in October 1992. Walter E. Pollock 56 Appointed to current position on October Senior Vice President 14, 1997. Served as Vice President, Enron Power Supply Capital and Trade and 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. Served as Assistant Administrator at BPA, Office of Power Sales from January 1988 until March 1994. Arleen N. Barnett 46 Appointed to current position on February Vice President 1, 1998. Served as Manager, Human Human Resources Resources from 1989 until appointed to current position. David K. Carboneau 52 Appointed to current position in October Vice President 1998. Served as President of First Products and Services 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 49 Appointed to current position on July 1, Vice President 1997. Served as General Manager, System Delivery System Planning and Engineering until appointed to Planning and current position. Served as Manager, Engineering Response and Restoration from May 1993 until May 1995. Served as Manager, Western Region from August 1990 until May 1993.
EXECUTIVE OFFICERS OF THE REGISTRANT (*) - CONTINUED. NAME AGE BUSINESS EXPERIENCE Pamela G. Lesh 42 Appointed to current position on December Vice President 31, 1998. Served as Vice President, Rates and Regulatory Strategy and Product Management with Affairs ConneXt Corp. of Seattle since June 1997. Previously served at Portland General Electric as Vice President, Rates and Regulatory Affairs from November 1996 to June 1997. Served as Director of Marketing Strategy from May 1996 to June 1997. Served as Director of Rates and Regulatory Affairs from 1992 to 1996. Joe A. McArthur 51 Appointed to current position on July 1, Vice President 1997. Served as Manager of Western Substation and Line Region from May 1996 until appointed to Operations current position. Served as Manager, System Planning from May 1995 to May 1996. Served as Commercial and Industrial Market Manager from 1993 to 1995. Served as Substation Maintenance and Metering Manager from 1980 to 1993. James J. Piro 46 Appointed to current position on Vice President February 23, 1998. Served as General Business Development Manager, Planning Support and Analysis from November 1992 until appointed to current position. Stephen M. Quennoz 51 Appointed to current position in October, Vice President 1998. Joined PGE in 1991 and held the Nuclear and Thermal position of Trojan Site Executive and Operations Plant General Manager since 1993. Christopher D. Ryder 49 Appointed to current position on July 1, Vice President 1997. Served as General Manager, Customer Distribution and Services and Southern Region Operations from Customer Service 1996 until appointed to current position. Served as General Manager, Customer Services and Marketing from 1992 to 1996. Mary K. Turina 31 Appointed to current position on March Treasurer, Controller 10, 1999. Served as Controller, Chief and Chief Accounting Accounting Officer and Assistant Treasurer Officer until appointed to current position. Served as Manager of Risk Management, Reporting and Control from March 1996 to July 1998. Served as Senior Business Analyst from 1991 to 1996. </TABLE> (*) Officers are listed as of March 10, 1999; 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, 1998, 1997, 1996 by the Chief Executive Officer and the four most highly compensated executive officers of PGE. <TABLE> <CAPTION> Long-Term Annual Compensation Compensation All Other <S> <C> <C> <C> <C> <C> Salary Restricted Stock Compensation Name and Principal Position Year (1) Bonus Awards (2) (3) Ken L. Harrison (5) 1998 $206,799 $183,200 $ 705,483 $12,050 Chairman 1997 243,570 236,592 204,755 68,051 Chief