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, 2000

   

OR

[   ]

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Transition period from ________________ to _______________

     

Commission File Number 1-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Oregon

(State or other jurisdiction of incorporation or organization)

93-0256820

(I.R.S. Employer Identification No.)

 

121 SW Salmon Street, Portland, Oregon 97204

(Address of principal executive offices) (zip code)

 

Registran's telephone number, including area code: (503) 464-8000

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange 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, 2001: $0.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 28, 2001: 42,758,877 shares of common stock, $3.75 par value. (All shares are owned by Enron Corp.)

 

DEFINITIONS

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

 

Abbreviations
or Acronyms Term
Beaver                     Beaver Combustion Turbine Plant
Boardman                     Boardman Coal Plant
BPA                     Bonneville Power Administration
CPUD                     Clatskanie Public Utility District
CRPUD                     Columbia River People's Utility District
Colstrip                     Colstrip Units 3 and 4 Coal Plant
Coyote Springs Unit 1                     Coyote Springs Unit 1 Generation Plant
CUB                     Citizens' Utility Board
DEQ                     Oregon Department of Environmental Quality
Enron                     Enron Corp.
EFSC                     Energy Facility Siting Council
EITF                     Emerging Issues Task Force
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
SCE                     Southern California Edison
SFAS                     Statement of Financial Accounting Standards issued by the FASB
Sierra                     Sierra Pacific Resources
Trojan                     Trojan Nuclear Plant
URP                     Utility Reform Project
USDOE                     United States Department of Energy
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

Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

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 7A. Quantitative and Qualitative Disclosures About

Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Item 9. Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  56

PART III

Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

 

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 3,150 square miles, including 51 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 2000 its service area population was approximately 1.5 million, comprising about 44% of the state's population. The Company added approximately 6,000 customers during the year, with the addition of about 13,150 new customers partially offset by the loss of about 7,150 customers who were transferred to two public utility districts upon the sale of a portion of PGE's service territory. At December 31, 2000, PGE served approximately 725,000 customers.

On July 1, 1997, Portland General Corporation (PGC), the former parent of PGE, merged with Enron Corp. (Enron) with Enron continuing in existence as the surviving corporation and PGE operating as a wholly owned subsidiary subject to control by Enron.

On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion. The closing has been delayed by the effect of recent events in California and Nevada on the buyer.

As of December 31, 2000, PGE had 2,781 employees. This compares to 2,787 and 2,728 employees at December 31, 1999 and 1998, respectively. Currently, 996 employees are covered under a three-year agreement with Local Union No. 125 of the International Brotherhood of Electrical Workers that is effective from March 1, 1998 through March 1, 2001. Negotiations on a new agreement between the Company and the Union, which began in early January 2001, are continuing. 

Operating Revenues

Retail

PGE serves a diverse retail customer base. Residential customers constitute the largest customer class and account for approximately 43% of total retail revenues, with commercial and industrial customers accounting for 37% and 20%, respectively. Residential demand is highly sensitive to the effects of weather, with company revenues highest during the winter heating season. Electricity sales increased somewhat from 1999 due to a rebound in the manufacturing sector. The commercial and industrial classes are not dominated by any single industry. While the 20 largest customers constitute about 21% of retail demand, they represent 8 different industrial groups, including paper manufacturing, high technology, metal fabrication, general merchandising and health services. No single customer represents more than 3.5% of PGE's total retail load. 

Wholesale

Wholesale electricity sales comprised about 52% of total operating revenues in 2000, up from about 26% in 1999. Most of PGE's wholesale sales have been to utilities and power marketers and have been predominantly short-term. PGE will continue its participation in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such participation includes power purchases and sales resulting from daily economic dispatch decisions for its own generation; this allows PGE to secure power for its customers at the lowest cost available.

The following table summarizes operating revenues and MWh sales for the years ended December 31: 

 

   

2000

1999

1998

Operating Revenues (Millions)

     
 

Residential

$ 448

$ 438

$ 432

 

Commercial (1)

388

367

345

 

Industrial

  208

  173

  132

   

Tariff Revenues

1,044

978

909

   

Accrued (Collected) Revenues

    14

    26

    (8)

 

Retail

1,058

1,004

901

 

Wholesale

1,171

355

234

 

Other

    24

    19

    41

   

Total Operating Revenues

 $ 2,253

$ 1,378

$ 1,176

Megawatt-Hours Sold (Thousands)

     
 

Residential

7,433

7,404

7,101

 

Commercial (1)

7,527

7,392

6,781

 

Industrial

4,912

4,463

3,562

   

Retail

19,872

19,259

17,444

   

Wholesale

18,548

12,612

10,869

     

Total MWh Sold

38,420

31,871

28,313

Energy Delivered to ESP Customers (2)

        -

        -

1,292

Total MWh Sold and Delivered

38,420

31,871

29,605

(1) Includes public street lighting.

(2) Represents energy delivered to customers of Energy Service Providers (ESPs) under PGE's Customer Choice pilot program.

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

Regulation

PGE is subject to the jurisdiction of the OPUC, comprised of three members appointed by Oregon's governor to serve non-concurrent four-year terms. The Commission approves the Company's retail rates and establishes conditions of utility service. The Commission further ensures that prices are fair and equitable and provides PGE an opportunity to earn a fair return on its investment. In addition, the Commission regulates the issuance of securities and prescribes the system of accounts to be kept by Oregon utilities.

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

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

The NRC regulates the licensing and decommissioning of nuclear power plants. In 1993, the NRC issued a possession-only license amendment to PGE's Trojan operating license and in early 1996 approved the Trojan Decommissioning Plan. Approval of the Trojan Decommissioning Plan by the NRC and EFSC has allowed PGE to begin decommissioning activities, which are proceeding satisfactorily and within approved cost estimates. Trojan is subject to NRC regulation until it is fully decommissioned, all nuclear fuel is removed from the site, and the license terminated. In February 2001, the NRC approved PGE's License Termination Plan, which outlines the Company's plans to decommission the Trojan site and meet regulatory requirements for decommissioned nuclear facilities. The Oregon Department of Energy also monitors Trojan. (For further information, see"Nuclear Decommissioning" in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations"). 

Regulatory Matters

Electric Power Industry Restructuring

In 1999, Oregon's governor signed into law State Senate Bill 1149 (SB1149) that provides all industrial and commercial customers of investor-owned utilities direct access to competing energy suppliers no later than October 1, 2001. Residential customers will be able to purchase electricity from a "portfolio" of rate options that will include a cost-of-service rate, a new renewable resource rate, and a market-based rate. (For further information, see "Regulation and Competition" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). 

Power Cost Mechanism

In January 2001, the OPUC staff and PGE filed applications with the Commission for deferral of a portion of PGE's excess net variable power costs for 2001. PGE's application requests authorization to defer for later ratemaking treatment changes in net variable power costs, positive or negative, which differ from such costs approved by the Commission in the Company's last general rate case. This application and filing replaces a November 20, 2000 filing by PGE that sought a 16.5% average increase in electricity prices, effective January 1, 2001. This filing was withdrawn on December 22, 2000. On February 8, 2001, PGE stipulated to a power cost mechanism with OPUC staff and other parties that shares with retail customers any changes in PGE's power costs outside of a pre-determined range for the period January through September 2001. Such costs will be shared equally within certain limits, with 90% of costs in excess of such limits charged or credited to retail customers. On February 20, 2001, the OPUC consolidated the two applications and authorized PGE to defer, for future ratemaking treatment, any changes from a net variable power cost baseline amount of $176 million (for nine months). In a subsequent proceeding, PGE will request the recovery (or refund) of a portion of the deferred amount in accordance with the formula agreed to with OPUC staff on February 8, 2001. PGE's earnings for the nine month period will only reflect the expected recovery amount.

Resource Plan

Under OPUC rules implementing Oregon's electric industry restructuring law, electric companies are required to file a Resource Plan proposing a disposition of their existing generating resources. Such disposition must facilitate a fully competitive market, provide consumers fair, non-discriminatory access to competitive markets, and retain the benefit of low-cost resources for customers.

On November 1, 2000, PGE filed with the OPUC its Resource Plan. Under the plan, PGE proposes to retain almost all of its resources, selling only its 20% share of Colstrip Units 3 and 4 in Montana. The plan also proposes that PGE's Coyote Springs Unit 1 combustion turbine generating plant be administratively valued and reclassified as an unregulated asset, with the Company retaining full ownership of the plant with the ability to sell its power within the western grid. All other generating resources would remain regulated, matching their output to the needs of PGE residential and small business customers. Following the Commission's review and public hearings, a decision by the OPUC on the Company's Resource Plan is anticipated by September 1, 2001.

Energy Efficiency

PGE has long promoted the efficient use of electricity. Current Demand Side Management (DSM) programs provide a range of services to all customer classes and seek to maximize those opportunities in which efficiency measures are most cost-effective. To accomplish this, the Company focuses on both commercial and industrial new construction and retrofitting, industrial process improvements, and residential weatherization measures, including a program for low-income families. In 2000, more than 36,000 residential customers utilized PGE's energy efficiency services, with total savings for industrial, commercial, and residential customers estimated at 6.2 megawatts for the year. 

RTO West and Proposed Independent Transmission Company

In a continued effort to more efficiently manage transmission, create fair pricing policies, and encourage competition, the FERC in late 1999 issued an Order that requires all owners of electricity transmission facilities to file plans for the formation of Regional Transmission Organizations (RTOs), to be implemented by December 15, 2001. (For further information, see "RTO West and Proposed Independent Transmission Company" in Item 7.  "Management's Discussion and Analysis of Financial Condition and Results of Operations"). 

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. PGE will continue its efforts to bring competitive market conditions to the industry, working closely with customers and regulators to achieve the state's policy goals. The outcome of these efforts to help create a more competitive electricity market will depend in large part on both statutory and regulatory changes. 

Retail Competition and Marketing

PGE operates within a state-approved service area and under current regulation is substantially free from direct retail competition with other electric utilities. PGE's competitors within its Oregon service territory include other fuel suppliers, such as the local natural gas company, which compete with PGE for the residential and commercial space and water heating market. In addition, there is the potential for the loss of PGE service territory from the creation of public utility districts or municipal utilities by voters.

In August 2000, following voter-approved condemnation and a settlement, PGE sold its service territory in four Columbia County cities to the Columbia River People's Utility District (CRPUD) and the Clatskanie Public Utility District (CPUD). After receiving approval from the OPUC, approximately 7,150 PGE customers were transferred to the two utility districts.

An initiative petition was filed in February 2000 by a local political committee, which is attempting to amend the charter of the City of Portland to require the city's acquisition of privately owned electricity distribution systems and facilities within its boundaries under certain circumstances. The petition further provides that costs to purchase, condemn, or otherwise acquire such facilities be paid from the issuance of revenue bonds. If sufficient signatures are obtained (approximately 21,000), the proposed amendment would appear on the May 2002 ballot.

On March 20, 2000, PGE filed a complaint with the Multnomah County Circuit Court, asking the court to enjoin the city auditor from certifying the petition as a ballot measure on the grounds that the proposed amendment is unconstitutional under Oregon law. On October 30, 2000, the Court ruled against PGE in this matter. The Company has filed an appeal of this decision with the Oregon Court of Appeals. 

Wholesale Competition and Marketing

Competition has transformed the electric utility industry at the wholesale level. The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers, and provided a framework for increased competition in the electric industry.  In 1996, the FERC issued Order 888, which requires non-discriminatory open access transmission by all public utilities that own interstate transmission; it also requires that investor-owned utilities allow others access to their transmission systems for wholesale power sales. Such access must be provided at the same price and terms the utilities would apply to their own wholesale customers. It also requires reciprocity from municipals, cooperatives, and federal power marketers receiving service under the tariff and allows public utilities to recover stranded costs in accordance with the terms, conditions and procedures set forth in the order.

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

The decreasing surplus of electric generating capability in the western United States, the entrance of numerous wholesale marketers and brokers into the market, and open access transmission are contributing to increasing competitive pressure on the price of power. In addition, the development of financial markets, including the NYMEX electricity contract, has led to enhanced price discovery available for market participants, further adding to the pressure on wholesale prices and margins. 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, administer its current long-term wholesale contracts, and to engage in limited trading activities. 

Power Supply

Growth within PGE's service territory has underscored the Company's need for sources of reliable, low-cost energy supplies. Retail energy demand has grown at an average annual rate of approximately 2.5% over the last 10 years and is expected to continue this upward trend. To meet its energy needs, PGE has relied increasingly upon short-term purchases to supplement its existing base of generating resources and long-term power contracts. Short-term purchases include both secondary as well as firm purchases for periods up to one year in duration. The availability of short-term firm purchase agreements and PGE's ability to renew these contracts have enabled PGE to minimize risk and enhance its ability to provide reliable low-cost energy to retail customers; however, increased competition has placed pressure on both the price and availability of short-term power. Northwest hydro conditions also have a significant impact on regional power supply, with water conditions a significant factor in the ability of the Company to economically displace more expensive thermal generation and power purchases. 

Generating Capability

PGE's existing hydroelectric, coal-fired, and gas-fired plants are important resources for the Company, providing 1,998 MW of generating capability (see Item 2. Properties, for a full listing of PGE's generating facilities). PGE's lowest-cost producers are its eight hydroelectric projects on the Clackamas, Sandy, Deschutes, and Willamette rivers in Oregon. These facilities operate under federal licenses, which will be up for renewal between the years 2001 and 2006. For further discussion of hydroelectric project relicensing, see "Hydro Relicensing" in Item 7.- Management's Discussion and Analysis of Financial Condition and Results of Operations.

During 2000, PGE resolved many of the outstanding issues associated with the relicensing of its 408-MW Pelton Round Butte Project on the Deschutes River, which provides about 20% of the Company's power-generating capacity. In April 2000, PGE executed an agreement with the Confederated Tribes of Warm Springs (Tribes) that would result in shared ownership and control; PGE would continue to operate the project. Under terms of this agreement, the Tribes will acquire an increasing share of the project starting in January 2002, when it will purchase a one-third interest at the net depreciated book value on December 31, 2001. The settlement, which was approved by the OPUC in August 2000, will replace the fees PGE had been paying the Tribes for the inundation of their property along the Deschutes and Metolius River. PGE and the Tribes completed the draft of their joint 50-year license application in 2000, and anticipate filing the final application with the FERC in the spring of 2001.

In July 2000, PGE sold its rights to build a combined cycle gas turbine power plant adjacent to its Coyote Springs Unit 1  plant, along with 50% of its interest in the plants' common facilities, to Avista Corp., which plans to build a 280-MW combined cycle gas turbine power plant on the site. The new Coyote Springs Unit 2 plant, scheduled for completion in June 2002, will be owned by Avista Power LLC and operated by PGE under a 15-year operations and maintenance contract.

PGE's current license on its 22-MW Bull Run Hydroelectric Project, which expires in November 2004, will not be renewed; a "Notice of Intent Not to File Application for New License" was filed with the FERC in November 1999. This decision was based upon projected costs associated with required environmental measures necessary to protect several runs of endangered salmon. The Bull Run Project is expected to operate until the end of its existing license, during which time decisions will be made, in coordination with state and federal agencies, regarding the project's removal from the Sandy and Little Sandy Rivers.

Under PGE's Resource Plan, filed in November 2000 with the OPUC, the Company proposes to retain the remainder of its resources, selling only its 20% share of Colstrip Units 3 and 4 in Montana (a previous proposal to sell such interest was denied in early 2000 by the Commission). The plan also proposes that PGE's Coyote Springs Unit 1 plant be administratively valued and reclassified as an unregulated asset, with the Company retaining full ownership of the plant with the ability to sell its power within the western grid. 

