PORTLAND GENERAL ELECTRIC COMPANY 2001 FORM 10-K

 

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, 2001

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)

 

Registrant'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 each 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 March 31, 2002: $0.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of March 31, 2002: 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 to the financial statements are defined below:

Abbreviations or Acronyms

AFDC

 . . . . . . . . . . . . . . . . . . . . .

Allowance For Funds Used During Construction

Bankruptcy Court

. . . . . . . . . . . .

United States Bankruptcy Court For The Southern District of New York

Beaver

 . . . . . . . . . . . . . . . . . . . . .

Beaver Combustion Turbine Plant

Boardman

 . . . . . . . . . . . . . . . .

Boardman Coal Plant

BPA

. . . . . . . . . . . . . . . . . . . . . . . . .

Bonneville Power Administration

COBRA

. . . . . . . . . . . . . . . . . . . .

Consolidated Omnibus Budget Reconciliation Act

Colstrip

. . . . . . . . . . . . . . . . . . . . 

Colstrip Units 3 and 4 Coal Plant

Coyote Springs

 . . . . . . . . . . . . . 

Coyote Springs Generation Plant

CUB

. . . . . . . . . . . . . . . . . . . . . . . . .

Citizens' Utility Board

DEQ

. . . . . . . . . . . . . . . . . . . . . . . . . 

Oregon Department of Environmental Quality

Dth

 . . . . . . . . . . . . . . . . . . . . . . .

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

EFSC

 . . . . . . . . . . . . . . . . . . . . . . .

Energy Facility Siting Council

Enron

 . . . . . . . . . . . . . . . . . . . . . . .

Enron Corp., as Debtor and Debtor in Possession in Chapter 11, Case No. 01-16034 pending in the US Bankruptcy Court For The Southern District of New York

EPA

. . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Protection Agency

ERISA

. . . . . . . . . . . . . . . . . . . . . .

Employee Retirement Income Security Act

ESA

. . . . . . . . . . . . . . . . . . . . . . . . .

Endangered Species Act

FERC

 . . . . . . . . . . . . . . . . . . . . . . . 

Federal Energy Regulatory Commission

Financial Statements

 . . . . . . . . . .

Financial Statements of Portland General Electric Company included in Part II, Item 8 of this report

IRC

. . . . . . . . . . . . . . . . . . . . . . . . .

Internal Revenue Code

IRS

. . . . . . . . . . . . . . . . . . . . . . . . .

Internal Revenue Service

kWh

. . . . . . . . . . . . . . . . . . . . . . . . .

Kilowatt-Hour

MW

 . . . . . . . . . . . . . . . . . . . . . . . . . .

Megawatt

MWa

  . . . . . . . . . . . . . . . . . . . . . . 

Average megawatts

MWh

. . . . . . . . . . . . . . . . . . . . . . .

Megawatt-hour

NRC

 . . . . . . . . . . . . . . . . . . . . . . . .

Nuclear Regulatory Commission

NW Natural

. . . . . . . . . . . . . . .

Northwest Natural Gas Company

NYMEX

. . . . . . . . . . . . . . . . . .

New York Mercantile Exchange

OPUC or the Commission

 . . . . . . 

Public Utility Commission of Oregon

PBGC

. . . . . . . . . . . . . . . . . . . . .

Pension Benefit Guaranty Corporation

PGE or the Company

  . . . . . . .

Portland General Electric Company

PUHCA

  . . . . . . . . . . . . . . . . . 

Public Utility Holding Company Act

Regional Power Act

  . . . . . . . . .

Pacific Northwest Electric Power Planning and Conservation Act

SEC

. . . . . . . . . . . . . . . . . . . . . . .

Securities and Exchange Commission

SFAS

. . . . . . . . . . . . . . . . . . . . . . .

Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board

Trojan

. . . . . . . . . . . . . . . . . . . . . . .

Trojan Nuclear Plant

URP

. . . . . . . . . . . . . . . . . . . . . . . . .

Utility Reform Project

USDOE

  . . . . . . . . . . . . . . . .  . . .

United States Department of Energy

VEBA

 . . . . . . . . . . . . . . . .  . . . . .

Voluntary Employee Beneficiary Association

WSCC

. . . . . . . . . . . . . . . . . . . . . .

Western Systems Coordinating Council

 

TABLE OF CONTENTS

Page

Page

Definitions

2

PART I
Item 1. Business 

4

Item 2. Properties 

15

Item 3. Legal Proceedings

18

 

Item 4.

 

Submission of Matters to a Vote of Security Holders 

 

 

 

 

 

20

PART II
 Item 5.  

Market for Registrant's Common Equity and Related Stockholder Matters 

 

 

 

 

 

21

Item 6.  Selected Financial Data 

21

Item 7.  

Management's Discussion and Analysis of Financial Condition and Results of Operations

 

 

 

 

 

22

Item 7A.  

Quantitative and Qualitative Disclosures About Market Risk

 

 

 

 

 

51

Item 8.   

Financial Statements and Supplementary Data

 

 

 

53

Item 9.  

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

 

 

 

 

 

 

 

 

97

PART III
Item 10.  

Directors and Executive Officers of the Registrant 

 

 

 

98

Item 11. Executive Compensation

102

Item 12.  

Security Ownership of Certain Beneficial Owners and Management

 

 

 

 

 

105

 

Item 13.

 

Certain Relationships and Related Transactions

 

 

 

105

 

 

PART IV
Item 14.  

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

 

 

 

 

 

106

Signatures 

108

          

Part I

 

Item 1. Business

General

PGE, incorporated in 1930, is a single, integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. PGE also sells wholesale electric energy to utilities, brokers, and power marketers located throughout the western United States, the majority of which sales take place in Oregon, or at the Oregon border. PGE's service area, which is located entirely within Oregon, 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 4,095 square miles. PGE estimates that at the end of 2001 its service area population was approximately 1.5 million, comprising about 43% of the state's population. The Company added approximately 11,000 customers during 2001, and at December 31, 2001 served approximately 736,000 customers.

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

In November 1999, Enron entered into an agreement to sell PGE to Sierra Pacific Resources. This agreement was terminated in April 2001 by mutual consent, based upon the regulatory and legislative environment resulting from the effect of events in California and Nevada energy markets.

On October 5, 2001, Enron and NW Natural, an Oregon corporation principally engaged in the distribution of natural gas in portions of western Oregon and southwest Washington, entered into a Stock Purchase Agreement providing for the acquisition by NW Natural of all of the issued and outstanding common stock of PGE. The transaction is subject to a number of conditions. For further information, see "Recent Events" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 15, Proposed Acquisition of PGE by NW Natural, in the Notes to Financial Statements.

On December 2, 2001, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. PGE is not included in the filing. Both Enron and NW Natural continue to pursue regulatory approval of the sale under terms of the agreement between the two companies. However, as a result of Enron's bankruptcy, the sale cannot be completed until Enron, as Debtor in Possession, has affirmed the Stock Purchase Agreement and obtained approval by the Bankruptcy Court. For further information, see "Recent Events" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

As of December 31, 2001, PGE had 2,790 employees. This compares to 2,781 and 2,787 employees at December 31, 2000 and 1999, respectively. Currently, 922 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, 2001 through February 29, 2004.

 

 

Operating Revenues

Retail

PGE serves a diverse customer base. Residential, the largest customer class, comprises about 88% of the Company's total number of customers and about 37% of its total retail MWh energy sales. Residential, commercial, and industrial customers provide about 42%, 38%, and 20%, respectively, of retail tariff revenues. Residential demand is sensitive to the effects of weather, with revenues highest during the winter heating season. Total retail electricity sales decreased somewhat from 2000 due to a slowing economy, energy conservation, and a demand buyback program, in which the Company paid large customers to reduce their load during peak demand periods. The commercial and industrial classes are not dominated by any single industry. While the 20 largest customers constitute about 22% of retail MWh demand, they represent 8 different commercial and industrial groups, including paper manufacturing, high technology, metal fabrication, general merchandising and health services. No single customer represents more than 3.2% of PGE's total retail load.

Wholesale

Wholesale electricity sales comprised about 63% of total operating revenues in 2001, up from about 52% in 2000; the increase was due to significantly higher wholesale market prices. Most of PGE's wholesale sales, which take place in Oregon or at the Oregon border, 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 price risk, and administer its current long-term wholesale contracts. Such participation includes power purchases and sales resulting from daily economic dispatch decisions for its own generation, which allows PGE to secure power for its customers at the lowest cost available.

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

 

   

2001

2000

1999

Operating Revenues (Millions)

     
 

Residential

$   475

$   448

$   438

 

Commercial (*)

424

388

367

 

Industrial

  222

  208

  173

   

Tariff Revenues

1,121

1,044

978

   

Accrued (Collected) Revenues

   (31)

    14

    26

 

Total Retail

1,090

1,058

1,004

 

Wholesale

1,929

1,171

355

 

Other

     28

     24

     19

   

Total Operating Revenues

 $ 3,047

$ 2,253

$ 1,378

Megawatt-Hours Sold (Thousands)

     
 

Residential

7,080

7,433

7,404

 

Commercial (*)

7,285

7,527

7,392

 

Industrial

 4,675

 4,912

 4,463

   

Total Retail

19,040

19,872

19,259

   

Wholesale

13,626

18,548

12,612

     

Total MWh Sold

32,666

38,420

31,871

            (*) Includes public street lighting

 

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, equitable, and provide PGE an opportunity to earn a fair return on its investment. In addition, the Commission regulates the issuance of stock and long-term debt, prescribes the system of accounts to be kept by Oregon utilities, and reviews applications to sell utility assets and engage in transactions with affiliated companies.

In 2001, two new appointments were made to the OPUC. Roy Hemmingway replaced Ron Eachus as Chairman and former State Senator Lee Beyer replaced Roger Hamilton as a member of the Commission. Commissioner Joan Smith has served since 1990.

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

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

The NRC regulates the licensing and decommissioning of nuclear power plants. In 1993, the NRC issued a possession-only license amendment to PGE's Trojan operating license and in early 1996 approved the Trojan Decommissioning Plan. In 2001, the NRC approved PGE's License Termination Plan (LTP). The LTP outlines the process by which PGE will complete the decommissioning of the Trojan site and meet regulatory requirements for decommissioned nuclear facilities. Trojan is subject to NRC regulation until it is fully decommissioned, all nuclear fuel is removed from the site, and the license terminated. The Oregon Department of Energy also monitors Trojan. (For further information, see Note 11, Trojan Nuclear Plant, in the Notes to Financial Statements).

PGE is a subsidiary of an exempt holding company (Enron) under PUHCA, but is subject only to Section 9(a)(2) with respect to the acquisition of the securities of other public utilities. Enron has applied to the SEC to continue as an exempt holding company. If Enron does not maintain its exemption, PGE could, after notice and opportunity for a hearing by the SEC, become subject to regulation by the SEC not only with respect to the acquisition of the securities of other public utilities, but also with respect to, among other things, payment of dividends, issuance of securities, and the acquisition of assets and interests in any other business. PGE has no reason to believe that Enron will not retain its status as an exempt holding company.

Regulatory Matters

Electric Power Industry Restructuring

In 1999, Oregon's governor signed into law State Senate Bill 1149 (SB1149). As later amended for a delay in implementation to March 1, 2002, SB1149 provides all non-residential customers of investor-owned utilities direct access to competing energy suppliers. Residential and small business customers can purchase electricity from a "portfolio" of rate options that include a basic service rate, a time of use rate, and renewable resource rates. (For further information, see "Regulation and Competition" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations").

General Rate Case

The OPUC issued an order in PGE's general rate case in August 2001 that provides for approximately $440 million in additional annual revenues, primarily to cover significant increases in the cost of wholesale power and fuel used to meet its retail load requirements. The order established PGE's return on equity at 10.5% and authorized retail price increases, which became effective October 1, 2001, of approximately 31.6% for residential customers, 37.3% for smaller business customers, and 53.2% for commercial and industrial customers. The order further includes approval of a power cost adjustment mechanism for the period October 1, 2001 through December 31, 2002 that addresses the Company's exposure to changes in retail load and prices of electricity and natural gas in the wholesale energy market.

Power Cost Mechanisms

Under power cost mechanisms approved in 2001 by the OPUC, PGE is authorized to defer for future recovery or refund net variable power costs that differ from baseline amounts. Under these mechanisms, PGE shares with retail customers its 2001 and 2002 power costs outside of certain ranges. (For further information, see "Power Cost Mechanisms" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations").

Resource Plan

Under OPUC rules implementing Oregon's electric industry restructuring law, electric utilities were required to file a Resource Plan, including an evaluation of, and recommendations regarding, existing generating resources. Such recommendations were required to facilitate a fully competitive market, provide consumers fair, non-discriminatory access to competitive markets, and retain the benefit of low-cost resources for customers. PGE filed its Resource Plan in late 2000.

The OPUC has not prescribed rules governing Resource Plan updates. However, PGE is considering submitting an updated Resource Plan to the Commission this year.

RTO West and 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 proposals to form or join Regional Transmission Organizations (RTOs). In response to this order, PGE joined with other western utilities and BPA in submitting to the FERC a timetable and framework for the development of RTO West, a regional non-profit transmission organization that would operate the transmission system and manage transmission pricing in the Pacific Northwest, Nevada, and parts of neighboring states. (For further information, see "RTO West and Independent Transmission Company" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations").

 

Competition and Marketing

General

Restructuring of the electric industry is continuing at the national level, although at a slower pace due to adverse events of the past few years affecting regional energy markets. 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 market benefits to the industry, working closely with customers and regulators to achieve the goals outlined in SB1149.

Retail Competition and Marketing

PGE operates exclusively in Oregon within a state-approved service area. Competitors within the Company's service territory include the local natural gas company (NW Natural), which competes for the residential and commercial space and water heating market, and fuel oil suppliers that compete primarily for residential space heating customers. In addition, commercial and industrial customers are allowed direct access to competing electricity service suppliers under Oregon's new electric power industry restructuring law (SB1149), which became effective March 1, 2002. Under SB1149, PGE offers new market-based rates to commercial and industrial customers, with about 290 accounts (representing about 10% of commercial and industrial demand) currently enrolled. For additional information, see "Regulation and Competition" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations".

Wholesale Competition and Marketing

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

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

A 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 have contributed to increasing competitive pressure on the price of power. In addition, the development of forward markets has led to enhanced price discovery for market participants. PGE will continue its participation in the wholesale energy marketplace in order to balance its supply of power to meet the needs of its retail customers, manage price risk, and administer its current long-term wholesale contracts. In addition, the Company will continue its trading activities to take advantage of price movements in electricity and natural gas.

 

Power Supply

To meet its energy needs, PGE relies upon its existing base of generating resources, long-term power contracts, and short-term purchases that together provide flexibility to respond to consumption changes and Oregon's restructuring law (SB1149). Short-term purchases include both secondary and firm purchases for periods of less than one year in duration. The balanced nature of this portfolio has enabled the Company to manage price risk and enhance its ability to provide reliable, flexible, and reasonably-priced energy to its customers.

In the last half of 2000 and first half of 2001, both the cost and availability of power were adversely affected by a reduction in the availability of surplus generation and weather conditions in California and the Southwest that resulted in high demand. In addition, higher natural gas prices and poor Northwest hydro conditions (accentuated by fish protection spill requirements) further resulted in increased costs and reduced supply. Since mid-2001, however, additional generation from both new plants and from those returning to service, moderating weather conditions, additional natural gas supplies, federal price mitigation, and a reduction in demand from a slowing economy and conservation efforts have together resulted in significantly lower market prices for both electricity and natural gas. These events have affected the balance of market supply and demand, and several independent power producers have delayed or cancelled plans for new generating plants.

Northwest hydro conditions continue to have a significant impact on the region's power supply, with water conditions a significant factor in the ability of the Company to economically displace more expensive thermal generation and spot-market power purchases. Current forecasts indicate a return to near normal conditions in 2002 from critically low water levels experienced in 2001.

Generating Capability

PGE's existing hydroelectric, coal-fired, and gas-fired plants are important resources for the Company, providing 2,046 MW of generating capability (see Item 2.- Properties, for a full listing of PGE's generating facilities). PGE's lowest-cost producers are its five FERC licensed hydroelectric projects incorporating eight powerhouses on the Clackamas, Sandy, Deschutes, and Willamette rivers in Oregon. These facilities operate under federal licenses, which will be up for renewal through 2006. (For further information, see "Hydro Relicensing" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations").

In 2000, PGE executed an agreement with the Confederated Tribes of Warm Springs (Tribes) that will result in shared ownership and control of the 410-MW Pelton Round Butte hydroelectric project, with PGE continuing as operator. The sale to the Tribes terminated the fees PGE had paid for the inundation of the Tribes' property along the Deschutes and Metolius rivers. PGE and the Tribes completed the draft of their joint 50-year license application in 2000, and filed the final joint application amendment with the FERC in June 2001. Under terms of this agreement, the Tribes acquired a 33.33% interest in the project on January 1, 2002, and have options to purchase an additional 16.66% interest in 2021 and a 0.02% interest prior to the expiration date of the joint license.

PGE's 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 1999. This decision was based upon a comparison of projected future operating costs of the project, including required environmental measures necessary to protect several runs of endangered salmon, with the future value of the project's energy output. PGE has engaged state and federal agencies to reach an agreement to submit to the FERC on how and when the project should be removed from the Sandy and Little Sandy rivers. Irrespective of an agreement, the Bull Run Project is expected to operate until at least the end of its existing license. It may operate for several years beyond its expiration date depending on the resolution of decommissioning issues and FERC's conditions in the license surrender order.

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

In early 2001, PGE filed a "Notice of Intent" with Oregon's EFSC to build a new 650-MW gas turbine plant adjacent to the Beaver plant site. An air contamination discharge permit application has been approved, with approval pending on a site certificate application. The Company will continue to evaluate its options with regard to constructing this plant and any other generation, considering the availability of reasonably priced power from the market, changes in economic conditions and resultant demand, and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.

The generating capability at the Beaver plant increased 24.5 MW in 2001 with the installation of a combustion turbine unit to be operated during peak demand periods. Although added in response to high wholesale prices and regional energy shortages early in 2001 (which have since moderated significantly), the unit is expected to provide needed capacity in the future.

Purchased Power

The Company will supplement its own generation with long-term and short-term contracts as needed to meet its retail load requirements. Under the provisions of state restructuring legislation (SB1149), PGE remains obligated to serve all of its customers, but may increasingly serve those customers eligible for direct access with short-term purchases. Under terms of a separate tariff schedule, customers who have a direct access option are required to provide PGE a year's advance notice if they do not want the Company to purchase power in advance to serve their load. Such customers are also required by the tariff to provide a year's advance notice should they choose to return to PGE for service.

PGE has long-term power contracts with four hydroelectric projects on the mid-Columbia River, which provide approximately 645 MW of firm capacity. PGE also has firm contracts, ranging in term from one to thirty years, to purchase 674 MW of power, primarily hydro-generated, from BPA and 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 continental United States, Canada, and Mexico. It provides the forum for its member systems to enhance communication, coordination, and cooperation in planning 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 climate, 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 while northern loads peak during winter heating months. According to WSCC forecasts, the nearly 118 electric organizations participating in the WSCC, which include utilities, independent power producers, and transmission utilities, will have sufficient capacity margin to meet forecast demand and energy requirements through the year 2011, assuming the timely completion of planned new generation.

During 2001, PGE's peak load was 3,512 MW, of which 36% was met through short-term purchases. PGE's total firm resource capacity, including short-term purchase agreements, was approximately 4,246 MW as of December 31, 2001.

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).  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.

Water conditions in 2001 were the lowest in many years, with volumetric water supply measurements indicating stream runoffs at approximately 56% of normal. However, a near normal snow pack in the Columbia basin in early 2002, combined with reduced electricity demand from the current economic slowdown and conservation efforts, has eased pressure on the federal power system's hydroelectric resources. If the snow pack remains at current levels, the federal system's large storage reservoirs should be refilled in the spring, resulting in normal hydroelectric energy production during 2002.

In 2001, legal actions were initiated by various environmental groups that challenged the commitment and effectiveness of federal efforts to protect endangered salmon. Resolution of such actions could result in further modification of the federal hydroelectric system in order to meet requirements of the ESA.

PGE continues to evaluate the impact of current and potential ESA listings on the operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette rivers. The Company's hydroelectric relicensing efforts, in combination with endangered species consultations with the National Marine Fisheries Service (NMFS) and the United States Fish and Wildlife Service (USFWS), address issues associated with the protection of fish runs on those rivers where PGE operates. The Company has completed an ESA consultation on the Deschutes River, the location of its Pelton Round Butte Project, that will be in effect until a new license is granted by the FERC; no significant operational changes to the project have been indicated. The Company is in ESA consultation regarding projects on the Clackamas and Willamette rivers, with near-term operational changes and further fish protection measures to be assessed. Such consultation, involving the FERC, NMFS, and USFWS, is required to obtain a FERC license for hydroelectric projects.

 

Fuel Supply

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

Coal

Boardman

PGE has agreements to purchase coal for Boardman that cover the plant's requirements through 2002, with sufficient supplies available to meet future requirements. The coal, obtained from surface mining operations in Wyoming and Montana and subject to federal, state, and local regulations, is delivered by rail under contracts with the Burlington Northern Santa Fe and Union Pacific Railroads. Coal purchases in 2001, totaling about 2.4 million tons, contained approximately 0.4% of sulfur by weight. Utilizing electrostatic precipitators, the plant emitted less than the EPA-allowed limit of 1.2 pounds of sulfur dioxide per MMBtu.

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 Westmoreland Mining LLC. The contract provides for delivered coal to not exceed a maximum sulfur content of 1.5% by weight. Utilizing wet scrubbers to minimize sulfur dioxide emissions, the plant operated in compliance with EPA's source-performance standards.

Natural Gas

In addition to the agreements discussed below, the Company utilizes short-term and spot market purchases to secure transportation capacity and gas supplies sufficient to fuel plant operations. PGE re-markets natural gas and transportation capacity 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. Firm gas supplies for Beaver, based on anticipated operation of the plant, are purchased at fixed prices for up to 24 months in advance. PGE believes that sufficient market supplies of gas are available to fully meet requirements of the plant in 2002 and beyond. PGE has access to 76,000 Dth/day of firm transportation capacity, sufficient to operate Beaver at a 70% load factor.

Coyote Springs

The Coyote Springs generating station utilizes 41,000 Dth/day of firm transportation capacity on three interconnecting pipeline systems accessing the gas fields in Alberta, Canada. Firm gas supplies for Coyote Springs, based on anticipated operation of the plant, are purchased at fixed prices for up to 24 months in advance. PGE believes that sufficient market supplies of gas are available to fully meet requirements of the plant in 2002 and beyond.

Oil

Beaver

The Beaver generating station has the capability to operate at full capacity on No. 2 diesel fuel oil when it is economic or if the plant's natural gas supply is interrupted. To ensure the plant's continued operability under such circumstances, an approximate 19-day supply of oil is maintained at the plant site.

Coyote Springs

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

 

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 and 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 EPA, revealed significant contamination of sediments within the harbor. Subsequently, the EPA has included Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund"). In December 2000, PGE, along with sixty-eight other companies on the Portland Harbor Initial General Notice List, received a "Notice of Potential Liability" regarding the Harborton Substation facility. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the potential liability of responsible companies, including PGE.

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

Air and 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 are at least equal to federal standards; Oregon's air quality standards exceed federal standards. Primary pollutants addressed by the Act that affect PGE are sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter. PGE manages its emissions by the use of low sulfur fuel, emission controls and monitoring, and combustion controls.

The SO2 emission allowances awarded under the Act, along with expected future annual allowances, are sufficient to operate Boardman at 60% to 67% of capacity without emissions reductions. In addition, current emission allowances are sufficient to operate Colstrip, which utilizes wet scrubbers. If necessary, PGE intends to acquire sufficient additional allowances to meet excess capacity needs. It is not yet known what impacts federal regulations on mercury transport, regional haze, or particulate matter standards may have on future plant operations, operating costs, or generating capacity.

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

 

The following are generating facilities owned by PGE:

Facility

Location

Fuel

Net MW Capability    At Dec. 31, 2001

 

Wholly Owned:

Faraday

Clackamas River

Hydro

44

North Fork

Clackamas River

Hydro

58

Oak Grove

Clackamas River

Hydro

44

River Mill

Clackamas River

Hydro

25

Pelton Deschutes River

Hydro

110 (*)

Round Butte

Deschutes River

Hydro

300 (*)

Bull Run

Sandy River

Hydro

22

Sullivan

Willamette River

Hydro

16

Beaver

Clatskanie, OR

Gas/Oil

524

Coyote Springs

Boardman, OR

Gas/Oil

245

Jointly Owned:

     

PGE Interest

Boardman

Boardman, OR

Coal

362

65.0%

Colstrip 3 & 4

Colstrip, MT

Coal

296

20.0%

Total

2,046

(*)  Effective with the January 1, 2002 sale of 33.33% interest in the Pelton Round Butte Project to the Confederated Tribes of Warm Springs, PGE's share of Pelton and Round Butte capabilities were reduced to 73 MW and 200 MW, respectively.

PGE holds licenses under the Federal Power Act for its hydroelectric generating plants, as well as licenses from the State of Oregon for all or portions of five of the plants. Licenses for the Sullivan and Bull Run projects expire in 2004 and licenses for all projects on the Clackamas River expire in 2006. The license for the Pelton Round Butte project expired at the end of 2001. In June 2001, PGE and the Confederated Tribes of Warm Springs jointly filed a 50-year license application, which is pending with the FERC.

The FERC requires that a notice of intent to relicense hydroelectric projects be filed approximately five years prior to license expiration. The Company has filed notice to relicense and is actively pursuing renewal of licenses for all of its hydroelectric generating plants except Bull Run, which will not be relicensed. (For further information, see "Hydro Relicensing" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations").

The generating capability at Beaver increased 24.5 MW in 2001 with the installation of a combustion turbine unit to be operated during peak demand periods. The turbine at the North Fork hydroelectric project was replaced in 2001, increasing its capacity by 4 MW. The Coyote Springs plant added 3 MW of capacity in 2001 with the installation of duct burners and equipment modifications that allow increased airflow to the turbines.

PGE owns transmission lines that deliver electricity from its Oregon plants both within its service territory and also to the Northwest grid, which also delivers energy from plants in other states. In addition, PGE owns 20% of the Pacific Northwest Intertie, a 4,800-MW transmission facility between John Day, in northern Oregon, and Malin, in southern Oregon near the California border. This line is used primarily for interstate purchases and sales of electricity among BPA, Pacific Northwest utilities (including PGE), and California utilities.

Leased Properties

PGE leases its Portland headquarters complex and coal-handling facilities at the Boardman plant, along with certain railroad cars used to deliver coal to the plant.

 

 

Item 3. Legal Proceedings 

 

Litigation

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

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

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

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

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

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

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

Also on August 26, 1998, the 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 and requested a hearing with the OPUC, challenging PGE's application for approval of the accounting and ratemaking elements of the settlement.

PGE 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 Commission 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 would assume that the cases are moot and dismiss them on that ground. PGE requested, and the Oregon Supreme Court granted, an extension of that time until April 16, 2001. PGE subsequently requested the Oregon Supreme Court to delay its consideration of this issue as moot until April 2002, allowing the OPUC opportunity to consider the issues raised by the URP complaint challenging PGE's application for approval of the accounting and ratemaking elements of the settlement. PGE has requested a further delay for such consideration until June 2002.

On March 25, 2002, the OPUC issued an order denying all of URP's challenges, and approving PGE's application of the accounting and ratemaking elements of the settlement.

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

Threatened Litigation

The Attorney General's Office of the State of California has notified the Company that it will file a complaint against PGE in the California State Court in mid-April 2002. The complaint will allege the failure of PGE to file rates charged for wholesale electricity sold in California and the charging of unjust and unreasonable rates in the California markets. At this time, management is unable to make any assessment of, or determination with respect to, this threatened litigation.

Union Grievances

In November 2001, several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, filed grievances against PGE with respect to losses in the bargaining unit employees' pension/savings plans resulting from the collapse of the price of Enron's stock. The grievances, on behalf of all present and retired bargaining unit members, allege that Enron manipulated the stock and caused the resultant losses. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. The IBEW and the Company have agreed to delay the grievance process until June 1, 2002, which may be extended by mutual agreement for an unlimited number of 30-day extensions.

 

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 common stock. Cash dividends declared on common stock were as follows (in millions):

 

Quarter

2001

2000

1

$ 20

$ 20

2

20

20

3

-

20

4

-

21

PGE is restricted, without prior OPUC approval, from making dividend distributions to Enron that would reduce PGE's common equity capital below 48% of total capitalization (including short-term borrowings). For additional information, see Note 15, Proposed Acquisition of PGE by NW Natural, in the Notes to Financial Statements.

 

Item 6. Selected Financial Data

  

For the Years Ended December 31

 

2001

2000

1999

1998

1997

 

(In Millions)

Operating Revenues

$3,047

$2,253

$1,378

$1,176

$ 1,416

Net Operating Income

134

206

190

200

208

Net Income

34

141

128

137

126

           

Total Assets

3,474

3,452

3,167

3,162

3,256

           

Long-Term Obligations *

972

880

763

876

1,038

  * Includes long-term debt and preferred stock subject to mandatory redemption requirements. Long-term capital lease obligations of $1 and $4 are included in 1998 and 1997, respectively; there were no capital lease obligations from 1999-2001.

 

Item 7.  Management's Discussion and Analysis of Financial   Condition and Results of Operations

 

Change in Independent Accountants

On February 5, 2002, Arthur Andersen LLP resigned as PGE's independent public accountants due to concerns about Arthur Andersen LLP's ability to continue as auditors for PGE. Arthur Andersen LLP's decision resulted from considerations of applicable professional standards including, but not limited to, those applicable to auditor independence relating to recent events involving Enron, PGE's parent company. PGE engaged PricewaterhouseCoopers LLP as its new independent accountants as of February 25, 2002 to audit PGE's 2001 financial statements. For additional information, see Item 9, Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Recent Events

Enron's Proposed Sale of PGE

In November 1999, Enron entered into an agreement to sell PGE to Sierra Pacific Resources, with the sale initially expected to close in late-2000. Although the OPUC approved the sale in October 2000, further progress was delayed by the effect of adverse events affecting energy markets in both California and Nevada. Due to the regulatory and legislative environment resulting from the effects of such events, the agreement was terminated in April 2001 by mutual consent between Enron and Sierra Pacific Resources.

In October 2001, Enron entered into an agreement to sell PGE to NW Natural, a natural gas distribution company located in Portland, Oregon, for $1.8 billion ($1.55 billion in cash and $250 million of equity securities to be issued to Enron). PGE will retain its approximately $1.1 billion in existing debt and preferred stock. In addition, the balance of the merger obligation due PGE, remaining from Enron's purchase of PGE in 1997 (Merger Receivable), would be assumed by NW Natural. The agreement also provides for the acquisition by NW Natural of PGH II, Inc., a subsidiary of Enron engaged in non-utility development, including assumption of balances payable to PGE.  See Enron Bankruptcy below "Amounts due from Enron and Enron-supported affiliates", for additional details.

The transaction between NW Natural and Enron is subject to regulatory approvals, applications for which have been filed, from the SEC, the FERC, the NRC, the OPUC, the EFSC, and the Washington Utilities and Transportation Commission. In addition, the proposed acquisition has been reported to the U.S. Department of Justice and the Federal Trade Commission for antitrust review. The transaction has been approved by the EFSC, FERC, and NRC, and the waiting period for antitrust review has expired with no further action required. The transaction is also subject to approval by NW Natural's shareholders. In addition, the sale cannot be completed until Enron, as Debtor in Possession, has assumed the stock purchase agreement and obtained approval by the Bankruptcy Court.

Although the OPUC decision was initially anticipated by late-May 2002, Enron and NW Natural requested, and the Commission approved, a 60-day suspension of the procedural schedule that provides for hearings to resume in mid-May 2002 and that waives the statutory time period for approval of the sale through late-September 2002. As a result, a decision by the OPUC is not expected until October 2002. Both Enron and NW Natural continue to pursue regulatory approval of the sale under terms of the agreement between the two companies. However, the new schedule accommodates NW Natural's need to further analyze any effects of Enron's bankruptcy on PGE, as well as Enron's need to interact with creditors and the Bankruptcy Court regarding reorganization options. Enron has announced that it is proceeding with reorganization efforts and expects to present restructuring alternatives to the Creditors' Committee participating in Enron's bankruptcy proceedings in the second quarter of 2002. Any plan of reorganization approved by the Creditors' Committee will ultimately need to be presented to the Bankruptcy Court for approval. Until a plan of reorganization is filed with the Bankruptcy Court, management does not know the role of PGE in any reorganization structure and cannot assess the impacts on PGE's business and operations. In light of Enron's bankruptcy proceedings, there is no assurance that regulatory, financing, and other conditions will be satisfied. For further information, see Note 15, Proposed Acquisition of PGE by NW Natural, in the Notes to Financial Statements.