Executive Officer 1996 399,510 252,193 251,410 40,480 Peggy Y. Fowler 1998 246,664 300,000 200,004 17,443 President, Chief Operating 1997 230,000 160,000 230,185 29,406 Officer 1996 202,504 106,379 150,500 24,045 Walter E. Pollock (4) 1998 176,191 140,000 75,037 5,664 Senior Vice President, 1997 37,500 24,000 0 826 Power Supply 1996 0 0 0 0 Frederick D. Miller 1998 181,684 150,000 68,760 10,233 Senior Vice President, Public 1997 175,020 105,000 0 48,906 Policy and Administrative 1996 161,259 73,811 75,250 36,400 Services James J. Piro 1998 157,535 128,063 50,043 5,081 Vice President, Business 1997 131,352 140,000 0 7,743 Development 1996 104,304 36,226 0 6,210 </TABLE> (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) Restricted stock awards are valued at the closing price of $41.4375 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 awards are valued at the closing price of $37.625 per share of PGC common stock for the September 10, 1996 grant, which converted to Enron shares on the effective date of the merger. Dividends on this grant are paid as declared. Restricted stock awarded to Mr. Harrison on October 12, 1998, is valued at the $50.9375 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 $57.0625 per share closing price of Enron common stock on that date. Aggregate restricted stock holdings listed below are valued at $57.0625 per share, the closing price of the Enron common stock on December 31, 1998. AGGREGATE RESTRICTED STOCK HOLDINGS AGGREGATE SHARES (#) VALUE Ken L. Harrison 58,743 $3,352,022 Peggy Y. Fowler 11,879 677,845 Walter E. Pollock 1,315 75,037 Frederick D. Miller 3,170 180,888 James J. Piro 877 50,044
(3) 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 1998: <TABLE> <CAPTION> Split Dollar Dollar Value of Contributions to Above Market Insurance Premiums Life Insurance 401 (k) and MDCP Interest on MDCP Total <S> <C> <C> <C> <C> <C> Ken L. Harrison $ 403 $1,130 $ 4,103 $ 6,414 $12,050 Peggy Y. Fowler 450 7,430 8,109 1,454 17,443 Walter E. Pollock 0 0 5,331 333 5,664 Frederick D. Miller 610 0 6,885 2,738 10,233 James J. Piro 0 0 4,859 222 5,081 </TABLE> (4) Mr. Pollock was hired November 1, 1996, and was not a PGE employee until October, 1997. (5) Mr. Harrison also serves as an executive officer of Enron. The compensation shown represents the amount allocated to PGE. The following lists information concerning options to purchase shares of Enron common stock that were granted to PGE's five highest paid officers during 1998. No stock appreciation rights were granted during 1998. OPTIONS/SAR GRANTS IN LAST FISCAL YEAR <TABLE> <CAPTION> Number of Securities % of Total Potential Realized Value Underlying Options/ at Assumed Annual Rates of Options/ SARs Granted to Exercise or Stock Price Appreciation for SARs{(1)} Employees in Base Price Expiration Option Term Name Granted Fiscal Year ($/SH) Date 5% 10% <S> <C> <C> <C> <C> <C> <C> Ken L. Harrison 14,320{(2)} 0.18% $40.1250 01/19/05 $ 233,916 $ 545,123 140,285{(3)} 1.80% 50.9375 10/12/08 4,493,935 11,388,513 117,925{(4)} 1.50% 50.9375 10/12/08 3,777,647 9,573,300 Peggy Y. Fowler 15,210{(5)} 0.19% 57.0625 12/31/05 353,331 823,411 Walter E. Pollock 5,705{(5)} 0.07% 57.0625 12/31/05 132,528 308,847 James J. Piro 3,805{(5)} 0.05% 57.0625 12/31/05 88,391 205,988 Frederick D. Miller 5,230{(5)} 0.07% 57.0625 12/31/05 121,494 283,132 </TABLE>