Purchased Power

As PGE's existing base of generating resources is reduced, the Company will continue to negotiate long-term and short-term contracts to meet its retail load requirements. Under the provisions of recent state legislation (SB1149) allowing large industrial and commercial customers direct access to competing energy suppliers, PGE will be obligated to serve only residential and small commercial customers beginning October 1, 2001.

PGE has long-term power contracts with four hydro projects on the mid-Columbia River, which provide approximately 650 MW of firm capacity. PGE also has firm contracts, ranging in term from one to thirty years, to purchase 369 MW of power, 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 the Company 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. Organized in 1967, it provides coordination for operating and planning a reliable and adequate electric power system for the western part of the continental United States, Canada, and Mexico. It provides the forum for its member systems to enhance communication, coordination, and cooperation in planing and operating a reliable interconnected electric system. During the last few years, the area covered by WSCC has become a dynamic marketplace for the trading of electricity. This area, which extends from Canada to Mexico and includes 14 Western states, has great diversity in climates and peak loads occur at different times of the year in the different regions within the WSCC area. Energy loads in the Southwest peak in summer due to air conditioning; northern loads peak during winter heating months. According to WSCC forecasts, the nearly 115 electric organizations participating in the WSCC, which include utilities, independent power producers and transmission utilities, have sufficient capacity margin to meet forecast demand and energy requirements through the year 2010. Such projection assumes both the timely completion of approximately 30,200 MW of net new generation and average weather conditions over this ten-year period.

During 2000, PGE's peak load was 3,695 MW, of which 36% was met through short-term purchases. PGE's firm resource capacity, including short-term purchase and sale agreements, totaled approximately 3,923 MW as of December 31, 2000. 

Restoration of Salmon Runs

Populations of many salmon species in the Pacific Northwest have shown significant decline over the last several decades. A significant number of these species have either been granted or are being evaluated for protection under the federal Endangered Species Act (ESA). While long term recovery plans for these species may include major operational changes to the region's hydroelectric projects, including PGE's, the impacts to date have been minimal. The biggest change has been modifying the timing of releases of water stored behind the dams in the upper part of the Columbia and Snake River basins.

A low snow pack in the Columbia Basin, combined with the federal power system's increased sale of electricity to California during the recent energy shortage, has created a potential shortage of hydroelectric power in 2001. If the snow pack remains low, there is an increasing likelihood that some of the large storage reservoirs in the federal system will not be refilled this spring. This would reduce the amount of hydroelectric energy available to the region late in the year, the impact of which will be determined based upon the forecasted runoff calculated in the spring.

PGE continues to evaluate the impact of current and potential listings on the operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette Rivers. PGE's hydroelectric relicensing efforts, in combination with endangered species consultations with the National Marine Fisheries Service (NMFS) and the United States Fish and Wildlife Service (USFWS), address issues associated with protecting runs of fish found in the rivers where PGE operates projects. Although the Company does not anticipate significant near-term operational changes to its hydroelectric projects, future recommendations that result in significant operational changes are possible. This would occur after the relicensing process on the hydroelectric projects is completed. FERC is required to consult with NMFS and USFWS before granting new operating licenses if endangered species are present. 

Fuel Supply

Fuel supply contracts are negotiated to support annual planned plant operations. Flexibility in contract terms is sought to allow for the most economic dispatch of PGE's thermal resources in conjunction with the current market price of wholesale power. 

Coal 

Boardman

PGE has agreements to purchase coal for Boardman that cover requirements through the year 2001. Ample supplies exist to fuel Boardman's requirements in future years. Coal purchases in 2000, totaling about 2 million tons, contained approximately 0.4% of sulfur by weight and emitted less than the EPA allowable limit of 1.2 pounds of sulfur dioxide per MMBtu when burned. The coal, from surface mining operations in Wyoming and Utah, was subject to federal, state and local regulations. Coal is delivered to Boardman, Oregon by rail under contracts with the Burlington Northern Santa Fe and Union Pacific Railroads. 

Colstrip

Coal for Colstrip Units 3 and 4, located in southeastern Montana, is provided under contract with Western Energy Company, a wholly owned subsidiary of Montana Power Company. The contract provides that the coal delivered will not exceed a maximum sulfur content of 1.5% by weight. The Colstrip plant has sulfur dioxide removal equipment to allow operation in compliance with EPA's source-performance emission standards.

   

Type of Pollution

Plant

Sulfur Content

Control Equipment

Boardman

0.4%

Electrostatic precipitators

Colstrip

0.7%

Wet Scrubbers

Natural Gas 

In addition to the agreements discussed below, the Company utilizes short-term and spot market purchases to secure transportation capacity and natural gas supplies sufficient to fuel plant operations. PGE remarkets any natural gas and transportation capacity that are in excess of its needs. 

Beaver

PGE owns 79% of the Kelso-Beaver Pipeline, which directly connects its Beaver generating station to Northwest Pipeline, an interstate gas pipeline operating between British Columbia and New Mexico. During 2000, 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 Unit 1 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 Unit 1, based on anticipated operation of the plant, are purchased at market-based prices up to two years prior to delivery. PGE believes that sufficient gas is available in the marketplace to meet the full fuel requirements of the plant. 

Environmental Matters

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

Regulation

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

Harborton

A 1997 investigation of a portion of the Willamette River known as the Portland Harbor, conducted by the U.S. Environmental Protection Agency (EPA), revealed significant contamination of sediments within the harbor. Subsequently, the EPA has included Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund").

The Oregon Department of Environmental Quality (DEQ) asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, the Company voluntarily completed on site testing and submitted a work plan for DEQ review and approval. Investigations of the site by PGE have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site. Remedial activities, if any, that PGE may ultimately perform with respect to this matter will depend on the results of further investigations. 

Air/Water Quality

PGE's operations, principally its fossil-fuel electric generation plants, are subject to the federal Clean Air Act (Act) and other federal regulatory requirements. State governments are also charged with monitoring and administering certain portions of the Act and are required to set guidelines that at least equal federal standards. Oregon has air quality standards that are more stringent than federal standards. The air pollutants addressed under the Act that primarily affect PGE are sulfur dioxide ("SO2"), nitrogen oxides ("NOx"), and particulate matter. PGE manages its emissions through burning low sulfur fuel, emission controls, emission monitoring, and good combustion controls.

The SO2 emission allowances awarded under the Act, and those allowances expected to be awarded annually in the future, are sufficient to operate Boardman at a 60% to 67% capacity factor without having to further reduce emissions. In addition, the number of emission allowances are sufficient to operate Colstrip, which utilizes wet scrubbers. If necessary, PGE intends to acquire a relatively small number of additional allowances in order to meet excess capacity needs. It is not yet known what impacts federal regulations on mercury transport, regional haze, or PM2.5 standards may have on future plant operations, operating costs, or generating capacity.

Federal operating air permits, issued by the DEQ, have been obtained for all of PGE's fossil fuel generating facilities, including its combustion turbine plants, and renewal applications have been filed with the DEQ for four water quality permits.

Item 2. Properties

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

 

OREGON

 

Generating facilities owned by PGE are set forth in the following table: 

 

 

 

Facility

 

 

Location

 

 

Fuel

PGE Net

MW

Capability

 

Wholly Owned:

Faraday

Clackamas River

Hydro

44

North Fork

Clackamas River

Hydro

54

Oak Grove

Clackamas River

Hydro

44

River Mill

Clackamas River

Hydro

25

Pelton

Deschutes River

Hydro

108

Round Butte

Deschutes River

Hydro

300

Bull Run

Sandy River

Hydro

22

Sullivan

Willamette River

Hydro

16

Beaver

Clatskanie, OR

Gas/Oil

500

Coyote Springs

Boardman, OR

Gas/Oil

242

 

Jointly Owned:

     

PGE 

Interest

Boardman

Boardman, OR

Coal

362

65.0%

Colstrip 3 & 4

Colstrip, MT

Coal

296

20.0%

Total

2,013

PGE holds licenses under the Federal Power Act for its hydroelectric generating plants, as well as licenses from the State of Oregon for all or portions of five of the plants. All of its licenses expire during the years 2001 to 2006. The FERC requires that a notice of intent to relicense these projects be filed approximately five years prior to expiration of the license.

PGE filed for relicensing of the Pelton Round Butte Project in December 1998. On April 12, 2000, the Confederated Tribes of Warm Springs (Tribes), the U.S. Department of the Interior, and PGE signed a settlement agreement that will result in shared ownership and control of the Project over a proposed 50-year license period. PGE would remain as the operator of the Project.

PGE's current license on its 22-MW Bull Run Hydroelectric Project, which expires in November 2004 will not be renewed; a "Notice of Intent Not to File Application for New License" was filed with the FERC in November 1999. PGE is actively pursuing the renewal of all other licenses for its hydroelectric generating plants. For further information see "Hydro Relicensing" in Item 7.- Management's Discussion and Analysis of Financial Condition and Results of Operations.

The generating capability of Boardman increased 14 MW in 2000 due to the upgrade of the plant's turbine generator.

Following the 1993 Trojan closure, PGE was granted a possession-only license amendment by the NRC. In early 1996, PGE received NRC approval of its Trojan decommissioning plan. See Note 11, Trojan Nuclear Plant, in the Notes to the Financial Statements for further information. 

Leased Properties

PGE leases its headquarters complex in downtown Portland and the coal-handling facilities and certain railroad cars for Boardman.

 

Item 3. Legal Proceedings

Utility

 

Citizens' Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O'Neill v. Public Utility Commission of Oregon, Marion County Oregon Circuit Court, the Court of Appeals of the State of Oregon, the Oregon Supreme Court.

The Citizens' Utility Board (CUB) appealed a 1994 ruling from the Marion County Circuit Court that upheld the order of the OPUC in its Declaratory Ruling proceeding (DR-10). In the DR-10 proceeding, PGE filed an Application with the OPUC requesting a Declaratory Ruling regarding recovery of the Trojan investment and decommissioning costs. On August 9, 1993 the OPUC issued the declaratory ruling. In its ruling, the OPUC agreed with an opinion issued by the Oregon Department of Justice (Attorney General) stating that under current law, the OPUC has authority to allow recovery of and a return on Trojan investment and future decommissioning costs.

In PGE's 1995 general rate case, the OPUC issued an order granting PGE full recovery of Trojan decommissioning costs and 87% of its remaining investment in the plant. The Utility Reform Project (URP) filed an appeal of the OPUC's order. URP alleged that the OPUC lacked authority to allow PGE to recover Trojan costs through its rates. The complaint sought to remand the case to the OPUC and have all costs related to Trojan immediately removed from PGE's rates.

The CUB also filed an appeal challenging the portion of the OPUC's order issued in PGE's 1995 general rate case that authorized PGE to recover a return on its remaining investment in Trojan. The CUB alleged that the OPUC's decision was not based upon evidence received in the rate case, is not supported by substantial evidence in the record of the case, was based on an erroneous interpretation of law and is outside the scope of the OPUC's discretion, and otherwise violates constitutional or statutory provisions. The CUB sought to have the order modified, vacated, set aside, or reversed.

On April 4, 1996, a circuit court judge in Marion County, Oregon rendered a decision that contradicted a November 1994 ruling from the same court. The 1996 decision found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan currently in PGE's rate base. The 1994 and 1996 circuit court decisions were consolidated and appealed to the Oregon Court of Appeals.

On June 24, 1998, the Court of Appeals of the State of Oregon ruled that the OPUC does not have the authority to allow PGE to recover a rate of return on its undepreciated investment in Trojan. The court upheld the OPUC's authorization of PGE's recovery of its undepreciated investment in Trojan. 

On August 26, 1998, PGE filed a Petition for Review with the Oregon Supreme Court, supported by amicus briefs filed by three other major utilities seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's return on its undepreciated investment in Trojan. The OPUC also filed such a petition for review.

Also on August 26, 1998, the URP filed a Petition for Review with the Oregon Supreme Court seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's recovery of its undepreciated investment in Trojan.

On April 29, 1999, the Oregon Supreme Court accepted the petitions for review of the June 24, 1998, Oregon Court of Appeals decision.

On June 16, 1999, Oregon's governor signed Oregon House Bill 3220 authorizing the OPUC to allow recovery of a return on the undepreciated investment in property retired from service. One of the effects of the bill is to affirm retroactively the OPUC's authority to allow PGE's recovery of a return on its undepreciated investment in Trojan.

Relying on the new legislation, on July 2, 1999, the Company requested the Oregon Supreme Court to vacate the June 24, 1998, adverse ruling of the Oregon Court of Appeals and affirm the validity of the OPUC's order allowing PGE to recover a return on its undepreciated investment in Trojan. The URP and CUB opposed such request on the ground that an effort was underway to gather sufficient signatures to place on the ballot a referendum to negate the new legislation. Such effort by the referendum's sponsors was successful, and in the November 7, 2000 election, the voters of Oregon rejected House Bill 3220.

In August 2000, PGE entered into settlement agreements with the CUB and the staff of the OPUC of the litigation related to PGE's recovery of its investment in the Trojan plant. The OPUC approved the elements of the settlement agreements on September 29, 2000. The URP has filed a complaint with the OPUC, challenging PGE's application for approval of the accounting and ratemaking elements of the settlement and requesting a hearing.

PGE has requested the Oregon Supreme Court to hold in abeyance its review of the June 24, 1998, Court of Appeals decision pending resolution of URP's complaint with the OPUC challenging PGE's application for approval of the accounting and ratemaking elements of the settlement agreements approved by the OPUC on September 29, 2000. In response, the Oregon Supreme Court indicated that unless one or more parties report to the Court otherwise on or before March 15, 2001, the Court will assume that the cases are moot and will dismiss them on that ground. PGE has requested and the Oregon Supreme Court has granted an extension of  that time until April 16, 2001.

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

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

None. 

 

Part II

 

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

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

 

Quarter

2000

1999

First

$ 20

$ 20

Second

20

20

Third

20

20

Fourth

21

21

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

 

2000

1999

1998

1997

1996

 

(Millions of Dollars)

Operating Revenues

$2,253

$1,378

$1,176

$1,416

$ 1,110

Net Operating Income

206

190

200

208

230

Net Income

141

128

137

126

156

           

Total Assets

$3,452

$3,167

$3,162

$3,256

$3,398

Long-Term Obligations *

880

763

876

1,038

963

           

* 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

2000 Compared to 1999

Net income in 2000 increased to $141 million from $128 million in 1999 as a result of higher margins on energy sales. Such higher margins were partially offset by increased operating expenses during the year.

Total operating revenues increased $875 million (63%) primarily due to a significant increase in the price of energy sold in the wholesale market. The price increase was the result of various conditions, including higher natural gas prices, reduced hydro conditions, and increased regional demand. Wholesale revenues increased $816 million (from $355 million to $1,171 million), as Portland General Electric Company (PGE or the Company) sold on the wholesale market excess power purchases; wholesale energy sales increased 47% at average prices that increased 124% due to higher power prices. PGE entered into power and gas purchase contracts in anticipation of higher retail demand in 2000. However, due to mild temperatures, such demand was lower than expected and the Company was able to economically sell its excess power and gas in the wholesale market.

Retail revenues increased $54 million as large paper, chemical, high tech, and metals manufacturers increased their energy use; prices averaged 3% higher than last year due to higher prices for customers whose power prices were indexed to the market price of power. Total retail energy sales increased 3% as higher sales to industrial customers were partially offset by flat residential sales caused by warmer weather during the first half of the year. Total retail customers increased by about 5,900 (1%) from the end of last year; such increase includes the offsetting effect of the loss of approximately 7,150 customers who were transferred to two public utility districts upon the sale of a portion of PGE's service territory (for further information, see "Asset Sales" in the Financial and Operating Outlook section). Other operating revenues increased $5 million (26%) due largely to increased sales of natural gas in excess of generation requirements.