On May 7, 2001, Enron granted an option to its indirect wholly-owned subsidiary, Enron Northwest Assets, LLC, to purchase all the common stock of PGE for one dollar for the purpose of effectuating tax planning, with the effect of de-consolidation of PGE from Enron's consolidated tax group. Enron Northwest Assets, LLC is also a party to the stock purchase agreement dated October 5, 2001, providing for the sale of PGE to NW Natural. The stock purchase agreement provides that at closing, either Enron Northwest Assets will exercise its option and convey the shares of PGE to NW Natural or, in the alternative, Enron will simply directly convey the shares of PGE to Northwest Natural. In connection with the negotiation of its Debtor in Possession financing (see Enron Debtor in Possession Financing below), Enron has agreed to take all necessary steps to ensure that the option held by Enron Northwest Assets is not exercised. Given the alternative means of closing the sale of PGE to NW Natural, the agreement by Enron to cause the option held by Enron Northwest Assets not to be exercised should not interfere with closing of the sale of PGE to NW Natural under the terms of the stock purchase agreement.

Enron Bankruptcy

In December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor several other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been suspended from trading on the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC and the State of Oregon. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.

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

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

  1. Amounts due from Enron and Enron-supported affiliates - As described in Note 12, Related Party Transactions, PGE is owed approximately $74 million by Enron relating to the Merger Receivable. NW Natural will assume Enron's obligation should the sale of PGE to NW Natural close. (See Note 15, Proposed Acquisition of PGE by NW Natural, for additional information). Because of uncertainties associated with Enron's bankruptcy, PGE established a reserve for the full amount of this receivable in December 2001. In addition, a credit reserve of $5 million was established in December 2001 related to uncertainties associated with the $6 million receivable balance due from Enron affiliates, which are part of the bankruptcy proceedings.

  2. Control Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plans and tax obligations of Enron.

           Pension Plans

           Funding Status

The pension plan for the employees of PGE (PGE Plan) is separate from the Enron pension plan (Enron Plan). The PGE Plan has assets that exceed the present value of all accrued benefits (see Note 2, Employee Benefits) on a SFAS No. 87 (Employers' Accounting for Pensions) basis and, management believes, on a plan termination basis. It is PGE management's understanding, based on discussion with Enron management, that the assets of the Enron Plan are currently less than the present value of all accrued benefits by approximately $90 million on a SFAS No. 87 basis and approximately $120 million on a plan termination basis. However, approximately 48% of that amount is attributable to members of the Enron controlled group that are not in bankruptcy.

It is permissible, subject to applicable law, for management to merge separate pension plans established by companies in the same controlled group. Enron could direct that the PGE Plan be merged with the Enron Plan with the result that the present value of all accrued benefits under both of the plans will not exceed the value of the assets in the combined plans. If the plans are merged, the assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC, which insures pension plans, including the PGE Plan and the Enron Plan, and the PGE Plan's surplus would be undiminished. Merging the plans would reduce the value of PGE, the stock of which is an asset available to Enron's creditors, and disproportionately benefit the PBGC. Management believes that it is unlikely that either Enron or Enron's creditors would agree to support merging the two plans.

Although the Enron Plan is underfunded and Enron is in bankruptcy, Enron cannot itself terminate the Enron Plan unless it provides 60 days notice and the PBGC, in the case of solvent entities, or the Bankruptcy Court, in the case of insolvent entities, determines that each member of Enron's controlled group, including PGE, is in financial distress, as defined in ERISA. Since in the opinion of management PGE, as a solvent entity, does not meet the financial distress test, management believes that it is unlikely that Enron can terminate the Enron Plan. However, Enron could, with consent of the PBGC (see below), seek to terminate the Enron Plan while it is underfunded.

The PBGC does have the authority, upon application to and approval by a Federal District Court, to terminate and take over control of underfunded pension plans in certain circumstances. In order to initiate this process, the PBGC must determine that either the minimum funding standard for the plan (see below) has not been met, or that the plan will not be able to pay benefits when due, or that there is a reasonable risk that long-run losses to the PBGC will be unreasonably increased or that certain improper distributions have been made from the plan. The court must determine that plan termination is necessary to protect participants, the plan, or the PBGC.

Upon termination of a plan, all members of the controlled group of the plan sponsor become jointly and severally liable for the underfunding, but are not obligated to pay until a demand for payment is made by the PBGC. The PBGC can demand payment from one or more of the members of the controlled group. If payment of the full amount demanded is not made, a lien in favor of the plan automatically attaches against all of the assets of each member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the member's aggregate net worth. The PBGC may perfect the lien by appropriate filings. The lien does not take priority over other previously perfected liens on the assets of a member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Any lien by the PBGC would be subordinate to that lien.

If the PBGC did look solely to PGE to pay any underfunded amount in respect of the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of the controlled group. Until such time as the Enron Plan is terminated and the PBGC makes a demand on PGE to pay some or all of the underfunded amount, PGE has no liability for the underfunded amount and no termination liens are attached to any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any underfunded amount assessed by the PBGC. No reserves have been established by PGE for any amounts related to this issue.

Minimum Funding Obligation

If the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically attaches to the assets of every member of the controlled group. The lien is in favor of the plan, but may be enforced by the PBGC. The PBGC may perfect the lien by appropriate filings. The lien does not take priority over other previously perfected liens on the assets of a member of the controlled group. If Enron does not timely satisfy its minimum funding obligation in excess of $1 million, a lien will attach to the assets of PGE and all other members of the controlled group. The PBGC would be entitled to file the lien and enforce it in favor of the Enron Plan against the assets of PGE and other members of the controlled group. However, substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Any lien by the PBGC would be subordinate to that lien.

Based on discussions with Enron management, PGE management understands that Enron has made all required contributions to date. PGE does not know if Enron will make future quarterly contributions of approximately $6 million as they become due. Management is unable to predict if Enron will miss a payment and, if so, whether the PBGC would seek to have PGE make any or all of the payment. If the PBGC did look solely to PGE to pay the missed payment, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover contributions from the other solvent members of the controlled group. Until Enron does miss a contribution, PGE has no liability and no liens will attach to any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any missed payments demanded by the PBGC. No reserves have been established by PGE for any amounts related to this issue.

Retiree Health Benefits

Under COBRA, retirees of a bankrupt employer who lose coverage under a group health plan of the employer as a result of certain bankruptcy proceedings, are entitled to continuation of health coverage in a group health plan maintained by the bankrupt employer or a member of its controlled group. Management understands, based on discussion with Enron management, that Enron had provided a plan for health insurance for certain retirees, and that the actuarial liability amounts to approximately $70 million. Management further understands that to meet its obligation, Enron has set aside approximately $34 million of assets in a VEBA trust which may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million. In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan, if any, or the appropriate group health plan of another member of the controlled group. Neither Enron nor any member of the controlled group would be required to fully fund the benefit or create new plans to provide coverage, and retirees would not be entitled to choose from which plan to obtain coverage. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to retirees under the most appropriate plan in the controlled group. Retirees electing to continue coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the average cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.

Management believes that in the event Enron terminates coverage, any material liability to PGE associated with Enron retiree health benefits is unlikely for two reasons. First, based on discussion with Enron management, PGE management understands that most of the retirees that would be affected by termination of the Enron plan are from solvent members of the controlled group and few, if any, live in Oregon. Management believes that it is unlikely that any PGE plans would be found to be the most appropriate to provide COBRA coverage. Second, even if a PGE plan were selected, management believes that retirees in good health should be able to find less expensive coverage from other providers, which will reduce the number of retirees electing coverage. Management believes that the additional cost to PGE to provide coverage to a limited number of retirees that are unable to acquire other coverage because they are hard to insure or have preexisting conditions will not be material. No reserves have been established by PGE for any amounts related to this issue.

          Income Taxes

Under the IRC, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with Portland General Corporation. PGE management understands, based on discussion with Enron management, that PGE ceased to be a member of Enron's consolidated group on May 7, 2001.

Enron's management has provided the following information to PGE:

    A. Enron's consolidated tax returns through 1995 have been audited and are closed. The IRS has completed its field audit of the consolidated tax returns for 1996-1997 and is currently auditing Enron's consolidated tax returns for 1998-2000. Enron's consolidated tax return for 2001 is expected to be filed in mid-2002 and Enron expects this return and its examination to be included in the bankruptcy process.

    B. For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron and its subsidiaries anticipate that the 2001 consolidated tax return will show a substantial loss, which would be carried back to tax year 2000, and result in a refund of taxes paid in 2000. The carryback of the 2001 loss to 2000 provides Enron and its subsidiaries substantial NOLs for any additional income tax liabilities for the periods in which PGE was a member of Enron's consolidated federal income tax returns. At this time, Enron anticipates claims, if any, made by the IRS in the bankruptcy proceedings for the years 1996-2001 will occur sometime in the fall of 2002.  If there were additional tax liabilities claimed by the IRS, these would be satisfied by funds in the bankruptcy estate ahead of unsecured Enron creditors.

    Although management cannot predict with certainty the outcome of the IRS audits, based on the above, it believes it is unlikely, at this time, that any tax claims by the IRS would offset the substantial NOLs available to the Enron consolidated tax returns.  If the IRS did seek payment and Enron did not pay, the IRS could look to one or more members of the consolidated group, including PGE. If the IRS did look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, are available for recovery in Enron's bankruptcy proceeding, or to otherwise obtain contributions from the other solvent members of the consolidated group who are not debtors in the bankruptcy case. Management believes the income tax exposure to PGE would be minimal, if any, related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated tax returns.  If PGE is not de-consolidated from Enron's consolidated tax group for periods after 2001, PGE would be severally liable for the tax liability of the consolidated group for those periods along with any other members of the consolidated group.  No reserves have been established by PGE for any amounts related to this issue.

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

Neither does management believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern.  PGE believes that, in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a Debtor in Possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose.  As Debtor in Possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management.   PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors.  No dividends could be paid to Enron, no assets could be sold, and no other transfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers.  Since the issue of whether a Bankruptcy Court has the authority to supersede state regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course.

Enron Debtor in Possession Financing

PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a Debtor In Possession credit agreement with Citicorp USA Inc. and JP Morgan Chase Bank. Under the terms of the credit agreement and related security agreements, all of which were approved by the Bankruptcy Court having jurisdiction over Enron's case, Enron pledged its stock in PGE to secure the repayment of any amounts due under the Debtor in Possession financing. Enron also granted the lenders a security interest in the proceeds of the sale of PGE to NW Natural. Under the terms of the pledge, the lenders are prohibited from exercising substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control over PGE unless and until (a) the stock purchase agreement between Enron and NW Natural for the sale of PGE has been terminated, rejected or otherwise is subject to termination, and (b) the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders. The credit agreement also prohibits Enron from amending, modifying, or waiving the terms of the stock purchase agreement with NW Natural without the approval of the lenders. The pledge automatically terminates upon the closing of the sale of PGE to NW Natural.

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

 

Results of Operations

2001 Compared to 2000

PGE's net income in 2001 was $34 million compared to $141 million in 2000. The effect of both significantly higher power costs and lower energy loads was only partially offset by a general rate increase that became effective at the beginning of the fourth quarter of 2001, contributing to an approximate 35% decrease in net operating income. Results for the year also include a $48 million after tax provision for uncollectible accounts receivable from Enron and affiliated companies due to uncertainties surrounding Enron's bankruptcy proceedings. In addition, the Company recorded after tax provisions of approximately $13 million in 2001 related to amounts receivable for energy sales in the California wholesale market, a franchise fee audit, and costs associated with the cancellation of a proposed gas turbine generation project.

Total operating revenues increased $794 million (35%), due primarily to higher prices for wholesale energy sales. Wholesale revenues increased $758 million (from $1,171 million to $1,929 million), as prices more than doubled due to the combined effect of higher natural gas prices, below normal hydro conditions, and market forces within the region. Wholesale sales volume decreased 27% as power trading activity slowed due to uncertainty and volatility in energy markets during the year.

Retail revenues increased $32 million due to a general rate increase that became effective October 1, 2001 (See "General Rate Case" in Part I, Item 1). Retail energy sales decreased 4% as a slowing economy, mild weather, conservation, and PGE's Demand Buyback program more than offset an approximate 11,000 (1.5%) increase in total customers from the end of last year. (See "Retail Customer Growth and Energy Sales" in the Financial and Operating Outlook section for further information). A total of $42 million in retail revenues was deferred to 2002 to reflect amounts collected in excess of net variable power costs (for further information, see "Deferred energy revenues" in Note 1, Summary of Significant Accounting Principles, in the Notes to Financial Statements).

Purchased power and fuel costs increased $900 million (62%), as PGE's average variable power cost increased 92% from 2000. During the fourth quarter of 2000 and through the first quarter of 2001, PGE entered into electricity and natural gas forward contracts for the last half of 2001 at forward prices reflecting the higher prevailing market prices. Western wholesale power prices moderated significantly in the last half of 2001 due to the combined effect of mild weather, additional generation capacity in the West, increased natural gas supplies, lower retail loads, and conservation. As prices declined, PGE was unable to sell excess wholesale power at prices covering the cost of such power, resulting in historically high net variable power costs in the last half of 2001. Conversely, in 2000, PGE achieved significantly lower net variable power costs in the last half of the year as the Company sold on the wholesale market excess power purchases, made in anticipation of higher retail demand, at prices significantly higher than cost. The Company also recorded additional provisions in 2001 related to the collectibility of receivable balances associated with certain energy sales in the California wholesale market. For further information, see Note 13, Receivables - California Wholesale Market, in the Notes to Financial Statements.

Partially offsetting the effect of increased prices was a 4% decrease in retail load from 2000.  PGE's Demand Buyback program, by which certain large customers voluntarily reduced their electricity usage during certain peak periods during the first nine months of 2001, contributed to the load reduction and partially offset the Company's increased cost of power. In addition, Purchased power and fuel costs in 2001 include an approximate $84 million credit related to the Company's power cost mechanism, in which a portion of net variable power costs exceeding a baseline amount are deferred for future recovery from customers. (See "Power Cost Mechanisms" in the Financial and Operating Outlook section for further information).

The following table indicates PGE's total system load (including both retail and wholesale) for the last two years. Company generation increased 8% in 2001, with a 15% increase in combustion turbine and coal generation partially offset by reduced hydro production. Total generation met approximately 61% of PGE's retail load during the year, compared to 54% last year. Average variable power costs for 2001 listed below exclude the effect of the approximate $84 million credit to Purchased power and fuel costs related to PGE's power cost mechanism.

 

 

 

Megawatt-Hours/Variable Power Costs

 

Megawatt-Hours (thousands)

 

Average Variable

Power Cost (Mills/KWh)

 

 

2001

 

2000

 

 

2001

 

2000

Generation

12,331

11,430

 

18.8

14.5

Term Purchases

19,433

25,049

 

98.8

34.9

Spot Purchases

2,138

3,258

 

104.7

123.6

Total Send-Out

33,902

39,737

 

71.4*

37.2*

     

(* includes wheeling costs)

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

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

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

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

Interest charges remained the same as last year. An increase in interest on long-term debt and other, due to both interest on wholesale trading deposits and to the March 2000 issuance of $150 million in unsecured notes, was offset by reduced interest on a lower average level of commercial paper outstanding during 2001.

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 PGE sold on the wholesale market excess power purchases; wholesale energy sales increased 47% at average prices that increased 124%. 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 in 1999 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 1999; 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. 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.  (For additional information, see Note 8, Price Risk Management, in the Notes to Financial Statements). In addition, PGE's Demand Buyback 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 2000.

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 2000, compared to 51% in 1999.

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 1999. Expenses in 1999 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 OPUC and the Company was subsequently granted 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 the amortization of regulatory assets and liabilities 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 CUB related to the Company's investment in the closed Trojan nuclear plant. (For additional information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements).

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 (net of tax) remained the same as last year. During 2000, the Company wrote off $5 million of its Trojan plant investment 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 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.

Capital Resources and Liquidity

Review of Cash Flow Statement

Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE, with supplemental cash obtained from external borrowings as needed. A significant portion of cash provided by operations consists of depreciation of utility plant and amortization of deferred amounts, charges which are recovered in customer revenues but require no current period cash outlay. Changes in accounts receivable and accounts payable can also result in significant sources and uses of cash.

Operating activities used $67 million of cash in 2001 compared to $423 million provided by such activities in 2000. This was due primarily to a change in margin deposit requirements related to the Company's energy trading activities and to other operating cash requirements, including power purchases. At the end of 2000, PGE held $139 million in performance assurance cash collateral from trading counterparties; at the end of 2001, the Company had posted $89 million of such collateral, and an additional $100 million in letters of credit, with such parties. Increased purchases of fuel oil, coal, and stores material, as well as major maintenance and overhaul expenditures at the Company's Coyote Springs combustion turbine plant, accounted for most of the remaining decrease in cash from operations during 2001.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. Capital expenditures of $203 million in 2001 and $173 million in 2000 were primarily for the expansion and upgrade of the Company's distribution system. In addition, costs of a new customer information and billing system, a 24.5-megawatt addition to the Company's Beaver combustion turbine plant, and certain large transmission substation and production plant improvements were incurred in 2001. Proceeds from sales of assets in 2000 consisted 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 non-generating facilities at its Coyote Springs plant. Capital expenditures are expected to approximate $200 million in 2002. The majority of expenditures are expected to consist of improvements to PGE's expanding distribution system to support both new and existing customers within the Company's service territory.

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

Short-term - PGE relies on the issuance of commercial paper, loans under its revolving credit facilities, letters of credit, and cash from operations to manage its daily liquidity requirements. A $158 million net increase in short-term borrowings in 2001 was utilized primarily to support the Company's operating and capital activities, including cash collateral requirements related to its wholesale electricity trading activities. For additional information, see Note 5, Credit Facilities and Debt, in the Notes to Financial Statements.

In December 2001, PGE received approval from the FERC to issue short-term debt (less than one year), including commercial paper, credit facilities, and other evidences of indebtedness up to $550 million for a two year period. At December 31, 2001, PGE had utilized approximately $274 million of its $350 million credit line capacity. The Company had $129 million in outstanding commercial paper, $45 million in bank loans, and had used approximately $100 million in letters of credit under its committed credit lines.

PGE is evaluating alternatives for the replacement of its $200 million line of credit, which expires in June 2002. Such alternatives include the issuance of First Mortgage Bonds and new revolving credit facilities.

Long-term - In February 2001, PGE filed a $250 million shelf registration statement with the SEC, increasing the Company's long-term debt shelf capacity with the Commission to $300 million. There are no changes to current debt covenants or other restrictions.

In December 2001, PGE issued $150 million of variable rate First Mortgage Bonds, maturing in December 2002, which were used to reduce commercial paper borrowings and bank loans under the Company's revolving credit facilities. As a private placement, this issue did not reduce the Company's long-term debt capacity under its SEC shelf registration. In addition, PGE repaid $45 million in matured First Mortgage Bonds, $6 million of variable rate pollution control bonds, and $7 million of conservation bonds. In 2000, PGE issued $150 million of 7.875% unsecured notes maturing in 2010 and, with other funds, reduced its short-term commercial paper by $250 million. In addition, PGE repaid $33 million in matured first mortgage and conservation bonds during 2000.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Articles of Incorporation and the Indenture securing the bonds. As of December 31, 2001, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital requirements.

Dividends - In 2001, PGE paid $40 million in common stock dividends to Enron and $2 million in preferred dividends. In 2000, the Company paid $81 million in common stock dividends to Enron and $2 million in preferred stock dividends. No common stock dividends were declared in the second half of 2001; management is currently evaluating future declaration of common stock dividends in light of expected cash requirements and other considerations.

The Stock Purchase Agreement between Enron and NW Natural requires that PGE pay a dividend to Enron based on PGE's total net income from 1999 though the closing date of the sale to NW Natural, less any dividends paid during this period. For further information, see Note 15, Proposed Acquisition of PGE by NW Natural, in the Notes to Financial Statements.

Credit Ratings

PGE's current credit ratings are as follows:

   

Moody's

 

Standard & Poor's

 

Fitch

             

First Mortgage Bonds

 

A3

 

                BBB+

 

          BBB+

Senior unsecured debt

 

Baa1

 

                BBB

 

          BBB

Preferred stock

 

Baa3

 

                BBB-

 

          BBB-

Commercial paper

 

P-2

 

A-2

 

F2

             

Status:

 

On review for possible downgrade

 

CreditWatch with Negative Implications

 

Ratings Watch Negative

In late 2001, credit rating agencies reviewed their ratings of the Company in response to the announced Stock Purchase Agreement for the sale of PGE to NW Natural and uncertainties surrounding PGE's ability to remain fully insulated from the current financial difficulties faced by Enron in bankruptcy. As a result of these reviews, the Company's ratings were lowered to their current levels, which are investment grade.  PGE has experienced higher interest rates for commercial paper and other short-term borrowings as a result.

In March 2002, Standard & Poor's (S&P) reaffirmed PGE's ratings based on the expectation that PGE will be sold. S&P stated that it would re-evaluate PGE's current ratings separation from Enron's ratings (presently below investment grade) if Enron considers retaining PGE. In that case, PGE's ratings would depend on any structural or regulatory mechanisms to protect the Company's assets from Enron and its creditors and whether there existed any economic incentives for Enron to cause PGE to file for bankruptcy protection. Should the rating agencies reduce the credit rating on the Company's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. Based on PGE's non-trading and trading portfolio and estimates of current energy market prices as of April 11, 2002, the approximate amount of additional collateral that could be requested upon such a downgrade event is $177 million. This amount decreases to approximately $19 million by September 2002 and is estimated to be near zero by year-end 2002 as current higher-price energy contracts continue to settle.  In addition to collateral calls, such a credit ratings reduction would likely have an adverse effect on the Company's ability to issue commercial paper and increase the cost of  funding its day-to-day working capital requirements.

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

For further information, see Note 16, Enron Bankruptcy, in the Notes to Financial Statements

 

Contractual Obligations and Commercial Commitments

The following indicates PGE's contractual obligations as of December 31, 2001 (in millions):

 

Payments Due

                         

After

 

Total

 

2002

 

2003

 

2004

 

2005

 

2006

 

2006

Long-Term Debt

$ 942

 

$ 173

 

$ 191

 

$ 55

 

$ 28

 

$   9

 

$ 486

Short-Term Debt

174

 

174

 

-

 

-

 

-

 

-

 

-

Preferred Stock

30

 

1

 

1

 

1

 

1

 

1

 

25

Operating Leases

186

 

10

 

9

 

10

 

8

 

6

 

143

Purchase Commitments

44

 

19

 

11

 

7

 

1

 

2

 

4

Purchased Power and Fuel:

                         
 

Electricity Purchases

1,353

 

784

 

185

 

129

 

121

 

101

 

33

 

Capacity Contracts

295

 

19

 

19

 

19

 

19

 

19

 

200

 

Natural Gas Agreements

254

 

102

 

29

 

15

 

15

 

14

 

79

 

Public Utility Districts

93

 

7

 

9

 

8

 

7

 

6

 

56

 

Coal Agreements

22

 

22

 

-

 

-

 

-

 

-

 

-

                             

Total Contractual

                         

Cash Obligations

$3,393

 

$1,311

 

$ 454

 

$ 244

 

$ 200

 

$ 158

 

$ 1,026

                           

Other Financial Obligations

PGE has entered into long-term power purchase contracts with certain public utility districts in the state of Washington under which PGE has acquired a percentage of the output (Allocation) of four hydroelectric projects. The Company is required to pay its proportionate share of the operating and debt service costs of the projects whether or not they are operable. The contracts further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE will be allocated a pro rata share of both the output and the operating and debt service costs of the defaulting purchaser, up to a cumulative maximum of 25% of its percentage Allocation. For further information, see "Purchased Power" in Note 7, Commitments, in the Notes to Financial Statements.

PGE has in prior years utilized off-balance sheet financing arrangements, including leveraged leases reflected as operating leases in PGE's financial statements. (For further information, see "Leases" in Note 7, Commitments, in the Notes to Financial Statements). In addition, PGE entered into a sale transaction in 1985 in which it sold an undivided 15% interest in its Boardman coal plant and a 10.714% undivided interest in the Pacific Northwest Intertie transmission line (Boardman Assets) to an unrelated third party (Purchaser). The Purchaser leased the Boardman Assets to a lessee unrelated to PGE or the Purchaser. PGE assigned to the lessee certain rights and interest, including the right to receive payment, in certain agreements for the sale of power and transmission services from the Boardman plant and the Intertie to a regulated electric utility unrelated to PGE, the Purchaser or the lessee. The payments by the utility to the lessee under those agreements exceed the payments to be made by the lessee to the Purchaser under the lease. However, in the event of a payment default by the lessee to the Purchaser, PGE could bear a risk of loss for any difference between the amount of the default and the amount it would be entitled to receive or recover from the lessee and the utility. Management believes that circumstances that could result in loss to the Company are remote.

 

Critical Accounting Policies

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (GAAP). In addition, PGE accounting policies are in compliance with the requirements and the ratemaking practices of regulatory authorities having jurisdiction. For certain transactions where revenues, costs and gains would otherwise be recorded in income under GAAP, they are being deferred for future ratemaking treatment under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to reflect the effects of regulation. (These assets and liabilities, titled Unamortized regulatory assets and Unamortized regulatory liabilities on the Consolidated Balance Sheets, total $582 million and $86 million, respectively, at December 31, 2001). As recoveries or refunds are reflected in future rates, the applicable regulatory asset or regulatory liability balances are amortized to income over the recovery or refund period.

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

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

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

PGE engages in price risk management activities for both non-trading and trading purposes, utilizing derivative instruments such as electricity forward and option, and natural gas forward, swap and futures contracts. Derivative contracts entered into for non-trading purposes are anticipated to serve the Company's regulated retail load. The non-trading derivative contracts are intended to protect the Company against variability in expected future cash flows due to associated price risk and to manage overall fuel costs for retail customers. PGE enters into derivative contracts for trading purposes to take advantage of price movements in electricity and natural gas. Such trading activities are not subject to regulation. Derivative contracts are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138. (Prior to 2001, trading contracts were recorded at fair value pursuant to Emerging Issues Task Force (EITF) Issue 98-10, Accounting for Energy Trading and Risk Management Activities). For non-trading activities, certain derivative instruments are recorded at fair value on the balance sheet, with changes in fair value reflected as a regulatory asset or regulatory liability under SFAS No. 71 to reflect the effects of regulation. As these contracts are settled, the regulatory asset or regulatory liability is reversed. For trading contracts, PGE records the changes in fair value in current earnings.

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

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

 

 Transactions with Related Parties

PGE's services to affiliated companies consist primarily of employee and corporate governance services. The Company also receives services from affiliated companies for employee benefit plans and corporate overheads. Transactions with affiliated companies are subject to OPUC regulation. Most affiliated interest transactions are made under a Master Service Agreement (MSA) approved by the Commission. Any transactions not covered by the MSA must be separately approved by the Commission. Services provided to affiliates by PGE are charged at the higher of cost or market while affiliated services received by PGE are charged at the lower of cost or market. In addition to affiliated services, PGE purchases and sells electricity and transmission services to an Enron subsidiary. The ultimate disposition of the intercompany receivable and payable balances with Enron and its subsidiaries at December 31, 2001 is uncertain due to Enron's bankruptcy proceedings. The Company has recorded provisions against certain receivable balances due from Enron companies in bankruptcy. For further information, see Note 12, Related Party Transactions, and Note 16, Enron Bankruptcy, in the Notes to Financial Statements.

Trading Activities Accounted for at Fair Value

PGE trading activities utilize electricity forward and option contracts and natural gas forward, swap and futures contracts to take advantage of price movements in electricity and natural gas. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value, and volatility factors underlying the commitments. All energy trading contracts have a maturity of less than one year. The following tables indicate fair values, and changes in fair values, of PGE's energy trading contracts in 2001, as well as the source of the fair value of the unrealized gain at December 31, 2001 (in millions):

 

Unrealized

2001 Trading Activity

Gain (Loss)

Unrealized gain of contracts as of January 1, 2001

$ 13

Less contracts realized during 2001:

 
 

Contracts entered in prior years

     (6)

 

Contracts entered in 2001

      7

Change in fair value attributable to market changes:

 
 

Contracts entered in prior years

     (7)

 

Contracts entered in 2001

     (4)

Unrealized gain of contracts as of December 31, 2001

$   3

 

         
 

Unrealized Gain of Trading Contracts at Year End

Source of Fair Value

Maturity

Maturity

Maturity over

Total Unrealized

At December 31, 2001

0 - 6 mos.

6 - 12 mos.

1 yr.

Gain

Prices actively quoted

$ 2

$ 1

$ -

$ 3

Prices provided by other external sources

   -

  -

   -

    -

Prices based on models and other valuation methods

   -

  -

   -

    -

Financial and Operating Outlook

Long-Range Power Forecast/Rate Reduction

A long-range power forecast prepared by PGE and communicated to the OPUC indicates a possible retail rate reduction in January 2003 due to falling wholesale energy market prices. It is currently anticipated that large commercial and industrial customers would receive the largest reductions, followed by small business customers. Benefits to residential customers are expected to be smaller as their rates are affected more by the cost of electricity from BPA and from PGE generation than by wholesale energy market prices.

PGE is currently developing an estimate of 2003 power costs that will serve as the basis of its required November 15, 2002 filing with the OPUC. The Company plans to conduct a series of workshops to further explain the power cost forecast used to develop estimated rate impacts and to establish a schedule for future updates. Current estimates of net variable power costs are subject to change based on the influence of several factors, including the market cost of power, market conditions in the WSCC, the cost of natural gas and coal, hydro conditions, customer loads, and thermal plant operations.

Power Cost Mechanisms

As PGE's generation and long-term power purchase contracts provide only a portion of its customers' load, the Company has relied upon short-term wholesale power purchase contracts and spot market purchases. PGE buys and sells power in a wholesale market in which prices are volatile. In order to protect both the Company and its customers from such volatility, PGE has received OPUC authorization to defer, for future rate making treatment, actual net variable power costs which differ from certain baseline amounts approved by the Commission. This was accomplished by the use of power cost mechanisms covering two periods.

January 1, 2001 - September 30, 2001

The initial power cost mechanism was effective for the nine-month period ended September 30, 2001 and authorized PGE to defer net variable power costs which differed from a baseline amount, with costs outside of this range shared with retail customers. During the nine-month period, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. Approximately $89 million (including $5 million of interest) is included within Unamortized regulatory assets on the Consolidated Balance Sheet at December 31, 2001. The OPUC has approved PGE's application to recover the balance from customers over a period of 3 1/2 years, beginning April 1, 2002. Such recovery will be partially offset by the refund of approximately $22 million in certain customer credits over the period April 1, 2002 through December 31, 2002; these consist primarily of a final distribution received in 2000 related to PGE's terminated membership in Nuclear Electric Insurance Limited (NEIL).

October 1, 2001- December 31, 2002

In its August 31, 2001 general rate order, the OPUC approved a Power Cost Adjustment mechanism extending from October 1, 2001 through the end of 2002. Under this mechanism, PGE shares with its retail customers the difference between actual net variable power costs and the amount used to establish base energy rates. In addition, PGE shares with customers the difference between actual energy revenues and a pre-determined base. A portion of the net difference between pre-determined levels and actual net variable power costs and revenues (termed "Power Cost Variance") is subject to recovery (or refund).

Any Power Cost Variance exceeding $28 million is shared with PGE customers, with any variance between $28 million and $38 million shared equally. Of the next $62 million (up to $100 million), PGE will collect or refund 85% of the variance, and of the next $100 million (up to $200 million), PGE will collect or refund 90% of the variance. For variances that exceed $200 million, PGE will collect or refund 95% of the variance.

PGE will maintain a Power Cost Adjustment Account to record both the calculated Power Cost Variance and amounts actually collected from or refunded to customers. Any tariff rate adjustments, calculated on a quarterly basis to fully recover or refund any balance by December 31, 2002, are subject to review and approval by the OPUC. In the initial three-month period, no adjustment was recorded, as actual net variable power costs and revenues approximated amounts used to establish base energy rates.

PGE has filed with the OPUC a plan to work with Commission staff and customer groups to develop a power cost mechanism for use beyond 2002.

Receivables - California Wholesale Market

As of April 1, 2002, PGE has accounts receivable totaling approximately $87 million that may be affected by the financial condition of two major California utilities. Significant increases in wholesale power prices in the last half of 2000 and in early 2001 severely affected the financial stability of both companies and resulted in the declaration of bankruptcy by one of the utilities. A credit reserve has been established by PGE for amounts due under wholesale electricity contracts. For further information, see Note 13, Receivables-California Wholesale Market, in the Notes to Financial Statements.

Refunds on Wholesale Transactions

The FERC has issued an order directing certain electricity suppliers, including PGE, to supply information regarding wholesale power sales to California made in 2000 and 2001. Settlement discussions have taken place between the power suppliers, the state of California, and the FERC regarding potential refunds by suppliers. The discussions did not resolve the issues and the FERC has now scheduled formal hearings in the spring of 2002 to determine any potential refunds for sales in the California spot market between October 2, 2000 and June 20, 2001.

FERC hearings were held to determine whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest by PGE and other suppliers from December 25, 2000 through June 20, 2001. A FERC Administrative Law Judge issued a recommended order that claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.

See Note 14, Refunds on Wholesale Transactions, in the Notes to Financial Statements for further information.

Wholesale Price Mitigation

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

Under the program, a ceiling price is set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator and in markets in the other Western states. The ceiling price, reflecting specified fuel, operations, and maintenance costs, is based upon the bid submitted by the highest cost gas-fired generating unit whose power is needed when reserves in California fall below 7 percent, triggering a Stage 1 supply emergency. No bid to sell power may exceed the ceiling price as long as the reserve emergency is in place. When reserves again exceed 7 percent, removing the emergency, the ceiling price drops to 85 percent of the highest hourly price in effect during the most recent Stage 1 reserve emergency. Because of increased credit risk, wholesale electricity sales to California are allowed a 10 percent surcharge.