(1) If a "Change of Control" (as defined in the Enron 1991 Stock Plan) were to occur before the options became exercisable and are exercised, the vesting described below will be accelerated and all such outstanding options shall be surrendered and the optionee shall receive a cash payment by Enron in an amount equal to the value of the surrendered options (as defined in the 1991 Stock Plan). (2) Represents stock options awarded January 19, 1998 which were fully vested on the date of grant. (3) Represents stock options awarded on October 12, 1998, which vested 25% at grant and 25% each on June 30 thereafter. (4) Represents stock options awarded on October 12, 1998, which cliff vest 100% on the 5th anniversary date of the grant. (5) Represents stock options awarded under the Long-Term Incentive Program for 1999. Stock options awarded on December 31, 1998 became 25% vested on the date of grant with an additional 25% vested on the anniversary of the date of grant until 100% vested December 31, 2001. The following lists information concerning options to purchase shares of Enron common stock that were exercised by the officers named above during 1998, and the total options and their value held by each at December 31, 1998. Aggregate Stock Options/SAR Exercised During 1998 AND STOCK OPTIONS/SAR VALUES AT DECEMBER 31, 1998 <TABLE> <CAPTION> Shares Acquired Value Exercisable Unexercisable Exercisable Unexercisable NAME ON EXERCISE REALIZED SHARES SHARES AMOUNT AMOUNT <S> <C> <C> <C> <C> <C> <C> Ken L. Harrison 20,900 $788,338 190,202 320,093 $4,611,889 $2,878,513 Peggy Y. Fowler 18,137 221,786 5,855 34,733 31,806 363,428 Walter E. Pollock 0 0 4,186 28,424 42,780 325,950 Frederick D. Miller 7,000 115,500 9,175 20,385 122,626 256,739 James J. Piro 0 0 27,170 21,037 684,680 343,097 </TABLE> LONG-TERM INCENTIVE PLAN - AWARDS IN 1998 The following table provides information concerning awards of performance units under the Performance Unit Plan of Enron for the 1998 - 2001 performance period. Grants are made at the beginning of each fiscal year and each unit is assigned a value of $1.00. The units are subject to a four-year performance period, at the end of which Enron's total shareholder return is compared to that of the 11 peer companies included in the Current Peer Group. At that time, the units are assigned a value ranging from $0 to $2.00 based on the rank of Enron's shareholder return within the Current Peer Group. To be valued at the maximum of $2.00, Enron must rank first, and to be valued at the target of $1.00, Enron must rank third. Regardless of Enron's rank, Enron's shareholder return must be above the return on 90-day U.S. Treasury Bills over the same performance period in order for any value to be assigned. <TABLE> <CAPTION> Number Performance of Shares or Other Estimated Future Payouts Units or Period Unit UNDER NON-STOCK PRICE-BASED PLANS Other Maturation Threshold Target Maximum NAME RIGHTS (#) PAYOUT ($) ($) ($) <S> <C> <C> <C> <C> <C> Ken L. Harrison 325,000 4 years 0 $325,000 $650,000 Peggy Y. Fowler 100,000 4 years 0 100,000 200,000 Walter E. Pollock 50,000 4 years 0 50,000 100,000 Frederick D. Miller 37,500 4 years 0 37,500 75,000 </TABLE>
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. <TABLE> <CAPTION> Pension Plan Table Estimated Annual Retirement Benefit Straight-Life Annuity, Age 65 <S> <C> <C> <C> Years of Service Final Average 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 </TABLE> 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, 23; Peggy Y. Fowler, 24; Frederick D. Miller, 6. 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 Mr. Harrison entered into a new employment agreement effective July 1, 1998, which superseded his July 20, 1996, employment agreement. The new agreement extends from the effective date through June 30, 2002, and provides for the following: 1. A base pay of not less than $550,000. 2. Participation in the Enron Annual Incentive Plan.