Purchased power and fuel costs increased $807 million (123%) due to significantly higher power prices and higher wholesale load. The average cost of firm and secondary power purchases doubled due to higher regional power and gas market prices. Combined with a 25% increase in power purchases, increased combustion turbine generation, and reduced hydro production, PGE's average variable power cost increased 86%. Partially offsetting the cost of purchased power and fuel was an approximate $13 million unrealized net gain on electricity trading contracts and natural gas swaps recorded during the year (see Note 8, Price Risk Management, in the Notes to Financial Statements for further information). In addition, PGE's Electricity Exchange pilot program, by which certain large commercial and industrial customers can voluntarily reduce their electricity usage during certain peak periods in exchange for energy credit payments, contributed to a reduction in the Company's net variable power costs during the second half of the year.

Company generation increased 9%, with a 69% increase in combustion turbine plant generation partially offset by reduced coal-fired and hydro production. Total generation met approximately 54% of PGE's retail load during the year, compared to 51% last year.

 

 

 

 

Megawatt-Hours/Variable Power Costs

 

 

Megawatt-Hours (thousands)

 

 

Average Variable Power Cost (Mills/KWh)

 

2000

1999

 

2000

1999

Generation

11,430

10,515

 

14.5

11.3

Firm Purchases

25,049

18,897

 

34.9

23.2

Spot Purchases

3,258

3,712

 

123.6

19.7

Total Send-Out

39,737

33,124

 

37.2*

20.0*

     

(* includes wheeling costs) 

Operating expenses (excluding purchased power and fuel, depreciation and taxes) increased $29 million (12%) as administrative, customer support, and fixed plant and delivery system costs all experienced increases from the prior year. Expenses last year were reduced by the effect of a non-recurring reduction in employee benefit accruals resulting from negotiated changes to union pension and Retirement Savings Plan enhancements. In 2000, the Company recorded a $2 million provision against deferred costs related to the proposed sale of its 20% interest in Units 3 and 4 of the Colstrip power plant. The sale was denied by the Oregon Public Utility Commission (OPUC), and in its recently filed restructuring plan, the Company seeks rate recovery of certain costs associated with this proposed sale. Other increases include approximately $5 million in maintenance and overhaul activities at the Boardman and Colstrip coal plants, $4 million in employee health insurance costs and insurance claim provisions, and $2 million in development expenditures related to the Company's customer information system. Beginning October 1, 2000, energy efficiency program expenditures, previously deferred and amortized over a five-year period, are charged to current operations, resulting in a $2 million increase in operating expenses. In addition, a $2 million contract termination settlement with an Oregon electric cooperative was recorded in 2000; this amount was deferred, in accordance with an accounting order from the OPUC, and offset within Depreciation and amortization expense.

Depreciation and amortization expense increased $9 million (6%) due to both a net increase in regulatory amortization and to normal capital additions. The increase in regulatory amortization was primarily attributable to the accounting effect of settlement agreements between PGE, the OPUC, and the Citizens' Utility Board (CUB) related to the Company's investment in the closed Trojan nuclear plant (see Note 10, Legal Matters, in the Notes to Financial Statements for further information).

Taxes other than income taxes increased $4 million (7%) due primarily to increased payroll taxes. Income taxes increased $10 million (12%) primarily because of the increase in taxable operating income.

Other Income remained the same as last year. During 2000, the Company wrote off its remaining $5 million investment in the Trojan plant as part of a settlement (discussed above) and incurred a $1 million loss in the value of trust owned life insurance, compared to an $11 million gain in 1999. These were largely offset by PGE's $15 million share of a distribution received in connection with the termination of the Company's membership in Nuclear Electric Insurance Limited (NEIL).

Interest charges increased $3 million (4%), caused primarily by the replacement of short-term debt with higher interest long-term debt, as $150 million of 7.875% unsecured notes were issued in March 2000. 

1999 Compared to 1998

Portland General Electric's net income for 1999 was $128 million compared to $137 million for 1998. Increased property, franchise, and income taxes, as well as a reduction from 1998's gains on the sale of Company land, were primarily responsible for the decrease. These were partially offset by an increased margin on higher electricity sales and by reduced interest charges.

Retail revenues increased $103 million primarily due to higher energy sales resulting from both the addition of 15,000 new customers as well as the termination of 1998's Customer Choice pilot program which enabled participating customers to purchase their electricity from other energy service providers. Revenues from power delivery services to energy service providers totaled $21 million in 1998; termination of the pilot program in 1999 caused the decrease in Other operating revenues.

Wholesale revenues increased $121 million (52%) due to both higher energy sales volume and prices. Increased energy sales resulted largely from sales in the wholesale market of excess power obtained to meet higher anticipated retail demand. Demand was lower than expected due to mild temperatures in 1999.

Purchased power and fuel costs increased $199 million (44%) due to higher prices for increased energy purchases. Higher regional power and gas market prices increased the cost of firm power purchases, resulting in a 25% increase in average power prices. Purchases were made to supply expected higher retail demand caused by weather volatility and customer growth, including the return of those customers participating in 1998's Customer Choice pilot program. Increased purchases also reflected PGE's ability to purchase power at a price more economical than generation. Company generation decreased from 37% to 32% of total power needs, primarily due to the economic displacement of gas powered generation, which declined about 21%. Coal and hydro generation in 1999 approximated that of 1998.

Operating expenses (excluding purchased power and fuel, depreciation and taxes) remained about the same as in 1998, as increased administrative and delivery system costs were offset by reduced generating plant expenses.

Depreciation and amortization expense increased $6 million (4%) primarily due to the effect of 1998's non-recurring $4 million gain on the sale of land formerly occupied by PGE's Western Division offices.

Taxes other than income taxes increased $4 million (7%) primarily due to higher state property taxes, caused by increases in taxable values, and city franchise fees that increased with higher electricity sales. Income taxes increased $3 million (4%) primarily because of the reversal of pre-1981 tax benefits related to the depreciation of certain regulatory assets; this was partially offset by a small decrease in net taxable income for the year.

Interest charges decreased $6 million (8%) due to a reduction in outstanding debt. 

 

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 2000, monthly balances ranged from $16 million to $278 million. PGE has two committed borrowing facilities: a $150 million facility maturing in July 2003 and a $100 million facility maturing in July 2001. Both facilities are used as backup for PGE's commercial paper facility.

A significant portion of cash provided by operations comes from depreciation and amortization of utility plant, charges which are recovered in customer revenues but require no current period cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash.

Cash provided by operating activities totaled $424 million in 2000, compared to $238 million in 1999. The increase is due primarily to the receipt of $134 million in deposits from wholesale electricity customers and from an increase in accounts payable to power suppliers, both reflected in the year's increase in accounts payable. This was partially offset by an increase in accounts receivable from wholesale electricity customers. Increased "Other non-cash income and expenses (net)" was due largely to the effect of reductions in customer refunds related to Oregon excise taxes and to customer savings under the Company's energy efficiency programs. Reflected in the change from last year's "Other working capital items" were reduced fuel and material inventory purchases in 2000. Included in "Other - net" is a $19 million accrual for the refund to customers of a termination distribution received from NEIL and a $12 million reduction from 1999 expenditures for maintenance and overhaul activities at the Company's Coyote Springs combustion turbine generating plant. 

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. Capital expenditures of $173 million in 2000 were primarily for the expansion and upgrade of PGE's distribution system. In 1999, capital expenditures of $182 million included the $37 million purchase of six combustion turbine generators at the Beaver generating plant, previously operated under terms of a long-term lease. Proceeds from sales of assets consist primarily of amounts received from the sale of a portion of PGE service territory to two public utility districts and from the sale of the Company's interest in certain rights and facilities at its Coyote Springs combustion turbine generating plant (for further information, see "Asset Sales" in the Financial and Operating Outlook section).

Capital expenditures are expected to approximate $186 million in 2001. Over the next few years, anticipated expenditures are expected to approximate current levels, with the majority of expenditures comprised of improvements to the Company's expanding distribution system to support both new and existing customers within PGE's service territory. 

Financing Activities provide supplemental cash for day-to-day operations and capital requirements as needed. PGE relies on commercial paper borrowings and cash from operations to manage its day-to-day financing requirements. In 2000, PGE issued $150 million of 7.875% unsecured notes maturing in 2010 and, with approximately $100 million in deposits received from wholesale electricity customers, reduced its short-term commercial paper by $250 million. In addition, PGE repaid $25 million in matured First Mortgage Bonds; issuance expenses on the newly issued notes and payment of conservation bonds, totaling $8 million, are also reflected in "Repayment of long-term debt".

In both 2000 and 1999, dividend payments totaled $83 million, consisting of $81 million in common stock dividends paid to its parent and $2 million in preferred stock dividends.

In July 1999, PGE received approval from the Federal Energy Regulatory Commission to issue short-term debt, including commercial paper, credit facilities, and other evidences of indebtedness up to $350 million. This approval is effective for two years and replaces and supercedes PGE's prior approval from the FERC authorizing short-term borrowing of $250 million. On July 27, 2000, PGE entered into a $250 million revolving credit facility with a group of commercial banks (see Note 5, Credit Facilities and Debt, in the Notes to Financial Statements for further information).

In November 1999, Standard & Poor's placed the ratings of the Company on CreditWatch Negative and Moody's Investors Services (Moody's) placed PGE's ratings, with the exception of Commercial Paper, on review for possible downgrade. Such actions were taken in response to the announced purchase and sale agreement of PGE to Sierra Pacific Resources and uncertainties surrounding the transaction. Standard & Poor's currently rates PGE's senior secured debt 'A', senior unsecured debt 'A-', preferred stock 'BBB+', and commercial paper 'A-1'. Moody's currently rates the Company's senior secured debt 'A2', senior unsecured debt 'A3', preferred stock 'a3', and commercial paper 'P-1'.

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, 2000, PGE has the capability to issue preferred stock and additional First Mortgage Bonds in amounts sufficient to meet its capital requirements. 

 

Financial and Operating Outlook

Proposed Acquisition

On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion, comprised of $2.02 billion in cash and the assumption of Enron's approximately $80 million merger payment obligation. The closing has been delayed by the effect of recent events in California and Nevada on the buyer. 

On September 1, 2000, a merger settlement agreement was reached between PGE, OPUC staff, Sierra, the Citizens' Utility Board, and the Industrial Customers of Northwest Utilities. The agreement includes a six-year rate freeze on distribution, transmission, and customer service costs. The freeze does not affect PGE's ability to adjust prices in response to changing wholesale electricity and fuel costs; in addition, transmission rates may be adjusted to the extent that the Federal Energy Regulatory Commission (FERC) approves changes caused by implementation of a Regional Transmission Organization. In addition, the settlement agreement includes up to $97 million in customer rate credits to be paid over seven years, customer protections that guarantee a continued high level of service quality and reliability, and PGE's agreement to continue its leadership role and support of Oregon's electric restructuring legislation. On October 30, 2000, the OPUC approved Sierra's application to acquire PGE. 

Receivables - California Wholesale Market

PGE has certain accounts receivable that may be affected by the financial condition of two major California utilities. Significant increases in wholesale power prices in 2000 and in early 2001, due in part to a sharp increase in natural gas prices paid by generators in producing electricity, have severely affected the financial stability of both companies. The utilities' recent wholesale power purchase costs have greatly exceeded revenues collected from customers through rates that are currently frozen, requiring the utilities to finance the majority of their power purchase costs. Adverse reaction of credit markets to continued regulatory uncertainty over the companies' ability to recover their power procurement costs has materially and adversely affected their liquidity (see Note 13, Receivables-California Wholesale Market, in the Notes to Financial Statements for further information).

Regulation and Competition 

State

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

In 1999, Oregon's governor signed into law State Senate Bill 1149 (SB1149) that provides all industrial and commercial customers of investor-owned utilities direct access to energy suppliers no later than October 1, 2001. Residential customers will be able to purchase electricity from a "portfolio" of rate options that will include a cost-of-service rate, a new renewable resource rate, and a market-based rate.

SB1149 also provides for a 10-year public purposes charge equal to 3% of retail revenues, designed to fund cost-effective conservation measures, new renewable energy resources, and weatherization measures for low-income housing. In addition, SB1149 provides for low-income electric bill assistance by affected utilities, which began in January 2000.

Also included in SB1149 is a requirement that investor-owned utilities unbundle the costs of service into power generation, transmission, distribution, and retail services. The law further provides for "transition" charges and credits that would allow recovery on prior uneconomic utility investment or a refund of benefits from prior economic utility investment. Utilities can propose incentives for the divestiture of generation assets, provided any divestiture does not deprive customers of the benefit of the utility's or the region's low cost resources. SB1149 further requires that its implementation have no material adverse impact on the ability of the affected investor-owned utilities to access cost-based power from the Bonneville Power Administration for its residential and small farm customers.

Following a series of issues discussion workshops and a formal rulemaking process, the Commission in September 2000 issued the first set of rules that provide a process for completing the steps necessary to move to direct access and protect all customer classes.

PGE filed its restructuring plan, including associated tariffs, with the OPUC on October 2, 2000. Such plan includes a request for increased revenues as well as rules and rate schedules that will allow the Company to implement direct access on October 1, 2001. As filed, the plan proposes a revenue requirement, based on a 2002 test year, of $1,452 million, an increase of $324 million over revenues derived from current base rates. The proposed increase in prices is largely attributable to higher wholesale electricity and natural gas fuel prices charged by PGE's suppliers; other factors include new facilities required to serve a growing number of customers, technology to meet customer service requirements, and rising labor costs. The increase to residential customers is expected to be partially offset by benefits from the Bonneville Power Administration. Business customers will have the option to purchase power on the open market. PGE remains subject to rate regulation and will continue to apply Financial Accounting Standards Board Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", to reflect the effects of rate regulation in its financial statements.

In accordance with a March 17, 2000, rate order from the OPUC, PGE is deferring incremental costs of implementing SB1149 for recovery in future electricity rates; at December 31, 2000, such costs totaled approximately $4 million. In January 2001, the staff of the OPUC filed initial settlement proposals containing its positions and proposed adjustments regarding the Company's filed 2002 test year revenue requirements. PGE is currently considering a stipulation with OPUC staff which, if finalized, will settle many of the revenue requirement issues. PGE will continue to work with the OPUC staff and other parties in settlement discussions, with OPUC staff and intervenor testimony scheduled for filing on February 20, 2001.

In January 2001, the OPUC staff and PGE filed applications with the Commission for deferral of a portion of PGE's excess net variable power costs for 2001. PGE's application requests authorization to defer for later ratemaking treatment changes in net variable power costs, positive or negative, which differ from such costs approved by the Commission in the Company's last general rate case. This application and filing replaces a November 20, 2000 filing by PGE that sought a 16.5% average increase in electricity prices, effective January 1, 2001. This filing was withdrawn on December 22, 2000. On February 8, 2001, PGE stipulated to a power cost mechanism with OPUC staff and other parties that shares with retail customers any changes in PGE's power costs outside of a pre-determined range for the period January through September 2001. Such costs will be shared equally within certain limits, with 90% of costs in excess of such limits charged or credited to retail customers. On February 20, 2001, the OPUC consolidated the two applications and authorized PGE to defer, for future ratemaking treatment, any changes from a net variable power cost baseline amount of $176 million (for nine months). In a subsequent proceeding, PGE will request the recovery (or refund) of a portion of the deferred amount in accordance with the formula agreed to with OPUC staff on February 8, 2001. PGE's earnings for the nine month period will only reflect the expected recovery amount. 

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.

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales increased 2.4% in 2000. Manufacturing sector energy sales increased 8.0% as large paper, chemical, high tech, and metals manufacturers significantly increased their energy use. Commercial sales growth remained strong at 2.2% over l999. Sales to residential customers, however, decreased 1.3% as average use declined and as approximately 6,000 residential customers were transferred to two public utility districts in the third quarter of the year, pursuant to the sale of a portion of PGE's service territory. PGE forecasts retail energy sales growth of approximately 2.5% in 2001.