PGE and other Northwest utilities expressed concerns regarding potentially adverse consequences of price mitigation measures on Northwest citizens, utilities, power marketers and generators. In response, the FERC in December 2001 temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the California Independent System Operator. The changes acknowledge differences between the Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. They include the discontinuation of the above reserve deficiency method to formulate the mitigated price and utilize instead incremental changes in the cost of natural gas to trigger adjustments in the price, initially set at $108/MWh. The changes will be in effect until May 1, 2002, at which time the previous methodology will again become effective.

Federal Investigation - Wholesale Power Markets

On February 13, 2002, the FERC issued an order directing its staff to conduct a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. The investigation is separate from FERC actions related to refunds and price mitigation described herein. Pursuant to the order, the FERC on March 5, 2002 directed all sellers with wholesale sales in the U.S. portion of the WSCC to provide, by April 2, 2002, certain historical and projected information for all energy transactions in calendar years 2000 and 2001, including all long-term transactions which were executed for delivery on or after January 1, 2000. PGE has compiled and submitted requested information to comply with the FERC's directive.

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 a more competitive open market under which customers have a choice of energy supplier. Federal laws and regulations now provide for open access to transmission systems. Several states have adopted or are considering new regulations to allow direct access to energy suppliers.

In 1999, Oregon's governor signed into law State Senate Bill 1149 (SB1149), which became effective March 1, 2002. It provides all commercial and industrial customers of investor-owned utilities direct access to energy suppliers as well as cost of service and market price options. Residential and small commercial and industrial customers can purchase electricity from a "portfolio" of rate options that include a basic service rate, a time of use rate, and renewable resource rates. Early inquiries by electricity service suppliers and enrollments by retail customers indicate a measured response and a gradual beginning of participation in a restructured market.

Also included in SB1149 is a requirement that investor-owned utilities unbundle and separately identify the costs of electric service on a functional basis, including energy resources, delivery, and other services. It further provides for payment of "transition charges" by large non-residential customers that choose to purchase energy at market rates from PGE or from competing electricity service suppliers. Such charges reflect the above-market cost of energy resources owned or purchased by PGE and are designed to ensure that such costs do not unfairly shift to PGE's remaining energy customers.

PGE remains obligated to provide bundled, or full, service to all of its customers, including delivery service and energy. However, PGE may increasingly utilize short-term power purchases to serve those customers eligible for direct access to energy suppliers. The Company's generating resources remain dedicated to providing energy to customers that remain on PGE's system.

PGE continues to operate as a cost-based regulated electric utility, where revenue requirements are determined based upon the cost to serve customers, including an appropriate rate of return to the Company; moreover, PGE's recent rate proceeding before the OPUC was based upon this cost-of-service model. At this time, the large majority of PGE's customers continue to be served under rate tariff schedules determined by the cost of service. While PGE continues to meet the criteria of SFAS No. 71 and currently applies the provisions to reflect the effects of rate regulation in its financial statements, the Company will continue to periodically assess the applicability of the statement to its business, or separable portions thereof. Such assessment will consider both the current and anticipated future rate environment and related accounting guidance, as outlined in SFAS No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS No. 71, and EITF Issue 97-4, Deregulation of the Pricing of Electricity - Issues Related to the Application of SFAS No. 71 and SFAS No. 101.

In accordance with an order from the OPUC, PGE is deferring incremental costs of implementing SB1149 for recovery in future electricity rates. A request for recovery of these costs, which totaled approximately $14 million at December 31, 2001, has not yet been submitted to the Commission for consideration.

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 (see "Energy Efficiency" in this section for further information). In addition, SB1149 provides for low-income electric bill assistance which began in January 2000.

In addition to the potential loss of revenues from those non-residential customers that choose to purchase energy directly from competing energy suppliers, there is also the potential for the loss of 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 to place on the May 2002 ballot an amendment to the City of Portland charter requiring the acquisition of privately owned electricity distribution systems and facilities within the City by the end of 2002. The deadline for filing the petition expired in January 2002 and the amendment will not appear on the ballot.

Public ownership of PGE's operations has recently been discussed by ratepayer activists and by certain local government agencies. Although no formal actions have yet been initiated, there remains a possibility that public acquisition efforts may surface in the future. PGE continues to believe its customers are best served by a local well-managed privately-owned utility and has taken a strong public stance against government ownership initiatives.

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 and more choices to wholesale energy customers.

Further legislation to restructure the electric industry, including retail choice, is under consideration at the federal level, although restructuring efforts are expected to proceed at a slower pace due to recent adverse events affecting energy markets. Congressional committee hearings on electricity restructuring are expected to continue, although there remains considerable uncertainty regarding their ultimate outcome. PGE continues to formulate strategies to meet the challenges of wholesale competition.

In 2001, PGE filed revisions to its open-access transmission tariff to decrease its transmission service rates and increase its ancillary service rates due to the reclassification of certain transmission facilities approved by the OPUC in the Company's recent general rate filing. In a January 2002 order, the FERC approved PGE's request to decrease its transmission rates effective November 1, 2001 and increase its ancillary service rates effective February 1, 2002. The net impact of these rate changes is not significant.

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales decreased 3.6% in 2001, of which about 1.1% was due to the effect of the Demand Buyback program, in which PGE pays large customers to reduce their load during peak demand periods. Declining state-wide economic activity also contributed to the decrease. In addition, approximately 7,150 retail customers were transferred to two public utility districts in the third quarter of 2000 as a result of the sale of a portion of PGE's service territory. Manufacturing sector energy sales declined 6.4% due primarily to the effect of the Demand Buyback program. Excluding the effects of this program, manufacturing sector sales decreased about 2.8%, as large paper, chemical, food, lumber and metals manufacturers reduced their energy use. Commercial sales declined 1.0% compared to 2000. Sales to residential customers decreased 3.8% as average use declined in response to conservation efforts, while the number of customers increased by about 10,000 (1.6%). PGE forecasts minimal retail energy sales growth in 2002, as continued customer growth is offset by both a slow economy and increased conservation efforts.

Energy Efficiency

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

In 2001, in response to higher energy prices and potential shortages, the Company significantly increased its energy efficiency efforts. An increasing number of customers utilized PGE's services, with total annual savings for industrial, commercial and residential customers estimated at approximately $13 million. Total energy savings for 2001 are estimated at 21.4 average megawatts, compared to 6.2 megawatts in 2000.

Beginning March 1, 2002, as provided by SB1149, PGE and other Oregon utilities and electricity service suppliers began collecting a 3% Public Purpose Charge from retail customers to fund cost-effective conservation measures, renewable energy resources, and weatherization measures for low-income housing. Amounts collected are distributed monthly to organizations responsible for the administration of these programs. The Energy Trust of Oregon, a non-profit organization, administers the conservation and renewable resources portion of the public purpose funds and has contracted with PGE to continue to provide services to the Company's customers during a transition period.

Wholesale Sales

A 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 forward markets has led to enhanced price discovery available for market participants, further adding to the pressure on wholesale prices and margins. During 2001, PGE's wholesale sales accounted for about 63% of total revenues, due largely to significantly higher wholesale market prices, and 42% of total energy sales. Wholesale revenues are expected to decrease significantly in 2002 due to substantially lower prices. 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

Wholesale power market products, along with PGE's base of thermal and hydroelectric generating capacity, currently provide the Company the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers. Although surplus generation diminished in recent years due to economic and population growth in the western United States, the recent construction of new generating plants has increased the region's capacity to meet its power needs.

During 2001, PGE generated approximately 61% of its retail load requirement, compared to approximately 54% in 2000. Short-term and long-term purchases were utilized to meet the remaining load. PGE has long-term power contracts with four hydro projects on the mid-Columbia River providing capability of 645 MW, and has also relied increasingly upon near-term forward purchases to meet its energy needs. The Company anticipates that an active wholesale market and generating capacity within the WSCC will provide wholesale energy to supplement its generation and purchases under existing firm power contracts.

Early forecasts for 2002 indicate hydro conditions approximating 91% of normal, compared to 56% 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 may affect the availability and price of purchased power. PGE continues to evaluate the impact of current and potential listings of salmon species for protection under the federal Endangered Species Act on its purchased power supply and the operation of its hydroelectric projects on the Deschutes, Sandy, Clackamas, and Willamette rivers.

Additional factors that could affect the availability and price of purchased power 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.

Residential Exchange Program

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

 

Pelton Round Butte Hydroelectric Project Sale

PGE and the Confederated Tribes of Warm Springs (Tribes) executed an agreement in 2000 that will result in shared ownership and control of the Company's 410-MW Pelton Round Butte hydroelectric project, which has provided about 20% of PGE's power-generating capacity. PGE and the Tribes completed the draft of their joint 50-year license application in 2000, and filed the final joint application amendment with the FERC in June 2001. The Tribes acquired a 33.33% interest in the project on January 1, 2002 and have options to purchase an additional 16.66% interest in 2021 and a 0.02% interest prior to the expiration date of the joint license. The sale to the Tribes terminated the approximately $10 million annual fees PGE had paid the Tribes for the inundation of their property along the Deschutes and Metolius rivers. The agreement provides for continued operation of the project by PGE.

Hydro Relicensing

PGE Hydro - PGE's five FERC-licensed hydroelectric projects consist of eight facilities which provide economical generation and flexible load following capabilities. In 2001, they produced approximately 2 million MWh of renewable energy, about 11% of PGE's total retail customer load. The plants operate under federal licenses, which are up for renewal through 2006. Costs of relicensing the Company's hydroelectric projects are capitalized.

PGE's relicensing processes for the Willamette and Clackamas River hydroelectric projects have begun and involve appropriate resource agencies, environmental groups, and the general public. These projects are licensed until December 2004 and August 2006, respectively, and have a combined output of 187 MW. A significant number of biological, cultural, recreational, and engineering studies are continuing in efforts to determine the projects' impacts and opportunities for mitigation and enhancements. Due to projected costs related to environmental measures necessary to protect several runs of endangered salmon, PGE's 22-MW Bull Run Project will not be relicensed when its existing federal license expires in November 2004.

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 cooperatives have initiated proceedings with the FERC seeking to change the allocation of generation from the Priest Rapids and Wanapum projects 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.

PGE has executed new agreements with Grant County Public Utility District (Grant), operator of the Priest Rapids and Wanapum projects. The new agreements are effective upon expiration of the current contracts and are subject to FERC approval. Under the agreements Grant will annually determine the output required for its purposes, with PGE required to purchase approximately 25% of the output beyond Grant's needs.

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

Nuclear Decommissioning

PGE currently estimates the total cost to decommission Trojan at $337 million (nominal dollars), with approximately $151 million expended through 2001. The total estimate assumes that the majority of decommissioning activities will be completed by 2004 after the spent fuel has been transferred to a temporary dry spent fuel storage. The plan anticipates final site restoration activities will begin in 2018 after PGE completes shipment of spent fuel to a USDOE facility.

Approval of the Trojan Decommissioning Plan by the NRC and EFSC has allowed PGE to begin decommissioning activities. The steam generator, reactor containment vessel and other major components have been removed and transported to the federal Hanford Nuclear Reservation in Washington State for permanent storage. Nuclear fuel will remain in the spent fuel pool at the Trojan site until it is moved to dry storage at the plant site, expected to be completed in 2003. PGE is constructing the Trojan Independent Spent Fuel Storage Installation (ISFSI) as an interim dry storage facility at Trojan to house the nuclear fuel until permanent storage at a federal facility is available. In February 2002, the USDOE formally recommended that Yucca Mountain, Nevada become the nation's first long-term geologic (underground) repository for high-level radioactive waste produced in the United States. The proposed location, which the current presidential administration has endorsed, is based on the conclusions of scientific studies of the site, conducted over 20 years, that support a finding of suitability as mandated by the Nuclear Waste Policy Act and various regulations of the NRC, USDOE, and the EPA. Lawsuits have been filed objecting to this recommendation. Further delays may create difficulties for PGE in disposing of its high-level radioactive waste by 2018. However, federal legislation has been introduced which would require the USDOE to provide interim storage for high-level waste until a permanent site is established. The availability of an off-site repository for the permanent storage of radioactive waste will allow PGE to remove spent nuclear fuel from the ISFSI, allowing final decommissioning and release of the Trojan site for unrestricted use.

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

Trojan Investment Recovery

Due to the closure of the Trojan nuclear plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals and regulatory actions have taken place. As a result of a settlement agreement that was implemented in 2000, the recovery of the Trojan plant investment is no longer included in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant. (For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements).

Union Grievances

Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing  PGE's union workers, with respect to losses in their pension/savings plans attributable to the collapse of the price of Enron's stock. The grievances, on behalf of all present and retired bargaining unit members, allege that Enron manipulated the stock and caused the resultant losses. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. The IBEW and the Company have agreed to delay the grievance process until June 1, 2002, which may be extended by mutual agreement for an unlimited number of 30-day extensions.

Environmental Matter

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

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, in May 2000 the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement. Pursuant to the Voluntary Agreement, PGE submitted a pre-remedial investigation work plan for DEQ review and approval.

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

In March 2001, a final study plan was submitted to the DEQ for approval, with testing initiated in June 2001. PGE has performed initial investigations and remedial activities based upon the approved study and plan. Such investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

In February 2002, PGE submitted a report to the DEQ summarizing its pre-remedial investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The report concluded that the Harborton Substation facility was not a source of contamination to the Willamette River because no likely sources of hazardous substance releases were identified. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign such order.

Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the potential liability of responsible companies, including PGE. (For further information, see Note 10, Legal and Environmental Matters, in the Notes to Financial Statements).

RTO West and Independent Transmission Company

In 1999, the FERC issued Order No. 2000 in a continuing effort to more efficiently manage transmission, create fair pricing policies, and encourage competition by providing equal access to the nation's electric power grids. The order requires all owners of electricity transmission facilities to file a proposal to form or to join Regional Transmission Organizations (RTOs). In response to this order, PGE joined with other western utilities and BPA in submitting to the FERC a framework and timetable for formation of RTO West, a regional non-profit transmission organization that would operate the transmission system and manage pricing in the Pacific Northwest, Nevada, and parts of neighboring states.

In April 2001, PGE and four other regional utilities received conditional approval from the FERC to form TransConnect, an independent for-profit transmission company that will participate in RTO West. As proposed, TransConnect could own or lease the high-voltage transmission facilities currently held by PGE and its other participants. Combining transmission resources into one independent entity could create new opportunities to attract capital for system improvements and expansion while improving transmission infrastructure and reducing regional transmission constraints. In November 2001, the utilities jointly filed with the FERC a proposed rate structure for the new company.

Decisions related to the formation of RTO West and TransConnect will continue to be subject to approvals by state and federal agencies and individual company boards of directors.

New Accounting Standards

See Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements for information regarding new accounting standards issued during 2001.

Statement Regarding Forward-Looking Statements

This report contains statements that are forward-looking within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or future events or performance. Words or phrases such as "anticipates", "believes", "estimates", "expects", "intends", "plans", "predicts", "projects", "will likely result", "will continue", or similar expressions identify forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by PGE, as applicable, to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that PGE's expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

  • matters related to Enron and certain of its subsidiaries' filings to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);

  • events related to Enron's proposed sale of PGE to NW Natural;

  • effects of electric industry restructuring in Oregon and in the United States and wholesale competition;

  • governmental policies and regulatory investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and rate structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of net variable power costs and other capital investments, and present or prospective wholesale and retail competition;

  • changes in weather, hydroelectric, and energy market conditions, which could affect PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;

  • wholesale energy prices (including the effect of June 2001 FERC price controls) and their effect on the availability and price of wholesale power purchases and sales in the western United States;

  • changes in, and compliance with, environmental and endangered species laws and policies;

  • residential, commercial, and industrial growth and demographic patterns in PGE's service territory;

  • the loss of any significant customer, or changes in the business of a major customer, that may result in changes in demand for PGE services;

  • the ability of PGE to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;

  • capital market conditions, including interest rate fluctuations and capital availability;

  • changes in PGE's credit ratings, which may have an impact on the availability and cost of capital;

  • legal and regulatory proceedings and issues; and,

  • employee workforce factors, including strikes, work stoppages, and the loss of key executives.

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

 

 

Item 7A.   Quantitative and Qualitative Disclosures About Market Risk

 

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

Commodity Price Risk

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

Gains and losses from instruments that reduce commodity price risks are recognized when settled in purchased power and fuel expense, or in wholesale revenue. In addition, Company policy allows the use of these instruments for trading purposes, which may expose the Company to market risks resulting from adverse changes in commodity prices. Unrealized gains and losses on such instruments are recognized within "Purchased power and fuel" expense on PGE's Income Statement. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value, and volatility factors underlying the commitments.

The Company actively manages its risk to ensure compliance with its risk management policies. PGE monitors open commodity positions in its energy portfolios using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 months, including estimates of retail load and plant generation in the non-trading portfolio. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology, the average, high, and low value at risk on the non-trading portfolio in 2000 was $2.0 million, $4.6 million, and $1.1 million, respectively. For 2001, the value at risk on the non-trading portfolio is not meaningful since the majority of the portfolio is effectively accounted for on an accrual or settlements basis. Additionally, the Company has power cost mechanisms in place (see "Power Cost Mechanisms" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations") that allow PGE to defer, for future ratemaking treatment, actual net variable power costs that differ from certain baseline amounts approved by the OPUC. In 2001, PGE did not reduce its non-trading value at risk by the amount of potential deferrals. The average, high, and low value at risk on the trading portfolio in 2001 was $0.8 million, $3.6 million, and zero, respectively, and in 2000 was $0.3 million, $0.5 million, and zero, respectively. Note that instances of zero value at risk occur when there are no open positions in the trading portfolio.

 Foreign Currency Risk

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

At December 31, 2001, a 10% change in the value of the Canadian dollar would result in a change in pre-tax income of approximately $4 million at the time the transactions settle over the next two years. Foreign currency risk in PGE's trading portfolio is immaterial to the Company's consolidated financial statements and is not expected to change materially in the near future.

Interest Rate Risk

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

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

     

Carrying Amounts by Maturity Date

   

Total Fair

                         

After

   

Value

 

Total

 

2002

 

2003

 

2004

 

2005

 

2006

 

2006

First Mortgage Bonds

 

$ 465

 

$ 478

 

$ 165

 

$  40

 

$ 45

 

$ 18

 

$ -

 

$ 210

Pollution Control Revenue Bonds

177

194

       -

142

      -

-

-

52

Other

 

257

 

270

 

      8

 

     9

 

    10

 

10

 

9

 

224

Total

 

$ 899

 

$ 942

 

$ 173

 

$ 191

 

$ 55

 

$ 28

 

$ 9

 

$ 486

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

Credit Risk

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

Risk Management Committee

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

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

 

Item 8. Financial Statements and Supplementary Data

 

Management's Responsibility for Financial Reporting

 

 

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

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

PGE assessed its internal control system as of December 31, 2001, 2000 and 1999, 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.

PricewaterhouseCoopers LLP was engaged to audit the 2001 financial statements of PGE and issue a report thereon. Arthur Andersen LLP was engaged to audit the 1999 and 2000 financial statements of PGE and issue reports on them. Their audits included developing an overall understanding of PGE's accounting systems, procedures, and internal controls, and conducting tests and other auditing procedures sufficient to support their opinions on the financial statements.

 

 

Report of Independent Accountants

 

 

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

In our opinion, the accompanying consolidated balance sheet as of December 31, 2001 and the related consolidated statements of income, of retained earnings, of comprehensive income, and of cash flows present fairly, in all material respects, the financial position of Portland General Electric Company and its subsidiaries at December 31, 2001, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of the Company as of December 31, 2000 and 1999 and for the years then ended were audited by other independent accountants whose report dated January 26, 2001 expressed an unqualified opinion on those statements.

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

 

PricewaterhouseCoopers LLP

Portland, Oregon

April 11, 2002

 

 

 

Report of Independent Public Accountants

 

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

We have audited the accompanying consolidated balance sheet of Portland General Electric Company (an Oregon corporation), and subsidiaries as of December 31, 2000, and the related consolidated statements of income, retained earnings and cash flow for each of the two years in the period ended December 31, 2000. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule 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 the results of their operations and their cash flows for each of the two years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

Our audits were 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 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

Consolidated Statements of Income

       

For the Years Ended December 31

 

2001

 

2000

 

1999

   

(In Millions)

Operating Revenues

$

3,047

$

2,253

$

1,378

Operating Expenses

           
 

Purchased power and fuel

 

2,361

 

1,461

 

654

 

Production and distribution

 

128

 

126

 

119

 

Administrative and other

 

151

 

137

 

115

 

Depreciation and amortization

 

170

 

164

 

155

 

Taxes other than income taxes

 

65

 

65

 

61

 

Income taxes

 

38

 

94

 

84

     

2,913

 

2,047

 

1,188

Net Operating Income

 

134

 

206

 

190

Other Income (Deductions)

           
 

Provision for uncollectible accounts receivable from affiliates

 

(79)

 

-

 

-

 

Miscellaneous

 

4

 

10

 

13

 

Income taxes

 

36

 

(3)

 

(6)

     

(39)

 

7

 

7

Interest Charges

           
 

Interest on long-term debt and other

 

68

 

63

 

59

 

Interest on short-term borrowings

 

4

 

9

 

10

     

72

 

72

 

69

Net Income before cumulative effect of a change in accounting principle

 

23

 

141

 

128

Cumulative effect of a change in accounting principle, net of related taxes of $(6)

 

11

 

-

 

-

Net Income

 

34

 

141

 

128

Preferred Dividend Requirement

 

2

 

2

 

2

Income Available for Common Stock

$

32

$

139

$

126

Portland General Electric Company and Subsidiaries

Consolidated Statements of Retained Earnings

               

For the Years Ended December 31

 

2001

 

2000

 

1999

     

(In Millions)

               

Balance at Beginning of Year

$

459

$

401

$

356

Net Income

 

34

 

141

 

128

     

493

 

542

 

484

Dividends Declared

           
 

Common stock

 

40

 

81

 

81

 

Preferred stock

 

2

 

2

 

2

     

42

 

83

 

83

Balance at End of Year

$

451

$

459

$

401

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

 

 

Portland General Electric Company and Subsidiaries

Consolidated Statements of Comprehensive Income

 

For the Years Ended December 31

 

2001

 

2000

 

1999

 

( In Millions)

Accumulated other comprehensive income (loss) - Beginning of Year

 

$       -

 

$        -

 

$      -

             

Net Income

 

$    34

 

$   141

 

$ 128

             

Other comprehensive income, net of tax:

           
 

Unrealized gains (losses) on derivatives classified as cash flow  hedges:

           
   

Unrealized holding gain due to cumulative effect of change in  accounting principle, net of related taxes of $(23)

 

35

 

-

 

-

   

Other unrealized holding losses arising during the period, net of related taxes of $37

 

(56)

 

-

 

-

   

Reclassification adjustment for contract settlements included in net income, net of related taxes of $7

 

(10)

 

-

 

-

   

Reclassification adjustment in net income due to discontinuance of cash flow hedges, net of related taxes of $(19)

 

30

 

-

 

-

   

Reclassification of unrealized losses to SFAS No. 71 regulatory asset, net of related taxes of $(1) 

 

1

 

-

 

-

 

Minimum pension liability adjustment

 

(2)

 

-

 

-

   

Total Other comprehensive income (loss)

 

    (2)

 

        -

 

      -

               
 

Comprehensive income

 

$    32

 

$   141

 

$ 128

               
Accumulated other comprehensive income (loss) - End of Year

$    (2)

$        -

$      -

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

 

 

Portland General Electric Company and Subsidiaries

Consolidated Balance Sheets

At December 31

2001

2000

(In Millions)

Assets

Electric Utility Plant - Original Cost

Utility plant

$

3,596

$

3,423

Accumulated depreciation

(1,643)

(1,532)

1,953

1,891

Other Property and Investments

Contract termination receivable

28

57

Receivable from parent (less allowance for uncollectible accounts of $74 and $0)

-

80

Nuclear decommissioning trust, at market value

30

33

Trust owned life insurance

81

86

Miscellaneous

35

21

174

277

Current Assets

Cash and cash equivalents

8

60

Accounts and notes receivable (less allowance for uncollectible accounts of $28 and $10)

272

287

Unbilled and accrued revenues

80

60

Assets from price risk management activities

170

279

Inventories, at average cost

44

31

Deposits

89

-

Prepayments and other

78

61

Deferred income taxes

6

-

747

778

Deferred Charges

Unamortized regulatory assets

582

484

Miscellaneous

18

22

600

506

$

3,474

$

3,452

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

481

480

Retained earnings

451

459

Accumulated other comprehensive income (loss)

(2)

-

Cumulative preferred stock subject to mandatory redemption

29

30

Long-term obligations

769

798

1,888

1,927

Commitments and Contingencies (Notes 7, 10-16)

Current Liabilities

Long-term debt due within one year

173

52

Preferred stock maturing within one year

1

-

Short-term borrowings

174

16

Accounts payable and other accruals

250

286

Liabilities from price risk management activities

196

266

Customer deposits

5

139

Deferred income taxes

-

5

Accrued interest

13

14

Dividends payable

1

1

Accrued taxes

15

8

Unamortized regulatory liabilities

42

-

870

787

Other

Deferred income taxes

339

360

Deferred investment tax credits

23

27

Trojan decommissioning and transition costs

205

218

Unamortized regulatory liabilities

44

34

Nonqualified benefit plan liabilities

62

52

Miscellaneous

43

47

716

738

$

3,474

$

3,452

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

 

2001

 

2000

 

1999

     

(In Millions)

               

Cash Flows From Operating Activities:

           
Reconciliation of net income to net cash provided by (used in)    operating activities
 

Net income

$

34

$

141

$

128

 

Non-cash items included in net income:

           
   

Cumulative effect of a change in accounting principle,

           
   

net of tax

 

(11)

 

-

 

-

   

Depreciation and amortization

 

170

 

164

 

155

   

Deferred income taxes

 

(31)

 

(8)

 

(3)

   

Net assets from price risk management activities

 

30

 

(13)

 

-

   

Power cost adjustment

 

(89)

 

-

 

-

   

Provision for uncollectible accounts receivable from affiliates

 

79

 

-

 

-

   

Other non-cash income and expenses (net)

 

27

 

36

 

(1)

 

Changes in working capital:

           
   

Net margin deposit activity

 

(223)

 

139

 

-

   

(Increase) decrease in receivables

 

(10)

 

(158)

 

(9)

   

Increase (decrease) in payables

 

(30)

 

118

 

(1)

   

Other working capital items - net

 

(29)

 

(14)

 

(18)

 

Other - net

 

16

 

18

 

(4)

Net Cash Provided by (Used in) Operating Activities

 

(67)

 

423

 

247

               

Cash Flows From Investing Activities:

           
 

Capital expenditures

 

(203)

 

(173)

 

(182)

 

Proceeds from sales of assets

 

-

 

27

 

-

 

Other - net

 

10

 

(1)

 

(3)

Net Cash Used in Investing Activities

 

(193)

 

(147)

 

(185)

               

Cash Flows From Financing Activities:

           
 

Net increase (decrease) in short-term borrowings

 

158

 

(250)

 

161

 

Repayment of long-term debt

 

(58)

 

(33)

 

(113)

 

Issuance of long-term debt

 

150

 

150

 

-

 

Dividends paid

 

(42)

 

(83)

 

(83)

 

Repayment of loans on corporate owned life insurance

 

-

 

-

 

(32)

 

Other - net

 

-

 

-

 

1

Net Cash Provided by (Used in) Financing Activities

 

208

 

(216)

 

(66)

Increase (Decrease) in Cash and Cash Equivalents

 

(52)

 

60

 

(4)

Cash and Cash Equivalents, Beginning of Period

 

60

 

-

 

4

Cash and Cash Equivalents, End of Period

$

8

$

60

$

-

               

Supplemental disclosures of cash flow information

           
 

Cash paid during the year:

           
   

Interest, net of amounts capitalized

$

66

$

62

$

58

   

Income taxes

 

35

 

109

 

139

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 2, 1997, Portland General Corporation (PGC), the former parent of PGE, merged with Enron, with Enron continuing in existence as the surviving corporation. PGE is currently a wholly owned subsidiary of Enron and subject to control by Enron. PGE is a single, integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also sells wholesale electric energy to utilities, brokers, and power marketers located throughout the western United States, the majority of which sales take place in Oregon, or at the Oregon border. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. 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 4,095 square miles. At the end of 2001, PGE's service area population was approximately 1.5 million, comprising about 43% of the state's population and serving approximately 736,000 customers.

On October 5, 2001, Enron and NW Natural entered into a Stock Purchase Agreement providing for the acquisition by NW Natural of all of the issued and outstanding common stock of PGE. The transaction is subject to a number of conditions, including obtaining regulatory approvals. See Note 15, Proposed Acquisition of PGE by NW Natural, for further information.

On December 2, 2001, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. PGE is not included in the filing. See Note 16, Enron Bankruptcy, for further information.

Note 1 - Summary of Significant Accounting Policies

Consolidation Principles

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

Basis of Accounting

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

Use of Estimates

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

Contingencies

Contingencies are evaluated based on SFAS No. 5, Accounting for Contingencies, using the best information available. A material loss contingency is accrued and disclosed when it is probable that an asset has been impaired or a liability incurred and the amount of the loss can be reasonably estimated. If a range of possible loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency is disclosed to the effect that the probable loss cannot be reasonably estimated. A material loss contingency will be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. Gain contingencies are recognized upon realization and are disclosed when material.

Reclassifications

Certain amounts in prior years have been reclassified for comparative purposes. These reclassifications had no material effect on PGE's previously reported consolidated financial position, results of operations, or cash flows.

Revenues

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

Purchased Power

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

In addition, that portion of net variable power costs deferred for future recovery from customers under the Company's power cost mechanism is reflected as a credit to Purchased power and fuel expense.

Capitalization of Property, Plant and Equipment

Additions to utility plant are capitalized at their original cost, consistent with accounting and regulatory guidelines. Costs include direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and allowance for funds used during construction. Plant replacements are capitalized, with minor items charged to expense as incurred. The costs to purchase/develop software applications are capitalized in accordance with AICPA Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use.

Utility plant at December 31 consists of the following (in millions):

 

 

2001

 

2000

Production

$1,367

 

$1,326

Transmission

350

 

359

Distribution

1,487

 

1,364

General

228

 

235

Intangible

67

 

61

Construction Work in Progress

97

 

78

Total

$3,596

 

$3,423

       

 

 

Depreciation and Amortization

Depreciation is computed using the straight-line method over the estimated average service lives of various classes of plant in service. It is based upon original cost and includes an estimate for any expected salvage less cost of asset removal. Classes of plant in service and their estimated service lives (in years) are as follows: Production (31), Transmission (39), Distribution (33), and General (14). Depreciation expense as a percent of the related average depreciable plant in service was approximately 4.2% in 2001, 2000 and 1999.

Periodic depreciation studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates). The studies are filed with the OPUC for approval to be included in a future rate proceeding. The last study was approved by the OPUC and incorporated in its August 2001 general rate order.

The original cost of depreciable property units together with cost of removal (net of salvage), is charged to accumulated depreciation when property is retired and removed from service.

Intangible plant, primarily computer software development costs, is amortized over estimated average service lives.

Major Maintenance Expenses

Costs of periodic major maintenance inspections and overhauls at the Company's generating plants are charged to operating expenses as incurred.

Allocations and Loadings

PGE utilizes a series of  cost distributions and loadings to allocate certain administrative and overhead costs between capital and operating accounts, based primarily on construction activities of the Company.

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. It is capitalized as part of the cost of plant and is credited to income but does not represent current cash earnings. The average rates used by PGE in 2001, 2000, and 1999 were 6.0%, 6.8%, and 5.3%, respectively. AFDC from borrowed funds was $3 million in 2001 and 2000 and $2 million in 1999. AFDC from equity funds was $3 million in 2001 and $0 in 2000 and 1999.

Debt Issuance Costs

Underwriting, legal and other direct costs incurred in connection with the issuance of debt securities are deferred and amortized to interest expense equitably over the life of the security. Unamortized debt issuance costs at December 31, 2001 and 2000 were $8.5 million and $9.5 million, respectively, and are classified within "Deferred charges - miscellaneous" on the Balance Sheet.

Income Taxes

PGE's federal taxable income has been included in Enron's consolidated federal income tax return since its merger with Enron on July 2, 1997. PGE paid Enron for net tax liabilities generated on the taxable income of PGE, less applicable tax credits. On May 7, 2001, Enron determined that PGE would no longer be a member of the Enron consolidated federal income tax return. Taxable income from PGE and its consolidated subsidiaries during the period January 1, 2001 through May 7, 2001 will be included in Enron's federal consolidated and Oregon combined income tax returns. For the period May 8, 2001 to December 31, 2001, PGE and its subsidiaries will file their own consolidated federal income tax return, and pay their own tax liability directly to the Internal Revenue Service. PGE and its subsidiaries will file their unitary state income tax returns in accordance with the appropriate state law. This will include filing their own unitary state income tax returns and paying their own state tax liabilities, as well as being included in some Enron and subsidiaries' unitary state income tax returns.

Deferred income taxes are provided for temporary differences between financial and income tax reporting. Investment tax credits utilized have been deferred and are amortized to income over the approximate lives of the related properties, not to exceed 25 years. See Note 3, Income Taxes, for further information.