3. A grant of 300,000 options under the Enron Communications, Inc. 1998 Stock Option Plan effective January 1, 1998, at a purchase price of one dollar ($1.00) per share that will vest 25% on the first anniversary of the date of grant and an additional 6.25% for each completed three month period. 4. A grant of 140,285 options under the Enron 1991 Stock Plan that will vest 25% at grant and 25% on each June 30 of 1999, 2000 and 2001. 5. A grant of 12,800 shares of restricted stock under the Enron 1991 Stock Plan that will vest 33 1/3 % each January 31 of 1999, 2000 and 2001. 6. Eligibility for $2.5 million long term value over a four year term as follows: i. 50% of such value to be delivered in a 25,000 share performance based restricted stock grant with 33.3% vesting conditioned on meeting Enron after tax net income and/or cash flow targets for 1999, 2000 and 2001. Targets are cumulative over the three year period beginning with 1999 so that missed vesting due to missed targets can vest on a cumulative basis if the cumulative performance target is met. ii. 50% of such value to be delivered in a 117,925 share Enron stock option grant with full 100% cliff vesting on 10/12/03, provided that the grant of options may accelerate vesting in 33.3% increments on each of 1/31/00, 1/31/01 and 1/31/02 conditioned on meeting Enron; performance targets to be established for 1999, 2000 and 2001. Additionally, following termination of Mr. Harrison's employment for any reason, he will receive the aggregate benefits he would have received pursuant to the Pension Plan and the SERP, as in effect on the effective date of his employment agreement, as if he had retired on the effective date of his employment agreement having attained the "unreduced benefit date" (as defined in the SERP), and 25 years of service and as if his "final average earnings" (as defined in the SERP) had equaled $1,050,000. In partial consideration of rescinding Mr. Harrison's previous agreement and executing his new employment agreement effective July 1, 1998, Enron is obligated to pay Mr. Harrison the lessor of $2,835,000 or 2.99 times his base amount, accruing the later of June 30, 2002, or the date Mr. Harrison ceases to be employed by a participating employer in the Management Deferred Compensation Plan. 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 will have 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 agreement provides for the grant of 25,000 options to purchase shares of Enron Common Stock while Ms. Fowler's provides for 30,000 options; (v) Ms. 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 (x) each agreement includes a noncompetition covenant. Mr. Pollock entered into an employment agreement effective November 1, 1996. The agreement extends 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 20,000 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 will vest 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 extends two years from the date of the merger between PGC and Enron and provides 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. COMPENSATIONS OF DIRECTORS There are no compensation arrangements for or fees paid to Directors of PGE. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION None
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, 1998 Consolidated Statements of Retained Earnings for each of the three years in the period ended December 31, 1998 Consolidated Balance Sheets at December 31, 1998 and 1997 Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 1998 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 19, 1999 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. Chairman and /S/ KEN L. HARRISON Chief Executive Officer March 19, 1999 Ken L. Harrison Treasurer, Controller and Chief Accounting Officer /S/ MARY K. TURINA (Principal financial officer March 19, 1999 Mary K. Turina and principal accounting officer) *James V. Derrick *Peggy Y. Fowler *Ken L. Harrison *Joseph M. Hirko Directors March 19, 1999 *Kenneth L. Lay *Jeffrey K. Skilling *By /S/ MARY K. TURINA (Mary K. Turina, Attorney-in-Fact)
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 19, 1999 By 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. Chairman and Chief Executive Officer March 19, 1999 Ken L. Harrison Treasurer, Controller and Chief Accounting Officer (Principal financial officer March 19, 1999 Mary K. Turina and principal accounting officer) *James V. Derrick *Peggy Y. Fowler *Ken L. Harrison *Joseph M. Hirko Directors March 19, 1999 *Kenneth L. Lay *Jeffrey K. Skilling *By (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)]. * Form of Articles of Amendment of the New Preferred Stock of Portland General Electric Company [Registration No. 33-21257, Exhibit (4)]. * 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,(Filed herewith). (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-Fourth Supplemental Indenture dated August 1, 1994 [Form 10-Q for the quarter ended September 30, 1994, 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 NUMBER EXHIBIT (4) * Forty-Sixth Supplemental Indenture dated August 1, 1996 [Form CONT 10-K for the fiscal year ended December 31, 1997, Exhibit (4)]. 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 for the 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)]. * Tax Indemnification 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) * Trust Indenture, Mortgage and Security Agreement, dated CONT 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). * Incorporated by reference as indicated. Note: Although the Exhibits furnished to the Securities and Exchange Commission with the Form 10-K have been omitted herein, they will be supplied upon written request and payment of a reasonable fee for reproduction costs. Requests should be sent to: Mary K Turina Treasurer, Controller, and Chief Accounting Officer Portland General Electric Company 121 SW Salmon Street Portland, OR 97204