Wholesale Sales

The decreasing surplus of electric generating capability in the western United States, the entrance of numerous wholesale marketers and brokers into the market, and open access transmission are contributing to increasing competitive pressure on the price of power. In addition, the development of financial markets, including the NYMEX electricity contract, has led to enhanced price discovery available for market participants, further adding to the pressure on wholesale prices and margins. During 2000, PGE's wholesale sales accounted for about 52% of total revenues and 48% of total energy sales. PGE will continue its participation in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts.

Power & Fuel Supply

PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the Company the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers. However, surplus generation has diminished in recent years due to economic and population growth in the western United States; in addition, current uncertainty over restructuring deregulation has discouraged construction of new generating plants. Higher prices for natural gas, recent weather conditions in California and the Southwest, temporary closure of a number of generating plants due to maintenance and other related reasons, and fish protection flow limits affecting hydro generation, are expected to increase both price and demand pressure on available resources.

PGE has long-term power contracts with four hydro projects on the mid-Columbia River providing capability of approximately 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 generating capacity within the Western Systems Coordinating Council should provide wholesale energy to supplement its generation and purchases under existing firm power contracts.

Early forecasts for 2001 indicate hydro conditions approximating only 63% of normal, compared to 92% of normal last year. Efforts to restore salmon runs on the Columbia and Snake rivers may additionally reduce the amount of water available for generation, which could affect the availability and price of purchased power. 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.

PGE generated approximately 54% of its 2000 retail load requirement, compared to approximately 51% in 1999. Short-term and long-term purchases were utilized to meet the remaining load.

Restoration of Salmon Runs - PGE continues to evaluate the impact of current and potential listings of salmon species for protection under the Federal Endangered Species Act on its purchased power supply and operations of hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette Rivers.

Retail Competition

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.

An initiative petition was filed in February 2000 by a local political committee, which is attempting to amend the charter of the City of Portland to require the city's acquisition of privately owned electricity distribution systems and facilities within its boundaries under certain circumstances. The petition further provides that costs to purchase, condemn, or otherwise acquire such facilities be paid from the issuance of revenue bonds. If sufficient signatures are obtained (approximately 21,000), the proposed amendment would appear on the May 2002 ballot.

On March 20, 2000, PGE filed a complaint with the Multnomah County Circuit Court, asking the court to enjoin the city auditor from certifying the petition as a ballot measure on the grounds that the proposed amendment is unconstitutional under Oregon law. On October 30, 2000, the Court ruled against PGE in this matter. The Company has filed an appeal of this decision with the Oregon Court of Appeals. 

Resource Plan

Under OPUC rules implementing Oregon's electric industry restructuring law, electric companies are required to file a Resource Plan proposing a disposition of their existing generating resources. Such disposition must facilitate a fully competitive market, provide consumers fair, non-discriminatory access to competitive markets, and retain the benefit of low-cost resources for customers.

On November 1, 2000, PGE filed with the OPUC its Resource Plan. Under the plan, PGE proposes to retain almost all of its resources, selling only its 20% share of Colstrip Units 3 and 4 in Montana. The plan also proposes that PGE's Coyote Springs combustion turbine generating plant be administratively valued and reclassified as an unregulated asset, with the Company retaining full ownership of the plant with the ability to sell its power within the western grid. All other generating resources would remain regulated, matching their output to the needs of PGE residential and small business customers. Following the Commission's review and public hearings, a decision by the OPUC on the Company's Resource Plan is anticipated by September 1, 2001.

Residential Exchange Program

The September 1998 Residential Exchange Termination Agreement with the Bonneville Power Administration provided approximately $35 million in BPA payments to PGE over two years, with benefits to PGE's residential and small farm customers continuing through the June 2001 termination of the agreement. At December 31, 2000, PGE had received the entire amount under the Agreement.

On October 31, 2000, PGE and BPA signed a Settlement Agreement that provides for BPA payments totaling $2.7 million, to be made from July through September of 2001; residential customer benefits will continue at the current rate through the end of this period. The Agreement further provides for additional residential exchange benefits, in the form of both cash payments and energy, over a ten-year period beginning October 1, 2001, with benefits continuing to pass directly to residential and small farm customers. The total amount of benefits will be determined based upon the outcome of BPA's current wholesale electric power and transmission rate proposals, approval of which is anticipated in 2001. 

Asset Sales

In April 2000, upon approval by the OPUC and FERC, PGE sold 12% of its interest (representing a 10.5% tenancy-in-common share) in the Kelso-Beaver Pipeline to B-R Pipeline. PGE now owns approximately 79% of the pipeline, which directly connects its Beaver generating station to Northwest Pipeline, an interstate gas pipeline operating between British Columbia and New Mexico.

In July 2000, PGE sold its rights to build a combined cycle gas turbine power plant adjacent to its Coyote Springs 1 combustion turbine generating plant, along with 50% of its interest in the plants' common facilities, to Avista Corp. for approximately $14 million. Avista Corp. plans to build a 280-MW combined cycle gas turbine power plant on the site, which is scheduled for completion in June 2002. The new Coyote Springs 2 power plant will be owned by Avista Power LLC and operated by PGE under a 15-year operations and maintenance contract. The pre-tax gain on the sale, approximately $11 million, has been deferred for future refund to PGE customers.

In August 2000, following voter-approved condemnation and a settlement, PGE sold its service territory in four Columbia County cities to the Columbia River People's Utility District (CRPUD) and the Clatskanie Public Utility District (CPUD). After receiving approval from the OPUC, approximately 7,150 PGE customers were transferred to the two utility districts. 

Hydro Relicensing

PGE Hydro - PGE's eight hydroelectric plants provide economical generation and flexible load following capabilities; in 2000, they produced 2.5 million MWh of renewable energy, about 13% of PGE's total retail customer load. The plants operate under federal licenses, which will be up for renewal between the years 2001 and 2006.

PGE's collaborative relicensing processes on the Willamette and Clackamas River hydroelectric projects are continuing. These projects are licensed until December 2004 and August 2006, respectively, and have a combined output of 181 MW. A significant number of biological, cultural, recreational, and engineering studies are being performed to determine the projects' impacts and opportunities for mitigation and enhancements. PGE's 22-MW Bull Run Project will not be relicensed when its existing federal license expires in November 2004.

During 2000, PGE resolved many of the outstanding issues associated with the relicensing of its 408-MW Pelton Round Butte Project on the Deschutes River, which provides about 20% of the Company's power-generating capacity. In April, PGE executed an agreement with the Confederated Tribes of Warm Springs (Tribes) that would result in shared ownership and control; PGE would continue to operate the project. Under terms of this agreement, the Tribes will acquire an increasing share of the project starting in January 2002, when it will purchase a one-third interest at the net depreciated book value on December 31, 2001. The settlement, which was approved by the OPUC in August 2000, will replace the fees PGE had been paying the Tribes for the inundation of their property along the Deschutes and Metolius River. PGE and the Tribes completed the draft of their joint 50-year license application in 2000, and anticipate filing the final application with the FERC in the spring of 2001. 

Mid-Columbia Hydro - PGE's long-term power purchase contracts with certain public utility districts in the state of Washington expire between 2005 and 2018. Certain Idaho Electric Utility Co-operatives have initiated proceedings with the FERC seeking to change the allocation of generation from the Priest Rapids and Wanapum dams between electric utilities in the region upon expiration of the current contracts. In early 1998, the FERC ruled that the portion of the output from these dams made available to purchasers such as PGE be reduced to 30%, and that such purchases be at market-based rather than cost-based prices. This decision could change both PGE's percentage share and the price of power from these facilities, although such changes are not yet determinable.

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

Trojan Investment Recovery

Due to the closure of PGE's Trojan nuclear plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals and regulatory actions have taken place. See Note 10, Legal Matters, in the Notes to Financial Statements for further information. 

Nuclear Decommissioning

PGE currently estimates the total cost to decommission Trojan at $337 million (nominal dollars), with approximately $140 million expended through 2000. The total estimate assumes that the majority of decommissioning activities will be completed after the spent fuel has been transferred to a temporary dry spent fuel storage facility in 2003. The plan anticipates final site restoration activities will begin in 2018 after PGE completes shipment of spent fuel to a United States Department of Energy (USDOE) facility. See Note 11, Trojan Nuclear Plant, in the Notes to Financial Statements for further information. 

Environmental Matter

A 1997 investigation of a portion of the Willamette River known as the Portland Harbor, conducted by the U.S. Environmental Protection Agency (EPA), revealed significant contamination of sediments within the harbor. Subsequently, the EPA has included Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund").

The Oregon Department of Environmental Quality (DEQ) asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, the Company voluntarily completed on site testing and submitted a work plan for DEQ review and approval. Investigations of the site by PGE have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site. Remedial activities, if any, that PGE may ultimately perform with respect to this matter will depend on the results of further investigations.

PGE does not expect environmental matters to have a material adverse impact on the financial condition or results of operations of the Company.

RTO West and Proposed Independent Transmission Company

In December 1999, the FERC issued Order No. 2000 in a continued effort to more efficiently manage transmission, create fair pricing policies, and encourage competition by providing equal access to the nation's electric power grids. The order requires all owners of electricity transmission facilities to file plans for the formation of Regional Transmission Organizations (RTOs), to be implemented by December 15, 2001.

In response to this order, nine western utilities, including PGE and BPA, on October 22, 2000 filed an initial plan with the FERC to form RTO West, a regional non-profit transmission organization that would operate the transmission system in the Pacific Northwest, Nevada, and parts of neighboring states.

In addition, PGE and five other regional utilities filed a proposal with the FERC to form an independent transmission company (ITC), to be called TransConnect. The new company would participate in RTO West and as a transmission owner would own or lease the high voltage transmission systems of the member companies. TransConnect would be formed as a for-profit transmission company meeting the independence criteria established by FERC for RTOs. As such, PGE believes TransConnect would enhance the efficiency and reliability of RTO West, as well as more quickly implement the RTO's decisions and simplify ratemaking. Because it would be a relatively large for-profit business, it could more readily raise capital for system improvements and expansion, easing congestion and further enhancing reliability.

The proposal, filed on October 15, 2000, is also subject to approval by state regulators and the board of directors of each filing company. It is currently anticipated that RTO West and TransConnect will begin operations no earlier than December 2001.

New Accounting Standard

In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes accounting and reporting standards requiring that every derivative instrument 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.

SFAS No. 133 is effective for fiscal years beginning after June 15, 2000, and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1998 (effective dates noted are as amended by SFAS No. 137). In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133.

PGE has evaluated the impact of SFAS No. 133, as amended, and adopted it on January 1, 2001. The derivative instruments identified were primarily, in the Company's evaluation, subject to the normal purchases and normal sales exception (see FASB issue below) with some as hedges of forecasted transactions and no hedging designation. The Company expects the transition adjustment upon adoption of SFAS No. 133 will be approximately an $11 million gain, net of tax, from a cumulative effect of a change in accounting principle, and about a $35 million increase, net of tax, in Other Comprehensive Income, a component of shareholders' equity, as of the effective date.

The impact of adoption, however, is dependent upon certain pending interpretations of the statement related to the application of the normal purchases and normal sales exception (i.e. electric utility's practice of "bookouts" and "net scheduling" of power contracts). For purposes of determining the impact upon adoption, the Company has elected to treat under the normal purchases and normal sales exception certain contracts for the purchase and sale of electricity that may be booked out or net scheduled. The interpretation of this issue is currently under consideration by the Derivatives Implementation Group and the FASB. Given the uncertainties of this issue, the Company cannot predict the ultimate outcome at this time. If the FASB ultimately rules that bookouts and net scheduling meet the net settlement provisions, then the affected power contracts would not qualify for the normal purchases and normal sales exception and would be required to be fair valued pursuant to SFAS No. 133. This may cause the amounts stated above and the relative impact to PGE's financial statements, to be materially different. However, pursuant to the regulatory process, the Company believes that any required revision that may impact PGE's results of operations and financial condition, would be mitigated by the application of SFAS 71, Accounting for the Effects of Certain Types of Regulation.

Information Regarding Forward-Looking Statements

This report 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 expectations 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, and adverse weather conditions during the periods covered by the forward-looking statements.

Item 7A. Quantitative and Qualitative Disclosures About

Market Risk

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

Gains and losses from instruments that reduce commodity price risks are recognized in purchased power and fuel expense, or in wholesale revenue. In addition, Company policy allows the use of these instruments for trading purposes in support of its operations; gains or losses on such instruments are recognized within "Purchased power and fuel" expense on PGE's Income Statement.

The use of derivative commodity instruments may expose the Company to market risks resulting from adverse changes in commodity prices; the Company actively manages this risk to ensure compliance with its risk management policies. Market risks associated with commodity derivatives held at December 31, 1999, were not material. In 2000, PGE's market risk profile changed because of increased volatility in electricity and natural gas prices. However, due to continuing low trading limits and volumes, the Company has maintained a limited exposure to market movements. The Company is subject to limits on open commodity positions and monitors this using a value at risk methodology, which measures the potential impact of market movements over a given time interval. Value at risk remains at an immaterial level at December 31, 2000.

In addition, PGE is exposed to risk resulting from changes in interest rates as a result of its issuance of variable rate commercial paper. Although the Company currently has no financial instruments to mitigate such risk, it will consider such instruments in the future as necessary.

For further information, including accounting policies for price risk management activities, see Note 1, Summary of Significant Accounting Policies, and Note 8, Price Risk Management, in the Notes to Financial Statements.

Item 8. Financial Statements and Supplementary Data

 

Management's Responsibility for Financial Reporting 

The following financial statements of Portland General Electric Company and subsidiaries (collectively, PGE) were prepared by management, which is responsible for their integrity and objectivity. The statements have been prepared in conformity with accounting principles generally accepted in the United States 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, 2000, 1999 and 1998, 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 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, 2000, 1999 and 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. Management is responsible for maintaining effective internal control over the reliability of the financial statements and the protection of assets against unauthorized acquisition, use or disposition. Our responsibility is to express an opinion on management's assertion based on our examination.

Our examination was made in accordance with standards established by the American Institute of Certified Public Accountants and, accordingly, included obtaining an understanding of the system of internal control over financial reporting and the protection of assets against unauthorized acquisition, use or disposition, testing and evaluating the design and operating effectiveness of the system of internal control and such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion.

Because of inherent limitations in any system of internal control, errors or irregularities may occur and not be detected. Also, projections of any evaluation of the system of internal control to future periods are subject to the risk that the system of internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assertion that the system of internal control of Portland General Electric Company and its subsidiaries as of December 31, 2000, 1999, and 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

January 26, 2001

 

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, 2000 and 1999, and the related consolidated statements of income, retained earnings and cash flow for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

Arthur Andersen LLP

Portland, Oregon

January 26, 2001

(except with respect to the matter discussed in

Note 13, as to which the date is February 21, 2001)

 

Portland General Electric Company and Subsidiaries

Consolidated Statements of Income 

 

For the Years Ended December 31

 

2000

 

1999

 

1998

 

(Millions of Dollars)

Operating Revenues

$

2,253

$

1,378

$

1,176

             

Operating Expenses

           
 

Purchased power and fuel

 

1,461

 

654

 

455

 

Production and distribution

 

126

 

119

 

120

 

Administrative and other

 

137

 

115

 

114

 

Depreciation and amortization

 

164

 

155

 

149

 

Taxes other than income taxes

 

65

 

61

 

57

 

Income taxes

 

94

 

84

 

81

     

2,047

 

1,188

 

976

               

Net Operating Income

 

206

 

190

 

200

               

Other Income (Deductions)

           
 

Miscellaneous

 

10

 

13

 

13

 

Income taxes

 

(3)

 

(6)

 

(1)

     

7

 

7

 

12

Interest Charges

           
 

Interest on long-term debt and other

 

63

 

59

 

68

 

Interest on short-term borrowings

 

9

 

10

 

7

     

72

 

69

 

75

             

Net Income

 

141

 

128

 

137

               

Preferred Dividend Requirement

 

2

 

2

 

2

               

Income Available for Common Stock

$

139

$

126

$

135

Portland General Electric Company and Subsidiaries

Consolidated Statements of Retained Earnings

               

For the Years Ended December 31

 

2000

 

1999

 

1998

   

(Millions of Dollars)

               

Balance at Beginning of Year

$

401

$

356

$

270

Net Income

 

141

 

128

 

137

     

542

 

484

 

407

               

Dividends Declared

           
 

Common stock - cash

 

81

 

81

 

49

 

Preferred stock

 

2

 

2

 

2

     

83

 

83

 

51

Balance at End of Year

$

459

$

401

$

356

The accompanying notes are an integral part of these consolidated financial statements.