Price Risk Management

PGE engages in price risk management activities in its electric business for both non-trading and trading purposes, utilizing derivative instruments such as electricity forward and option, and natural gas forward, swap and futures contracts. On January 1, 2001, PGE adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under SFAS No. 133, derivative instruments are recorded on the Balance Sheet as Assets and Liabilities from Price Risk Management Activities measured at fair value, with changes in fair value recognized currently in earnings unless hedge accounting applies. Prior to 2001, trading contracts were recorded at fair value pursuant to Emerging Issues Task Force (EITF) Issue 98-10, Accounting for Energy Trading and Risk Management Activities.

Non-Trading

Non-trading electricity and natural gas forward contracts and electricity options that are entered into in anticipation of serving the Company's regulated retail load generally meet the requirements for treatment under the normal purchases and normal sales exception under SFAS No. 133. Other non-trading activities consist of certain natural gas forwards and swaps that qualify as cash flow hedges of forecasted transactions, and certain natural gas swaps with no hedging designation. Such activities are intended to protect against variability in expected future cash flows due to associated price risk and are utilized to manage overall fuel costs for retail customers.

PGE's electric retail business is subject to OPUC regulation. The OPUC recognizes non-trading contracts only at the time of settlement. Contracts that qualify for the normal purchases and normal sales exception are not required to be recorded at fair value. Unrealized gains and losses from contracts that qualify as cash flow hedges are recorded net in Other Comprehensive Income (OCI) and contracts not designated as hedges are recorded net in Purchased power and fuel on the Statement of Income. To reflect the effects of regulation, PGE records a regulatory asset or regulatory liability under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to offset unrealized gains and losses recorded prior to settlement. The regulatory asset or regulatory liability is reflected as Unamortized regulatory assets or Unamortized regulatory liabilities, respectively, on the Balance Sheet. Upon settlement, the regulatory asset or regulatory liability is reversed. Due to performance risk and credit risk of the parties to each contract, sales are recorded in Operating revenues and purchases are recorded in Purchased power and fuel on the Statement of Income.

Trading

Trading contracts are reflected at fair value on the Balance Sheet with unrealized gains and losses recorded net in Purchased power and fuel on the Statement of Income. As trading contracts with performance risk and credit risk are settled, power sales are recorded in Operating revenues and electricity purchases and options and natural gas swaps and futures are recorded in Purchased power and fuel on the Statement of Income.

For additional information, see Note 8, Price Risk Management.

Cash and Cash Equivalents

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

Margin Deposits on Wholesale Trading Activities

In the course of its wholesale energy trading activities, PGE both receives and deposits performance assurance cash collateral, with required amounts based upon provisions contained in certain wholesale power agreements with counterparties. Amounts deposited with and received from counterparties under such agreements are reflected as Deposits and Customer deposits, respectively, within the Current assets and Current liabilities sections of the Balance Sheet.

Trust Owned Life Insurance

The cash surrender value of insurance contracts is reported as an asset at the end of the reporting period. The changes in such values between reporting periods are recognized as income or expense of the period (see "Non-Qualified Benefit Plans" in Note 2, Employee Benefits, for further information).

Inventories

PGE's inventories are recorded at cost, which includes the purchase price (less discounts), applicable taxes, transportation and handling costs, etc. The average cost method is utilized to price inventory as fuel is burned at the generating plants and as materials and supplies are issued for operations, maintenance and capital activities. General storeroom operation costs, including procurement, management and storage, are recorded in the unallocated stores account and distributed equitably as materials and supplies are issued.

Inventories at December 31 are summarized as follows (in millions):

 

2001

2000

Coal

$      5

$        5

Fuel oil

14

4

Materials and supplies

23

21

Unallocated stores account

  2

  1

Total

$    44

$      31

Trojan Decommissioning and Transition Costs

Trojan decommissioning costs consist of those expenditures related to the decommissioning of the plant, as well as certain transition costs associated with operating and maintaining the spent fuel pool and securing the plant until fuel is transferred to dry storage. Estimates of future expenditures are reflected as a liability on the Balance Sheet, with actual expenditures charged to the liability account as incurred. Estimated future expenditures are revised periodically and are stated in nominal dollars. See Note 11, Trojan Nuclear Plant, for further information.

Regulatory Assets and Liabilities

PGE is subject to the provisions of SFAS No. 71. When the requirements of SFAS No. 71 are met, the Company 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 will ultimately be refunded to customers. Regulatory assets and liabilities are reflected within Current assets and Current liabilities, Deferred charges, and Other liabilities on the Balance Sheet and are amortized over the period in which they are included in billings to customers.

Amounts in the Balance Sheet as of December 31 consist of the following (in millions):

 

2001

 

2000

Unamortized regulatory assets:

     
 

Trojan decommissioning costs

$           172

 

$           190

 

Income taxes recoverable

127

 

136

 

Prior tax benefits recoverable

37

 

45

 

Debt reacquisition costs

20

 

21

 

Conservation investments - secured

46

 

54

 

Energy efficiency programs

35

 

19

 

Power cost adjustment

89

 

-

 

Price risk management

28

 

-

 

Regulatory restructuring costs (SB1149)

14

 

4

 

Year 2000 remediation costs

-

 

6

 

Miscellaneous

  14

 

    9

 

Total

$           582

 

$           484

   

 

Unamortized regulatory liabilities:

     
 

NEIL distribution

$             21

 

$             19

 

Deferred gains on sales of major assets

-

 

11

 

Merger savings obligation

8

 

-

 

Miscellaneous

  15

 

   4

 

Subtotal

44

 

34

 

Deferred energy revenues (current)

  42

 

    -

 

Total

$             86

 

$             34

Income taxes recoverable - Tax benefits previously flowed to customers through rates for temporary differences between book and tax reporting. The income taxes recoverable amount is reduced as temporary differences reverse and the increase in current tax expense is recovered in rates.

Prior tax benefits recoverable - In 2000, PGE 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, along with several largely offsetting regulatory liabilities. The settlement also allows recovery of approximately $47 million in income taxes recoverable 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 and Environmental Matters, for further information.

Conservation investments-secured - In 1996, $81 million of PGE's energy efficiency investment was designated as Bondable Conservation Investment upon the Company's issuance of 10-year 6.91% conservation bonds collateralized by OPUC-authorized revenues, which fund the debt service obligation. The issuance of such bonds provided PGE immediate recovery of its unamortized energy efficiency program expenditures while providing future savings to customers.

Energy efficiency programs - PGE's energy efficiency program expenditures, formerly deferred and amortized, have been expensed directly since October 1, 2000. The unamortized balance of those expenditures incurred prior to October 1, 2000, as well as amounts recoverable under the Company's SAVE energy efficiency program and certain other energy efficiency costs, have been combined within a single regulatory asset account. Beginning October 1, 2001, amounts are recovered from retail customers by a separate supplemental tariff schedule and amortized to expense over an approximate three-year period.

Power cost adjustment - In February 2001, the OPUC authorized PGE to defer net variable power costs which differ from a baseline amount. Under this mechanism, PGE shares with its retail customers power costs outside of this range from January through September 2001. As of December 31, 2001, approximately $89 million, including interest, has been deferred for future recovery from customers. The OPUC has approved PGE's application to recover this balance from customers over a period of 3 1/2 years, beginning April 1, 2002.

Price risk management - Effective October 1, 2001, the OPUC approved rates based on the value of all the Company's resources, including non-trading derivative instruments that will settle during the 15-month period ending December 31, 2002. SFAS No. 133 requires unrealized gains and losses on derivative instruments that do not qualify for either the normal purchase and normal sale exception or hedge accounting to be recorded in earnings in the current period. The timing difference between the recognition of gains and losses on derivative instruments and their realization and subsequent collection in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. At December 31, 2001, PGE had recorded $28 million as a regulatory asset to fully offset the effects of unrealized gains and losses from changes in fair values of these contracts. As contracts are settled, the regulatory asset or regulatory liability is reversed. See Note 8, Price Risk Management, for further information.

NEIL distribution - In 2000, PGE received a distribution related to the termination of its membership in Nuclear Electric Insurance Limited (NEIL), with the customers' share deferred pending disposition by the OPUC. The Commission has approved PGE's application to refund the deferred amount over a nine-month period beginning April 1, 2002, partially offsetting the amount to be collected under the Company's power cost mechanism.

Merger savings obligation - As a condition of PGE's 1997 merger with Enron, retail customers were guaranteed $36 million in rate credits over a four-year period to reflect anticipated merger-related savings. In the Company's 2001 general rate proceeding, such savings were incorporated into operating expenses utilized to set new rates that became effective October 1, 2001. To reflect PGE's remaining liability for future customer credits, approximately $8 million was recorded as a regulatory liability at December 31, 2001; this amount is expected to be fully refunded by the end of 2002.

Deferred energy revenues - In PGE's recent general rate case, the OPUC authorized new electricity rates to cover forecast power costs that fluctuate materially due to market volatility. In order to properly match revenues and expenses, PGE defers the difference between base energy revenues and base variable power costs over a 15-month test period utilized to determine the Company's authorized revenues. Beginning October 1, 2001, monthly differences are deferred and offset within Operating revenues; deferred amounts will be recognized as revenues as expected power costs are incurred.

Regulatory restructuring costs (SB1149) - The OPUC has authorized PGE to defer incremental costs related to the implementation of Oregon restructuring legislation and to recover such costs from customers in future periods. Application for recovery of these costs has not yet been submitted to the Commission for consideration.

Other items - As part of its August 2001 general rate order, the OPUC approved a supplemental tariff that refunds to retail customers the net unamortized balance of several regulatory liabilities and assets over an approximate one-year period beginning October 1, 2001. The largest of such items consist of deferred gains on the sale of certain major assets and deferred Year 2000 remediation costs. The unamortized balance to be refunded under the supplemental tariff is $8 million at December 31, 2001 (included within "Miscellaneous" regulatory liabilities).

Recovery/refund period - As of December 31, 2001, the majority of the Company's regulatory assets and liabilities are reflected in customer rates. Based on such rates, the Company estimates that it will collect substantially all of its regulatory assets, and refund its regulatory liabilities, within the next 10 years.

New Accounting Standards

During 2001, the Financial Accounting Standards Board (FASB) issued the following statements:

SFAS No. 141, Business Combinations, which requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method. PGE evaluated the effect of SFAS No. 141 and determined that there were no financial impacts related to its adoption by the Company.

SFAS No. 142, Goodwill and Other Intangible Assets, which modifies the accounting and reporting of goodwill and other intangible assets. Although PGE has no goodwill, it has other intangible assets, consisting primarily of software development costs, which are currently being amortized and recovered in rates over their estimated and approved average useful lives. The Company capitalizes intangible costs related to the relicensing of its hydroelectric projects as project plant costs. Under SFAS No. 142, entities are required to determine the useful life of other intangible assets and amortize them over that period; if the useful life is determined to be indefinite, no amortization is to be recorded. For intangible assets recognized prior to the adoption of SFAS No. 142, the useful life is to be reassessed. PGE evaluated the impact of SFAS No. 142 and determined that there were no financial impacts related to its adoption by the Company.

SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the recognition, as an Asset Retirement Obligation (ARO), of a liability for dismantlement and restoration costs associated with the retirement of tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition, the probability weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ARO liability classified as an operating expense on the income statement. SFAS No. 143 must be applied for fiscal years beginning after June 15, 2002. PGE is currently evaluating the application of SFAS No. 143 to its tangible long-lived assets, substantially all of which are included in rate-regulated operations, and has not completed the quantification of the impact of this statement.

SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which was adopted by PGE on January 1, 2002. SFAS No. 144 supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. SFAS No. 144 retains the fundamental provisions of  SFAS No. 121 for the measurement and recognition of the impairment of long-lived assets to be held and used, as well as the measurement of long-lived assets to be disposed of by sale. SFAS No. 144 resolves significant implementation issues related to SFAS No. 121, broadens the component of an entity to be included in the presentation for discontinued operations, and measures long-lived assets held for sale at the lower of their carrying amount or fair value (less cost to sell), while ceasing depreciation. SFAS No. 144 also retains the amendments in SFAS No. 121 pertaining to regulatory assets under SFAS No. 71 and SFAS No. 90, Regulated Enterprises - Accounting for Abandonments and Disallowances of Plant Costs. PGE evaluated the impact of SFAS No. 144 and determined that there were no financial impacts related to its adoption by the Company.

 

 

 Note 2 - Employee Benefits

 Pension and Other Post-Retirement Plans

PGE participates in a non-contributory defined benefit pension plan with PGH and its subsidiaries. Substantially all of the pension plan members are current or former PGE employees. The pension plan assets are held in a trust.

The Non-Qualified Benefit Plans below primarily represent obligations for a Supplemental Executive Retirement Plan (SERP). Investments in trust owned life insurance policies (TOLI) are intended to be the primary source for financing these plans. TOLI assets of $22 million and $29 million as of December 31, 2001 and 2000, respectively, are shown in the table below for informational purposes only and are not considered segregated and restricted as defined by SFAS No. 87.  In addition, the recognized (gains)/losses on the TOLI assets of $6 million and $(5) million for 2001 and 2000, respectively, are included in net periodic pension cost.

PGE further 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 employees' beneficiary association to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers.

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

 

                  Defined Benefit

                   Non-Qualified

                    Pension Plan

                    Benefit Plans

Other Benefits

2001

2000

2001

2000

2001

2000

Reconciliation of benefit obligation:

Obligation at January 1

$ 266

$  253

$ 14

$ 14

$ 31

$ 29

Service cost

9

9

-

-

1

1

Interest cost

20

19

1

1

2

2

Participants' contributions

-

-

-

-

1

1

Actuarial loss

28

2

5

-

3

1

Benefit payments

(17)

 (17)

(1)

 (1)

 (3)

 (3)

Obligation at December 31

$ 306

266

$ 19

$ 14

$ 35

$ 31

Reconciliation of fair value of plan assets:

Fair value of plan assets at January 1

$ 424

$  439

$ 29

$ 24

$ 30

$ 35

Actual return (loss) on plan assets

(11)

2

(7)

5

-

(3)

Company contributions

-

-

1

1

-

-

Participants' contributions

-

-

-

-

1

1

Benefit payments

(16)

 (17)

 (1)

 (1)

 (3)

 (3)

Fair value of plan assets at December 31

$ 397

424

$ 22

$ 29

$ 28

$ 30

Funded status:

Funded status at December 31

$   91

$  158

$   3

$ 15

$ (7)

$ (1)

Unrecognized transition (asset)/liability

(5)

(7)

-

-

3

4

Unrecognized prior service cost

8

9

2

2

1

2

Unrecognized gain

(39)

(121)

  3

   -

   1

 (5)

Prepaid pension cost

$   55

$    39

$   8

$ 17

$ (2)

$    -

Amounts recognized in the Balance Sheet

consist of:

Prepaid benefit cost

$     -

$      -

$ 10

$ 17

$    -

$    -

Accrued benefit liability

-

-

-

-

-

-

Accumulated other comprehensive income

    -

      -

(2)

    -

   -

   -

Net amount recognized

    -

$      -

$  8

$ 17

$   -

$    -

Assumptions:

Discount rate used to calculate benefit obligation

7.25%

7.75%

7.25%

7.75%

7.25%

7.75%

Rate of increase in future compensation levels

4.0 - 9.5%

4.0 - 9.5%

5.5 - 5.75%

5.5 - 5.75%

4.0 - 9.5%

4.0 - 9.5%

Long-term rate of return on assets

9.00%

9.00%

N/A

N/A

9.50%

9.50%

Components of net periodic benefit cost:

Service cost

$     9

$     9

$   -

$   -

$   1

$   1

Interest cost on benefit obligation

20

19

1

1

2

2

Expected return on plan assets

(37)

(35)

-

-

(2)

(3)

Amortization of transition asset

(2)

(2)

-

-

-

-

Amortization of prior service cost

1

2

-

-

-

-

Recognized (gain)/loss

(6)

(6)

   8

 (5)

   -

   -

Net periodic benefit cost

$ (15)

$ (13)

$   9

$ (4)

$   1

$   -

For measurement purposes, a 9.5% 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 can affect 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):

 

 

One-Percentage      Point Increase

One-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)

Other Non-Qualified Benefit Plans

In addition to the SERP Plan discussed above, PGE provides certain employees with benefits under an unfunded Management Deferred Compensation Plan (MDCP). Obligations for the MDCP were $48 million and $40 million at December 31, 2001 and 2000, respectively (not included in table). The costs of the SERP and MDCP Plans are excluded from rates charged to customers. Investments in trust owned life insurance policies of $56 million at December 31, 2001 are intended to be the primary source for financing the MDCP Plan. (For additional information, see Note 15, Proposed Acquisition of PGE by NW Natural).

Employee Stock Ownership Plan

In addition, PGE participated in the Portland General Holdings 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. Employee contributions up to 6% of base pay were matched by employer contributions in the form of Enron common stock through November 2001; such matching contributions were terminated December 1, 2001 as a result of the Enron bankruptcy filing. Enron has indicated that it believes its existing equity has and will have no value and that any Chapter 11 plan of reorganization confirmed by the Bankruptcy Court will not provide its existing equity holders with any interest in the reorganized entity.

All Employee Stock Option Plan

Enron stock options were granted to PGE employees on December 31, 1997 at the fair value of the stock at the date of the grant. As discussed above, shares of Enron common stock are no longer considered to have value.

 

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 (in Millions):

 

2001

2000

1999

Income Tax Expense

Currently payable

Federal

$   32

$  88

$ 78

State and local

     3

 17

 15

   35

105

 93

Deferred income taxes

Federal

(25)

(2)

(1)

State and local

   (5)

    -

   2

 (30)

 (2)

   1

Investment tax credit adjustments

  (3)

  (6)

 (4)

Total income tax expense before cumulative

effect of a change in accounting principle

$     2

$  97

$ 90

Provision Allocated to:

Operations

$   38

$ 94

$ 84

Other income and deductions

(36)

   3

   6

Total income tax expense before cumulative

effect of a change in accounting principle

$    2

$ 97

$ 90

Effective Tax Rate Computation:

Computed tax based on statutory federal

income tax rate (35%) applied to income 
before income taxes

$    9

$ 84

$ 77

Flow through depreciation

5

6

7

State and local taxes - net of federal tax
benefit

(1)

11

11

Investment tax credits

(3)

(6)

(4)

Excess deferred taxes

(1)

(1)

(1)

Deferred tax and other adjustments

(7)

  3

   -

Total income tax expense before cumulative

effect of a change in accounting principle

$    2

$ 97

$ 90

Effective tax rate

9.1% (*)

40.8%

41.3%

(*) The low effective tax rate for 2001 is primarily due to an approximate $5 million adjustment to deferred income taxes resulting from tax audit settlements, amended tax returns and the 2000 return to provision adjustment, $3 million in amortization of deferred investment tax credits, $2 million in state energy tax credits (net of the federal tax effect), and a $1 million tax effect related to non-taxable equity AFDC.

As of December 31, 2001 and 2000, the significant components of PGE's deferred income tax assets and liabilities were as follows (in millions):

 

2001

2000

Deferred income tax assets

Depreciation and amortization

$        20

$       24

Employee benefits

11

13

Deferred energy revenue

17

-

Allowance for uncollectible accounts

10

3

Land reclamation costs

8

8

Regulatory liabilities

NEIL distribution

8

8

Deferred gain on sale of major asset

-

4

Miscellaneous

8

7

Other

  11

    2

Total deferred income tax assets

  93

  69

Deferred income tax liabilities

Depreciation and amortization

323

330

Receivable from parent

4

31

Price risk management

1

5

Regulatory assets

Prior tax benefits recoverable

14

18

Debt reacquisition costs

8

8

Conservation investments

16

18

Energy efficiency programs

9

8

Power cost adjustment

35

-

Miscellaneous

7

2

Other

    9

 14

Total deferred income tax liabilities

426

434

Net deferred income taxes

$      333

$      365

Classification of net deferred income taxes

Included in current assets

$          6

$          -

Included in noncurrent liabilities

339

360

Included in current liabilities

-

5

Net deferred income taxes

$      333

$      365

 

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

 

of Shares

Value

of Shares

Value

Capital

(Dollars in Millions)

 

December 31, 1999

42,758,877

$160

300,000

$30

$480

December 31, 2000

42,758,877

160

300,000

30

480

December 31, 2001

42,758,877

160

300,000

30

481

 

Cumulative Preferred Stock

PGE has authorized 30 million shares of cumulative preferred stock, no par value; there are 300,000 shares of the 7.75% series outstanding. The 7.75% series preferred stock has an annual sinking fund requirement, which requires the redemption of 15,000 shares at $100 per share beginning in 2002. At its option, PGE may redeem, through the sinking fund, an additional 15,000 shares each year. All remaining shares shall be mandatorily redeemed by sinking fund in 2007. This series is only redeemable by operation of the sinking fund.

No dividends may be paid on common stock or any class of stock over which the preferred stock has priority unless all amounts required to be paid for dividends and sinking fund payments have been paid or set aside, respectively.

Common Stock Dividends

Enron owns all of the issued and outstanding common stock of PGE. Under Oregon law and specific OPUC merger conditions, Enron's access to PGE cash or assets (through dividends or otherwise) is limited. PGE is restricted from paying dividends or making other distributions to Enron without prior OPUC approval to the extent that such payment or distribution would reduce PGE's common stock equity capital below 48% of its total capitalization (excluding short-term borrowings). For additional information, see Note 15, Proposed Acquisition of PGE by NW Natural.

 

Note 5 - Credit Facilities and Debt

At December 31, 2001, PGE had committed lines of credit totaling $350 million. Credit lines of $150 million, with an annual fee of 0.14%, expire in July 2003; credit lines of $200 million, with an annual fee of 0.10%, expire in June 2002. 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. PGE's $200 million credit agreement also allows for the issuance of letters of credit of up to $100 million. At December 31, 2001, PGE used approximately $100 million in letters of credit under its committed credit lines.

PGE is evaluating alternatives for the replacement of its $200 million line of credit, which expires in June 2002. Such alternatives include the issuance of First Mortgage Bonds and new revolving credit facilities. The Company has sufficient capacity under its Indenture of Mortgage to issue additional debt if necessary.

Unused committed lines of credit must be at least equal to the amount of PGE's commercial paper outstanding. Commercial paper and lines of credit borrowings are at rates reflecting current market conditions.

PGE is required to comply with various covenants contained in its debt agreements. At December 31, 2001, the Company was in compliance with these covenants.

Short-term borrowings and related interest rates were as follows:

 

2001

2000

As of year-end:

(Dollars in Millions)

Aggregate short-term debt outstanding

Commercial paper

$129

$16

Bank Loans

45

-

Weighted average interest rate*

Commercial paper

3.50%

6.80%

Bank Loans

4.75%

-

Committed lines of credit

$350

$250

For the year ended:

Average daily amounts of short-term

debt outstanding

Commercial paper

$124

$120

Bank loans

4

-

Weighted daily average interest rate*

Commercial paper

3.30%

6.20%

Bank loans

4.75%

-

Maximum amount outstanding

during the year

Commercial paper

$301

$278

Bank loans

86

-

* 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

2001

 

2000

 

                 (In Millions)

       

First Mortgage Bonds

     
 

Maturing 2002 - 2005 (6.47% - 9.07%)

$        118

 

$        163

 

Maturing 2002 - variable rate (average rate 2.99%)

150

 

-

 

Maturing 2007 (7.15%)

50

 

50

 

Maturing 2021 - 2023 (7.75% - 9.46%) (a)

 160

 

 160

   

 478

 

 373

         

Pollution Control Bonds

     
 

Port of Morrow, Oregon, variable rate, due 2031

     
   

(Average rate 3.95% for 2001, 4.31% for 2000)

-

 

6

 

Port of Morrow, Oregon, variable rate, due 2033

     
   

(4.60% fixed rate to 2003) (b)

23

 

23

 

City of Forsyth, Montana, variable rate, due 2033

     
   

(4.60% - 4.75% fixed rate to 2003) (b)

119

 

119

 

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

     
   

(4.80% - 5.25% fixed rate to 2003) (b)

47

 

47

 

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

     5

 

     5

     

 194

 

   200

           

Other

     
 

8.25% Junior Subordinated Deferrable Interest Debentures,

     
   

due December 31, 2035 (c)

75

 

75

 

6.91% Conservation Bonds maturing monthly to 2006

46

 

53

 

7.875% Notes due March 15, 2010

150

 

150

 

Unamortized debt discounts

  (1)

 

   (1)

     

 270

 

 277

   

942

 

850

 

Long-term debt due within one year

(173)

 

 (52)

Total long-term debt

$        769

$        798

        (a) Indicated amount includes $115 million of 7.75% rate bonds due in 2023 that are redeemable by PGE after April 15, 2003 at initial redemption price of 103.751% of face value. Also includes $25 million of 9.46% rate bonds due in 2021 that are redeemable by PGE after August 12, 2001 at initial redemption price of 104.73% of face value.

        (b) Effective May 1, 2003, the interest rate on these bonds may be changed from time to time to Daily, Monthly, Weekly, Flexible, or Term interest rates. On the day next succeeding any interest rate change, the bonds are callable by PGE at 100% of face value. Also effective May 1, 2003, the bondholders can put the bonds back to PGE at 100%.

        (c) Redeemable by PGE at 100% of principal amount since October 10, 2000.

 

The following principal amounts (in millions) of long-term debt become due through regular maturities for the years indicated:

Year

Debt Maturities

2002

$ 173

2003

   191

2004

    55

2005

    28

2006

      9

Thereafter

  486

Total

$ 942

 

Note 6 - Other 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.

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. These include the Contract termination receivable (from SCE), Nuclear decommissioning trust, Trust owned life insurance, and other miscellaneous financial instruments.

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 (in millions):

 

 

2001

2000

 

Carrying Amount

Fair Value

Carrying Amount

Fair Value

Preferred stock subject to mandatory redemption

$ 30

$ 27

$ 30

$ 30

         

Long-term debt including current maturities

$942

$899

$850

$869

         

Lower fair values in relation to carrying amounts for preferred stock and long-term debt in 2001 resulted from recent credit rating downgrades.

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. These agreements require net payments of approximately $102 million in 2002, $29 million in 2003, $15 million in 2004 and 2005, $14 million in 2006, and $79 million over the remaining years of the contracts. These contracts expire at varying dates from 2002 to 2015.

Purchase Commitments

Certain commitments have been made for capital and other purchases for 2002 and beyond. Such commitments, totaling $44 million as of December 31, 2001, relate to information systems, upgrades to production facilities, and maintenance work. Termination of these agreements could result in cancellation charges.

Coal Agreements

PGE has coal agreements with take-or-pay provisions of approximately $22 million for 2002.

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 regarding these projects is summarized as follows (dollars in millions):

 

Rocky Reach

Priest Rapids

Wanapum

Wells

Portland Hydro

Revenue bonds outstanding at

         

December 31, 2001

$ 358

$ 162

$ 160

$ 170

$ 29

PGE's current share of:

         
 

Output

12.0%

13.9%

18.7%

20.3%

100%

 

Net capability (megawatts)

154

133

194

164

36

PGE's Annual cost, including debt service:

         
 

2001

$ 7

$ 4

$ 7

$ 6

$ 4

 

2000

7

4

6

6

4

 

1999

6

4

6

6

4

Contract expiration date

2011

2005

2009

2018

2017

PGE's share of debt service costs, excluding interest, is approximately $7 million in 2002, $9 million in 2003, $8 million in 2004, $7 million in 2005, and $6 million in 2006. Total minimum payments through the remainder of the contracts are estimated at $56 million.

PGE has executed new agreements with Grant County Public Utility District (Grant), operator of the Priest Rapids and Wanapum projects. The new agreements, which are subject to FERC approval, are effective upon expiration of the current contracts and the issuance of a new license to Grant. Under the agreements, Grant will annually determine the output required for its purposes, with PGE required to purchase over the term of the new license approximately 25% of the output beyond Grant's needs.

PGE has entered into power purchase contracts with other counterparties requiring payments of approximately $784 million in 2002, $185 million in 2003, $129 million in 2004, $121 million in 2005, $101 million in 2006, and $33 million over the remaining years of the contracts. These contracts expire at varying dates from 2002 to 2014. PGE also has entered into power capacity contracts requiring payments of approximately $19 million annually through 2006. After that time, capacity contract charges will average $20 million annually through 2016. PGE has entered into power sale contracts with other counterparties of approximately $278 million in 2002, $23 million in 2003, $20 million in 2004, $14 million in 2005 and 2006, and $90 million over the remaining years of the contracts.

PGE also has a long term power exchange contract with a summer-peaking Southwest utility to help meet the Company's winter-peaking power requirements. At December 31, 2001, PGE owed 12,470 MWhs of electricity, which was returned in February 2002.

Leases

PGE has operating lease arrangements for its headquarters complex, coal-handling facilities and certain railroad cars for Boardman. Lease payments charged to expense were $20 million in both 2001 and 2000, and $24 million in 1999.

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

Year Ending December 31

Operating Leases        (Net of Sublease Rentals)

2002

$  10

2003

      9

2004

    10

2005

      8

2006

      6

Remainder

  143

Total

$186

Included in the future minimum operating lease payments schedule above is approximately $98 million for PGE's headquarters complex.

Note 8 - Price Risk Management

PGE engages in non-trading and trading activities by utilizing derivative financial instruments in its electric utility business. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), which was adopted on January 1, 2001, derivative instruments are recorded on the balance sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings (in Purchased power and fuel), unless specific hedge accounting criteria are met. As contracts settle, sales are recorded in Operating revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel on the Statements of Income. Upon adoption of SFAS No. 133 on January 1, 2001, PGE recorded in earnings an after-tax gain of $11 million and in OCI an after-tax gain of $35 million from the cumulative effect of a change in accounting principle.

Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. As discussed below, the effects of changes in fair value of derivative instruments entered into to hedge the company's future retail resource requirements are subject to regulation and therefore are deferred pursuant to SFAS No. 71.

Non-Trading Activities

As PGE's primary business is to serve its retail customers, it enters into derivative instruments, including electricity forward and option, and natural gas forward and swap contracts to manage its exposure to commodity price risk and thereby attempt to minimize net power costs for customers. Effective October 1, 2001, PGE's base rates changed as a result of an OPUC general rate order. The new rates reflect an update of PGE's net variable power costs to include electricity and natural gas contracts that will settle over the next 15-month period. In addition to this change, the OPUC approved a 15-month power cost adjustment mechanism from October 1, 2001 to help PGE mitigate its exposure to risk associated with volatility of power and natural gas prices. The power cost mechanism provides an incentive for the Company to continue to actively manage resources it has procured to serve its retail load and reduce retail power costs over the next 15 months. The mechanism provides that PGE recover or refund a portion of the difference in changes in power costs and energy revenues from baseline amounts as a result of continuing management of its resources and changes in the forecasted load. The collection or refund is expected to be completed over the same 15-month period through adjustments to retail customer rates. Each year thereafter, PGE will provide updates of its net variable power costs to the OPUC for inclusion in base rates for the year.

SFAS No. 133 requires unrealized gains and losses on derivative instruments that do not qualify for either the normal purchase and normal sale exception or hedge accounting to be recorded in earnings in the current period. OPUC-approved rates are based on the value of all the Company's resources, including derivative instruments that will settle during the 15-month period from October 1, 2001 to December 31, 2002. The timing difference between the recognition of gains and losses on derivative instruments and their realization and subsequent collection in rates will be recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. As a result, in the third quarter of 2001 PGE began recording a regulatory asset or regulatory liability pursuant to SFAS No. 71 to offset the effects of unrealized gains and losses from changes in fair values of these contracts recorded prior to settlement. As contracts are settled, the regulatory asset or regulatory liability is reversed. In 2001, PGE recorded $26 million in net unrealized losses in earnings on natural gas swaps in its retail portfolio; this was fully offset by the recording of a SFAS No. 71 regulatory asset.

Derivative activities in 2001 from cash flow hedges consist of $2 million in unrealized losses that were fully offset by the recording of a SFAS No. 71 regulatory asset. No amount was reclassified into earnings as a result of hedge ineffectiveness. Cash flow hedges of $49 million were discontinued and reversed to Purchased power and fuel during 2001 due to the probability that the original forecasted transactions will not occur. As of December 31, 2001, the maximum length of time over which PGE is hedging its exposure to such transactions is two years. Of the transition adjustment recorded in OCI at January 1, 2001, losses of $19 million were reclassified into earnings during 2001. The Company estimates that of the $2 million of unrealized losses at December 31, 2001, $1 million will be reclassified into earnings within the next twelve months.

New Accounting Guidance - On December 19, 2001, the FASB approved an interpretation issued by the Derivatives Implementation Group (DIG) outlined in SFAS No. 133 Implementation Issue No. C16, Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract. The guidance disallows normal purchases and normal sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The guidance will become effective on April 1, 2002. PGE is currently evaluating the impact of this implementation guidance on its financial statements.

Trading Activities

PGE trading activities utilize electricity forward and option contracts and natural gas forward, swap and futures contracts to take advantage of price movements in electricity and natural gas. Such activities are not subject to regulation. In 2001, PGE recorded in earnings an $11 million loss from trading activities, consisting of $10 million in unrealized losses and $1 million in realized losses. In 2000, PGE recorded in earnings a $30 million gain from trading activities, comprised of $17 million of realized gains and $13 million of unrealized gains.

 

The fair value as of December 31 related to price risk management trading activities are set forth below:

 

Fair Value

 

Fair Value

(in millions)

as of 12/31/2001

 

as of 12/31/2000

 

Assets

 

Liabilities

 

Assets

 

Liabilities

Electric forward contracts

$ 93

 

$ 90

 

$ 270

 

$ 254

Natural gas swaps

44

 

44

 

9

 

12

Total

$ 137

 

$ 134

 

$ 279

 

$ 266

 

Note 9 - Jointly Owned Plant

At December 31, 2001, PGE had the following investments in jointly owned generating plants (dollars in millions):

Facility

Location

Fuel

MW Capacity

PGE %Interest

Plant In Service

Accumulated Depreciation

Boardman

Boardman, OR

Coal

362

65.0

$ 392

$244

Colstrip 3&4

Colstrip, MT

Coal

296

20.0

459

276

             

Above amounts represent PGE's share of each jointly owned plant, with the Company's share of both direct expenses and utility plant costs included in its financial statements. Each joint owner of the plants has provided its own financing.

In 2000, the Confederated Tribes of Warm Springs (Tribes) and PGE executed an agreement that will result in shared ownership and control of PGE's 410-MW Pelton Round Butte hydroelectric project, which has provided about 20% of the Company's power-generating capacity. The Tribes purchased an initial 33.33% interest on January 1, 2002 and have options to purchase an additional 16.66% interest in 2021 and a 0.02% interest prior to the expiration date of the joint license; exercise of such options would result in majority ownership of the project by the Tribes. The January 2002 sale to the Tribes, for the project's approximate $27 million net book value, terminated the approximately $10 million in annual fees paid the Tribes for the inundation of their property along the Deschutes and Metolius rivers. The agreement provides for continued operation of the project by PGE.

 

Note 10 - Legal and Environmental 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 of PGE's decision earlier in the year to cease commercial operation of Trojan as a part of its least cost planning process. In 1995, the OPUC issued a general rate order which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals and requested reviews 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, CUB, and the staff of the OPUC entered into agreements to settle 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 consisted 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 through 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 challenged the settlement agreements and the OPUC order. Collection of decommissioning costs at Trojan is unaffected by the settlement agreements or the OPUC order.

PGE had requested the Oregon Supreme Court to hold in abeyance its review of the 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 Commission on September 29, 2000. On March 25, 2002, the OPUC issued an order denying all of URP's challenges, and approving PGE's application of the accounting and ratemaking elements of the settlement. PGE has requested the Oregon Supreme Court to further delay its consideration until June 2002.

Management cannot predict the ultimate outcome of the above litigation. However, it believes 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.

Union Grievances - Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, on behalf of all present and retired bargaining unit members, allege that Enron manipulated the stock resulting in the losses. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. The IBEW and the Company have agreed to delay the grievance process until June 1, 2002. No reserves have been established by PGE for any amounts related to this issue.

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.

 

Environmental Matter - A 1997 investigation of a 5.5 mile segment of the Willamette river known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor.  Based upon analytical results of the investigation, the EPA has included the Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund") in 2000.

 

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the harbor sediments.  While PGE does not believe that it is responsible for any contamination in Portland Harbor, in May 2000 the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement.  Pursuant to the Voluntary Agreement, PGE submitted a pre-remedial investigation work plan for DEQ review and approval.

 

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

 

In March 2001, a final study plan was submitted to the DEQ for approval, with testing initiated in June 2001.  PGE has performed initial investigations and remedial activities based upon the approved study and plan.  Such investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

 

In February 2002, PGE submitted a report to the DEQ summarizing its pre-remedial investigations conducted in accordance with the May 2000 Voluntary Agreement.  The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site.  Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment.  The report concluded that the Harborton Substation facility was not a source of contamination to the Willamette river because no likely sources of hazardous substance releases were identified.  A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.

 

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign such order.  Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE.

 

Although management does not believe it has any responsibility for contamination of the Portland Harbor, it cannot predict the ultimate outcome of this matter or estimate any possible loss.

 

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.

Decommissioning - In October 2000, PGE filed an updated decommissioning plan estimate with the OPUC, which was approved as part of the general rate order issued in August 2001. The plan includes estimates of 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 original estimate in 1994 was a lower inflation rate, coupled with the acceleration of certain decommissioning activities, partially offset by cost increases related to the spent fuel storage project. The current estimate assumes that the majority of the remaining decommissioning activities will be completed by 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 Nuclear Fuel Disposal discussion below). Stated in 2001 dollars, the decommissioning cost estimate is $300 million.

 

 

TROJAN DECOMMISSIONING LIABILITY

(In Millions)

   

Estimate - 12/31/94

$      351

Updates - 11/16/95

7

Updates - 12/01/97

(19)

Updates - 10/01/01

(2)

 

337

Expenditures through 12/31/01

(151)

Liability - 12/31/01

186

Transition costs

19

Total Trojan obligation

$      205

 

PGE collects $14 million annually from customers through 2011 for decommissioning costs (and records an equal amount in amortization expense). 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 2001 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 decommissioning costs collected from customers. PGE expects any future changes in estimated decommissioning costs to be incorporated in future revenues collected from customers.

 

DECOMMISSIONING TRUST ACTIVITY

(In Millions)

     
 

2001

2000

Beginning Balance

$ 33

$ 42

 

Activity

   
 

Contributions

12

15

 

Gain

2

2

 

Disbursements

(17)

(26)

       

Ending Balance

$ 30

$ 33

 

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 kilowatt-hour sold at Trojan, which the Company paid during the period of plant operation. Significant delays are expected in the USDOE acceptance schedule of spent fuel from domestic utilities, with no federal repository expected to be available until at least 2010.

In February 2002, the USDOE formally recommended that Yucca Mountain, Nevada become the nation's first long-term geologic (underground) repository for high-level radioactive waste produced in the United States. The proposed location, which the current presidential administration has endorsed, is based on the conclusions of scientific studies of the site, conducted over 20 years, that support a finding of suitability as mandated by the Nuclear Waste Policy Act and various regulations of the NRC, USDOE, and the EPA. Lawsuits have been filed objecting to this recommendation. Further delays may create difficulties for PGE in disposing of its high-level radioactive waste by 2018. However, federal legislation has been introduced which would require the USDOE to provide interim storage for high-level waste until a permanent site is established. PGE is constructing an interim storage facility at Trojan to house the nuclear fuel until a federal site is available. The availability of an off-site repository for the permanent storage of radioactive waste will allow PGE to remove spent nuclear fuel from the Trojan Independent Spent Fuel Storage Installation (ISFSI), allowing final decommissioning and release of the Trojan site for unrestricted use.

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, with funding provided by both domestic nuclear utilities and the federal government. Contributions are based upon each utility's share of total 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 share of the total funding requirement is approximately $17 million. Amounts are paid over 15 years, beginning in 1993; PGE is current on all payments.

New Security Requirements - In response to the terrorist attacks of September 11, 2001, the NRC plans to issue new requirements for interim compensatory security measures for a generalized high-level threat environment at closed nuclear reactors that are in the decommissioning process. The new requirements are expected to remain in effect until such time as the NRC determines that the level of threat has diminished, or that other security changes are needed, based upon a comprehensive re-evaluation of current safeguards and security programs.

Until NRC requirements are determined, it is not known whether the costs associated with their implementation will impact the Trojan decommissioning cost estimate and related funding requirements. However, as new security requirements are evaluated, any additional costs will be determined and decommissioning cost estimates revised as necessary.

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 remains 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 $41 million level.

 

Note 12 - Related Party Transactions

The tables below detail the Company's related party balances and transactions (in millions):

For the Years Ended December 31

 

2001

 

2000

           

Receivables from affiliated companies

       
 

Enron Corp and other Enron Subsidiaries:

       
   

Merger Receivable

$

74

$

80

   

Allowance for Uncollectible - Merger Receivable

 

(74)

 

-

   

Income Taxes Receivable(a)

 

4

 

1

   

Accounts Receivable(b)

 

2

 

2

   

Other Allowance for Uncollectible Accounts(b)

 

(5)

 

-

 

Portland General Holdings and its subsidiaries:

       
   

Accounts Receivable(b)

 

33

 

39

         

Payables to affiliated companies

       
 

Enron Corp:

       
   

Accounts Payable(a)

 

11

 

1

 

Other Enron subsidiaries:

       
   

Accounts Payable(a)

 

-

 

1

             

(a) Included in Accounts payable and other accruals on the Consolidated Balance Sheets

(b) Included in Accounts and notes receivable on the Consolidated Balance Sheets

 

 

 

For the Years Ended December 31

 

2001

 

2000

 

1999

               

Revenues from affiliated companies

           
 

Other Enron subsidiaries:

           
   

Sales of electricity(a)

$

143

$

206

$

33

                 

Expenses billed to affiliated companies

           
 

Enron Corp:

           
   

Intercompany services(b)

 

4

 

-

 

1

 

Portland General Holdings and its subsidiaries:

           
   

Intercompany services(b)

 

1

 

3

 

4

 

Other Enron subsidiaries:

           
   

Intercompany services (b)

 

1

 

3

 

2

                 

Expenses billed from affiliated companies

           
 

Enron Corp:

           
   

Intercompany services(b)

 

30

 

36

 

26

 

Portland General Holdings and its subsidiaries:

           
   

Intercompany services(b)

 

-

 

1

 

1

 

Other Enron subsidiaries:

           
   

Purchases of electricity(c)

 

140

 

205

 

33

   

Intercompany services(b)

 

-

 

1

 

1

                 

Interest (net) from affiliated companies

           
 

Enron Corp:

           
   

Interest income(d)

 

7

 

3

 

-

   

Interest expense(e)

 

-

 

-

 

1

 

Portland General Holdings and its subsidiaries:

           
   

Interest income(d)

 

3

 

3

 

2

(a) Included in Operating Revenues on the Consolidated Statements of Income

(b) Included in Administrative and other on the Consolidated Statements of Income

(c) Included in Purchased power and fuel on the Consolidated Statements of Income

(d) Included in Other Income (Deductions) on the Consolidated Statements of Income

(e) Included in Interest on short-term borrowings on the Consolidated Statements of Income

Merger Receivable - Under terms of the companies' 1997 merger agreement, Enron and PGE agreed to provide $105 million of benefits to PGE's customers through price reductions payable over an eight-year period. Although the remaining liability to customers was reduced to zero under terms of a 2000 settlement agreement related to PGE's recovery of its investment in Trojan, Enron remained obligated to PGE for the approximate $80 million remaining balance and continued to make monthly payments, as provided under the merger agreement.

Enron suspended its monthly payments to PGE in September 2001, pursuant to its Stock Purchase Agreement with NW Natural, which will assume Enron's merger payment obligation upon its purchase of PGE. At December 31, 2001, Enron owed PGE approximately $74 million. The sale of PGE to NW Natural is subject to various regulatory approvals, as well as approvals from Enron's bankruptcy proceedings. The realization of the Merger Receivable from Enron is uncertain at this time due to Enron's bankruptcy. Based on this uncertainty, PGE established a reserve for the full amount of this receivable in December 2001. For further information, See Note 15, Proposed Acquisition of PGE by NW Natural, and Note 16, Enron Bankruptcy.

Income Taxes Receivable - As a member of Enron's consolidated income tax return, PGE made income tax payments to Enron for PGE's income tax liabilities. The $4 million balance at December 31, 2001 represents a receivable from Enron for refunds of prior income taxes paid by PGE.

Intercompany Receivables and Payable - As part of its ongoing operations, PGE bills affiliates for various services provided. These include services provided by PGE employees along with other corporate governance services and are billed at the higher of cost or market. Also, PGE is billed for services received at the lower of cost or market, primarily for employee benefit plans and corporate overheads. All affiliated interest transactions with PGE are subject to approval of the OPUC and are described below.

Enron - PGE receives management services from Enron and provides incidental services to Enron. In 2001, Enron billed PGE approximately $30 million for allocated overhead and other direct costs, including $14 million for corporate overhead, $7 million for retirement savings plan matching, and $7 million for medical and dental benefits. In 2000, Enron billed PGE $36 million for allocated overhead and other direct costs, comprised of $11 million for corporate overheads, $5 million for retirement savings plan matching, $7 million for medical and dental benefits, $4 million for the Employee Stock Option Plan, $2 million for information system costs, and $7 million for other administrative services. In 1999, Enron billed PGE $26 million for allocated overhead and other direct costs, including $14 million for corporate overhead, $4 million for the Employee Stock Option Plan, and $6 million for other administrative services. In 2001, PGE billed Enron $4 million, including $3 million for costs related to the termination of a proposed merger with Sierra Pacific Resources.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001. PGE has since stopped making its payments to Enron, except those for employee benefit plans, pending the ultimate disposition of payables to and receivables from Enron resulting from Enron's bankruptcy proceedings. At December 31, 2001, the $11 million balance consisted primarily of $7 million for employee benefits ($6 million of which was paid by PGE in January 2002) and $3 million for corporate overheads.

Other Enron Subsidiaries - PGE provided services and sublease of office space to other Enron subsidiaries, including Enron Broadband Services and Enron North America. PGE purchased and sold electricity and transmission services to Enron Power Marketing, Inc. (EPMI), a subsidiary of Enron North America. Under these transactions with EPMI, the purchases and sales of energy were primarily for like quantities and hours. PGE purchased power at prices no higher than the Dow Jones Mid-Columbia Index and charged at prices at or higher than the Dow Jones Mid-Columbia Index. At December 31, 2001, PGE is owed $1 million from EPMI for these power transactions. In addition, PGE has a receivable from Enron North America at December 31, 2001 of $1 million, primarily for the sublease of office space in Portland's World Trade Center (WTC), most of which was paid in February 2002. These Enron subsidiaries are all part of the Enron bankruptcy proceeding.

Portland General Holdings and Subsidiaries - Portland General Holdings (PGH) is a wholly owned subsidiary of Enron. Prior to Enron's bankruptcy, Enron had provided a portion of the funding for operations of PGH and its subsidiaries. With Enron's bankruptcy, any future funding from Enron will be subject to approval of the Bankruptcy Court. PGH and its subsidiaries are not part of Enron's bankruptcy proceedings at this time. PGE has an outstanding receivable balance from PGH and its subsidiaries at December 31, 2001 of $33 million, comprised primarily of $29 million related to previous non-regulated asset sales and $4 million related to PGH employee benefit plans. PGE also bills PGH and its subsidiaries for employee services and other corporate governance services.

In 1999, PGE transferred $21 million of corporate owned life insurance policies to PGH, creating a receivable balance due PGE. PGH transferred these policies to a trust for non-qualified benefit plan obligations, leaving a receivable balance due PGE. Later in 1999 PGH recorded a capital transaction with its wholly owned subsidiary PGH II, Inc. (PGH2), transferring the $21 million PGE intercompany payable to PGH2. PGH retained the trust owned life insurance policies in this transaction. The transfer to PGH2 was the result of negotiations between Enron and Sierra Pacific Resources related to the proposed sale of PGE and PGH2 to Sierra (the sale of which was later terminated). As of December 31, 2001, PGH2 has made no payments to PGE on the outstanding balance of $26 million (includes accrued interest).

PGH2 is the parent company of various subsidiaries that receive services from PGE. These include Portland General Distribution Company and Portland General Broadband Wireless (telecommunications companies), Enron Microclimates (a project management company), and Portland Energy Solutions, which provides heating and cooling services to buildings in downtown Portland, Oregon. At December 31, 2001, PGE has a $3 million receivable balance from Portland General Distribution Company related to assets sold for a capital project and for employee services provided by PGE.

Under the Stock Purchase Agreement between Enron and NW Natural, PGH2 and its subsidiaries are included in the purchase by NW Natural. Accordingly, assets and obligations of PGH2 would then be part of the NW Natural consolidated group. The sale to NW Natural is subject to various regulatory approvals and approvals from Enron's bankruptcy proceedings. If the sale of PGE and PGH2 to NW Natural does not close, management believes PGH2 has access to assets and other resources, including those of its parent (PGH), to support the realization of PGE's intercompany receivable from PGH2. For further information, See Note 15, Proposed Acquisition of PGE by NW Natural.

PGE also provides services to its consolidated subsidiaries, including funding under a cash management agreement and the sublease of office space in the WTC. Intercompany balances and transactions have been eliminated in consolidation.

PGE maintains no compensating balances and provides no guarantees for related parties.

Interest Income and Expense - Interest was accrued on the Enron Merger Receivable balance at PGE's current authorized cost of capital (9.083%); receivable balances from PGH and its subsidiaries accrued interest at 9.5%. Prior to 2001, interest was accrued at 9.5% on other outstanding receivable and payable balances with Enron and its subsidiaries. Beginning in 2001, interest was no longer accrued on those other outstanding balances with Enron due to the proposed merger with Sierra Pacific Resources, which was terminated in April 2001.

Management Assessment - Due to Enron's bankruptcy, management cannot predict the ultimate outcome of the above matters and the realization of its receivables. In particular, the collectibility of the $74 million Enron Merger Receivable would be uncertain under Enron's bankruptcy proceedings should the sale of PGE to NW Natural not occur. As a result, the Company has established a reserve for the entire amount of this receivable. In addition, a credit reserve of $5 million has been established related to the above remaining receivable balances associated with Enron and its subsidiary companies which are part of the bankruptcy proceedings.

 

 

Note 13 - Receivables - California Wholesale Market

As of April 1, 2002, PGE has accounts receivable totaling approximately $87 million that may be affected by the financial condition of two California utilities. Remaining payments totaling approximately $21 million (including imputed interest at 6.79%) were 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. SCE has made its scheduled monthly payments under the termination agreement, with the final payment due in December 2002. In addition, a balance of approximately $66 million is currently owed the Company by the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to SCE and Pacific Gas & Electric Company (PG&E).

On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, PG&E retains control of its assets and is authorized to operate its business as a debtor in possession while subject to the jurisdiction of the Bankruptcy Court.

PGE is pursuing collection of all past due amounts. Management is continually assessing PGE's exposure relative to its California receivables and has established a credit reserve for amounts due under its wholesale electricity contracts.

The Company has retained legal counsel on the bankruptcy matters and has numerous options, including legal, regulatory, and other means to pursue collection of amounts ultimately not received. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.

Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

Note 14 - Refunds on Wholesale Transactions

California

In a June 19, 2001 FERC order adopting a price mitigation program for 11 states within the WSCC area, the issue of refunds for spot market sales made between October 2, 2000 through June 20, 2001 was referred to a settlement judge. Subsequently, the settlement judge recommended to the FERC that the potential for refunds during the period October 2, 2000 through June 20, 2001 be set for hearing.

On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds related to non federally-mandated transactions in the spot markets operated by the ISO and the PX. In addition, an evidentiary hearing proceeding was ordered to develop a factual record to provide the basis for the refund calculation. The Company's potential refund obligation, using the FERC methodology, is currently estimated to be in the range of $20 million to $30 million, with final determination to be made after FERC review of calculations filed by the ISO. Hearings were held in March, 2002, with additional hearings scheduled for June 2002. PGE will have the opportunity to challenge the FERC's determination of the amount of any proposed refunds.

Pacific Northwest

In the July 25, 2001 order, the FERC called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During this period, PGE both sold and purchased electricity in the Pacific Northwest. Upon completion of hearings, the appointed Administrative Law Judge issued a recommended order that the claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the Commission for action.

Any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest are eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism. This could potentially mitigate the financial effect of any refunds made or received by the Company.

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

Note 15 - Proposed Acquisition of PGE by NW Natural

On October 5, 2001, Enron and NW Natural, an Oregon corporation principally engaged in the distribution of natural gas in major portions of western Oregon and southwest Washington, entered into a Stock Purchase Agreement providing for the purchase by NW Natural of all the issued and outstanding common stock of PGE. PGH2 and its subsidiaries are also included in the proposed purchase by NW Natural. Under terms of the agreement, Enron will sell PGE to NW Natural for $1.8 billion, comprised of $1.55 billion in cash and $250 million of equity securities to be issued to Enron. In addition, the balance of the merger obligation due PGE remaining from Enron's purchase of PGE in 1997 would be assumed by NW Natural (see Note 12, Related Party Transactions, for further information). PGE will retain its approximately $1.1 billion in existing debt and preferred stock.

The transaction is subject to a number of conditions, including obtaining regulatory approvals from the SEC, the FERC, the NRC, the OPUC, the EFSC, and the Washington Utilities and Transportation Commission. The proposed acquisition has been reported to the U.S. Department of Justice and the Federal Trade Commission for antitrust review; the waiting period for such review expired with no further action required. The EFSC, FERC, and NRC have approved the transaction, which is also subject to the approval of NW Natural's shareholders.

The agreement provides for PGE to continue to conduct its business in a manner consistent with past practice, using all reasonable efforts to preserve intact its present business organization and goodwill. It further prevents the Company from declaring dividends to Enron that exceed its total net income from 1999 through the closing date of the sale, less any dividends previously paid. PGE's 2001 net income included a $44 million after-tax provision related to uncertainties associated with the realization of the $74 million merger receivable balance due from Enron. (See Note 12, Related Party Transactions, for further information). Since NW Natural would assume this obligation to PGE when the proposed acquisition is completed, PGE would reverse this provision at the sale closing date, making the amount available for dividend distribution to Enron under terms of the agreement. Based upon actual net income, adjusted for the reversal of the merger receivable provision and for dividends previously paid, PGE would owe Enron a cash dividend of approximately $140 million for the period 1999-2001, with an additional amount required based on net income from January 1, 2002 to the closing date of the sale. In addition, the agreement provides for PGE to pay Enron an additional $4.5 million dividend, defined as the Specified Enron Merger Obligation under the Stock Purchase Agreement. PGE expects to pay these amounts, to be funded by the issuance of either long-term or short-term debt, at or near the close of the sale.

Both Enron and NW Natural continue to pursue regulatory approval of the sale under terms of the agreement between the two companies. However, as a result of Enron's bankruptcy, the sale cannot be completed until Enron, as Debtor in Possession, has affirmed the Stock Purchase Agreement and obtained approval by the Bankruptcy Court. In light of the bankruptcy proceedings, there is no assurance that regulatory, financing, and other conditions will be satisfied.

On March 19, 2002, the OPUC approved a request by Enron and NW Natural for a 60-day suspension of the procedural schedule that waives the statutory time period for approval of the sale through late-September 2002. The new schedule accommodates NW Natural's need to analyze further any effects of Enron's bankruptcy on PGE and Enron's need to interact with creditors and the Bankruptcy Court regarding reorganization options.

Note 16 - Enron Bankruptcy

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

Enron has announced that it is proceeding with reorganization efforts and intends to present restructuring alternatives to the Unsecured Creditors' Committee participating in Enron's bankruptcy proceedings in the second quarter of 2002. In connection with any such restructuring, Enron has stated that it believes that the total amount of the liquidated, undisputed claims against Enron and its subsidiaries exceeds and will exceed the current fair market value of the consolidated operations and assets of Enron and its subsidiaries. Accordingly, Enron has stated that it believes its existing equity has and will have no value and that any Chapter 11 plan confirmed by the Bankruptcy Court will not provide Enron's existing equity holders with any interest in the reorganized debtor. Any and all Chapter 11 plans are subject to creditor approval and judicial determination of confirmability.

Management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day to day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997 (merger conditions), Enron's access to PGE cash or assets (through dividends or otherwise) is limited. Under the merger conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The merger conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.

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

  1. Amounts due from Enron and Enron-supported affiliates - As described in Note 12, Related Party Transactions, PGE is owed approximately $74 million by Enron relating to the Merger Receivable. NW Natural will assume Enron's obligation should the sale of PGE to NW Natural close. (See Note 15, Proposed Acquisition of PGE by NW Natural, for additional information). Because of uncertainties associated with Enron's bankruptcy, PGE established a reserve for the full amount of this receivable in December 2001. In addition, a credit reserve of $5 million was established in December 2001 related to uncertainties associated with other receivable balances from Enron affiliates which are part of the bankruptcy proceedings.

  2. Control Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plan and tax obligations of Enron.

          Pension Plans

The pension plan for the employees of PGE (PGE Plan) is separate from the Enron pension plan (Enron Plan). The PGE Plan has assets that exceed the present value of all accrued benefits on a SFAS No. 87 (Employers' Accounting for Pensions) basis and, management believes on a plan termination basis (See Note 2, Employee Benefits, for further details). It is management's understanding, based on discussion with Enron management, that the assets of the Enron Plan are currently less than the present value of all accrued benefits by approximately $90 million on a SFAS No. 87 basis and approximately $120 million on a plan termination basis. However, approximately 48% of that amount is attributable to members of the Enron controlled group that are not in bankruptcy. Pension Benefit Guaranty Corporation (PBGC) insures pension plans, including the PGE Plan and the Enron Plan.

Subject to applicable law, management is permitted to merge separate pension plans established by companies in the same controlled group. If the Enron Plan and PGE Plan are merged, the excess assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC and the PGE Plan's assets would be undiminished.

Since the Enron Plan is underfunded and Enron is in bankruptcy, in certain circumstances the Enron Plan may be terminated and taken control by the PBGC upon approval of a Federal District Court. In addition, with consent of the PBGC, Enron could seek to terminate the Enron Plan while it is underfunded.

Upon termination of the plan, all of the members of the controlled group of the plan sponsor become jointly and severally liable for the plan's underfunding. The PBGC can demand payment from one or more of the members of the controlled group. If payment is not made, a lien in favor of the plan automatically attaches against all of the assets of each member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the member's aggregate net worth. In addition, if the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically attaches to the assets of every member of the controlled group. In either case, the PBGC is entitled to file the lien and enforce it against the assets of members of the controlled group. Since substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds, any lien by the PBGC would be subordinate to that lien. Based on discussions with Enron's management, PGE's management understands that to date Enron has made all required contributions.

Management cannot predict the outcome of the above matters or estimate any potential loss. In addition, if the PBGC did look solely to PGE to pay any amount with respect to the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of the controlled group. No reserves have been established by PGE for any amounts related to this issue.

           Retiree Health Benefits

Under COBRA, certain retirees of Enron who lose coverage under Enron's group health plan due to Enron's bankruptcy proceedings are entitled to a continuation of their health coverage in a group plan maintained by Enron or a member of its controlled group. Management understands, based on discussions with Enron management, that Enron had provided a plan for health insurance and that the actuarial liability is approximately $70 million. Management further understands that to meet its obligation Enron has set aside approximately $34 million of assets in a VEBA trust which may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million.

In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan, if any, or the appropriate group health plan of another member of the Enron controlled group. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to retirees under the most appropriate existing plan in the controlled group. Retirees electing to purchase COBRA coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the average cost of coverage for similarly situated beneficiaries. Retirees are not required to purchase coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.

Management cannot predict the outcome of the above matter or estimate any potential loss. However, management believes that in the event Enron terminates coverage, any liability to PGE associated with the number of retirees that choose to remain under Enron's retiree health plan will not be material. No reserves have been established by PGE for any amounts related to this issue.

          Income Taxes

Under the IRC, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with Portland General Corporation. Based on discussions with Enron's management, PGE management understands that PGE ceased to be a member of Enron's consolidated group on May 7, 2001.

Enron's management has provided the following information to PGE:

        A. Enron's consolidated tax returns through 1995 have been audited and are closed. The IRS has completed its field audit of the consolidated tax returns for 1996-1997 and is currently auditing Enron's consolidated tax returns for 1998-2000. Enron's consolidated tax return for 2001 is expected to be filed in mid-2002 and Enron expects this return and its examination to be included in the bankruptcy process.

        B. For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron and its subsidiaries anticipate that the 2001 consolidated tax return will show a substantial loss, which would be carried back to tax year 2000, and result in a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 provides Enron and its subsidiaries substantial NOLs for any additional income tax liabilities for the periods in which PGE was a member of Enron's consolidated federal income tax returns. At this time, Enron anticipates claims, if any, made by the IRS in the bankruptcy proceedings for the years 1996-2001 will occur sometime in the fall of 2002.   If there were additional tax liabilities claimed by the IRS, these would be satisfied by funds in the bankruptcy estate ahead of unsecured Enron creditors.

Although management cannot predict with certainty the outcome of IRS audits, based on the above, it believes it is unlikely at this time, that any tax claims by the IRS would offset the substantial NOLs available to the Enron consolidated tax returns.  If the IRS did seek payment and Enron did not pay, the IRS could look to one or more members of the consolidated group, including PGE. If the IRS did look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, are available for recovery in Enron's bankruptcy proceeding, or to otherwise to obtain contributions from the other solvent members of the consolidated group, who are not debtors in the bankruptcy case. As a result, management believes the income tax exposure to PGE would be minimal, if any, related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated tax returns. No reserves have been established by PGE for any amounts related to this issue.

3. Enron/NW Natural Transaction - Although both Enron and NW Natural are continuing to seek regulatory approvals of the sale of PGE and PGH2, the sale cannot be completed until Enron has assumed the Stock Purchase Agreement and obtained approval of the Bankruptcy Court. See Note 15, Proposed Acquisition of PGE by NW Natural, for additional details.

Enron Debtor in Possession Financing - PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor-in-possession credit agreement with Citicorp USA Inc. and JP Morgan Chase Bank. Under the terms of the credit agreement and related security agreements, all of which were approved by the Bankruptcy Court having jurisdiction over Enron's case, Enron pledged its stock in PGE to secure the repayment of any amounts due under the Debtor in Possession financing. Enron also granted the lenders a security interest in the proceeds of the sale of PGE to NW Natural. Under the terms of the pledge, the lenders are prohibited from exercising substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control over PGE unless and until (a) the stock purchase agreement between Enron and NW Natural for the sale of PGE has been terminated, rejected or otherwise is subject to termination, and (b) the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders. The credit agreement also prohibits Enron from amending, modifying or waiving the terms of the Stock Purchase Agreement with NW Natural without the approval of the lenders. The pledge automatically terminates upon the closing of the sale of PGE to NW Natural.

Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.

 

 

 

 

QUARTERLY COMPARISON FOR 2001 AND 2000 (Unaudited)

           
           
 

March 31

June 30

September 30

December 31

Total

 

(In Millions)

2001

         

Operating revenues

$766

$831

$905

$545

$3,047

Net operating income

50

43

11

30

134

Net income (loss)

43

29

(5)

(33)

34

Income (loss) available for

         
 

common stock

42

29

(6)

(33)

32

           
           

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

 

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

(a) Arthur Andersen LLP

(i) On February 5, 2002, Arthur Andersen LLP resigned as PGE's independent public accountants due to concerns about Arthur Andersen LLP's ability to continue as auditors for PGE. Arthur Andersen LLP's decision resulted from considerations of applicable professional standards including, but not limited to, those applicable to auditor independence relating to recent events involving Enron Corp. PGE is a wholly owned subsidiary of Enron Corp., though it is not a part of Enron Corp.'s bankruptcy proceedings.

(ii) The reports of Arthur Andersen LLP on the financial statements for the past two years (1999 and 2000) contained no adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principle. Arthur Andersen LLP has indicated that they have not withdrawn any of their opinions expressed in their auditors' reports for any periods for which they conducted PGE's audits.

(iii) In connection with its audits for the two most recent years (1999 and 2000) and through February 5, 2002, there have been no disagreements with Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of Arthur Andersen LLP would have caused them to make reference thereto in their report on the financial statements for such years.

(iv) During the two most recent years (1999 and 2000) and through February 5, 2002, there have been no reportable events (as defined in Regulation S-K Item 304(a)(1)(v)).

(v) PGE requested that Arthur Andersen LLP furnish it with a letter addressed to the SEC stating whether or not it agrees with the above statements. Such letter, dated February 12, 2002, was provided, stating that Arthur Andersen LLP agreed with the above statements.

(b) PricewaterhouseCoopers LLP

PGE engaged PricewaterhouseCoopers LLP as its new independent accountants as of February 25, 2002. During the two most recent fiscal years and through February 5, 2002, neither PGE nor any one on behalf of PGE has consulted with PricewaterhouseCoopers LLP regarding (i) either the application of accounting principles to a specific transaction, either completed or proposed; or the type of audit opinion that might be rendered on PGE's financial statements; or (ii) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K, or a reportable event, as that term is defined in Item 304(a)(1)(v) of Regulation S-K, with PGE's former accountant Arthur Andersen LLP.

Part III

 

Item 10. Directors and Executive Officers of the Registrant

Directors of the Registrant (*)

 PEGGY Y. FOWLER, age 50

Director since 1998

Ms. Fowler has served as Chief Executive Officer and President of Portland General Electric since April 2000. She served as President from February 1998 until April 2000. She served as Chief Operating Officer PGE Distribution Operations from November 1996 until February 1998. She served in various positions including Senior Vice President Customer Service and Delivery and Vice President Power Production and Supply. Ms. Fowler began her career with PGE in 1974 as a chemist. She also serves on the boards of Regence Blue Cross/Blue Shield, Legacy Health Systems, Oregon Independent College Foundation, and Oregon Business Council.

STANLEY C. HORTON, age 52

Director since May 1, 2001

Mr. Horton has served as Chairman and Chief Executive Officer of Enron Global Services since September 2001 and served as Chairman and Chief Executive Officer of Enron Transportation Services from January 1997 until September 2001. He served as Co-Chairman and Chief Executive Officer of Enron Operations Corp. from June 1993 until February 1996 and President and Chief Operations Officer of Pipeline and Liquids Group from March 1993 until June 1993. He held several management positions with Enron from 1985 until 1993, including President for Florida Gas, Northern Natural Gas Co., and Transwestern Pipeline Co. He began his career with Enron in 1973 as a staff economist for Florida Gas Transmission Company. He also serves as Chairman of the Board of EOTT Energy Partners, L.P; board member of the Interstate Natural Gas Association of America; and is Chairman of the Natural Gas Council. He is also a member of the Northern Border Partners, L.P., Policy Committee.