 

Portland General Electric Company and Subsidiaries

Consolidated Balance Sheets 

 

At December 31

2000

1999

(Millions of Dollars)

Assets

Electric Utility Plant - Original Cost

Utility plant (includes construction work in progress of $78 and $44)

$

3,423

$

3,295

Accumulated depreciation

(1,532)

(1,430)

1,891

1,865

Other Property and Investments

Contract termination receivable

57

85

Receivable from parent

80

89

Nuclear decommissioning trust, at market value

33

42

Trust owned life insurance

86

85

Miscellaneous

21

17

277

318

Current Assets

Cash and cash equivalents

60

-

Accounts and notes receivable

287

140

Unbilled and accrued revenues

60

49

Assets from price risk management activities

279

-

Inventories, at average cost

31

37

Prepayments and other

61

41

778

267

Deferred Charges

Unamortized regulatory assets

484

691

Miscellaneous

22

26

506

717

$

3,452

$

3,167

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

459

401

Cumulative preferred stock

Subject to mandatory redemption

30

30

Long-term obligations

798

701

1,927

1,772

Current Liabilities

Long-term debt due within one year

52

32

Short-term borrowings

16

266

Accounts payable and other accruals

286

163

Liabilities from price risk management activities

266

-

Customer deposits

139

4

Accrued interest

14

11

Dividends payable

1

1

Accrued taxes

8

12

782

489

Other

Deferred income taxes

365

351

Deferred investment tax credits

27

36

Trojan decommissioning and transition costs

218

234

Unamortized regulatory liabilities

34

197

Miscellaneous

99

88

743

906

$

3,452

$

3,167

The accompanying notes are an integral part of these consolidated financial statements.

 

Portland General Electric Company and Subsidiaries

Consolidated Statements of Cash Flow

 
       

For the Years Ended December 31

 

2000

 

1999

 

1998

   

(Millions of Dollars)

Cash Flows From Operating Activities:

           

Reconciliation of net income to net cash provided by 

  operating activities

 

Net income

$

141

$

128

$

137

 

Non-cash items included in net income:

           
   

Depreciation and amortization

 

164

 

155

 

149

   

Deferred income taxes

 

(8)

 

(3)

 

(6)

   

Net assets from price risk management activities

 

(13)

 

-

 

-

   

Other non-cash income and expenses (net)

 

17

 

(10)

 

(11)

 

Changes in working capital:

           
   

(Increase) decrease in receivables

 

(158)

 

(9)

 

(8)

   

Increase (decrease) in payables

 

257

 

(1)

 

(50)

   

Other working capital items - net

 

(14)

 

(18)

 

(1)

 

Other - net

 

38

 

(4)

 

55

Net Cash Provided by Operating Activities

 

424

 

238

 

265

               

Cash Flows From Investing Activities:

           
 

Capital expenditures

 

(173)

 

(182)

 

(144)

 

Proceeds from sales of assets

 

27

 

-

 

-

 

Other - net

 

(2)

 

6

 

(4)

Net Cash Used in Investing Activities

 

(148)

 

(176)

 

(148)

               

Cash Flows From Financing Activities:

           
 

Repayment of long-term debt

 

(33)

 

(113)

 

(214)

 

Net increase (decrease) in short-term borrowings

 

(250)

 

161

 

6

 

Issuance of long-term debt

 

150

 

-

 

142

 

Dividends paid

 

(83)

 

(83)

 

(51)

 

Repayment of loans on corporate owned life insurance

 

-

 

(32)

 

-

 

Other - net

 

-

 

1

 

1

Net Cash Used in Financing Activities

 

(216)

 

(66)

 

(116)

             

Increase (Decrease) in Cash and Cash Equivalents

 

60

 

(4)

 

1

Cash and Cash Equivalents, Beginning of Period

 

-

 

4

 

3

Cash and Cash Equivalents, End of Period

$

60

$

-

$

4

               

Supplemental disclosures of cash flow information

           
 

Cash paid during the year:

           
   

Interest, net of amounts capitalized

$

66

$

60

$

63

   

Income taxes

 

109

 

139

 

133

The accompanying notes are an integral part of these consolidated financial statements.

 

Portland General Electric Company and Subsidiaries

Notes to Financial Statements 

Nature of Operations

On July 1, 1997, Portland General Corporation (PGC), the former parent of PGE, merged with Enron Corp. (Enron) with Enron continuing in existence as the surviving corporation. PGE is currently a wholly owned subsidiary of Enron and subject to control by the Board of Directors of Enron. PGE is engaged in the generation, purchase, transmission, distribution, and sale of electricity in the State of Oregon. PGE also sells energy to wholesale customers, predominately utilities, marketers and brokers throughout the western United States. PGE's Oregon service area is 3,150 square miles, including 51 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 2000, PGE's service area population was approximately 1.5 million, comprising about 44% of the state's population and serving approximately 725,000 customers.

On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion. The closing has been delayed by the effect of recent events in California and Nevada on the buyer. 

Note 1 - Summary of Significant Accounting Policies

Consolidation Principles

The consolidated financial statements include the accounts of PGE and its majority-owned subsidiaries. Inter-company balances and transactions have been eliminated.

Basis of Accounting

PGE and its subsidiaries' financial statements conform to accounting principles generally accepted in the United States. In addition, PGE's accounting policies are in accordance with the requirements and the rate making practices of regulatory authorities having jurisdiction. PGE's consolidated financial statements do not reflect an allocation of the purchase price that was recorded by Enron as a result of the PGC merger.

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications

Certain amounts in prior years have been reclassified for comparative purposes.

Revenues

PGE accrues estimated unbilled revenues for services provided from the meter read date to month-end.

Purchased Power

PGE credits purchased power costs for the benefits received through a power purchase and sale contract with the Bonneville Power Administration (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. A September 1998 agreement between PGE and BPA will continue to provide benefits to PGE's residential and small farm customers through at least June 30, 2001. A new agreement signed October 31, 2000, provides for continued benefits from July 1 through September 30, 2001 and provides for additional benefits over a ten-year period beginning October 1, 2001.

Depreciation

PGE's depreciation is computed on the straight-line method based on the estimated average service lives of the various classes of plant in service. Depreciation expense as a percent of the related average depreciable plant in service was approximately 4.2% in 2000 and 1999 and 4.3% in 1998.

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. 

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 in 2000 was 6.8%. 

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. 

Price Risk Management

PGE engages in price risk management activities for both trading and non-trading purposes. Financial instruments utilized in connection with trading activities are accounted for using the mark-to-market method, pursuant to Emerging Issues Task Force (EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management Activities". Under this method of accounting, instruments utilized for trading activities are reflected at fair value, with unrealized gains and losses recorded within "Purchase power and fuel" on the Income Statement and shown as "Assets and Liabilities from Price Risk Management Activities" in the Balance Sheet. Gains and losses on instruments utilized in non-trading activities are recognized in purchased power and fuel expense, or in wholesale revenue upon settlement. See Note 8, Price Risk Management, for further information. 

Cash and Cash Equivalents

Highly liquid investments with original maturities of three months or less are classified as cash equivalents.

Trust Owned Life Insurance

Under the purchase and sale agreement between Enron and Sierra, PGE's investment in trust owned life insurance will be transferred to Enron before the sale of PGE to Sierra.

Energy Efficiency

Beginning October 1, 2000, PGE's Demand Side Management (DSM) program expenditures, formerly deferred and amortized over a five-year period, are being expensed. This change in cost recognition, approved by the OPUC, was accompanied by an approximate 1% increase in rates. PGE's unamortized DSM investment prior to implementation of the change continues to be recovered in rates over a five-year period. This change in cost recognition is in response to SB1149, which encourages a competitive marketplace for energy services and provides for a public service charge to fund conservation measures.

Major Maintenance and Overhaul Accruals

PGE performs periodic major maintenance inspections and overhauls at its Coyote Springs combustion turbine generating plant based upon manufacturers' specifications and hours of operation. The OPUC has authorized the Company to accrue and recover in rates the projected costs of such major maintenance and overhaul activities. The estimated cost of such activities is accrued each month to Production and distribution expense, with an equal amount recorded as a non-current miscellaneous liability on the balance sheet, with the actual cost of work performed charged to the liability account.

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: 

 

 

2000

1999

 

(Millions of Dollars)

Unamortized regulatory assets:

   
 

Trojan investment

$ -

$202

 

Trojan decommissioning costs

190

196

 

Income taxes recoverable

136

165

 

Prior tax benefits recoverable

45

-

 

Debt reacquisition costs

21

23

 

Conservation investments - secured

54

61

 

Energy efficiency programs

19

22

 

Miscellaneous

  19

  22

   

Total

$484

  $691

Unamortized regulatory liabilities:

   

Deferred gain on SCE termination

$ -

$ 81

 

Merger payment obligation

-

88

 

NEIL distribution

19 -

-

 

Deferred gain on sale of major asset

11

-

 

Miscellaneous

    4

  28

Total

$  34

$197

During 2000, the Company entered into settlement agreements related to the recovery of its investment in the Trojan plant. The agreements provided for removal from the Company's balance sheet of the remaining before-tax investment in Trojan of approximately $180 million, along with several largely offsetting regulatory liabilities. The largest of such amounts were the deferred gain on the termination of a power sales agreement with Southern California Edison Company (SCE) and the Enron/PGC merger payment obligation. The settlement also allows recovery of approximately $47 million in income tax benefits related to the Trojan investment, which had been flowed to customers in prior years; such amount is being recovered from PGE customers, with no return on the unamortized balance, over an approximate five-year period. See Note 10, Legal Matters, for further information.

As of December 31, 2000, 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 2000, the Company estimates that it will collect substantially all of its regulatory assets within the next 11 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, 2000, the outstanding balance on the bonds was $53 million.

Note 2 - Employee Benefits

Pension and Other Post-Retirement Plans

PGE participates in a non-contributory defined benefit pension plan (the Plan) with other affiliated companies. Substantially all of the plan members are current or former PGE employees. The plan's assets are held in a trust. 

PGE also participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" below). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. Contributions are made to a voluntary employee's beneficiary association to fund these plans.

 The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of plans' assets, a statement of the funded status, and components of net periodic pension expense (in millions):

 

Pension Benefits

Other Benefits

2000

1999

2000

1999

Reconciliation of benefit obligation:

Obligation at January 1

$267

$284

$ 29

$ 29

Service cost

9

8

1

1

Interest cost

20

20

2

2

Plan amendments

-

6

-

-

Curtailments (a)

-

(8)

-

-

Participants' contributions

-

-

1

-

Actuarial loss (gain)

2

(25)

1

(1)

Benefit payments

(18)

(18)

(3)

(2)

Obligation at December 31

$280

$267

$  31

$  29

Reconciliation of fair value of plan assets:

Fair value of plan assets at January 1

$439

$401

$ 35

$ 33

Actual return on plan assets

2

55

(3)

3

Participants'' contributions

-

-

-

1

Company contributions

1

1

1

-

Benefit payments

  (18)

  (18)

    (3)

    (2)

Fair value of plan assets at December 31

$424

$439

$  30

$  35

Funded status:

Funded status at December 31

$144

$172

$ (1)

$ 6

Unrecognized transition (asset)

(8)

(9)

4

4

Unrecognized prior service cost

12

13

2

2

Unrecognized gain

(121)

(162)

 (5)

 (13)

Prepaid Pension Cost

$  27

$  14

$  0

$ (1)

Assumptions:

Discount rate used to calculate benefit obligation

7.75%

7.75%

7.75%

7.75%

Rate of increase in future compensation levels

4.0 - 9.5%

4.0 - 9.5%

4.0 - 9.5%

4.0 - 9.5%

Long-term rate of return on assets

9.00%

9.00%

9.50%

9.50%

Components of net periodic pension expense:

Service cost

$ 9

$ 8

$ 1

$ 1

Interest cost on benefit obligation

20

20

2

2

Expected return on plan assets

(35)

(31)

(3)

(2)

Amortization of transition asset

(2)

(2)

-

-

Amortization of prior service cost

2

1

-

-

Recognized gain

(6)

(3)

-

(1)

Effect of curtailment (a)

      -

    (5)

   -

   -

Net periodic pension expense (benefit)

$ (12)

$ (12)

$ 0

$ 0

(a) Represents one-time nonrecurring event associated with certain union employees ceasing participation in the pension plan as a result of union negotiations.

Included in the above Pension Benefits amounts are the unfunded obligations for the supplemental executive retirement plan. At December 31, 2000 and 1999, respectively, the projected benefit obligation for this plan was $13 million and $12 million. Under the purchase and sale agreement between Enron and Sierra, this obligation will be assumed by Enron before the sale of PGE to Sierra.

For measurement purposes, a 10.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate was assumed to decrease .5% per year to 5.0% in 2010 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects (in millions):

 
 

1-Percentage

Point Increase

1-Percentage

Point Decrease

Effect on total of service and interest cost components

$0.1

$(0.1)

     

Effect on post-retirement benefit obligation

$0.7

$(0.6)

 Deferred Compensation

PGE provides certain employees with benefits under an unfunded Management Deferred Compensation Plan (MDCP). Obligations for the MDCP were $40 million and $34 million at December 31, 2000 and 1999, respectively. Under the purchase and sale agreement between Enron and Sierra, this obligation will be assumed by Enron before the sale of PGE to Sierra.

Employee Stock Ownership Plan

PGE participated in the PGH Retirement Savings Plan through June 30, 1999. On July 1, 1999, the plan merged into the Enron Savings Plan and PGE continued participation. The successor plan includes an Employee Stock Ownership Plan (ESOP). Previously matched 50% by employer contributions, employee contributions up to 6% of base pay will be matched 100% by employer contributions in the form of Enron common stock, beginning in 2001.