JAMES J. PIRO, age 49

Director since January 28, 2002

Mr. Piro has served as Senior Vice President Finance, Chief Financial Officer & Treasurer of Portland General Electric since May 2001. He served as Vice President, Chief Financial Officer of Portland General Electric from November 2000 to May 2001. Mr. Piro has been with Portland General Electric since 1980 and has held a number of different positions in the company during his tenure. He currently acts as Treasurer for the PGE/Enron Foundation, and serves on the Board of the Portland Oregon Sports Authority.

(*) 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

Peggy Y. Fowler

Chief Executive Officer

and President

 

50

 

Appointed to current position on April 1, 2000. Served as President from February 1998 until appointed to current position. Served as Chief Operating Officer PGE Distribution Operations from November 1996 until February 1998. Served in various positions including Senior Vice President Customer Service and Delivery and Vice President Power Production and Supply.

 

Frederick D. Miller

Executive Vice President,

Retail and Distribution Services

 

59

 

Appointed to current position on May 1, 2001. Served as Senior Vice President, Public Policy and Administrative Services from December 1996 until May 2001. 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.

 

James J. Piro

Senior Vice President, Finance

Chief Financial Officer

and Treasurer

 

49

 

Appointed to current position on May 1, 2001. Served as Vice President, Chief Financial Officer and Treasurer from November 1, 2000 until May 1, 2001. Served as Vice President, Business Development from February 1998 until promoted to Vice President & Chief Financial Officer position. Served as General Manager, Planning & Support and Analysis from 1992 until 1998.

 

Arleen N. Barnett

Vice President

Human Resources and Information Technology

 

50

 

Appointed to current position on May 1, 2001. Served as Manager, Generating Division from 1987 to 1989 and Manager, Human Resources Operations from 1989 until 1997 when appointed to Vice President, Human Resources on February 1, 1998. Appointed Vice President, Human Resources and Informational Technology in May 2001.

 

David K. Carboneau

Vice President,

Marketing and Business

Development

 

55

 

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

System Planning and

Engineering

 

52

 

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

 

51

 

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

 

Pamela G. Lesh

Vice President

Public Policy and Regulatory

Affairs

 

45

 

Appointed to current position in May 2001. Served as Vice President, Rates and Regulatory Affairs from December 31, 1998 until appointed to current position. Served as Vice President, Strategy and Product Management with ConneXt Corp. of Seattle from June 1997 until December 1998. 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.

 

James F. Lobdell

Vice President

Risk Management Reporting,

Controls and Credit

 

43

 

Appointed to current position on May 1, 2001. Served as Senior Director of Business Development and Vice President of Portland General Distribution Company and Portland General Holdings II from July 1, 1999 until appointed to current position. Joined PGE in 1984 as a business analyst and held a number of positions within the Company and its affiliates.

 

Joe A. McArthur

Vice President

Distribution

 

54

 

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.

 

Douglas R. Nichols

Vice President

General Counsel and Secretary

 

59

 

Appointed to current position on May 1, 2001. Served as Acting Deputy General Counsel from February 1, 2001 until appointed to current position. Served as Assistant General Counsel from May 1, 1991 to February 1, 2001.

 

Stephen M. Quennoz

Vice President

Power Supply/Generation

 

54

 

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

 

52

 

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

Community/Business Development

 

57

 

Appointed to current position on May 1, 2001. Served as Vice President, Government Affairs and Economic Development from May 1999 until appointed to current position.  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

 

34

 

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 Vice President Finance, 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, 2002; 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, 2001, 2000, and 1999 by the Chief Executive Officer and the four most highly compensated executive officers of PGE.

 

   

Annual Compensation

 
       

All Other

Name and Principal Position

Year

Salary(1)

Bonus(2)

Compensation(3)

Peggy Y. Fowler

Chief Executive Officer

and President

2001

2000

1999

$329,063

300,002

267,502

$400,000

450,000

400,000

$38,561

36,710

16,646

 

David K. Carboneau

Vice President,

Marketing and Business Development

2001

2000

1999

200,004

211,499

211,498

325,000

105,002

80,000

16,018

14,151

8,330

 

 

Frederick D. Miller

Executive Vice President, Retail

and Distribution Services

2001

2000

1999

218,230

205,518

197,708

150,000

200,000

200,000

26,418

27,125

12,757

 

James J. Piro

Senior Vice President, Finance

Chief Financial Officer and Treasurer

2001

2000

1999

183,670

171,564

169,089

170,000

150,000

110,000

13,782

9,034

5,874

 

Ronald W. Johnson

Vice President,

Power Supply/Resource Development

and Engineering Services

2001

2000

1999

179,900

138,288

139,262

160,000

120,184

92,693

8,189

9,386

5,346

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

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

(3) Other compensation includes: (i) company-paid split dollar insurance premiums; (ii) the dollar value of life insurance benefits as determined under the Commission's methodology for valuing such benefits; (iii) company contributions to the Retirement Savings Plan (RSP) and the MDCP; and (iv) earnings on amounts in the MDCP which are greater than 120 percent of the federal long-term rate which was in effect at the time the rate was set.

              The following are amounts for 2001:

 

Split Dollar Insurance Premiums

Dollar Value of Life Insurance

Contributions to RSP and MDCP

Above Market Interest on MDCP

 

Total

Peggy Y. Fowler

$ 756

$ 14,203

$ 10,089

$ 13,513

$ 38,561

           

David K. Carboneau

550

-

10,501

4,967

16,018

           

Frederick D. Miller

800

-

6,533

19,085

26,418

           

James J. Piro

-

-

8,815

4,967

13,782

           

Ronald W. Johnson

-

-

5,952

2,237

8,189

Aggregate restricted stock holdings listed below (including any annual bonus converted to Phantom stock) are valued at $0.60 per share, the closing price of Enron common stock on December 31, 2001.

 

 

Aggregate Restricted Stock Holdings

 

Aggregate Shares (#)

Value

Peggy Y. Fowler

4,559

$2,735

David K. Carboneau

-

-

Frederick D. Miller

803

482

James J. Piro

1,075

645

Ronald W. Johnson

-

-

 

The following lists information concerning options to purchase shares of Enron common stock that were exercised by the officers named above during 2001 and the total options and their value held by each at December 31, 2001.

 

Aggregate Stock Options/SAR Exercised During 2001

And Stock Options/SAR Values at December 31, 2001

 

Shares Acquired on Exercise

Value Realized

Exercisable Options

Unexercisable Options

Exercisable Amount

Unexercisable Amount

Peggy Y. Fowler

-

$             -

38,654

24

$              -

$            -

David K. Carboneau

12,513

766,359

400

824

-

-

Frederick D. Miller

4,182

235,885

4,152

24

-

-

James J. Piro

-

-

80,526

10,044

-

-

Ronald W. Johnson

1,000

62,852

10,354

3,224

-

-

The cost to exercise all options exceeds the market value of the security at December 31, 2001.

No new grants were made to any officers during 2001.

 

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, 27; David K. Carboneau, 32; Frederick D. Miller, 9. James J. Piro and Ronald W. Johnson 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, 55; David K. Carboneau, 55; and Frederick D. Miller, 62.

Employment Contract

Mr. Carboneau entered into an employment agreement with PGE on June 30, 2001. The agreement generally provides as follows: (i) a term of one year; (ii) severance pay in the event of involuntary termination by PGE of one year's annual base pay and any retention bonus payments not yet paid; (iii) a base salary of $200,000 per year and participation in the annual cash incentive plan or replacement bonus plan; and (iv) a cash retention bonus in the amount of $250,000 paid on June 30, 2001 and a subsequent cash retention bonus of $250,000 payable on June 15, 2002.

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. None of PGE's officers 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

Page

     
 

Financial Statements

 
 

Reports of Independent Public Accountants

 54-55

 

Consolidated Statements of Income for each of the three years in the period ended December 31, 2001

 56

 

Consolidated Statements of Retained Earnings for each of the three years in the    period ended December 31, 2001

 56

 

Consolidated Statements of Comprehensive Income for each of the three years in    the period ended December 31, 2001

 57

 

Consolidated Balance Sheets at December 31, 2001 and 2000

 58

 

Consolidated Statements of Cash Flows for each of the three years in the period     ended December 31, 2001

 59

 

Notes to Financial Statements

 60

     
 

Financial Statement Schedules

 
 

Schedule II - Consolidated Valuation and Qualifying Accounts

 107

     
 

Exhibits

 
 

See Exhibit Index on Page 109 of this report.

 
     

(b)

Reports on Form 8-K

 
 

October 25, 2001 - Item 5. Other Events: Results of Operations, General Rate Increase and Other Regulatory Matters, Proposed Acquisition

 
 

November 20, 2001 - Item 5. Other Events: General Rate Case, Enron Bankruptcy Proceedings, Proposed Acquisition of PGE by NW Natural, Financing Activities

 
 

February 5, 2002 - Item 4. Changes in Registrant's Certifying Accountant

 
 

February 25, 2002 - Item 4. Changes in Registrant's Certifying Accountant

 

 

 

Portland General Electric Company and Subsidiaries

Schedule II - Consolidated Valuation and Qualifying Accounts

For The Years Ended December 31, 2001, 2000, and 1999

(In Millions)

   

Allowance for Uncollectible Accounts

     

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

     

Balance at January 1, 2001

10

 

Provision charged to income

96

 

Amounts written off, less recoveries

(4)

Balance at December 31, 2001

$ 102

 

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

     
     

April 15, 2002

 

By

/s/ Peggy Y. Fowler

       

Peggy Y. Fowler

         
       

Chief Executive Officer

       

and President

 

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

 

Chief Executive Officer

   April 15, 2002
 

Peggy Y. Fowler

 

and President and Director

 

 

           

/s/ James J. Piro

 

Senior Vice President, Finance

 

April 15, 2002

 

James J. Piro

 

Chief Financial Officer and

   
     

Treasurer and Director

   

 

         

/s/ Kirk M. Stevens

 

Controller and

 

April 15, 2002

 

Kirk M. Stevens

 

Assistant Treasurer

   
         

 

*Stanley C. Horton

 

Director

 

April 15, 2002

 

 

*By

/s/ Kirk M. Stevens

   
   

(Kirk M. Stevens, 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)].

     
   

Bylaws of Portland General Electric Company as amended on December 31, 1999 [filed herewith].

     

(4)

 

Instruments defining the rights of security holders, including indentures

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
   

Forty-Seventh Supplemental Indenture dated December 14, 2001 (filed herewith).

     
 

*

Supplemental Indenture dated April 30, 1999 [S3 Registration No. 333-77469, dated April 30, 1999, Exhibit 4(c)].

     
   

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

     

(10)

 

Material Contracts

     
 

*

Residential Purchase and Sale Agreement with the Bonneville Power Administration [Form 10-K for the fiscal year ended December 31, 1981, Exhibit (10)].

     
 

*

Power Sales Contract and Amendatory Agreement Nos. 1 and 2 with Bonneville Power Administration [Form 10-K for the fiscal year ended December 31, 1982, Exhibit (10)].

     
 

The following 12 exhibits were filed in conjunction with the 1985 Boardman/Intertie Sale:

     
 

*

Long-term Power Sale Agreement dated November 5, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

Long-term Transmission Service Agreement dated November 5, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

Bargain and Sale Deed, Bill of Sale, and Grant of Easements and Licenses, dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

Supplemental Bill of Sale dated December 30, 1985 [Form 10-K for the fiscal year ended December 31, 1985, Exhibit (10)].

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

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

     
 

Executive Compensation Plans and Arrangements

     
 

*

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

     
 

*

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

     
 

*

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

     
 

*

Portland General Electric Company Annual Incentive 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 Experts and Counsel

 

 

Consent of Independent Accountants PricewaterhouseCoopers LLP (filed herewith).

Consent of Independent Public Accountants 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, 1WTC 0501

Portland, OR 97204

Consents of Independent Public Accountants

Consent of Independent Accountants

 

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-77469 and 333-56062) of Portland General Electric Company of our report dated April 11, 2002, relating to the consolidated financial statements and financial statement schedule, which appears in this Form 10-K.

 

PricewaterhouseCoopers LLP

Portland, Oregon

April 15, 2002

 

 

Consent of Independent Public Accountants

 

As independent public accountants, we hereby consent to the incorporation of our report dated January 26, 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

April 11, 2002

Portland General Electric Company 2001 Form 10-K Bylaws

AMENDED AND RESTATED BYLAWS

 

OF

PORTLAND GENERAL ELECTRIC COMPANY

 

 

An Oregon Corporation

 

 

Date of Adoption

December 31, 1999

 

 

 

AMENDED AND RESTATED BYLAWS

Table of Contents

                                                                                                                                             Page

ARTICLE I ........................................................................................................................................................................  1

OFFICES ................................................................................................................................................................ 1

Section 1. Registered Office .............................................................................................................................  1

Section 2. Other Offices ....................................................................................................................................  1

ARTICLE II ......................................................................................................................................................................  1

SHAREHOLDERS ..............................................................................................................................................  1

Section 1. Place of Meetings  ........................................................................................................................... 1

Section 2. Quorum; Adjournment of Meetings .............................................................................................  1

Section 3. Annual Meetings ............................................................................................................................  2

Section 4. Special Meetings ...........................................................................................................................  2

Section 5. Record Date ...................................................................................................................................  2

Section 6. Notice of Meetings ........................................................................................................................  3

Section 7. Shareholder List ............................................................................................................................  3

Section 8. Proxies  ...........................................................................................................................................  4

Section 9. Voting; Elections; Inspectors .....................................................................................................  4

Section 10. Conduct of Meetings ..................................................................................................................  5

Section 11. Voting of Certain Shares ..........................................................................................................  5

Section 12. Action Without Meeting ...........................................................................................................  5

Section 13. Business to be Brought Before the Annual Meeting ............................................................ 6

ARTICLE III ..................................................................................................................................................................  7

BOARD OF DIRECTORS ...............................................................................................................................  7

Section 1. Power; Number; Term of Office .................................................................................................  7

Section 2. Quorum; Voting ............................................................................................................................  7

Section 3. Place of Meetings; Order of Business .......................................................................................  7

Section 4. First Meeting .................................................................................................................................  7

Section 5. Regular Meetings .........................................................................................................................  8

Section 6. Special Meetings ..........................................................................................................................  8

Section 7. Nomination of Directors .............................................................................................................  8

Section 8. Removal .......................................................................................................................................... 9

Section 9. Vacancies; Increases in the Number of Directors ..................................................................  9

Section 10. Compensation .............................................................................................................................  9

Section 11. Action Without a Meeting; Telephone Conference Meetings .........................................  10

Section 12. Approval or Ratification of Acts or Contracts by Shareholders ....................................  10

ARTICLE IV ................................................................................................................................................................  10

COMMITTEES ..............................................................................................................................................  10

Section 1. Executive Committee ................................................................................................................  10

Section 2. Audit Committee ........................................................................................................................  11

Section 3. Other Committees ......................................................................................................................  11

Section 4. Procedure; Meetings; Quorum ...............................................................................................  11

Section 5. Substitution and Removal of Members; Vacancies .............................................................  11

Section 6. Limitation on Power and Authority of Committees ............................................................  11

ARTICLE V ................................................................................................................................................................  12

OFFICERS ......................................................................................................................................................  12

Section 1. Number, Titles and Term of Office ..........................................................................................  12

Section 2. Powers and Duties of the Chairman of the Board ..............................................................  12

Section 3. Powers and Duties of the Chief Executive Officer ..............................................................  13

Section 4. Powers and Duties of the President. .....................................................................................  13

Section 5. Powers and Duties of the Vice Chairman of the Board ....................................................  13

Section 6 . Vice Presidents ........................................................................................................................  13

Section 7 .General Counsel ......................................................................................................................  14

Section 8. Secretary ...................................................................................................................................  14

Section 9. Deputy Corporate Secretary and Assistant Secretaries ..................................................  14

Section 10. Treasurer ................................................................................................................................  14

Section 11. Assistant Treasurers .............................................................................................................  14

Section 12. Action with Respect to Securities of Other Corporations .............................................  15

Section 13. Delegation .............................................................................................................................. 15

ARTICLE VI .............................................................................................................................................................  15

CAPITAL STOCK .......................................................................................................................................  15

Section 1. Certificates of Stock ...............................................................................................................  15

Section 2. Transfer of Shares ...................................................................................................................  16

Section 3. Ownership of Shares ..............................................................................................................  16

Section 4. Regulations Regarding Certificates .................................................................................... 16

Section 5. Lost or Destroyed Certificates .............................................................................................  16

ARTICLE VII ...........................................................................................................................................................  16

LIABILITY OF DIRECTORS AND INDEMNIFICATION ....................................................................  16

Section 1. Personal Liability of Directors ............................................................................................  16

Section 2. Indemnification ........................................................................................................................ 17

ARTICLE VIII ..........................................................................................................................................................  18

MISCELLANEOUS PROVISIONS ............................................................................................................  18

Section 1. Fiscal Year ...............................................................................................................................  18

Section 2. Corporate Seal ........................................................................................................................  18

Section 3. Notice and Waiver of Notice ................................................................................................  19

Section 4. Facsimile Signatures .............................................................................................................  19

Section 5. Reliance upon Books, Reports and Records .....................................................................  19

Section 6. Application of Bylaws ............................................................................................................ 19

ARTICLE IX ............................................................................................................................................................  20

AMENDMENTS .........................................................................................................................................  20

 

AMENDED AND RESTATED BYLAWS

OF

PORTLAND GENERAL ELECTRIC COMPANY

 

Article I

Offices

        Section 1. Registered Office. The registered office of the Corporation required by the Oregon Business Corporation Act to be maintained in the State of Oregon shall be CT Corporation System, 520 S. W. Yamhill, Suite 800, Portland, Oregon 97204, or such other office as may be designated from time to time by the Board of Directors in the manner provided by law.

        Section 2. Other Offices. The Corporation may also have offices at such other places both within and without the State of Oregon as the Board of Directors may from time to time determine or the business of the Corporation may require.

Article II

Shareholders

        Section 1. Place of Meetings. All meetings of the shareholders shall be held at the principal office of the Corporation, or at such other place within or without the State of Oregon as shall be specified or fixed in the notices or waivers of notice thereof.

        Section 2. Quorum; Adjournment of Meetings Unless otherwise required by law or provided in the Articles of Incorporation, (i) the holders of a majority of the voting power attributable to the shares issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at any meeting of shareholders for the transaction of business, (ii) in all matters other than election of directors, the affirmative vote of the holders of a majority of the voting power attributable to such shares so present or represented and voting at any meeting of shareholders at which a quorum is present shall constitute the act of the shareholders, and (iii) where a separate vote by a class or classes is required, a majority of the voting power attributable to the outstanding shares of such class or classes, present in person or represented by proxy shall constitute a quorum entitled to take action with respect to that vote on that matter and the affirmative vote of the majority of the voting power attributable to the shares of such class or classes present in person or represented and voting by proxy at the meeting shall be the act of such class.

        Directors shall be elected by a plurality of the votes cast by the shares present in person or represented by proxy at the meeting and entitled to vote on the election of directors.

        Notwithstanding the Articles of Incorporation or the other provisions of these Bylaws, the chairman of the meeting or the holders of a majority of the voting power attributable to the issued and outstanding shares, present in person or represented by proxy and entitled to vote thereat, at any meeting of shareholders, whether or not a quorum is present, shall have the power to adjourn such meeting from time to time, without any notice other than announcement at the meeting of the time and place of the holding of the adjourned meeting. If the adjournment is for more than thirty (30) days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder of record entitled to vote at such meeting. At such adjourned meeting at which a quorum shall be present or represented any business may be transacted which might have been transacted at the meeting as originally called.

        Section 3. Annual Meetings. An annual meeting of the shareholders, for the election of directors to succeed those whose terms expire and for the transaction of such other business as may properly come before the meeting, shall be held at such place (within or without the State of Oregon), on such date, and at such time as the Board of Directors shall fix and set forth in the notice of the meeting, which date shall be within thirteen (13) months subsequent to the last annual meeting of shareholders.

        Section 4. Special Meetings. Unless otherwise provided in the Articles of Incorporation, special meetings of the shareholders for any purpose or purposes may be called at any time by the Chairman of the Board, by the President, by the Vice Chairman of the Board, by a majority of the Board of Directors, or by a majority of the Executive Committee (if any), or, to the extent required by law, by the holders of not less than 10% of all shares entitled to vote on any issue at the proposed special meeting, if such holders sign, date and deliver to the Corporation's Secretary one or more written demands for the meeting describing the purpose or purposes for which it is to be held, then in each case, at such time and at such place as may be stated in the notice of the meeting. Business transacted at a special meeting shall be confined to the purpose(s) stated in the notice of such meeting.

        Section 5. Record Date. For the purpose of determining shareholders entitled to notice of or to vote at any meeting of shareholders, or any adjournment thereof, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of shares or for the purpose of any other lawful action, the Board of Directors of the Corporation may fix a date as the record date for any such determination of shareholders, which record date shall not precede the date on which the resolutions fixing the record date are adopted and which record date, in the case of a meeting of shareholders, shall not be more than seventy (70) days nor less than ten (10) days before the date of such meeting of shareholders, nor, in the case of any other action, more than seventy (70) days prior to any such action.

        If the Board of Directors does not fix a record date for any meeting of the shareholders, the record date for determining shareholders entitled to notice of or to vote at such meeting shall be at the close of business on the day before notice is mailed or otherwise transmitted to shareholders. If the Board of Directors does not fix the record date for determining shareholders for any other purpose, the record date shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto. A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting and must do so if the meeting is adjourned to a date more than 120 days after the date fixed for the original meeting.

        For the purpose of determining the shareholders entitled to consent to corporate action in writing without a meeting, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the Board of Directors, and which date shall not be more than ten (10) days after the date upon which the resolution fixing the record date is adopted by the Board of Directors. If the Board of Directors does not fix the record date, the record date for determining shareholders entitled to consent to corporate action in writing without a meeting, when no prior action by the Board of Directors is necessary, shall be the first date on which a signed written consent setting forth the action taken or proposed to be taken is delivered to the Corporation at its registered office in the State of Oregon, at its principal place of business, or to an officer or agent of the Corporation having custody of the book in which proceedings of meetings of shareholders are recorded. Delivery made to the Corporation's registered office shall be by hand or by certified or registered mail, return receipt requested. If the Board of Directors does not fix the record date, and prior action by the Board of Directors is necessary, the record date for determining shareholders entitled to consent to corporate action in writing without a meeting shall be at the close of business on the day on which the Board of Directors adopts the resolution taking such prior action.

        Section 6. Notice of Meetings. Written notice of the place, date and hour of all meetings, and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be given by or at the direction of the Chairman of the Board, the President, the Vice Chairman of the Board, the Secretary or other person(s) calling the meeting to each shareholder entitled to vote thereat not less than ten (10) nor more than sixty (60) days before the date of the meeting. Such notice is given when deposited in the United States mail, postage prepaid, directed to the shareholder at such shareholder's address as it appears on the records of the Corporation.

        Section 7. Shareholder List. A complete list of shareholders entitled to vote at any meeting of shareholders, arranged in alphabetical order for each class of shares and showing the address of each such shareholder and the number of shares registered in the name of such shareholder, shall be open to the examination of any shareholder, for any purpose germane to the meeting, during ordinary business hours, beginning two business days after notice of the meeting is given for which the list was prepared and continuing through the meeting, either at the Corporation's principal office, or at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting. The shareholder list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any shareholder or such shareholder's agent or attorney during the meeting or any adjournment thereof.

        Section 8. Proxies. Each shareholder entitled to vote at a meeting of shareholders may authorize another person or persons to act for him by proxy. Proxies for use at any meeting of shareholders shall be filed with the Secretary, or such other officer as the Board of Directors may from time to time determine by resolution, before or at the time of the meeting. All proxies shall be received and taken charge of and all ballots shall be received and canvassed by the secretary of the meeting, who shall decide all questions touching upon the qualification of voters, the validity of the proxies, and the acceptance or rejection of votes, unless an inspector or inspectors shall have been duly appointed as provided in Section 9 of Article II hereof, in which event such inspector or inspectors shall decide all such questions.

        No proxy shall be valid after eleven (11) months from its date, unless the proxy provides for a longer period. Each proxy shall be revocable unless expressly provided therein to be irrevocable and coupled with an interest sufficient in law to support an irrevocable power.

        Should a proxy designate two or more persons to act as proxies, unless such instrument shall provide the contrary, a majority of such persons present at any meeting at which their powers thereunder are to be exercised shall have and may exercise all the powers of voting or giving consents thereby conferred, or if only one be present, then such powers may be exercised by that one; or, if an even number attend and a majority do not agree on any particular issue, each person designated to act as proxy and so attending shall be entitled to exercise such powers in respect of such portion of the shares as is equal to the reciprocal of the fraction equal to the number of persons designated to act as proxies and in attendance divided by the total number of shares represented by such proxies.

        Section 9. Voting; Elections; Inspectors Unless otherwise required by law or provided in the Articles of Incorporation, each shareholder shall on each matter submitted to a vote at a meeting of shareholders have one vote for each share of stock entitled to vote which is registered in his name on the record date for the meeting. For the purposes hereof, each election to fill a directorship shall constitute a separate matter. Shares registered in the name of another corporation, domestic or foreign, or other legal entity may be voted by such officer, agent or proxy as the bylaws (or comparable instrument) of such corporation or other legal entity may prescribe, or in the absence of such provisions, as the Board of Directors (or comparable body) of such corporation or other legal entity may determine. Shares registered in the name of a deceased person may be voted by the executor or administrator of such person's estate, either in person or by proxy.

        All voting, except as required by the Articles of Incorporation or where otherwise required by law, may be by a voice vote; provided, however, upon request of the chairman of the meeting or upon demand therefor by shareholders holding a majority of the issued and outstanding shares present in person or by proxy at any meeting, a stock vote shall be taken. Every stock vote shall be taken by written ballots, each of which shall state the name of the shareholder or proxy voting and such other information as may be required under the procedure established for the meeting. All elections of directors shall be by written ballots, unless otherwise provided in the Articles of Incorporation.

        In advance of any meeting of shareholders, the Chairman of the Board, the Vice Chairman of the Board, the President or the Board of Directors shall appoint one or more inspectors, each of whom shall subscribe an oath or affirmation to execute faithfully the duties of inspector at such meeting with strict impartiality and according to the best of such inspector's ability. Such inspector(s) shall receive the written ballots, count the votes, make and sign a certificate of the result thereof and take such further action as may be required of the inspector(s) under the laws of the State of Oregon. The Chairman of the Board, the Vice Chairman of the Board, the President or the Board of Directors may appoint any person to serve as inspector, except no candidate for the office of director shall be appointed as an inspector.

        Unless otherwise provided in the Articles of Incorporation, cumulative voting for the election of directors shall be prohibited.

        Section 10. Conduct of Meetings. The meetings of the shareholders shall be presided over by the Chairman of the Board, or if the Chairman of the Board is not present, by the President, or if the President is not present, by the Vice Chairman of the Board, or if none of the Chairman of the Board, the President and the Vice Chairman of the Board is present, by a chairman elected at the meeting. The Secretary of the Corporation, if present, shall act as secretary of such meetings, or if the Secretary is not present, the Deputy Corporate Secretary or an Assistant Secretary shall so act; if none of the Secretary, the Deputy Corporate Secretary and an Assistant Secretary is present, then a secretary shall be appointed by the chairman of the meeting. The chairman of any meeting of shareholders shall determine the order of business and, subject to the requirements of the laws of the State of Oregon, the procedure at the meeting, including such regulation of the manner of voting and the conduct of discussion as seem to the chairman in order.

        Section 11. Voting of Certain Shares. No other corporation of which the Corporation owns a majority of the shares entitled to vote in the election of directors of such other corporation shall vote, directly or indirectly, shares of the Corporation's stock owned by such other corporation, and such shares shall not be counted for quorum purposes. Nothing in this Section 11 shall be construed as limiting the right of the Corporation to vote shares, including but not limited to its own shares, held by it in a fiduciary capacity.

        Section 12. Action Without Meeting. Unless otherwise provided in the Articles of Incorporation, any action permitted or required by law, the Articles of Incorporation or these Bylaws to be taken at a meeting of shareholders may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by all of the shareholders entitled to vote thereon and shall be delivered to the Corporation by delivery to its registered office in the state of incorporation, its principal place of business, or an officer or agent of the Corporation having custody of the book in which proceedings of meetings of shareholders are recorded. Delivery made to the Corporation's registered office shall be by hand or by certified or registered mail, return receipt requested.

        Every written consent shall bear the date of signature of each shareholder who signs the consent, and no written consent shall be effective to take the corporate action referred to therein unless, written consents signed by all shareholders are delivered to the Corporation in the manner required by this Section 12 within sixty (60) days of the earliest dated consent. Any action taken by written consent is effective when the last shareholder signs, unless the consent specifies an earlier or later date.

        Section 13. Business to be Brought Before the Annual Meeting. To be properly brought before the annual meeting of shareholders, business must be either (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise brought before the meeting by or at the direction of the Board of Directors, or (c) otherwise properly brought before the meeting by a shareholder of the Corporation who is a shareholder of record at the time of giving of notice provided for in this Section 13, who shall be entitled to vote at such meeting and who complies with the notice procedures set forth in this Section 13. In addition to any other applicable requirements, for business to be brought before an annual meeting by a shareholder of the Corporation, the shareholder must have given timely notice thereof in writing to the Secretary of the Corporation. To be timely, a shareholder's notice must be delivered to or mailed and received at the principal executive offices of the Corporation not less than 120 days prior to the anniversary date of the proxy statement for the preceding annual meeting of shareholders of the Corporation. A shareholder's notice to the Secretary shall set forth as to each matter (i) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (ii) the name and address, as they appear on the Corporation's books, of the shareholder proposing such business, (iii) the acquisition date, the class and the number of shares of voting stock of the Corporation which are owned beneficially by the shareholder, (iv) any material interest of the shareholder in such business, and (v) a representation that the shareholder intends to appear in person or by proxy at the meeting to bring the proposed business before the meeting.

        Notwithstanding anything in these Bylaws to the contrary, no business shall be conducted at the annual meeting except in accordance with the procedures set forth in this Section 13.

        The chairman of the annual meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting in accordance with the provisions of this Section 13, and if the chairman should so determine, the chairman shall so declare to the meeting and any such business not properly brought before the meeting shall not be transacted.

        Notwithstanding the foregoing provisions of this Section 13, a shareholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder with respect to the matters set forth in this Section 13.

Article III

Board of Directors

        Section 1. Power; Number; Term of Office. The business and affairs of the Corporation shall be managed by or under the direction of the Board of Directors, and subject to the restrictions imposed by law or the Articles of Incorporation, the Board of Directors may exercise all the powers of the Corporation.

        The number of directors that shall constitute the whole Board of Directors shall be determined from time to time by the Board of Directors (provided that no decrease in the number of directors which would have the effect of shortening the term of an incumbent director may be made by the Board of Directors). If the Board of Directors makes no such determination, the number of directors shall be three. Each director shall hold office until such director's successor shall have been elected and qualified or until such director's earlier death, resignation or removal.

        Unless otherwise provided in the Articles of Incorporation, directors need not be shareholders nor residents of the State of Oregon.

        Section 2. Quorum; Voting. Unless otherwise provided in the Articles of Incorporation, a majority of the total number of directors shall constitute a quorum for the transaction of business of the Board of Directors and the vote of a majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors.

        Section 3. Place of Meetings; Order of Business. The directors may hold their meetings and may have an office and keep the books of the Corporation, except as otherwise provided by law, in such place or places, within or without the State of Oregon, as the Board of Directors may from time to time determine. At all meetings of the Board of Directors business shall be transacted in such order as shall from time to time be determined by the Chairman of the Board, or in the Chairman of the Board's absence by the President (should the President be a director), or in the President's absence by the Vice Chairman of the Board, or by the Board of Directors.

Section 4. First Meeting. Each newly elected Board of Directors may hold its first meeting for the purpose of organization and the transaction of business, if a quorum is present, immediately after and at the same place as the annual meeting of the shareholders. Notice of such meeting shall not be required. At the first meeting of the Board of Directors in each year at which a quorum shall be present, held next after the annual meeting of shareholders, the Board of Directors shall elect the officers of the Corporation.

        Section 5. Regular Meetings. Regular meetings of the Board of Directors shall be held at such times and places as shall be designated from time to time by the Chairman of the Board or, in the absence of the Chairman of the Board, by the President (should the President be a director), or in the President's absence, by the Vice Chairman of the Board, or by the Board of Directors. Notice of such regular meetings shall not be required.

        Section 6. Special Meetings. Special meetings of the Board of Directors may be called by the Chairman of the Board, the President (should the President be a director), the Vice Chairman of the Board or, on the written request of any two directors, by the Secretary, in each case on at least twenty-four (24) hours personal, written, telegraphic, cable or wireless notice to each director. Such notice, or any waiver thereof pursuant to Section 3 of Article VIII, need not state the purpose or purposes of such meeting, except as may otherwise be required by law or provided for in the Articles of Incorporation or these Bylaws. Meetings may be held at any time without notice if all the directors are present or if those not present waive notice of the meeting in writing.