 All Employee Stock Option Plan

Enron stock options were granted to PGE employees on December 31, 1997. The options were granted at the fair value of the stock at the date of the grant. One-third of the options vested each year in 1998, 1999, and 2000. PGE pays Enron the estimated value of the shares vesting each year. The fair value of shares vesting in both 2000 and 1999 was $4 million. 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):

 

2000

1999

1998

Income Tax Expense

Currently payable

Federal

$ 88

$ 78

$75

State and local

 17

 15

 13

105

93

88

Deferred income taxes

Federal

(2)

(1)

(1)

State and local

    -

    2

  (1)

(2)

1

(2)

Investment tax credit adjustments

(6)

(4)

(4)

$ 97

$ 90

$ 82

Provision Allocated to:

Operations

$ 94

$ 84

$ 81

Other income and deductions

3

6

1

$ 97

$ 90

$ 82

Effective Tax Rate Computation:

 

Computed tax based on statutory federal

income tax rates applied to income before

income taxes

$ 84

$ 77

$ 77

Flow through depreciation

6

7

4

State and local taxes - net

11

11

7

Investment tax credits

(6)

(4)

(4)

Excess deferred taxes

(1)

(1)

(1)

Other

3

-

(1)

$ 97

$ 90

$ 82

Effective tax rate

40.8%

41.3%

37.4%

As of December 31, 2000 and 1999, the significant components of PGE''s deferred income tax assets and liabilities were as follows (millions of dollars):

 

2000

1999

Deferred Tax Assets

Depreciation and amortization

$ 24

$ 24

Employee benefits

13

15

Regulatory liabilities

SCE termination

-

39

Merger payment obligation

-

35

NEIL distribution

8

-

Deferred gain on sale of major asset

4

-

Miscellaneous

5

10

Other deferred tax assets

 13

 20

 67

143

Deferred Tax Liabilities

Depreciation and amortization

$330

$356

Trojan investment

-

56

Receivable from parent

31

35

Price risk management

5

-

Regulatory assets

Prior tax benefits recoverable

18

-

Debt reacquisition costs

8

9

Conservation investments

18

19

Energy efficiency programs

8

8

Miscellaneous

-

9

Other deferred tax liabilities

  14

    2

432

494

Total

$365

$351

PGE has recorded deferred tax assets and liabilities for all temporary differences between the financial statement basis and tax basis of assets and liabilities.

Note 4 - Common and Preferred Stock

 
 

Common Stock

Cumulative Preferred

 
 

Number

$3.75 Par

Number

No- Par

Paid-in

(Millions of Dollars

of Shares

Value

of Shares

Value

Capital

except share amounts)

         

December 31, 1998

42,758,877

$160

300,000

$30

$480

December 31, 1999

42,758,877

$160

300,000

$30

$480

December 31, 2000

42,758,877

$160

300,000

$30

$480

Cumulative Preferred Stock

PGE has authorized 30 million shares of cumulative preferred stock, no par value; there are 300,000 shares of the 7.75% series outstanding. The 7.75% series preferred stock has an annual sinking fund requirement, which requires the redemption of 15,000 shares at $100 per share beginning in 2002. At its option, PGE may redeem, through the sinking fund, an additional 15,000 shares each year. All remaining shares shall be mandatorily redeemed by the operation of the 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 Stock Dividend

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.

The purchase and sale agreement between Enron and Sierra requires PGE to pay dividends to Enron equal to the lesser of PGE's aggregate income available for common stock for the period January 1, 1999 through the closing date or, an amount equal to the aggregate of approximately $129 million for 1999, $143 million for 2000, and $144 million for 2001 (prorated to the date of sale). Based on net income and dividend payments made for these time periods, as of December 31, 2000, an additional cash dividend of $104 million would be due Enron under terms of the purchase and sale agreement.

Note 5 - Credit Facilities and Debt

At December 31, 2000, PGE had committed lines of credit totaling $250 million. Credit lines of $150 million, with an annual fee of 0.11%, expire in July 2003; credit lines of $100 million, with an annual fee of 0.085%, expire in July 2001. These lines of credit, which do not require compensating cash balances, are used primarily as backup for both commercial paper and borrowings from commercial banks under uncommitted lines of credit.

Unused committed lines of credit must be at least equal to the amount of PGE's commercial paper outstanding. Commercial paper and lines of credit borrowings are at rates reflecting current market conditions. Short-term borrowings and related interest rates were as follows:

2000

1999

As of year-end:

(Millions of Dollars)

Aggregate short-term debt outstanding

Commercial paper

$ 16

$ 266

Weighted average interest rate*

Commercial paper

6.8%

6.1%

Committed lines of credit

$ 250

$ 300

For the year ended:

Average daily amounts of short-term debt outstanding

Commercial paper

$ 120

$ 162

Weighted daily average interest rate*

Commercial paper

6.2%

5.5%

Maximum amount outstanding

during the year

$ 278

$ 266

* Interest rates exclude the effect of commitment fees, facility fees and other financing fees.

The Indenture securing PGE's First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property.

 Schedule of long-term debt at December 31

2000

1999

 

(Millions of Dollars)

First Mortgage Bonds

   
 

Maturing 2000 - 2005 6.47% - 9.07%

$ 163

$ 170

 

Maturing 2007 7.15%

50

68

 

Maturing 2021 - 2023 7.75% - 9.46%

160

160

     

373

398

     

Pollution Control Bonds

   
 

Port of Morrow, Oregon, variable rate, due 2031

   
   

(Average rate 4.3% for 2000, 3.4% for 1999)

6

6

 

Port of Morrow, Oregon, variable rate, due 2033

   
   

(4.60% fixed rate to 2003)

23

23

 

City of Forsyth, Montana, variable rate, due 2033

   
   

(4.60% - 4.75% fixed rate to 2003)

119

119

 

Port of St. Helens, Oregon, variable rate due 2010 & 2014

   
   

(4.80% - 5.25% fixed rate to 2003)

47

47

 

Port of St. Helens, Oregon, due 2014 (7.13% fixed rate)

   5 

    5

     

200

200

     

Other

   
 

8.25% Junior Subordinated Deferrable Interest Debentures,

   
   

due December 31, 2035

75

75

 

6.91% Conservation Bonds maturing monthly to 2006

53

61

 

7.875% Notes due March 15, 2010

150

-

 

Unamortized debt discounts

  (1)

(1)

     

277

135

   

850

733

 

Long-term debt due within one year

 (52)

 (32)

Total long-term debt

$ 798

$ 701

The following principal amounts of long-term debt (excluding commercial paper) become due through regular maturities (millions of dollars):

 
   

2001

2002

2003

2004

2005

 

Maturities:

         

PGE

$52

$23

$49

$55

$28

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.

The estimated fair values of debt and equity instruments are as follows (millions of dollars):

 

2000

1999

 

Carrying

Amount

Fair

Value

Carrying

Amount

Fair

Value

Preferred stock subject to mandatory redemption

$ 30

$ 30

$ 30

$ 32

         

Long-term debt including current maturities

$850

$869

$733

$714

 

Note 7 - Commitments

Natural Gas Agreements

PGE has entered into agreements for the purchase, sale, and transmission of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities, requiring net payments of approximately $162 million in 2001, $72 million in 2002, $15 million in 2003 through 2005, and $93 million over the remaining years of the contracts. These contracts expire at varying dates from 2001 to 2015.

Purchase Commitments

Certain commitments have been made related to capital expenditures planned for 2001. As of December 31, 2000, total commitments of approximately $80 million have been made for system construction, hydro re-licensing, and information systems. 

Coal Agreements

PGE has coal agreements with take-or-pay obligations totaling approximately $8 million for 2001.

Purchased Power

PGE has long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon. PGE is required to pay its proportionate share of the operating and debt service costs of the hydro projects whether or not they are operable.

Selected information is summarized as follows (millions of dollars):

 

Rocky

Reach

Priest

Rapids

 

Wanapum

 

Wells

Portland

 Hydro

Revenue bonds outstanding at

         

December 31, 2000

$214

$165

$180

$178

$ 31

PGE's current share of:

         
 

Output

12.0%

13.9%

18.7%

20.3%

100%

 

Net capability (megawatts)

154

133

194

171

36

Annual cost, including debt service:

         
 

2000

$ 7

$ 4

$ 6

$ 6

$ 4

 

1999

6

4

6

6

4

 

1998

6

4

6

6

4

Contract expiration date

2011

2005

2009

2018

2017

PGE's share of debt service costs, excluding interest, will be approximately $7 million for 2001, $8 million for 2002, $9 million for 2003, and $7 million for 2004 and 2005. The minimum payments through the remainder of the contracts are estimated to total $59 million.

PGE has entered into power purchase and sale contracts with other utilities, requiring net payments of approximately $603 million in 2001, $187 million in 2002, $36 million in 2003, and $19 million in 2004 and 2005. After that date, contract charges will average $20 million annually until 2016.

 Leases

PGE has operating lease arrangements for its headquarters complex, coal-handling facilities and certain railroad cars for Boardman. PGE's aggregate rental payments charged to expense amount to $20 million for 2000, $24 million for 1999, and $23 million for 1998.

Future minimum lease payments under non-cancelable leases are as follows (millions of dollars):

 

Year Ending

December 31

Operating Leases

(Net of Sublease Rentals)

2001

$  20

2002

       9

2003

       9

2004

    10

2005

      8

Remainder

  148

Total

$204

Included in the future minimum operating lease payments schedule above is approximately $104 million for PGE's headquarters complex.

Note 8 - Price Risk Management

PGE is exposed to market risk arising from the need to purchase power to meet the needs of its retail customers and to purchase fuel for its natural gas fired generating units. The Company uses instruments such as forward contracts, options, and swaps to mitigate risk that arises from market fluctuations of commodity prices. In 2000, PGE expanded the use of such instruments for trading purposes. Instruments utilized in connection with these trading activities are accounted for as prescribed by Issue 98-10 of the Emerging Issues Task Force of the Financial Accounting Standards Board ("EITF 98-10"). Under EITF 98-10, the Company's portfolio of electric forward contracts and natural gas swaps with third parties used in its trading activities are reflected at fair value, with gains and losses included in earnings and shown as"Assets and liabilities from price risk management activities" in the Consolidated Balance Sheet. Changes in assets and liabilities from energy trading activities result primarily from changes in the valuation of the portfolio of contracts, newly originated transactions, and the timing of settlement. Market prices used to value these transactions reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors underlying the commitments.

Unrealized gains and losses from newly originated contracts and the impact of price movements are recorded within "Purchased power and fuel" on the Income Statement. In 2000, an unrealized net gain of $16 million on electricity forward contracts was recorded, partially offset by an unrealized $3 million net loss on natural gas swaps.

The fair value as of December 31, 2000, and the average fair value of instruments related to price risk management trading activities held during the year are set forth below:

     

Average Fair Value

 

Fair Value

 

for the Year Ended

 

as of 12/31/2000

 

12/31/2000(a)

(Dollars in Millions)

Assets

 

Liabilities

 

Assets

 

Liabilities

Electric forward contracts

$ 270

 

$ 254

 

$ 78

 

67

Natural gas swaps

9

 

12

 

4

 

5

Total

$ 279

 

$ 266

 

$ 82

 

$ 72

(a) Computed using the balances at each month-end.

 

Note 9 - Jointly Owned Plant

At December 31, 2000, PGE had the following investments in jointly owned generating plants (millions of dollars):

 

Facility

 

Location

 

Fuel

MW

Capacity

PGE %

Interest

Plant

In Service

Accumulated

Depreciation

Boardman

Boardman, OR

Coal

   561

65.0

$ 391

$232

Colstrip 3&4

Colstrip, MT

Coal

1,556

20.0

  456

  263

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. The Company's share of the direct expenses of these plants is included in the corresponding operating expenses in the consolidated statements of income.

In April 2000, the Confederated Tribes of Warm Springs (Tribes) and PGE executed an agreement that would result in shared ownership and control of PGE's 408-MW Pelton Round Butte hydroelectric project, which provides about 20% of the Company's power-generating capacity. The agreement with the Tribes, which was approved by the OPUC in August 2000, provides for increased ownership by the Tribes over a proposed 50-year license period, which PGE and the Tribes are now jointly pursuing with the FERC. The Tribes will initially purchase a one-third interest at the net depreciated book value on December 31, 2001. PGE will continue to operate the project.

Note 10 - Legal Matters

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

Numerous challenges, appeals and requested reviews have been filed in Marion County, Oregon Circuit Court, Oregon Court of Appeals and with the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of and a return on the Trojan investment. The primary plaintiffs in the litigation are the Citizens' Utility Board (CUB) and the Utility Reform Project (URP). Rulings issued to date by the Circuit Court and the Court of Appeals have been inconsistent on the issue. The Court of Appeals issued the latest ruling in 1998 stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upheld the OPUC's authorization of PGE's recovery of the Trojan investment. PGE and the OPUC requested the Oregon Supreme Court to conduct a review of the Court of Appeals' decision on the return on investment issue. In addition, URP requested the Oregon Supreme Court to review the Court of Appeals decision on the return of investment issue. The Supreme Court has indicated it will conduct a review.

 In 2000, PGE entered into settlement agreements with CUB and the staff of the OPUC of the litigation related to PGE's recovery of its investment in the Trojan plant. Under the agreements, CUB agreed to withdraw from the litigation and support the settlement as the means to resolve the Trojan litigation. The settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consist of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and about $80 million remaining obligation under terms of the Enron/PGC merger. The settlement also allows PGE recovery of approximately $47 million in income tax benefits related to the Trojan investment which had been flowed to customers in prior years; such amount is being recovered from PGE customers, with no return on the unamortized balance, over an approximate five year period. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. The URP has challenged the settlement agreements and the OPUC order. Collection of decommissioning costs at Trojan is unaffected by the settlement agreements or the OPUC order.

With CUB's withdrawal, the URP is the one remaining significant adverse party in the litigation. The URP has indicated it plans to continue to challenge the orders that allow PGE recovery of and a return on its investment in Trojan. The Oregon Supreme Court's review is on hold pending resolution of the URP's latest challenge with the OPUC.

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

 Other Legal Matters - PGE is party to various other claims, legal actions and complaints arising in the ordinary course of business. These claims are not material.

 

Note 11 - Trojan Nuclear Plant

 Plant Shutdown and Transition Costs - PGE is a 67.5% owner of Trojan. In early 1993, PGE ceased commercial operation of the nuclear plant. Since plant closure, PGE has committed itself to a safe and economical transition toward a decommissioned plant. Transition costs associated with operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage will be paid from current operating funds. Delays have extended the expected completion date of transferring the fuel to dry storage through 2003.

 

TROJAN DECOMMISSIONING LIABILITY

(Millions of Dollars)

 

 

Estimate - 12/31/94

$351

Updates filed with NRC - 11/16/95

7

Updates filed with OPUC - 12/01/97

(19)

Updates filed with OPUC - 10/02/00

(2)

 

337

Expenditures through 12/31/00

(140)

Liability - 12/31/00

197

Transition costs

21

Total Trojan obligation

$218

Decommissioning - In October 2000, PGE filed an updated decommissioning plan estimate with the OPUC. The plan estimates PGE's cost to decommission Trojan at $337 million reflected in nominal dollars (actual dollars expected to be spent in each year). The primary reason for the reduction from the $351 million 1994 estimate is a lower inflation rate, coupled with the acceleration of certain decommissioning activities and partially offset by cost increases related to the spent fuel storage project. The current estimate assumes that the majority of decommissioning activities will occur between 1998 and 2004, while fuel management costs extend through the year 2018. The original plan represents a site-specific decommissioning estimate performed for Trojan by an engineering firm experienced in estimating the cost of decommissioning nuclear plants. Updates to the plan's original estimate have been prepared by PGE. Final site restoration activities are anticipated to begin in 2018 after PGE completes shipment of spent fuel to a USDOE facility (see the Nuclear Fuel Disposal discussion below). Stated in 2000 dollars, the decommissioning cost estimate is $300 million.

DECOMMISSIONING TRUST ACTIVITY

(Millions of Dollars)

2000

1999

Beginning Balance

$42

$72

Activity

Contributions

15

14

Gain

2

-

Disbursements

(26)

(44)

Ending Balance

$33

$42

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 2000 to cover the costs of general decommissioning and activities in support of the independent spent fuel storage installation. Decommissioning funds are invested in investment-grade preferred stock, tax-exempt bonds, 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.

 

 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 nine of the 15 annual payments with the first payment made in September 1993.

 Nuclear Insurance - The Price-Anderson Amendment of 1988 limits public liability claims that could arise from a nuclear incident and provides for loss sharing among all owners of nuclear reactor licenses. Because Trojan has been permanently defueled, the NRC has exempted PGE from participation in the secondary financial protection pool covering losses in excess of $200 million at other nuclear plants. In addition, the NRC has reduced the required primary nuclear insurance coverage for Trojan from $200 million to $100 million following a 3 year cool-down period of the nuclear fuel that is still on-site. The NRC has allowed PGE to self-insure for on-site decontamination. PGE continues to carry non-contamination property insurance on the Trojan plant at the $158 million level.

Note 12 - Related Party Transactions

As part of its ongoing operations, PGE receives management services from Enron and provides incidental services to Enron and its affiliated companies. In 2000, approximately $35 million was paid to Enron for allocated overhead and other direct costs, including $5 million for retirement savings plan matching, $7 million for medical and dental benefits, and $4 million for the Employee Stock Option Plan. In 1999, PGE paid $23 million to Enron for allocated overhead and other direct costs, including PGE's $4 million share of the Employee Stock Option Plan. In 1998, PGE paid $17 million to Enron for management services, including $5 million for employee stock options. In 2000, PGE electricity purchases from and sales to an Enron affiliate totaled $205 million and $206 million, respectively; in 1999, such purchases and sales both totaled $33 million, with no purchases or sales in 1998.

Note 13 - Receivables - California Wholesale Market

As of December 31, 2000, PGE had approximately $119 million of accounts receivable that may be affected by the financial condition of two major California utilities. A balance of approximately $60 million was owed by Southern California Edison Company (SCE) under terms of a 1996 agreement providing for the termination of a Power Sales Agreement between the two companies. In addition, a balance of approximately $59 million was owed the Company by the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales. The Company estimates that approximately 70%-80% of such sales were to SCE and Pacific Gas & Electric Company (PG&E), major participants with other California utilities in the ISO and PX for the purchase of wholesale electricity.

Significant increases in wholesale power prices in 2000 and in early 2001, due in part to a sharp increase in natural gas prices paid by generators in producing electricity, has severely affected the financial stability of both SCE and PG&E. Recently, the utilities' wholesale power purchase costs have greatly exceeded revenues collected from customers through rates that are currently frozen, requiring the utilities to finance the majority of their power purchase costs.

Adverse reaction of the credit markets to continued regulatory uncertainty over SCE's and PG&E's ability to recover their power procurement costs has materially and adversely affected their liquidity. Both companies have recently defaulted on financial obligations and their ability to make future payments to PGE is in question. Unless legislative or regulatory actions are taken, the utilities may be unable to secure additional sources of financing and may have to seek protection of the bankruptcy courts.

SCE has made its scheduled 2001 payments to date under the termination agreement. PGE continued to make limited sales to the ISO and PX in early 2001 primarily under federal order. The ISO made its scheduled January 2001 payment; however, PGE received approximately 24% of the $8.2 million payment due in early February. The PX paid approximately 77% of the $1.6 million due in January, and has delayed payment of the $7.6 million amount due in February. The total balance due from both the ISO and PX is approximately $75 million as of February 21, 2001. PGE is pursuing collection of all past due amounts.

Although the Company has established general credit reserves for amounts due under its wholesale electricity contracts, no reserves have been specifically provided for amounts due from SCE under the termination agreement or from the ISO and PX for wholesale power sales to SCE and PG&E. Although some wholesale power sales may be mandated by the federal government, PGE management continues to evaluate and monitor the prudency of future sales to the California market.

The Company has numerous options available to pursue collection of any amounts ultimately not received, including legal, regulatory or other means. Due to the uncertainties surrounding the financial stability of SCE and PG&E and the California power situation, management cannot predict the ultimate realization of these receivables, nor can it reasonably estimate any possible loss.

Management believes that the ultimate outcome of these matters will not have a material adverse impact on the financial condition of the Company. However, it may have a material impact on the results of operations for future reporting periods.

 

QUARTERLY COMPARISON FOR 2000 AND 1999 (Unaudited)

           
           
 

March 31

June 30

September 30

December 31

Total

 

(Millions of Dollars)

2000

         

Operating revenues

$397

$430

$728

$698

$2,253

Net operating income

51

41

54

60

206

Net income

39

25

32

45

141

Income available for

         
 

common stock

38

25

31

45

139

           
           

1999

         

Operating revenues

$299

$294

$408

$377

$1,378

Net operating income

58

40

39

53

190

Net income

45

26

24

33

128

Income available for

         
 

common stock

44

25

24

33

126

 

 

Item 9. Changes in and Disagreements with Accountants on  

Accounting and Financial Disclosure

None.

 

Part III

 

Item 10. Directors and Executive Officers of the Registrant

Directors of the Registrant (*)

JAMES V. DERRICK, JR., age 56

Director since 1997

Mr. Derrick has served as Executive Vice President and General Counsel of Enron since July 1999, and as Senior Vice President and General Counsel from June 1991 until July 1999. Mr. Derrick was a partner at the law firm of Vinson & Elkins L.L.P. for over 13 years prior to joining Enron in 1991.

PEGGY Y. FOWLER, age 49

Director since 1998

Ms. Fowler has served as Chief Executive Officer of Portland General Electric Company since April 2000 and as President since 1997. She served as Executive Vice President and Chief Operating Officer of Portland General Electric from November 1996 until June 1997. Ms. Fowler also serves on the boards of George Fox University, Portland Streetcar, Inc., Nature Conservancy, Oregon Business Council, Oregon Independent College Foundation, Regence Blue Cross/Blue Shield, PGE/Enron Foundation, Goodwill Industries, Legacy Health System, and Western Energy Institute.

KEN L. HARRISON, age 58

Director since 1987

Mr. Harrison serves as a Director of Enron and has served as Chairman of Portland General Electric Company since 1988. He served as Chief Executive Officer from 1988 until his retirement on March 31, 2000 from Portland General Electric Company. 

KENNETH L. LAY, age 58

Director since 1997

Mr. Lay has served as Chairman of the Board of Enron since February 1986 and served as Chief Executive Officer of Enron from February 1986 until February 2001. Mr. Lay is also a Director of Eli Lilly and Company, Compaq Computer Corporation, EOTT Energy Corp. (the general partner of EOTT Energy Partners, L.P.), i2 Technologies, Inc. and The New Power Company.

JEFFREY K. SKILLING, age 47

Director since 1997

Mr. Skilling was elected Chief Executive Officer of Enron on February 12, 2001. Mr. Skilling served as President and Chief Operating Officer from January 1997 to February 2001. 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 executive managerial positions. Mr. Skilling is also a director of the Houston Branch of the Federal Reserve Bank of Dallas.

(*) Directors of PGE hold office until the next annual meeting of shareholders or until their respective successors are duly elected and qualified.

 

Executive Officers of the Registrant (*)

Name

 

Age

 

Business Experience

Ken L. Harrison

Chairman

 

58

 

Appointed to current position of Chairman on December 7, 1988. Served as Chief Executive Officer from 1988 until his retirement on March 31, 2000.

Peggy Y. Fowler

President and Chief

Executive Officer

 

49

 

Appointed to current position on April 1, 2000. Served as President and Chief Operating Officer from June 1997 until appointed to current position. Served as Executive Vice President and Chief Operating Officer, PGE from November 1996 until June 1997. Served as Senior Vice President, Customer Service and Delivery from September 1995 until November 1996. Served as Vice President, Distribution and Power Production from January 1990 to September 1995.

Alvin L. Alexanderson

Senior Vice President,

General Counsel and Secretary

 

53

 

Appointed to current position on December 12, 1995. Served as Vice President, Rates and Regulatory Affairs from February 1991 until appointed to current position.

Frederick D. Miller

Senior Vice President

Public Policy and Administrative

Services

 

58

 

Appointed to current position on November 5, 1996. Served as Vice President, Public Affairs and Corporate Services from October until November 1996. Served as Director of Executive Department, State of Oregon, from 1987 until October 1992.

Walter E. Pollock

Senior Vice President

Power Supply

 

58

 

Appointed to current position on October 14, 1997. Served as Vice President, Enron 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.

Arleen N. Barnett

Vice President

Human Resources

 

48

 

Appointed to current position on February 1, 1998. Served as Manager, Generating Division from 1987 to 1989 and Manager, Human Resources Operations from 1989 until appointed to current position.

David K. Carboneau

Vice President

Retail Services

 

54

 

Appointed to current position in October 1998. Served as President of First Point Utility Solutions until appointed to current position. Served as Vice President, Utility Service and Telecommunications from January 1997 until July 1997. Served as Vice President, Information Technology from January 1996 until January 1997. Served as Vice President, Thermal and Power Operations from September 1995 to January 1996. Served as Vice President, PGE Administration from October 1992 to September 1995.

Stephen R. Hawke

Vice President

Delivery System Planning

and Engineering 

 

51

 

Appointed to current position on July 1, 1997. Served as General Manager, System Planning and Engineering until appointed to current position. Served as Manager, Response and Restoration from May 1993 until May 1995.

Ronald W. Johnson

Vice President

Power Supply/Resource Development

and Engineering Services

50

Appointed to current position on January 30, 2001. Served as Vice President, Deputy General Counsel and Assistant Secretary from May 1, 1999 until appointed to current position. In 1989 became Deputy General Counsel, managing the Legal Department.

Pamela G. Lesh

Vice President

Rates and Regulatory Affairs

 

44

 

Appointed to current position on December 31, 1998. Served as Vice President, Strategy and Product Management with ConneXt Corp. of Seattle from June 1997 until appointed to current position. Previously served at PGE as Vice President, Rates and Regulatory Affairs from November 1996 to June 1997. Served as Director, Regulatory Policy, from August 1989 to October 1996.

Joe A. McArthur

Vice President

Substation and Line Crew

Operations

 

53

 

Appointed to current position on July 1, 1997. Served as Manager of Western Region from May 1996 until appointed to current position. Served as Manager, System Planning from May 1995 to May 1996. Served as Commercial and Industrial Market Manager from 1993 to 1995.

James J. Piro

Vice President,

Chief Financial Officer

and Treasurer

 

48

 

Appointed to current position on November 1, 2000. Served as Vice President Business Development from February 1998 until appointed to current position. Served as General Manager, Planning Support and Analysis from 1992 until 1998.

Stephen M. Quennoz

Vice President

Power Supply/Generation

 

53

 

Appointed to current position on January 30, 2001. Served as Vice President Nuclear and Thermal Operations from October 1998 until appointed to current position. Joined PGE in 1991 and held the position of Trojan Site Executive and Plant General Manager since 1993.

Christopher D. Ryder

Vice President

Customer Service

Delivery

 

51

 

Appointed to current position on July 1, 1997. Served as General Manager, Customer Services and Southern Region Operations from 1996 until appointed to current position. Served as General Manager, Customer Services, Marketing and Sales from 1992 to 1996.

Carl B. Talton

Vice President

Government Affairs and

Economic Development

 

56

 

Appointed to current position May 1, 1999. Joined PGE in July 1998 as Director of Economic Development. Prior to that worked 25 years for PacificCorp, where he held several management positions.

Mary K. Turina

Vice President

Power Supply/Power Operations

 

33

 

Appointed to current position on November 1, 2000. Served as Vice President Finance, Chief Financial Officer and Treasurer from September 1999 until appointed to current position. Served as Controller, Chief Accounting Officer, Treasurer, and Principal Financial Officer from May 1999 to September 1999. Served as Controller and Assistant Treasurer from July 1998 to May 1999. Served as Manager of Risk Management, Reporting and Control from 1996 to 1998.

(*) Officers are listed as of February 28, 2001; 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, 2000, 1999, and 1998 by the Chief Executive Officer and the four most highly compensated executive officers of PGE.

       

Long-Term

 
   

Annual Compensation

Compensation

 
       

Restricted Stock

All Other

Name and Principal Position

Year

Salary(1)

Bonus(2)

Awards(3)

Compensation(4)

Ken L. Harrison

Chairman and Chief

Executive Officer (5)(6)

2000

1999

1998

$111,715

244,163

206,799

$ -

-

183,200

$ -

-

705,483

$113,782

28,959

12,050

Peggy Y. Fowler

President,

Chief Executive Officer

2000

1999

1998

300,002

267,502

246,664

450,000

400,000

300,000

-

-

200,004

36,710

16,646

17,443

Walter E. Pollock

Senior Vice President

Power Supply

2000

1999

1998

205,761

189,697

176,191

230,000

200,000

140,000

-

-

75,037

11,028

6,575

5,664

Frederick D. Miller

Senior Vice President, Public

Policy and Administrative

Services

2000

1999

1998

205,518

197,708

181,684

200,000

200,000

150,000

-

-

68,760

27,125

12,757

10,233

James J. Piro

Vice President,

Chief Financial Officer and

Treasurer

2000

1999

1998

171,564

169,089

157,535

150,000

110,000

128,063

-

-

50,043

9,034

5,874

5,081

David K. Carboneau

Vice President,

Retail Services

2000

1999

1998

211,499

211,498

63,353

105,002

80,000

48,000

-

-

-

14,151

8,330

2,133

(1) Amounts shown include cash compensation earned and received by the executive officer, as well as amounts earned but deferred at the election of the officer.

 (2) Bonuses include amounts, if any, converted to stock options and phantom stock at the election of the officer.

(3) Enron restricted stock awarded to Mr. Harrison on October 12, 1998 is valued at the $25.4688 per share closing price of Enron common stock on that date; one-third of the shares vest on January 31 of each of the next three years beginning in 1999. Restricted stock awarded to other officers was granted December 31, 1998, and is valued at the $28.5313 per share closing price of Enron common stock on that date. Aggregate restricted stock holdings listed below (including any annual bonus converted to Phantom stock) are valued at $83.125 per share, the closing price of the Enron common stock on December 31, 2000.

 

 

Aggregate Restricted Stock Holdings

 

Aggregate Shares (#)

Value

Peggy Y. Fowler

14,641

$1,217,033

Walter E. Pollock

1,753

145,718

Frederick D. Miller

4,733

393,431

James J. Piro

1,075

89,359

David K. Carboneau

3,930

326,681

(4) Other compensation includes: (i) company-paid split dollar insurance premiums; (ii) the dollar value of life insurance benefits;    (iii) company contributions to the Retirement Savings Plan (RSP) and the Management Deferred Compensation Plan (MDCP); and (iv) earnings on amounts in the MDCP which are greater than 120% of the federal long-term rate which was in effect at the time the rate was set.

The following are amounts for 2000:

 
 

Split Dollar Insurance Premiums

Dollar Value of Life Insurance

Contributions to 401(k) and MDCP

Above Market Interest on MDCP

 

Total

Ken L. Harrison

$ 896

$ -

$ 2,738

$ 110,148

$ 113,782

Peggy Y. Fowler

619

14,495

6,244

15,352

36,710

Walter E. Pollock

-

-

6,173

4,855

11,028

Frederick D. Miller

740

-

5,852

20,533

27,125

James J. Piro

-

-

4,867

4,167

9,034

David K. Carboneau

520

-

5,850

7,781

14,151

(5) Mr. Harrison resigned as Chief Executive Officer on March 31, 2000, remaining as Chairman.

 (6) Mr. Harrison also served as an executive officer of Enron until July 1, 1999. The compensation shown represents the amount allocable to PGE.

The following lists information concerning options to purchase shares of Enron common stock that were exercised by the officers named above during 2000 and the total options and their value held by each at December 31, 2000.