        Section 7. Nomination of Directors. Only persons who are nominated in accordance with the following procedures shall be eligible for election as directors, except as otherwise provided in Section 9 of this Article III. Nominations of persons for election to the Board of Directors of the Corporation may be made at a meeting of shareholders(a) by or at the direction of the Board of Directors or (b) by any shareholder of the Corporation who is a shareholder of record at the time of giving of notice provided for in this Section 7, who shall be entitled to vote for the election of directors at the meeting and who complies with the notice procedures set forth in this Section 7. Such nominations, other than those made by or at the direction of the Board of Directors, shall be made pursuant to timely notice in writing to the Secretary of the Corporation. To be timely, a shareholder's notice shall be delivered to or mailed and received at the principal executive offices of the Corporation (i) with respect to an election to be held at the annual meeting of the shareholders of the Corporation, 120 days prior to the anniversary date of the proxy statement for the immediately preceding annual meeting of shareholders of the Corporation, and (ii) with respect to an election to be held at a special meeting of shareholders of the Corporation for the election of directors, not later than the close of business on the 10th day following the day on which such notice of the date of the meeting was mailed or public disclosure of the date of the meeting was made, whichever first occurs. Such shareholder's notice to the Secretary shall set forth (a) as to each person whom the shareholder proposes to nominate for election or re-election as a director, all information relating to the person that is required to be disclosed in solicitations for proxies for election of directors, or is otherwise required, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (including the written consent of such person to be named in the proxy statement as a nominee and to serve as a director if elected); and (b) as to the shareholder giving the notice (i) the name and address, as they appear on the Corporation's books, of such shareholder, and (ii) the class and number of shares of capital stock of the Corporation which are beneficially owned by the shareholder. At the request of any officer of the Corporation, any person nominated by the Board of Directors for election as a director shall furnish to the Secretary of the Corporation that information required to be set forth in a shareholder's notice of nomination which pertains to the nominee.

        In the event that a person is validly designated as nominee to the Board and shall thereafter become unable or unwilling to stand for election to the Board of Directors, the Board of Directors or the shareholder who proposed such nominee, as the case may be, may designate a substitute nominee.

        Except as otherwise provided in Section 9 of this Article III, no person shall be eligible to serve as a director of the Corporation unless nominated in accordance with the procedures set forth in this Section 7. The chairman of the meeting of shareholders shall, if the facts warrant, determine and declare to the meeting that a nomination was not made in accordance with the procedures prescribed by the Bylaws, and if the chairman should so determine, the chairman shall so declare to the meeting and the defective nomination shall be disregarded.

        Notwithstanding the foregoing provisions of this Section 7, a shareholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder with respect to the matters set forth in this Section 7.

        Section 8. Removal. Any director or the entire Board of Directors may be removed, with or without cause by the holders of a majority of the shares then entitled to vote at an election of directors; provided that, with respect to the removal without cause of a director or directors elected by the holders of any class or series entitled to elect one or more directors, only the holders of outstanding shares of that class or series shall be entitled to vote on such removal.

        Section 9. Vacancies; Increases in the Number of Directors. Unless otherwise provided in the Articles of Incorporation, vacancies existing on the Board of Directors for any reason and newly created directorships resulting from any increase in the authorized number of directors to be elected by all of the shareholders having the right to vote as a single class may be filled by the affirmative vote of a majority of the directors then in office, although less than a quorum, or by a sole remaining director; and any director so chosen shall hold office until the next annual election and until such director's successor shall have been elected and qualified, or until such director's earlier death, resignation or removal.

        Section 10. Compensation. Directors and members of standing committees may receive such compensation as the Board of Directors from time to time shall determine to be appropriate, and shall be reimbursed for all reasonable expenses incurred in attending and returning from meetings of the Board of Directors.

        Section 11. Action Without a Meeting; Telephone Conference Meetings. Unless otherwise restricted by the Articles of Incorporation, any action required or permitted to be taken at any meeting of the Board of Directors, or any committee designated by the Board of Directors, may be taken without a meeting if all members of the Board of Directors or committee, as the case may be, consent thereto in writing, and the writing or writings are filed with the minutes of proceedings of the Board of Directors or committee. Such consent shall have the same force and effect as a unanimous vote at a meeting and may be stated as such in any document or instrument filed with the Secretary of State of the State of Oregon.

        Unless otherwise restricted by the Articles of Incorporation, subject to the requirement for notice of meetings, members of the Board of Directors or members of any committee designated by the Board of Directors may participate in a meeting of such Board of Directors or committee, as the case may be, by means of a conference telephone connection or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in such a meeting shall constitute presence in person at such meeting, except where a person participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened.

        Section 12. Approval or Ratification of Acts or Contracts by Shareholders. The Board of Directors in its discretion may submit any act or contract for approval or ratification at any annual meeting of the shareholders, or at any special meeting of the shareholders called for the purpose of considering any such act or contract, and any act or contract that shall be approved or be ratified by the affirmative vote of the holders of a majority of the voting power attributable to such shares so present or represented and voting at such meeting of shareholders (provided that a quorum is present) shall be as valid and as binding upon the Corporation and upon all the shareholders as if it has been approved or ratified by every shareholder of the Corporation.

Article IV

Committees

        Section 1. Executive Committee. The Board of Directors may, by resolution passed by a majority of the whole Board of Directors, designate an Executive Committee consisting of two or more of the directors of the Corporation, one of whom shall be designated chairman of the Executive Committee. During the intervals between the meetings of the Board of Directors, the Executive Committee shall possess and may exercise all the powers of the Board of Directors, except as provided in Section 6 of this Article IV. The Executive Committee shall also have, and may exercise, all the powers of the Board of Directors, except as aforesaid, whenever a quorum of the Board of Directors shall fail to be present at any meeting of the Board.

        Section 2. Audit Committee. The Board of Directors may, by resolution passed by a majority of the whole Board of Directors, designate an Audit Committee consisting of two or more of the directors of the Corporation, one of whom shall be designated chairman of the Audit Committee. The Audit Committee shall have and may exercise such powers and authority as provided in the resolution creating it and as determined from time to time by the Board of Directors, except as provided in Section 6 of this Article IV.

        Section 3. Other Committees. The Board of Directors may, by resolution passed from time to time by a majority of the whole Board of Directors, designate such other committees as it shall see fit consisting of two or more of the directors of the Corporation, one of whom shall be designated chairman of each such committee. Any such committee shall have and may exercise such powers and authority as provided in the resolution creating it and as determined from time to time by the Board of Directors, except as provided in Section 6 of this Article IV.

        Section 4. Procedure; Meetings; Quorum. Any committee designated pursuant to this Article IV shall keep regular minutes of its actions and proceedings in a book provided for that purpose and report the same to the Board of Directors at its meeting next succeeding such action, shall fix its own rules or procedures, and shall meet at such times and at such place or places as may be provided by such rules, or by such committee or the Board of Directors. Should a committee fail to fix its own rules, the provisions of these Bylaws, pertaining to the calling of meetings and conduct of business by the Board of Directors, shall apply as nearly as practicable. At every meeting of any such committee, the presence of a majority of all the members thereof shall constitute a quorum, except as provided in Section 5 of this Article IV, and the affirmative vote of a majority of the members present shall be necessary for the adoption by it of any resolution.

        Section 5. Substitution and Removal of Members; Vacancies. The Board of Directors may designate one or more directors as alternate members of any committee who may replace any absent or disqualified member at any meeting of such committee. The Board of Directors shall have the power at any time to remove any member(s) of a committee and to appoint other directors in lieu of the person(s) so removed and shall also have the power to fill vacancies in a committee.

        Section 6. Limitation on Power and Authority of Committees. No committee of the Board of Directors shall have the power or authority of the Board of Directors to:

                    (a) authorize distributions, except as may be permitted by paragraph (g) hereof;

                    (b) approve or propose to shareholders actions that are required under the Oregon Business Corporation Act to be approved by shareholders;

                    (c) fill vacancies on the Board of Directors or on any of its committees;

                    (d) amend the Articles of Incorporation pursuant to Oregon Revised Statutes Section 60.434, except as may be necessary to document a determination of the relative rights, preferences and limitations of a class or series of shares by a committee or an officer of the Corporation as permitted by paragraph (h) hereof;

                    (e) adopt, amend or repeal these Bylaws;

                    (f) approve a plan of merger not requiring shareholder approval;

                    (g) authorize or approve reacquisition of shares, except within limits prescribed by the Board of Directors; or

                    (h) authorize or approve the issuance or sale or contract for sale of shares or determine the designation and relative rights, preferences and limitations of a class or series of shares, except that the Board of Directors may authorize a committee or an officer of the Corporation to do so (i) pursuant to a stock option or other stock compensation plan, or (ii) by approving the maximum number of shares to be issued and delegating the authority to determine all or any part of the terms of the issuance or sale or contract of sale and the designation and relative rights, preferences and limitations of the class or series of shares.

Article V

Officers

        Section 1. Number, Titles and Term of Office. The officers of the Corporation shall be a Chairman of the Board, a President, one or more Vice Presidents (any one or more of whom may be designated Executive Vice President or Senior Vice President), a Treasurer, a Secretary, a General Counsel and such other officers as the Board of Directors may from time to time elect or appoint (including, but not limited to, a Vice Chairman of the Board, a Deputy Corporate Secretary, one or more Assistant Secretaries and one or more Assistant Treasurers). Each officer shall hold office until such officer's successor shall be duly elected and shall qualify or until such officer's death or until such officer shall resign or shall have been removed. Any number of offices may be held by the same person, unless the Articles of Incorporation provide otherwise. Except for the Chairman of the Board and the Vice Chairman of the Board, no officer need be a director.

        Section 2. Powers and Duties of the Chairman of the Board. The Chairman of the Board shall preside at all meetings of the shareholders and of the Board of Directors; and he shall have such other powers and duties as designated in these bylaws and as from time to time may be assigned to him by the Board of Directors.

        Section 3. Powers and Duties of the Chief Executive Officer. The Chairman of the Board shall be the chief executive officer of the Corporation unless the Board of Directors designates the President as chief executive officer. Subject to the control of the Board of Directors and the executive committee (if any), the chief executive officer shall have general executive charge, management and control of the properties, business and operations of the Corporation with all such powers as may be reasonably incident to such responsibilities; may agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Corporation and may sign all certificates for shares of capital stock of the Corporation; and shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to the chief executive officer by the Board of Directors.

        Section 4. Powers and Duties of the President. Unless the Board of Directors otherwise determines, the President shall have the authority to agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Corporation; and, unless the Board of Directors otherwise determines, the President shall, in the absence of the Chairman of the Board or if there be no Chairman of the Board, preside at all meetings of the shareholders and (should the President be a director) of the Board of Directors; and the President shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to the President by the Board of Directors or the Chairman of the Board.

        Section 5. Powers and Duties of the Vice Chairman of the Board. The Board of Directors may assign areas of responsibility to the Vice Chairman of the Board, and, in such event, and subject to the overall direction of the Chairman of the Board and the Board of Directors, the Vice Chairman of the Board shall be responsible for supervising the management of the affairs of the Corporation and its subsidiaries within the area or areas assigned and shall monitor and review on behalf of the Board of Directors all functions within the corresponding area or areas of the Corporation and each such subsidiary of the Corporation. In the absence of the President, or in the event of the President's inability or refusal to act, the Vice Chairman of the Board shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions upon the President. Further, the Vice Chairman of the Board shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to the Vice Chairman of the Board by the Board of Directors or the Chairman of the Board.

        Section 6. Vice Presidents. Subject to any restrictions that may be imposed by the Board of Directors, each Vice President shall at all times possess power to sign all certificates, contracts and other instruments of the Corporation, except as otherwise limited in writing by the Chairman of the Board, the President or the Vice Chairman of the Board of the Corporation. Each Vice President shall have such other powers and duties as from time to time may be assigned to such Vice President by the Board of Directors, the Chairman of the Board, the President or the Vice Chairman of the Board.

        Section 7. General Counsel. The General Counsel shall act as chief legal advisor to the Corporation. The General Counsel may have one or more staff attorneys and assistants, and may retain other attorneys to conduct the legal affairs and litigation of the Corporation under the General Counsel's supervision.

        Section 8 Secretary. The Secretary shall keep the minutes of all meetings of the Board of Directors, committees of the Board of Directors and the shareholders, in books provided for that purpose; shall attend to the giving and serving of all notices; may in the name of the Corporation affix the seal of the Corporation to any contract of the Corporation and attest the affixation of the seal of the Corporation thereto; may sign with the other appointed officers all certificates for shares of capital stock of the Corporation; shall have charge of the certificate books, transfer books and stock ledgers, and such other books and papers as the Board of Directors may direct, all of which shall at all reasonable times be open to inspection of any director upon application at the office of the Corporation during business hours; shall have such other powers and duties as designated in these Bylaws and as from time to time may be assigned to the Secretary by the Board of Directors, the Chairman of the Board, the President or the Vice Chairman of the Board; and shall in general perform all acts incident to the office of Secretary, subject to the control of the Board of Directors, the Chairman of the Board, the President or the Vice Chairman of the Board.

        Section 9. Deputy Corporate Secretary and Assistant Secretaries. The Deputy Corporate Secretary and each Assistant Secretary shall have the usual powers and duties pertaining to such offices, together with such other powers and duties as designated in these Bylaws and as from time to time may be assigned to the Deputy Corporate Secretary or an Assistant Secretary by the Board of Directors, the Chairman of the Board, the President, the Vice Chairman of the Board or the Secretary. The Deputy Corporate Secretary shall exercise the powers of the Secretary during that officer's absence or inability or refusal to act.

        Section 10. Treasurer. Subject to any restrictions that may be imposed by the Board of Directors, the Treasurer shall have responsibility for the custody and control of all the funds and securities of the Corporation, and shall have such other powers and duties as designated in these Bylaws and as from time to time may be assigned to the Treasurer by the Board of Directors, the Chairman of the Board, the President or the Vice Chairman of the Board. The Treasurer shall perform all acts incident to the position of Treasurer, subject to the control of the Board of Directors, the Chairman of the Board, the President and the Vice Chairman of the Board; and the Treasurer shall, if required by the Board of Directors, give such bond for the faithful discharge of the Treasurer's duties in such form as the Board of Directors may require.

        Section 11. Assistant Treasurers. Each Assistant Treasurer shall have the usual powers and duties pertaining to such office, together with such other powers and duties as designated in these Bylaws and as from time to time may be assigned to each Assistant Treasurer by the Board of Directors, the Chairman of the Board, the President, the Vice Chairman of the Board or the Treasurer. Any Assistant Treasurer may exercise the powers of the Treasurer during that officer's absence or inability or refusal to act.

        Section 12. Action with Respect to Securities of Other Corporations. Unless otherwise directed by the Board of Directors, the Chairman of the Board, the President or the Vice Chairman of the Board, together with the Secretary, the Deputy Corporate Secretary or any Assistant Secretary shall have power to vote and otherwise act on behalf of the Corporation, in person or by proxy, at any meeting of security holders of or with respect to any action of security holders of any other corporation in which this Corporation may hold securities and otherwise to exercise any and all rights and powers which this Corporation may possess by reason of its ownership of securities in such other corporation.

        Section 13. Delegation. For any reason that the Board of Directors may deem sufficient, the Board of Directors may, except where otherwise provided by statute, delegate the powers or duties of any officer to any other person, and may authorize any officer to delegate specified duties of such officer to any other person. Any such delegation or authorization by the Board shall be effected from time to time by resolution of the Board of Directors.

Article VI

Capital Stock

        Section 1. Certificates of Stock. The certificates for shares of the capital stock of the Corporation shall be in such form, not inconsistent with that required by law and the Articles of Incorporation, as shall be approved by the Board of Directors. Every holder of shares represented by certificates shall be entitled to have a certificate signed by or in the name of the Corporation by the Chairman of the Board, President, Vice Chairman of the Board or a Vice President and the Secretary, Deputy Corporate Secretary or an Assistant Secretary or the Treasurer or an Assistant Treasurer of the Corporation representing the number of shares (and, if the shares of the Corporation shall be divided into classes or series, certifying the class and series of such shares) owned by such shareholder which are registered in certified form; provided, however, that any of or all the signatures on the certificate may be facsimile. The stock record books and the blank stock certificate books shall be kept by the Secretary, or at the office of such transfer agent or transfer agents as the Board of Directors may from time to time determine. In case any officer, transfer agent or registrar who shall have signed or whose facsimile signature or signatures shall have been placed upon any such certificate or certificates shall have ceased to be such officer, transfer agent or registrar before such certificate is issued by the Corporation, such certificate may nevertheless be issued by the Corporation with the same effect as if such person were such officer, transfer agent or registrar at the date of issue. The stock certificates shall be consecutively numbered and shall be entered in the books of the Corporation as they are issued and shall exhibit the holder's name and number of shares.

        Section 2. Transfer of Shares. The shares of stock of the Corporation shall be transferable only on the books of the Corporation by the holders thereof in person or by their duly authorized attorneys or legal representatives upon surrender and cancellation of certificates for a like number of shares. Upon surrender to the Corporation or a transfer agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, it shall be the duty of the Corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books.

        Section 3. Ownership of Shares. The Corporation shall be entitled to treat the holder of record of any share or shares of capital stock of the Corporation as the holder in fact thereof and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of the State of Oregon.

        Section 4. Regulations Regarding Certificates. The Board of Directors shall have the power and authority to make all such rules and regulations as they may deem expedient concerning the issue, transfer and registration or the replacement of certificates for shares of capital stock of the Corporation.

        Section 5. Lost or Destroyed Certificates. The Board of Directors may determine the conditions upon which the Corporation may issue a new certificate for shares in place of a certificate theretofore issued by it which is alleged to have been lost, stolen or destroyed and may require the owner of such certificate or such owner's legal representative to give bond, with surety sufficient to indemnify the Corporation and each transfer agent and registrar against any and all losses or claims which may arise by reason of the alleged loss, theft or destruction of any such certificate or the issuance of such new certificate in the place of the one so lost, stolen or destroyed.

Article VII

Liability of Directors and Indemnification

        Section 1. Personal Liability of Directors. A director of the Corporation shall not be personally liable to the Corporation or its shareholders for monetary damages for conduct as a director, except for liability (i) for any breach of the director's duty of loyalty to the Corporation or its shareholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for any unlawful distribution under Oregon Revised Statutes Section 60.367, or (iv) for any transaction from which the director derived an improper personal benefit. Any repeal or amendment of this provision shall be prospective only and shall not adversely affect any limitation on the liability of a director of the Corporation existing at the time of such repeal or amendment. In addition to the circumstances in which a director of the Corporation is not liable as set forth in the foregoing provisions, a director shall not be liable to the fullest extent permitted by any provisions of the statutes of Oregon hereafter enacted that further limits the liability of a director.

        Section 2. Indemnification. Each person who was or is made a party to, or is threatened to be made a party to, or is involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a "Proceeding"), by reason of the fact that he or she, or a person of which he or she is the legal representative, is or was a director or officer, of the Corporation or is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is alleged action in an official capacity as a director, officer, partner, trustee, employee or agent or in any other capacity while serving as a director, officer, partner, trustee, employee or agent, shall be indemnified and held harmless by the Corporation to the fullest extent authorized by the Oregon Business Corporation Act, as the same exists or may hereafter be amended (but, in the case of any such amendments, only to the extent that such amendment permits the Corporation to provide broader indemnification rights than said law permitted the Corporation to provide prior to such amendment), against all expense, liability and loss (including attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith, and such indemnification shall continue as to a person who has ceased to serve in a capacity to which the above indemnification applies and shall inure to the benefit of his or her heirs, executors and administrators; provided, however, that, except as provided in this Section 2, the Corporation shall indemnify any such person seeking indemnification in connection with a proceeding (or part thereof) initiated by such person only if such proceeding (or part thereof) was authorized by the Board of Directors of the Corporation. The right to indemnification conferred in this Section 2 shall be a contract right and shall include the right to be paid by the Corporation for expenses incurred in defending any such proceeding in advance of its final disposition; provided, however, that, if the Oregon Business Corporation Act requires, the payment of such expenses incurred by a director or officer in his or her capacity as a director or officer (and not in any other capacity in which service was or is rendered by such person while a director or officer, including, without limitation, service to an employee benefit plan) in advance of the final disposition of the proceeding, such payment of expenses shall be made only upon delivery to the Corporation of a written affirmation of the director or officer's good faith belief that such director has met the standard of conduct described in Oregon Revised Statutes Section 60.391 and of an undertaking, by or on behalf of such director or officer, to repay all amounts so advanced if it shall ultimately to be determined that such director or officer is not entitled to be indemnified under this Section 2 or otherwise. The Corporation may, by action of its Board of Directors, provide indemnification to employees and agents of the Corporation not covered by the foregoing with the same scope and effect as the foregoing indemnification of directors and officer.

        If a claim under this Section 2 is not paid in full by the Corporation within thirty (30) days after a written claim has been received by the Corporation, the claimant may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim and, if successful in whole or in part, the claimant shall be entitled to be paid also the expense of prosecuting such claim. It shall be a defense to any such action (other than an action brought to enforce a claim for expenses incurred in defending any proceeding in advance of its final disposition where the required undertaking, if any is required, has been tendered to the Corporation) that the claimant has not met the standards of conduct which make it permissible under the Oregon Business Corporation Act for the Corporation to indemnify the claimant for the amount claimed, but the burden of proving such defense shall be on the Corporation. Neither the failure of the Corporation (including its Board of Directors, independent legal counsel, or its shareholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is proper in the circumstances because he or she has met the applicable standard of conduct set forth in the Oregon Business Corporation Act, nor an actual determination by the Corporation (including its Board of Directors, independent legal counsel, or its shareholders) that the claimant has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that the claimant has not met the applicable standard of conduct.

        The right to indemnification and the payment of expenses incurred in defending a proceeding in advance of its final disposition conferred in this Section 2 shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, provision of the Articles of Incorporation, bylaw, agreement, vote of shareholders or disinterested directors or otherwise.

        The Corporation may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the Corporation or another corporation, partnership, joint venture, trust or other enterprise against any such expense, liability or loss, whether or not the Corporation would have the power to indemnify such person against such expense, liability or loss under the Oregon Business Corporation Act.

        The provisions of this Section 2 shall be effective as of July 1, 1997, to the extent that this Section 2 (i) provides broader indemnification rights than those contained in the bylaws in effect prior to May 1, 1998, the date of adoption of these bylaws, or (ii) provides indemnification rights to persons not covered by the bylaws in effect prior to May 1, 1998.

Article VIII

Miscellaneous Provisions

        Section 1. Fiscal Year. The fiscal year of the Corporation shall end on the last day of December of each year.

        Section 2. Corporate Seal. The corporate seal shall be circular in form and shall have inscribed thereon the name of the Corporation and the state of its incorporation, which seal shall be in the charge of the Secretary and shall be affixed to certificates of stock, debentures, bonds, and other documents, in accordance with the direction of the Board of Directors, and as may be required by law; however, the Secretary may, if the Secretary deems it expedient, have a facsimile of the corporate seal inscribed on any such certificates of stock, debentures, bonds, contracts or other documents. Duplicates of the seal may be kept for use by the Deputy Corporate Secretary or any Assistant Secretary.

        Section 3. Notice and Waiver of Notice. Whenever any notice is required to be given by law, the Articles of Incorporation or these Bylaws, said notice shall be deemed to be sufficient if given (i) by telegraphic, cable or wireless transmission (including by telecopy or facsimile transmission) or (ii) by deposit of the same in a post office box or by delivery to an overnight courier service company in a sealed prepaid wrapper addressed to the person entitled thereto at such person's post office address, as it appears on the records of the Corporation, and such notice shall be deemed to have been given on the day of such transmission or mailing or delivery to courier, as the case may be.

        Whenever notice is required to be given by law, the Articles of Incorporation or these Bylaws, a written waiver thereof, signed by the person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a person, including without limitation a director, at a meeting shall constitute a waiver of notice of such meeting, except when the person attends a meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the shareholders, directors or members of a committee of directors need be specified in any written waiver of notice unless so required by the Articles of Incorporation or these Bylaws.

        Section 4. Facsimile Signatures. In addition to the provisions for the use of facsimile signatures elsewhere specifically authorized in these Bylaws, facsimile signatures of any officer or officers of the Corporation may be used whenever and as authorized by the Board of Directors.

        Section 5. Reliance upon Books, Reports and Records. A member of the Board of Directors, or a member of any committee designated by the Board of Directors, shall, in the performance of such person's duties, be fully protected in relying in good faith upon the records of the Corporation and upon such information, opinion, reports or statements presented to the Corporation by any of the Corporation's officers or employees, or committees of the Board of Directors, or by any other person as to matters the member reasonably believes are within such other person's professional or expert competence and who has been selected with reasonable care by or on behalf of the Corporation.

        Section 6. Application of Bylaws. In the event that any provisions of these Bylaws is or may be in conflict with any law of the United States, of the State of Oregon or of any other governmental body or power having jurisdiction over this Corporation, or over the subject matter to which such provision of these Bylaws applies, or may apply, such provision of these Bylaws shall be inoperative to the extent only that the operation thereof unavoidably conflicts with such law and shall in all other respects be in full force and effect.

 

Article IX

Amendments

        The Board of Directors may amend or repeal the Corporation's Bylaws unless: (a) the Articles of Incorporation reserve the power exclusively to the shareholders in whole or in part, or (b) the shareholders in amending or repealing a particular Bylaw provide expressly that the Board of Directors may not amend or repeal that Bylaw. The Corporation's shareholders may amend or repeal the Corporation's Bylaws even though the Bylaws may also be amended or repealed by the Board of Directors.

 

PORTLAND GENERAL ELECTRIC COMPANY FORM 10-K EXHIBIT 4 B

 

PORTLAND GENERAL ELECTRIC COMPANY

 

TO

 

HSBC BANK USA

(FORMERLY THE MARINE MIDLAND TRUST

COMPANY OF NEW YORK)

Trustee.

 

Forty-Seventh Supplemental Indenture

 

Dated: December 14, 2001

 

First Mortgage Bonds,

Second Series due 2002

 

 

Supplemental to Indenture of Mortgage and Deed of Trust,

dated July 1, 1945 of Portland General Electric Company.

 

THIS INSTRUMENT GRANTS A SECURITY INTEREST BY A TRANSMITTING UTILITY

THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS

 

 

        This FORTY-SEVENTH SUPPLEMENTAL INDENTURE (hereafter this "Supplemental Indenture"), dated December 14, 2001 is made by and between Portland General Electric Company, an Oregon corporation (hereinafter called the "Company"), and HSBC Bank USA (formerly The Marine Midland Trust Company of New York), a New York banking corporation and trust company (hereinafter called the "Trustee").

        WHEREAS, the Company has heretofore executed and delivered its Indenture of Mortgage and Deed of Trust (herein sometimes referred to as the "Original Indenture"), dated July 1, 1945, to the Trustee to secure an issue of First Mortgage Bonds of the Company ("Bonds"); and

        WHEREAS, Bonds in the aggregate principal amount of $34,000,000 have heretofore been issued under and in accordance with the terms of the Original Indenture as Bonds of an initial series designated "First Mortgage Bonds, 3 1/8% Series due 1975" (herein sometimes referred to as the "Bonds of the 1975 Series"); and

        WHEREAS, the Company has heretofore executed and delivered to the Trustee several supplemental indentures which provided, among other things, for the creation or issuance of several new series of First Mortgage Bonds under the terms of the Original Indenture as follows:

 

Supplemental
Indenture

Dated

Series Designation

Principal Amount

First

11-1-47

3-1/2

%

Series due 1977

$ 6,000,000

(1)

Second

11-1-48

3-1/2 % Series due 1977

4,000,000

(1)

Third

5-1-52

3-1/2

%

Second Series due 1977

4,000,000

(1)

Fourth

11-1-53

4-1/8

%

Series due 1983

8,000,000

(2)

Fifth

11-1-54

3-3/8

%

Series due 1984

12,000,000

(1)

Sixth

9-1-56

4-1/4

%

Series due 1986

16,000,000

(1)

Seventh

6-1-57

4-7/8

%

Series due 1987

10,000,000

(1)

Eighth

12-1-57

5-1/2

%

Series due 1987

15,000,000

(3)

Ninth

6-1-60

5-1/4

%

Series due 1990

15,000,000

(1)

Tenth

11-1-61

5-1/8

%

Series due 1991

12,000,000

(1)

Eleventh

2-1-63

4-5/8

%

Series due 1993

15,000,000

(1)

Twelfth

6-1-63

4-3/4

%

Series due 1993

18,000,000

(1)

Thirteenth

4-1-64

4-3/4

%

Series due 1994

18,000,000

(1)

Fourteenth

3-1-65

4.70

%

Series due 1995

14,000,000

(1)

Fifteenth

6-1-66

5-7/8

%

Series due 1996

12,000,000

(1)

Sixteenth

10-1-67

6.60

%

Series due October 1, 1997

24,000,000

(1)

Seventeenth

4-1-70

8-3/4

%

Series due April 1, 1977

20,000,000

(1)

Eighteenth

11-1-70

9-7/8

%

Series due November 1, 2000

20,000,000

(4)

Nineteenth

11-1-71

8

%

Series due November 1, 2001

20,000,000

(4)

Twentieth

11-1-72

7-3/4

%

Series due November 1, 2002

20,000,000

(4)

Twenty-first

4-1-73

7.95

%

Series due April 1, 2003

35,000,000

(4)

Twenty-second

10-1-73

8-3/4

%

Series due October 1, 2003

17,000,000

(4)

Twenty-third

12-1-74

10-1/2

%

Series due December 1, 1980

40,000,000

(1)

Twenty-fourth

4-1-75

10

%

Series due April 1, 1982

40,000,000

(1)

Twenty-fifth

6-1-75

9-7/8

%

Series due June 1, 1985

27,000,000

(1)

Twenty-sixth

12-1-75

11-5/8

%

Series due December 1, 2005

50,000,000

(4)

Twenty-seventh

4-1-76

9-1/2

%

Series due April 1, 2006

50,000,000

(4)

Twenty-eighth

9-1-76

9-3/4

%

Series due September 1, 1996

62,500,000

(4)

Twenty-ninth

6-1-88

8-3/4

%

Series due June 1, 2007

50,000,000

(4)

Thirtieth

10-1-78

9.4

%

Series due January 1, 1999

25,000,000

(4)

Thirty-first

11-1-78

9.80

%

Series due November 1, 1998

50,000,000

(4)

Thirty-second

2-1-80

13-1/4

%

Series due February 1, 2000

55,000,000

(4)

Thirty-third

8-1-80

13-7/8

%

Series due August 1, 2010

75,000,000

(4)

Thirty-sixth

10-1-82

13-1/2

%

Series due October 1, 2012

75,000,000

(4)

Thirty-seventh

11-15-84

11-5/8

%

Extendable Series A due

November 15, 1999

75,000,000

(4)

Thirty-eighth

6-1-85

10-3/4

%

Series due June 1, 1995

60,000,000

(4)

Thirty-ninth

3-1-86

9-5/8

%

Series due March 1, 2016

100,000,000

(4)

Fortieth

10-1-90

Medium Term Note Series

200,000,000

Forty-first

12-1-91

Medium Term Note Series I

150,000,000

Forty-second

4-1-93

7-3/4

%

Series due April 15, 2023

150,000,000

Forty-third

7-1-93

Medium Term Notes Series II

75,000,000

Forty-fourth

8-1-94

Medium Term Notes Series III

75,000,000

(1)

Forty-fifth

5-1-95

Medium Term Notes Series IV

75,000,000

Forty-sixth

8-1-96

Medium Term Notes Series V

50,000,000

(1)

(1) Paid in full at maturity.

(2) This entire issue of Bonds was redeemed out of proceeds from the sale of First Mortgage Bonds, 3-3/8% Series due 1984.

(3) This entire issue of Bonds was redeemed out of proceeds from the sale of First Mortgage         Bonds, 4-5/8% Series due 1993.