 
 

Aggregate Stock Options/SAR Exercised During 2000

And Stock Options/SAR Values at December 31, 2000

 

Shares Acquired on Exercise

 

Value Realized

 

Exercisable Options

 

Unexercisable Options

 

Exercisable Amount

 

Unexercisable Amount

Ken L. Harrison

149,032

$8,211,084

50

-

$ 1,031

$ -

Peggy Y. Fowler

21,274

1,324,578

26,935

11,743

1,501,937

671,902

Walter E. Pollock

27,186

1,250,183

7,623

4,941

431,720

284,653

Frederick D. Miller

30,578

1,443,476

4,169

4,189

259,460

259,873

James J. Piro

5,894

368,469

77,411

13,159

5,021,725

833,087

Dave K. Carboneau

7,043

285,066

12,500

1,237

780,078

63,160

Each of the named officers received a stock option grant of 50 shares during 2000. In aggregate, the grants are less than 1% of total options granted to employees during the year. The exercise price is $55.50 per share, and expire January 18, 2007. (Mr. Harrison's shares expire April 1, 2003 and have an exercise price of $62.50). The potential realized values at assumed annual stock appreciation rates of 5% and 10% for the maximum option term are $1,130 and $2,633, respectively. (The potential values of Mr. Harrison's shares are $493 and $1,034, respectively).

Estimated annual retirement benefits payable upon normal retirement at age 65 for the named executive officers are shown in the table below. Amounts in the table reflect payments from the Portland General Holdings, Inc. Pension Plan and Supplemental Executive Retirement Plan ("SERP") combined.

 

Pension Plan Table

Estimated Annual Retirement Benefit

Straight-Life Annuity, Age 65

 

   

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

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: Peggy Y. Fowler, 26; Frederick D. Miller, 8; Dave K. Carboneau, 31. 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: Peggy Y. Fowler, 54; Frederick D. Miller, 68; Dave K. Carboneau, 54.

Employment Contract

Mr. Carboneau entered into an employment agreement on July 1, 1997, the effective date of the merger between Enron and PGC, the former parent of PGE. As amended, the agreement generally provides as follows: (i) a term of four years; (ii) severance pay in the event of involuntary termination by PGE based on the greater of two years or the remainder of the term; (iii) a minimum base salary of $200,000 per year, with a minimum guaranteed annual cash incentive of $48,000; (iv) a grant to of 25,000 options to purchase shares of Enron Common Stock; (v) the failure of PGE and the employee to extend or enter into a new agreement in either case for two years will be treated as involuntary termination; (vi) a supplemental retirement benefit; (vii) in the event that the severance or other payments payable under the agreement for involuntary termination (except for an involuntary termination of the type described in clause (v) above) constitute "excess parachute payments" within the meaning of Section 280G of the Code and the employee becomes liable for any tax penalties, the employer will pay in cash to the employee an amount equal to such tax penalties and any incremental income tax liability arising from such payments, grossing up for the employee until the amount of the last gross up is less than one hundred dollars; and (viii) a noncompetition covenant.

Compensation of Directors

There are no compensation arrangements for or fees paid to Directors of PGE.

Compensation Committee Interlocks and Insider Participation

The Compensation and Management Development Committee of the Enron Board of Directors is responsible for developing and administering compensation philosophy. Salary increases, annual incentive awards and long-term incentive grants are reviewed annually to ensure consistency with Enron's total compensation philosophy. In 2000, PGE's Chairman and Chief Executive Officer, Ken L. Harrison, participated in those deliberations affecting the Company's executive officer compensation.

 

Item 12. Security Ownership of Certain Beneficial Owners

and Management

PGE is a wholly owned subsidiary of Enron.

 

Item 13. Certain Relationships and Related Transactions

There are no relationships or transactions involving PGE's directors and executive officers.

 

Part IV

 

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

 (a)

Index to Financial Statements and Financial Statement Schedules

 

Financial Statements

Page

 

Reports of Independent Public Accountants

34 - 35

 

Consolidated Statements of Income for each of the three years in the period ended December 31, 2000

36

 

Consolidated Statements of Retained Earnings for each of the three years in the period ended December 31, 2000

36

 

Consolidated Balance Sheets at December 31, 2000 and 1999

37

 

Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 2000

38

 

Notes to Financial Statements

39

 

Financial Statement Schedules

 
 

Report of Independent Public Accountants on Financial Statement Schedule

 65 

Schedule II -  Valuation and Qualifying Accounts

66

     
 

Exhibits

 
 

See Exhibit Index on Page 68 of this report.

 

(b)

Reports on Form 8-K

 
 

November 22, 2000 - Item 5. Other Events: General Rate Increase

 
 

February 22, 2001 - Item 5. Other Events: 2000 Financial Information.

 

 

Report of Independent Public Accountants

 

To the Board of Directors and Shareholder of Portland General Electric Company:

We have audited in accordance with auditing standards generally accepted in the United States the consolidated financial statements of Portland General Electric Company and its subsidiaries included in this Form 10-K and have issued our report thereon dated January 26, 2001 (except with respect to the matter discussed in Note 13, as to which the date is February 21, 2001). Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14(a) is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

Arthur Andersen LLP

Portland, Oregon

January 26, 2001

 

Portland General Electric Company and Subsidiaries

Schedule II - Consolidated Valuation and Qualifying Accounts

For The Years Ended December 31, 2000, 1999, and 1998

(Millions of Dollars)

 
 

Allowance for

 

Uncollectible

 

Accounts

   
   

Balance at January 1, 1998

$ 2

Provision charged to income

6

Amounts written off, less recoveries

(4)

Balance at December 31, 1998

4

   

Balance at January 1, 1999

4

Provision charged to income

7

Amounts written off, less recoveries

(3)

Balance at December 31, 1999

8

   

Balance at January 1, 2000

8

Provision charged to income

7

Amounts written off, less recoveries

(5)

Balance at December 31, 2000

$ 10

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

   

Portland General Electric Company

     
     

March 2, 2001

 

By

/s/ Peggy Y. Fowler

       

Peggy Y. Fowler

         
       

President and

       

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

 /s/ Peggy Y. Fowler

 

President and

   
 

Peggy Y. Fowler

 

Chief Executive Officer

 

March 2, 2001

         
           

/s/ James J. Piro

 

Vice President

 

March 2, 2001

 

James J. Piro

 

Chief Financial Officer and

   
     

Treasurer

   
         

/s/ Kirk M. Stevens

 

Controller and

 

March 2, 2001

 

Kirk M. Stevens

 

Assistant Treasurer

   
         
          
 

*James V. Derrick

       
 

*Peggy Y. Fowler

       
 

*Ken L. Harrison

 

Directors

 

March 2, 2001

 

*Kenneth L. Lay

       
 

*Jeffrey K. Skilling

       
           

 

 

*By

 

/s/ James J. Piro

   
   

(James J. Piro, Attorney-in-Fact)

   

 

PORTLAND GENERAL ELECTRIC COMPANY AND

SUBSIDIARIES

EXHIBIT INDEX

Number

 

Exhibit

     

(2)

 

Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

     
 

*

Amended and Restated Agreement and Plan of Merger, dated as of July 20, 1996 and amended and restated as of September 24, 1996 among Enron Corp., Enron Oregon Corp., and Portland General Corporation [Amendment 1 to S4 Registration Nos. 333-13791 and 333-13791-1, dated October 10, 1996, Exhibit No. 2.1].

     

(3)

 

Articles of Incorporation and bylaws

     
 

*

Copy of Articles of Incorporation of Portland General Electric Company [Registration No. 2-85001, Exhibit (4)].

     
 

*

Certificate of Amendment, dated July 2, 1987, to the Articles of Incorporation limiting the personal liability of directors of Portland General Electric Company [Form 10-K for the fiscal year ended December 31, 1987, Exhibit (3)].

     
 

*

Bylaws of Portland General Electric Company as amended on October 1, 1991 [Form 10-K for the fiscal year ended December 31, 1991, Exhibit (3)].

     
 

*

Bylaws of Portland General Electric Company as amended on May 1, 1998 [Form 10-K for the fiscal year ended December 31, 1998, Exhibit (3)].

     

(4)

 

Instruments defining the rights of security holders, including indentures

     
 

*

Portland General Electric Company Indenture of Mortgage and Deed of Trust dated July 1, 1945.

     
 

*

Fortieth Supplemental Indenture dated October 1, 1990 [Form 10-K for the fiscal year ended December 31, 1990, Exhibit (4)].

     
 

*

Forty-First Supplemental Indenture dated December 1, 1991 [Form 10-K for the fiscal year ended December 31, 1991, Exhibit (4)].

     
 

*

Forty-Second Supplemental Indenture dated April 1, 1993 [Form 10-Q for the quarter ended March 31,1993, Exhibit (4)].

     
 

*

Forty-Third Supplemental Indenture dated July 1, 1993 [Form 10-Q for the quarter ended September 30, 1993, Exhibit (4)].

     
 

*

Forty-Fifth Supplemental Indenture dated May 1, 1995 [Form 10-Q for the quarter ended June 30, 1995, Exhibit (4)].

PORTLAND GENERAL ELECTRIC COMPANY AND

SUBSIDIARIES

EXHIBIT INDEX

Number

 

Exhibit

     

(4)

   

Cont

   
   

Other instruments, which define the rights of holders of long-term debt not required to be filed, herein, will be furnished upon written request.

     

(10)

 

Material Contracts

     
 

*

Residential Purchase and Sale Agreement with the Bonneville Power Administration [Form 10-K 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)].

PORTLAND GENERAL ELECTRIC COMPANY AND

SUBSIDIARIES

EXHIBIT INDEX

Number

 

Exhibit

     

(10)

   

Cont

   
 

*

Tax Indemnification Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

Trust Indenture, Mortgage and Security Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

Trust Indenture, Mortgage and Security Agreement dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

Restated and Amended Trust Indenture, Mortgage and Security Agreement dated February 27, 1986 [Form 10-K for the fiscal year ended December 31, 1997, Exhibit (10)].

     
 

*

Portland General Holdings, Inc. Outside Directors' Deferred Compensation Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10].

     
 

*

Portland General Holdings, Inc. Retirement Plan for Outside Directors, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10].

     
 

*

Portland General Holdings, Inc. Outside Directors' Life Insurance Benefit Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10].

     
 

Executive Compensation Plans and Arrangements

     
 

*

Portland General Holdings, Inc. Management Deferred Compensation Plan, 1997 Restatement dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10].

     
 

*

Portland General Holdings, Inc. Senior Officers Life Insurance Benefit Plan, 1997 Restatement Amendment No. 1 dated June 25, 1997 [Form 10-K for fiscal year ended December 31, 1997, Exhibit 10].

     
 

*

Portland General Electric Company Annual Incentive MasterPlan [Form 10-K for the fiscal year ended December 31, 1987, Exhibit (10)].

PORTLAND GENERAL ELECTRIC COMPANY AND

SUBSIDIARIES

EXHIBIT INDEX

Number

 

Exhibit

     

(10)

   

Cont

   
 

*

Portland General Electric Company Annual Incentive MasterPlan, 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].

     

(23)

Consents of Arthur Andersen LLP - Filed herewith.

   

(24)

 

Power of Attorney

     
   

Portland General Electric Company Power of Attorney (filed herewith).

   

Unanimous Written Consent of Directors (filed herewith).

 

* Incorporated by reference as indicated.

Note:

 

The Exhibits furnished to the Securities and Exchange Commission with the Form 10-K will be supplied upon written request and payment of a reasonable fee for reproduction costs. Requests should be sent to:

     
   

Kirk M. Stevens

Controller and Assistant Treasurer

Portland General Electric Company

121 SW Salmon Street, 1WTC0501

Portland, OR 97204

 

Consents of Independent Public Accountants

 As independent public accountants, we hereby consent to the incorporation of our report dated January 26, 2001, (except with respect to the matter discussed in Note 13, as to which the date is February 21, 2001), included in this Form 10-K, into Portland General Electric Company's previously filed Registration Statements File Nos. 333-77469 and 333-56062. 

 Arthur Andersen LLP

Portland, Oregon

March 2, 2001

 

POWER OF ATTORNEY

PORTLAND GENERAL ELECTRIC COMPANY

 

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by the Company of its Annual Report on Form 10-K for the year ended December 31, 2000, with the Securities and Exchange Commission, the undersigned director(s) of the Company hereby constitute and appoint Alvin L. Alexanderson and James J. Piro, and each of them with full power (any one of them acting alone), as true and lawful attorneys-in-fact and agents, for and on behalf and in the name, place, and stead of the undersigned, in any and all capacities, to sign, execute, and file such Annual Report on Form 10-K, together with all amendments or supplements thereto, with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto each above-mentioned individual the full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, hereby ratifying and confirming all the said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

Effective as of February 28, 2001.

 

/s/ James V. Derrick, Jr.

 

/s/ Peggy Y. Fowler

                James V. Derrick, Jr.

 

                         Peggy Y. Fowler

 

/s/ Ken L. Harrison

 

/s/ Kenneth L. Lay

                    Ken L. Harrison

 

                          Kenneth L. Lay

 

/s/ Jeffrey K. Skilling

                   Jeffrey K. Skilling

 

 

PORTLAND GENERAL ELECTRIC COMPANY

Unanimous Written Consent of Directors

The undersigned, constituting all of the directors of PORTLAND GENERAL ELECTRIC COMPANY, an Oregon corporation, in accordance with the provisions of Section 60.341 of the Oregon Revised Statutes, do hereby consent to the adoption of the following resolutions and, upon execution of this consent or a counterpart hereof by each of the directors listed below, do hereby adopt such resolutions:

 RESOLVED, that the Board of Directors of Portland General Electric Company (the "Company"), hereby approves the draft Portland General Electric Company 2000 Annual Report on Form 10-K ("Form 10-K"), in substantially the form as presented, with such changes as may be necessary and as approved by management and the Company's independent public accountants; and further

 RESOLVED FURTHER, that Alvin Alexanderson and James J. Piro (the "Authorized Officers"), individually, are hereby appointed as attorney-in-fact for the members of this Board as authorized by the Power of Attorney executed this day and each are authorized and directed to execute on behalf of the Boards and file the final Form 10-K with the SEC; and further

 RESOLVED FURTHER, that the Form 10-K shall be executed on behalf of the Boards by its attorney-in-fact appointed in the foregoing resolution upon compliance with and in accordance with the preceding resolutions, and, upon execution, the officers named in the preceding resolution, individually, are hereby authorized and directed to file, or cause to be filed, the Form 10-K with the SEC; and further

RESOLVED FURTHER, that the proper officers of the Company, and its respective counsel be, and each of them hereby is, authorized, empowered, and directed (any one of them acting alone) to take any and all such further action, to amend, execute, and deliver all such further instruments and documents, for and in the name and on behalf of the Company, under such Company's corporate seal or otherwise, and to pay all such expenses as in their discretion appear to be necessary, proper, or advisable to carry into effect the purposes and intentions of this and each of the foregoing resolutions and to perform the obligations of the Company under all instruments executed on behalf of the Company in connection with the transactions contemplated hereby;

 RESOLVED FURTHER, that the execution by any of said Authorized Officers of any document authorized by the foregoing resolutions or any document executed in the accomplishment of any action or actions so authorized, is (or shall become upon delivery) the enforceable and binding act and obligation of the Company, without the necessity of the signature or attestation of any other officer of the Company, or the affixing of the Company's seal thereto; and

RESOLVED FURTHER, that all acts, transactions, or agreements undertaken prior to the adoption of these resolutions by any of the Authorized Officers or representatives of the Company in the name and for the account of such company in connection with the foregoing matters are hereby ratified, confirmed, and adopted by the Company.

Dated effective as of February 28, 2001.

 

/s/ James V. Derrick, Jr.

 

James V. Derrick, Jr.

 

 

/s/ Peggy Y. Fowler

 

Peggy Y. Fowler

 

 

/s/ Ken L. Harrison

 

Ken L. Harrison

 

 

/s/ Kenneth L. Lay

 

Kenneth L. Lay

 

 

/s/ Jeffrey K. Skilling

 

Jeffrey K. Skilling