                    (4) Redeemed in full prior to maturity.

which bonds are sometimes referred to herein as the "Bonds of the 1977 Series", "Bonds of the 1977 Second Series", "Bonds of the 1983 Series", "Bonds of the 1984 Series", "Bonds of the 1986 Series", "Bonds of the 4⅞% Series due 1987", "Bonds of the 5 1/2% Series due 1987", "Bonds of the 1990 Series", "Bonds of the 1991 Series", "Bonds of the 4⅝% Series due 1993", "Bonds of the 4 3/4% Series due 1993", "Bonds of the 1994 Series", "Bonds of the 1995 Series", "Bonds of the 1996 Series", "Bonds of the 1997 Series", "Bonds of the 1977 Third Series", "Bonds of the 2000 Series", "Bonds of the 2001 Series", "Bonds of the 2002 Series", "Bonds of the 2003 Series", "Bonds of the 2003 Second Series", "Bonds of the 1980 Series", "Bonds of the 1982 Series", "Bonds of the 1985 Series", "Bonds of the 2005 Series", "Bonds of the 2006 Series", "Bonds of the 1996 Second Series", "Bonds of the 2007 Series", "Bonds of the 1999 Series", "Bonds of the 1998 Series", "Bonds of the 2000 Second Series", "Bonds of the 2010 Series", "Bonds of the 2012 Series", "Bonds of the Extendable Series A", "Bonds of the 1995 Second Series", "Bonds of the 2016 Series", "Bonds of the Medium Term Note Series", "Bonds of the Medium Term Note Series I", "Bonds of the 2023 Series", "Bonds of the Medium Term Note Series II", "Bonds of the Medium Term Note Series III", "Bonds of the Medium Term Note Series IV", and "Bonds of the Medium Term Note Series V," respectively; and

        WHEREAS, the Original Indenture provides that the Company and the Trustee, subject to the conditions and restrictions in the Original Indenture contained, may enter into an indenture or indentures supplemental thereto, which shall thereafter form a part of said Original Indenture, among other things, to mortgage, pledge, convey, transfer or assign to the Trustee and to subject to the lien of the Original Indenture with the same force and effect as though included in the granting clauses thereof, additional properties acquired by the Company after the execution and delivery of the Original Indenture, and to provide for the creation of any series of Bonds (other than the Bonds of the 1975 Series), designating the series to be created and specifying the form and provisions of the Bonds of such series as therein provided or permitted, and to provide a sinking, amortization, replacement or other analogous fund for the benefit of all or any of the Bonds of any one or more series, of such character and of such amount, and upon such terms and conditions as shall be contained in such supplemental indenture; and

        WHEREAS, the Company has heretofore executed and delivered to the Trustee the Fortieth Supplemental Indenture and the Forty-first Supplemental Indenture amending in certain respects the Original Indenture, as theretofore supplemented (such Original Indenture as so supplemented and amended is hereinafter referred to as the "Mortgage"); and

        WHEREAS, the Company desires to further amend the Mortgage in certain respects pursuant to Section 17.01 of the Original Indenture, and the Trustee has agreed to such amendments; and

        WHEREAS, the Company desires to provide for the creation of a new series of Bonds to be known as "First Mortgage Bonds, Second Series due 2002" (sometimes herein referred to as the "Bonds of the 2002 Second Series"), and to specify the form and provisions of the Bonds of the 2002 Second Series, and to mortgage, pledge, convey, transfer or assign to the Trustee and to subject to the lien of the Mortgage certain additional properties acquired by the Company since the execution and delivery of the Original Indenture; and

        WHEREAS, the Company intends at this time to issue $150,000,000 aggregate principal amount of Bonds of the 2002 Second Series under and in accordance with the terms of the Mortgage; and

        WHEREAS, the Bonds of the 2002 Second Series and the Trustee's authentication certificate to be executed on the Bonds of the 2002 Second Series are to be substantially in the following forms, respectively:

 

(Form of Bond of the 2002 Second Series)

[Face of Bond]

 

No. _____                                                                                                                         $150,000,000

PORTLAND GENERAL ELECTRIC COMPANY

FIRST MORTGAGE BOND, SECOND SERIES DUE 2002

 

ORIGINAL ISSUE DATE:                     December 14, 2001

INITIAL INTEREST RATE:                  2.995%

MATURITY DATE:                             December 16, 2002

INTEREST PAYMENT DATES:           March 14, 2002

                                                          June 14, 2002

                                                          September 14, 2002

                                                          December 16, 2002

 

        Portland General Electric Company, an Oregon corporation (hereinafter sometimes called the "Company"), for value received, hereby promises to pay to BANK ONE, NA, or registered assigns, the principal sum of One Hundred Fifty Million Dollars ($150,000,000) on the Maturity Date (except to the extent redeemed or repaid prior to the Maturity Date), and to pay interest thereon at the Interest Rate as defined below, until the principal hereof is paid or duly made available for payment, quarterly on the Interest Payment Dates specified above, in each year commencing on the first Interest Payment Date next succeeding the Original Issue Date specified above. Interest on this bond will accrue from the most recent Interest Payment Date to which interest has been paid or duly provided for or, if no interest has been paid, from the Original Issue Date specified above, until the principal hereof has been paid or duly made available for payment. If the Maturity Date or an Interest Payment Date falls on a day which is not a Business Day as defined below, principal or interest payable with respect to such Maturity Date or Interest Payment Date will be paid on the next succeeding Business Day with the same force and effect as if made on such Maturity Date or Interest Payment Date, as the case may be, and no interest shall accrue for the period from and after such Maturity Date or Interest Payment Date. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, subject to certain exceptions, be paid to the person in whose name this bond (or one or more predecessor bonds) is registered at the close of business on the fifteenth day (whether or not a Business Day) next preceding such Interest Payment Date (the "Regular Record Date"); provided, however, that interest payable on the Maturity Date will be payable to the person to whom the principal hereof shall be payable. Should the Company default in the payment of interest ("Defaulted Interest"), the Defaulted Interest shall be paid to the person in whose name this bond (or one or more predecessor bonds) is registered on a subsequent record date fixed by the Company, which subsequent record date shall be fifteen (15) days prior to the payment of such Defaulted Interest. As used herein (A) "Interest Rate" shall mean the sum of (i) the applicable British Bankers' Association Interest Settlement Rate for deposits in U.S. dollars, for a period of three (3) months commencing on the Original Issue Date or the applicable Interest Payment Date (the "Interest Period"), appearing on Reuters Screen FRBD as of 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period (provided that (x) if Reuters Screen FRBD is not available to Bank One, NA for any reason, the rate determined pursuant to this clause for the relevant Interest Period shall instead be the applicable British Bankers' Association Interest Settlement Rate for deposits in U.S. dollars as reported by any other generally recognized financial information service as of 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, and (y) if no such British Bankers' Association Interest Settlement Rate is available to Bank One, NA, the rate determined pursuant to this clause for the relevant Interest Period shall instead be the rate determined by Bank One, NA to be the rate at which Bank One, NA or one of its affiliate banks offers to place deposits in U.S. dollars with first-class banks in the London interbank market at approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period), in the principal amount hereof, plus (ii) 1.125%; provided that if any principal of this bond is not paid when due (by acceleration or otherwise), such principal shall bear interest from such due date until paid in full at a rate per annum equal to the greater of the rate set forth above and the sum of 2% plus the "prime rate" announced by Bank One, NA or by its parent, Bank One Corporation, from time to time, changing when and as said prime rate changes; and (B) "Business Day" means any day, other than a Saturday or Sunday, on which banks in The City of New York are not required or authorized by law to close.

        Payment of the principal of and interest on this bond will be made in immediately available funds at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, The City of New York, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts.

        Reference is hereby made to the further provisions of this bond set forth on the reverse hereof, and such further provisions shall for all purposes have the same effect as though fully set forth at this place.

        This bond shall not become or be valid or obligatory for any purpose until the authentication certificate hereon shall have been signed by the Trustee.

        IN WITNESS WHEREOF, PORTLAND GENERAL ELECTRIC COMPANY has caused this instrument to be executed manually or in facsimile by its duly authorized officers and has caused a facsimile of its corporate seal to be imprinted hereon.

 

 

Dated:                                     

                                                                                      PORTLAND GENERAL ELECTRIC COMPANY

   

                                                                                      By:                                                                            

                                                                                                                              [Title]

                                                                                                                    

Attest:                                                            

                                                      Secretary

 

 

(Form of Trustee's Authentication Certificate for

Bonds of the 2002 Second Series)

        This is one of the bonds, of the series designated herein, described in the within-mentioned Indenture.

                                                                                                         HSBC BANK USA, AS TRUSTEE

 

                                                                                                          By:                                                    

                                                                                                                                        Authorized Officer

 

[Reverse of Bond]

        This bond is one of the bonds, of a series designated as First Mortgage Bonds, Second Series due 2002 (sometimes herein referred to as the "Bonds of the 2002 Second Series") of an authorized issue of bonds of the Company, known as First Mortgage Bonds, not limited as to maximum aggregate principal amount, all issued or issuable in one or more series under and equally secured (except insofar as any sinking fund, replacement fund or other fund established in accordance with the provisions of the Indenture hereinafter mentioned may afford additional security for the bonds of any specific series) by an Indenture of Mortgage and Deed of Trust dated July 1, 1945, duly executed and delivered by the Company to HSBC Bank USA (formerly known as The Marine Midland Trust Company of New York), as Trustee, as supplemented and modified by forty-seven supplemental indentures (such Indenture of Mortgage and Deed of Trust as so supplemented and modified being hereinafter called the "Indenture"), to which Indenture and all indentures supplemental thereto, reference is hereby made for a description of the property mortgaged and pledged as security for said bonds, the nature and extent of the security, and the rights, duties and immunities thereunder of the Trustee, the rights of the holders of said bonds and of the Trustee and of the Company in respect of such security, and the terms upon which said bonds may be issued thereunder.

        The Bonds of the 2002 Second Series may be redeemed prior to maturity as a whole at any time or in part from time to time (upon notice given not more than five nor less than three days prior to the date of redemption), at a redemption price equal to 100% of the principal amount to be redeemed together with interest accrued on the bonds to the date of redemption (plus, if such redemption is made on a date other than a scheduled Interest Payment Date, any loss or expense incurred by Bank One, NA in liquidating or employing deposits acquired to fund or maintain its investment in the Bonds of the 2002 Second Series).

        If this bond or any portion thereof ($1,000 or an integral multiple thereof) is duly called for redemption and payment duly provided for as specified in the Indenture, this bond or such portion thereof shall cease to be entitled to the lien of the Indenture from and after the date payment is so provided for and shall cease to bear interest from and after the date fixed for such redemption.

        In the event of the selection for redemption of a portion only of the principal of this bond, payment of the redemption price will be made only upon surrender of this bond in exchange for a bond or bonds (but only of authorized denominations of the same series) for the unredeemed balance of the principal amount of this bond.

        This bond will not be subject to any sinking fund.

        Interest payments on this bond will include interest accrued to but excluding the Interest Payment Date or the Maturity Date, as the case may be. Interest payments for this bond will be computed and paid on the basis of a 360-day year.

        The Indenture contains provisions permitting the Company and the Trustee, with the consent of the holders of not less than seventy-five percent in principal amount of the bonds (exclusive of bonds disqualified by reason of the Company's interest therein) at the time outstanding, including, if more than one series of bonds shall be at the time outstanding, not less than sixty percent in principal amount of each series affected, to effect, by an indenture supplemental to the Indenture, modifications or alterations of the Indenture and of the rights and obligations of the Company and of the holders of the bonds and coupons; provided, however, that no such modification or alteration shall be made without the written approval or consent of the holder hereof which will (a) extend the maturity of this bond or reduce the rate or extend the time of payment of interest hereon or reduce the amount of the principal hereof, (b) permit the creation of any lien, not otherwise permitted, prior to or on a parity with the lien of the Indenture, or (c) reduce the percentage of the principal amount of the bonds upon the approval or consent of the holders of which modifications or alterations may be made as aforesaid.

        The transfer of this bond is registrable by the registered owner hereof in person or by such owner's attorney duly authorized in writing, at the corporate trust office of the Trustee in the Borough of Manhattan, City and State of New York, upon surrender of this bond for cancellation and upon payment of any taxes or other governmental charges payable upon such transfer, and thereupon a new registered bond or bonds of the same series and of a like aggregate principal amount will be issued to the transferee or transferees in exchange therefor.

        The Company, the Trustee and any paying agent may deem and treat the person in whose name this bond is registered as the absolute owner hereof for the purpose of receiving payments of or an account of the principal hereof and interest due hereon, and for all other purposes, whether or not this bond shall be overdue, and neither the Company, the Trustee nor any paying agent shall be affected by any notice to the contrary.

        Bonds of this series are issuable only in fully registered form without coupons in denominations of $1,000 or any integral multiple thereof. The registered owner of this bond at its option may surrender the same for cancellation at said office of the Trustee and receive in exchange therefor the same aggregate principal amount of registered bonds of the same series but of other authorized denominations upon payment of any taxes or other governmental charges payable upon such exchange and subject to the terms and conditions set forth in the Indenture.

        If an event of default as defined in the Indenture shall occur, the principal of this bond may become or be declared due and payable before maturity in the manner and with the effect provided in the Indenture. The holders, however, of certain specified percentages of the bonds at the time outstanding, including in certain cases specified percentages of bonds of particular series, may in the cases, to the extent and as provided in the Indenture, waive certain defaults thereunder and the consequences of such defaults.

        No recourse shall be had for the payment of the principal of or the interest on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, against any incorporator, shareholder, director or officer, past, present or future, as such, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, shareholders, directors and officers, as such, being waived and released by the holder and owner hereof by the acceptance of this bond and as provided in the Indenture.

        The Indenture provides that this bond shall be deemed to be a contract made under the laws of the State of New York, and for all purposes shall be construed in accordance with and governed by the laws of said State.

(End of Form of Bond of the Second Series due 2002)

and

        WHEREAS, all acts and proceedings required by law and by the charter or articles of incorporation and bylaws of the Company necessary to make the Bonds of the 2002 Second Series to be issued hereunder, when executed by the Company, authenticated and delivered by the Trustee and duly issued, the valid, binding and legal obligations of the Company, and to constitute this Supplemental Indenture a valid and binding instrument, have been done and taken; and the execution and delivery of this Supplemental Indenture have been in all respects duly authorized;

        NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH, that, in order to secure the payment of the principal of, premium, if any, and interest on all Bonds at any time issued and outstanding under the Original Indenture as supplemented and modified by the forty-six supplemental indentures hereinbefore described and as supplemented and modified by this Supplemental Indenture, according to their tenor, purport and effect, and to secure the performance and observance of all the covenants and conditions therein and herein contained, and for the purpose of confirming and perfecting the lien of the Mortgage on the properties of the Company hereinafter described, or referred to, and for and in consideration of the premises and of the mutual covenants herein contained, and acceptance of the Bonds of the 2002 Second Series by the holders thereof, and for other valuable consideration, the receipt whereof is hereby acknowledged, the Company has executed and delivered this Supplemental Indenture and by these presents does grant, bargain, sell, warrant, alien, convey, assign, transfer, mortgage, pledge, hypothecate, set over and confirm unto the Trustee the following property, rights, privileges and franchises (in addition to all other property, rights, privileges and franchises heretofore subjected to the lien of the Original Indenture as supplemented by the forty-six supplemental indentures hereinbefore described and not heretofore released from the lien thereof), to wit:

CLAUSE I

        Without in any way limiting anything hereinafter described, all and singular the lands, real estate, chattels real, interests in land, leaseholds, ways, rights-of-way, easements, servitudes, permits and licenses, lands under water, riparian rights, franchises, privileges, electric generating plants, electric transmission and distribution systems, and all apparatus and equipment appertaining thereto, offices, buildings, warehouses, garages, and other structures, tracks, machine shops, materials and supplies and all property of any nature appertaining to any of the plants, systems, business or operations of the Company, whether or not affixed to the realty, used in the operation of any of the premises or plants or systems or otherwise, which have been acquired by the Company since the execution and delivery of the Original Indenture and not heretofore included in any indenture supplemental thereto, and now owned or which may hereafter be acquired by the Company (other than excepted property as defined in the Mortgage).

CLAUSE II

        All corporate, Federal, State, municipal and other permits, consents, licenses, bridge licenses, bridge rights, river permits, franchises, grants, privileges and immunities of every kind and description, owned, held, possessed or enjoyed by the Company (other than excepted property as defined in the Mortgage) and all renewals, extensions, enlargements and modifications of any of them, which have been acquired by the Company since the execution and the delivery of the Original Indenture and not heretofore included in any indenture supplemental thereto, and now owned or which may hereafter be acquired by the Company.

CLAUSE III

        Also all other property, real, personal or mixed, tangible or intangible (other than excepted property as defined in the Mortgage) of every kind, character and description and wheresoever situated, whether or not useful in the generation, manufacture, production, transportation, distribution, sale or supplying of electricity, hot water or steam, which have been acquired by the Company since the execution and delivery of the Original Indenture and not heretofore included in any indenture supplemental thereto, and now owned or which may hereafter be acquired by the Company (other than excepted property as defined in the Mortgage).

CLAUSE IV

        Together with all and singular the plants, buildings, improvements, additions, tenements, hereditaments, easements, rights, privileges, licenses and franchises and all other appurtenances whatsoever belonging or in any wise pertaining to any of the property hereby mortgaged or pledged, or intended so to be, or any part thereof, and the reversion and reversions, remainder and remainders, and the rents, revenues, issues, earnings, income, products and profits thereof, and every part and parcel thereof, and all the estate, right, title, interest, property, claim and demand of every nature whatsoever of the Company at law, in equity or otherwise howsoever, in, of and to such property and every part and parcel thereof (other than excepted property as defined in the Mortgage).

TO HAVE AND TO HOLD all of said property, real, personal and mixed, and all and singular the lands, properties, estates, rights, franchises, privileges and appurtenances hereby mortgaged, conveyed, pledged or assigned, or intended so to be, together with all the appurtenances thereto appertaining and the rents, issues and profits thereof, unto the Trustee and its successors and assigns, forever:

        SUBJECT, HOWEVER, to the exceptions, reservations, restrictions, conditions, limitations, covenants and matters contained in all deeds and other instruments whereunder the Company has acquired any of the property now owned by it, and to permitted encumbrances as defined in Subsection B of Section 1.11 of the Mortgage;

        BUT IN TRUST NEVERTHELESS, for the equal and proportionate use, benefit, security and protection of those who from time to time shall hold the Bonds authenticated and delivered under the Original Indenture and the forty-six supplemental indentures hereinbefore described or this Supplemental Indenture, and duly issued by the Company, without any discrimination, preference or priority of any one Bond over any other by reason of priority in the time of issue, sale or negotiation thereof or otherwise, except as provided in Section 11.28 of the Mortgage, so that, subject to said Section 11.28, each and all of said Bonds shall have the same right, lien and privilege under the Original Indenture and the forty-six supplemental indentures hereinbefore described, or this Supplemental Indenture, and shall be equally secured thereby and hereby and shall have the same proportionate interest and share in the trust estate, with the same effect as if all of the Bonds had been issued, sold and negotiated simultaneously on the date of delivery of the Original Indenture;

        AND UPON THE TRUSTS, USES AND PURPOSES and subject to the covenants, agreements and conditions in the Original Indenture and the forty-six supplemental indentures hereinbefore described and herein set forth and declared.

ARTICLE ONE.
AMENDMENTS TO THE MORTGAGE.

        SECTION 1.01. Amendments to Subsections A and G of Section 1.10 of the Mortgage. The holders of all outstanding Bonds of all Series having consented thereto, Subsections A and G of Section 1.10 of the Mortgage are and shall hereby be amended so as to read as follows:

        "A. The term 'bondable public utility property' shall mean and comprise any tangible property now owned or hereafter acquired by the Company and subjected to the lien of this Indenture, which is located in the States of Oregon, Washington, California, Arizona, New Mexico, Idaho, Montana, Wyoming, Utah, Nevada and Alaska and is used or is useful to it in the business of furnishing or distributing electricity for heat, light or power or other use, or supplying hot water or steam for heat or power or steam for other purposes, including, without limiting the generality of the foregoing, all properties necessary or appropriate for purchasing, generating, manufacturing, producing, transmitting, supplying, distributing and/or disposing of electricity, hot water or steam; provided, however, that the term 'bondable public utility property' shall not be deemed to include any nonbondable property, as defined in Subsection B of this Section 1.10, or any excepted property."

        "G. The term 'minimum provision for depreciation' for the period from March 31, 1945 through December 31, 1966, as applied to bondable public utility property, whether or not subject to a prior lien, shall mean $35,023,487.50.

        "The term 'minimum provision for depreciation' for any calendar year subsequent to December 31, 1966, as applied to bondable public utility property, shall mean the greater of (i) an amount equal to 2% of depreciable bondable public utility property, as shown by the books of the Company as of January 1 of such year, with respect to which the Company was as of that date required, in accordance with sound accounting practice, to make appropriations to a reserve or reserves for depreciation or obsolescence, or (ii) the amount actually appropriated by the Company on its books of account to a reserve or reserves for depreciation or obsolescence in respect of depreciable bondable public utility property for such calendar year, in either case less an amount equal to the aggregate of (a) the amount of any property additions which during such calendar year were included in an officers' certificate filed with the Trustee as the basis for a sinking fund credit pursuant to the provisions of a sinking fund for Bonds of any series and which as a result of having been so included have been deemed, either without time limit or only so long as any Bonds of such series are outstanding, to have been 'included in an officers' certificate filed with the Trustee as the basis for a sinking fund credit' and to have been 'made the basis for action or credit hereunder' as such term is defined in Subsection H of Section 1.10 of the Original Indenture, and (b) 166-2/3% of the principal amount of Bonds of any series which shall have been delivered to the Trustee as a credit, or which the Company shall have elected to apply as a credit, against any sinking fund payment due during such calendar year for Bonds of any series, or which shall have been redeemed in anticipation of, or out of moneys paid to the Trustee on account of, any sinking fund payment due during such calendar year for Bonds of any series and which as a result of having been so made the basis of a credit upon a sinking fund payment and/or so redeemed by operation of a sinking fund shall have been disqualified, either without time limit or only so long as any Bonds of such series are outstanding, from being made the basis of the authentication and delivery of Bonds or of any other further action or credit under the Original Indenture or any supplemental indenture. Bonds delivered to the Trustee as, or applied as, a credit against any sinking fund payment and Bonds redeemed in anticipation of any sinking fund payment, regardless of the time when they were actually delivered, applied or redeemed, for purposes of the preceding sentence shall be deemed to have been delivered, applied or redeemed, as the case may be, on the sinking fund payment date when such sinking fund payment was due. Bonds redeemed out of moneys paid to the Trustee on account of any sinking fund payment shall, regardless of the date when they were redeemed, for purposes of the second preceding sentence, be deemed to have been redeemed on the later of (i) the date on which such moneys were paid to the Trustee or (ii) the sinking fund payment date when such sinking fund payment was due."

        "The minimum provision for depreciation for any calendar year subsequent to December 31, 1966, as applied to bondable public utility property not subject to a prior lien, shall be determined as set forth in the paragraph immediately preceding, except that all references therein to 'depreciable bondable public utility property' shall be deemed to be 'depreciable bondable public utility property not subject to a prior lien'.

        "The minimum provision for depreciation as applied to bondable public utility property and the minimum provision for depreciation as applied to bondable public utility property not subject to a prior lien for any period commencing subsequent to December 31, 1966 which is of twelve whole calendar months' duration but is other than a calendar year or which is of less than twelve whole calendar months' duration shall be determined by multiplying the number of whole calendar months in such period by one-twelfth of the corresponding minimum provision for depreciation for the most recent calendar year completed prior to the end of such period, and fractions of a calendar month shall be disregarded.

        "The aggregate amount of the minimum provision for depreciation as applied to bondable public utility property and the aggregate amount of the minimum provision for depreciation as applied to bondable public utility property not subject to a prior lien from March 31, 1945 to any date shall be the sum of the corresponding minimum provision for depreciation for each completed calendar year between December 31, 1966 and such date, plus (1) the corresponding minimum provision for depreciation for the period, if any, from the end of the most recent such completed calendar year to such date, in each case determined as set forth above, plus (2) $35,023,487.50, plus (3) an amount equal to the aggregate of (a) the amount of any property additions which, between December 31, 1966 and such date, became property additions of the character described in clause (a) of the second paragraph of this Subsection G and which, thereafter, also between December 31, 1966 and such date, became 'available additions' as a result of the fact that all Bonds of such series ceased to be outstanding, and (b) 166-2/3% of the principal amount of Bonds of any series which, between December 31, 1966 and such date, become Bonds of the character described in clause (b) of the second paragraph of this Subsection G and which, thereafter, also between December 31, 1966 and such date, became 'available Bond retirements' as a result of the fact that all Bonds of such series ceased to be outstanding."

        SECTION 1.02. Other Amendments to the Mortgage. The holders of all outstanding Bonds of all Series having consented thereto:

        (1)     Subsection H of Section 1.10 of the Mortgage is and hereby shall be amended by inserting before the semicolon preceding clause (ii) thereof, and as a part of clause (1) thereof, the words "if, to the extent that, and so long as, the provisions of this Indenture or any supplemental indentures creating or providing for any such fund or any supplemental indentures amending the provisions creating or providing for any such fund shall preclude the use of property additions so included in an officers' certificate as the basis for further action or credit hereunder"; Subsection I of Section 1.10 of the Mortgage is and hereby shall be amended by changing the reference therein from "Item 5" to "Item 7"; and Subsection J of Section 1.10 of the Mortgage is and hereby shall be amended by changing the reference therein from "Item 4" to "Item 5";

        (2)     Paragraph (3) of Section 3.01.A of the Mortgage is and hereby shall be amended by changing the period at the end thereof to a comma and adding the following words thereto: "except to the extent otherwise provided in this Indenture or in any supplemental indenture";

        (3)     The Certificate of Available Additions set forth in Section 3.03.A of the Mortgage is and hereby shall be amended by

(i)     adding new paragraphs (5) and (6) thereto immediately preceding existing paragraph (5) thereof, as follows:

"(5)     The aggregate amount, if any, of available additions included in Item 4 above which were so included because the same were made the basis of a credit upon any sinking fund payment for Bonds of any series and which have subsequently again become 'available additions' as a result of the fact that all Bonds of such series ceased to be outstanding, is $______.

"(6)     The aggregate amount of available additions heretofore made the basis for action or credit under said Indenture of Mortgage and which have not subsequently again become 'available additions' as set forth in Item 5 above, namely Item 4 above minus Item 5 above is $ _______

(ii)     renumbering existing paragraph (5) as paragraph (7) and changing the references in renumbered paragraph (7) from "Item 3 above minus Item 4 above" to "Item 3 above minus Item 6 above",

(iii)     renumbering existing paragraphs (6) and (7) as paragraphs (8) and (9) and changing the references in renumbered paragraph (9) from "Item 5 above minus Item 6 above" to "Item 7 above minus Item 8 above", and

(iv)     deleting "Item 7 above" in the second line of the paragraph immediately succeeding renumbered paragraph (9) and substituting "Item 9 above" therefor; and

        (4)     The Certificate of Available Bond Retirements set forth in Section 3.03.B of the Mortgage is and hereby shall be amended by

(i)     adding a new paragraph (4) thereto immediately preceding the existing paragraph (4) thereof, as follows:

"(4)     The aggregate amount, if any, of Bonds previously made the basis of a credit upon any sinking fund payment for Bonds of any series, and/or redeemed (whether on a sinking fund payment date or in anticipation of sinking fund payment) by operation of the sinking fund for Bonds of such series, which have subsequently become 'available Bond retirements' as a result of the fact that all Bonds of such series ceased to be outstanding is $ _______"

(ii)     renumbering the existing paragraph (4) as paragraph (5) and revising the same to read as follows: "The amount of presently available Bond retirements, namely the sum of Items (1), (2), (3) and (4) above, is $_______"

(iii)     renumbering the existing paragraphs (5) and (6) as (6) and (7), respectively, and changing the reference in renumbered paragraph (7) from "Item 4 minus Item 5" to "Item 5 minus Item 6".

ARTICLE TWO.
BONDS OF THE 2002 SECOND SERIES AND
CERTAIN PROVISIONS RELATING THERETO.

        SECTION 2.01A. Definitions Pertaining to Series. Capitalized terms used in this Supplemental Indenture but not otherwise defined herein shall have the respective meanings given to them in the Mortgage and the following terms shall have the meanings set forth below:

        Credit Agreement:

        The term "Credit Agreement" shall mean the Second Amended and Restated Credit Agreement dated as of July 12, 2001 among the Company, various financial institutions and Bank One, NA, as Administrative Agent, as such Credit Agreement is in effect on the date hereof (and without giving effect to (i) any amendment thereof or waiver thereunder unless consented to by Bank One, NA or (ii) any termination thereof).

        Sample Bond:

        The term "Sample Bond" shall mean the Form of Bond of the 2002 Second Series set forth in the recitals to this Supplemental Indenture.

        SECTION 2.01B. Certain Terms of Bonds of the 2002 Second Series. There is hereby established a series of First Mortgage Bonds of the Company designated and entitled as "First Mortgage Bonds, Second Series due 2002" (sometimes referred to as the "Bonds of the 2002 Second Series"). The aggregate principal amount of the Bonds of the 2002 Second Series shall be limited to One Hundred Fifty Million Dollars ($150,000,000), excluding, however, any Bonds of the 2002 Second Series which may be executed, authenticated and delivered in exchange for or in lieu of or in substitution for other Bonds of such Series pursuant to the provisions of the Mortgage or of this Supplemental Indenture.

        The definitive Bonds of the 2002 Second Series shall be issuable in substantially the form of the Sample Bond and only in fully registered form without coupons in the denomination of $1,000, or any amount in excess thereof that is an integral multiple of $1,000. Notwithstanding the provisions of Section 2.05 of the Mortgage, each Bond of the 2002 Second Series shall be dated as of the date of its authentication, shall mature on the Maturity Date specified on the face of the Sample Bond, shall bear interest at a variable rate as provided in the Sample Bond, and shall have such other terms and conditions not inconsistent with the Mortgage and this Supplemental Indenture as the Board of Directors of the Company, or any officer of the Company acting pursuant to authority granted by the Board of Directors, may determine (the execution of any Bond of the 2002 Second Series by any authorized officer of the Company being, with regard to any holder of such bond, conclusive evidence of such approval). Interest on Bonds of the 2002 Second Series shall be payable on the dates established on the date of first authentication of such Bond ("Original Issue Date"). The person in whose name any Bond of the 2002 Second Series is registered at the close of business on the applicable record date with respect to any interest payment date shall be entitled to receive the interest payable thereon on such interest payment date notwithstanding the cancellation of such Bond upon any registration of transfer or exchange thereof subsequent to such record date and prior to such interest payment date, unless the Company shall default in the payment of the interest due on such interest payment date, in which case such defaulted interest shall be paid to the person in whose name such Bond is registered on a subsequent record date fixed by the Company, which subsequent record date shall be fifteen (15) days prior to the payment of such defaulted interest. Such interest payments shall be made in such manner and in such places as provided in the Sample Bond. The principal of the Bonds of the 2002 Second Series shall be payable in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts at the office or agency of the Company in the Borough of Manhattan, City and State of New York, and interest on such Bonds shall be payable in like coin or currency at said office or agency.

        Upon compliance with the provisions of Section 2.06 of the Mortgage and as provided in this Supplemental Indenture, and upon payment of any taxes or other governmental charges payable upon such exchange, Bonds of the 2002 Second Series may be exchanged for a new Bond or Bonds of different authorized denominations of like aggregate principal amount.

        The Trustee hereunder shall, by virtue of its office as such Trustee, be the registrar and transfer agent of the Company for the purpose of registering permitted transfers of Bonds of the 2002 Second Series.

        Notwithstanding the provisions of Section 2.11 of the Mortgage, no service charge shall be made for any exchange or registration of transfer of Bonds of the 2002 Second Series, but the Company at its option may require payment of a sum sufficient to cover any tax or other governmental charge incident thereto.

        SECTION 2.01C. Covenants Related to Bonds of the 2002 Second Series. The Company agrees that, prior to payment in full of all obligations arising in connection with the Bonds of the 2002 Second Series, it will:

        (a) not incur or guarantee any indebtedness (including any debt borrowed or guaranteed or otherwise assumed, including the issuance of debt securities or warrants or rights to acquire debt) other than (x) an aggregate of up to $550,000,000 in short-term indebtedness outstanding at any time, (y) long-term indebtedness incurred in connection with the refinancing of existing indebtedness either at its stated maturity or at a lower cost of funds and (c) up to $300,000,000 in additional indebtedness;

        (b) not sell, lease, assign, transfer or otherwise dispose of any assets or interest therein to an affiliate of the Company except for full payment in cash for the fair market value thereof (as determined in good faith by the Board of Directors of the Company); and

        (c) perform each covenant set forth in Article VI of the Credit Agreement as if such covenants and all related definitions mutatis mutandis were set forth herein (it being understood that any reference to the "Borrower" shall be deemed to be a reference to the Company, and any reference to the "Agent," "Bank," "Lender" or "Required Lenders" shall be deemed to be a reference to Bank One, NA and any other registered holder of a Bond of the 2002 Second Series).

        Notwithstanding anything to the contrary set forth herein, (i) if the Company fails to comply with this Section 2.01C or (ii) any "Default" under and as defined in the Credit Agreement shall have occurred and be continuing, then the registered holder of a Bond of the 2002 Second Series shall be entitled to declare the principal of and accrued interest on the Bonds of the 2002 Second Series (and all other amounts payable hereunder) to be forthwith due and payable in full, and by a notice in writing to the Company (and to the Trustee) and upon any such declaration, such amount shall become immediately due and payable.

        SECTION 2.02. Redemption Provisions for Bonds of the 2002 Second Series. The Bonds of the 2002 Second Series are subject to redemption prior to maturity as a whole at any time or in part from time to time upon payment of the principal amount thereof together with interest thereon payable to the date of redemption (plus, if such redemption is made on a date other than a scheduled interest payment date, any loss or expense incurred by Bank One, NA in liquidating or employing deposits acquired to fund or maintain its investment in the Bonds of the 2002 Second Series), it being understood the terms set forth in this Section 2.02 shall only apply to Bonds of the 2002 Second Series.

        SECTION 2.03. Sections 4.04, 4.05 and 4.06 to Remain in Effect. Notwithstanding the provisions of Section 4.07 of the Mortgage, the provisions of Sections 4.04, 4.05 and 4.06 of the Mortgage shall remain in full force and effect and shall be performed by the Company so long as any Bonds of the 2002 Second Series remain outstanding.

        SECTION 2.04. Certain Requirements to Remain Applicable. The requirements which are stated in the next to the last paragraph of Section 1.13 and in Clause (9) of Paragraph A of Section 3.01 of the Mortgage to be applicable so long as any of the Bonds of the 1975 Series are outstanding shall remain applicable so long as any of the Bonds of the 2002 Second Series are outstanding.

        SECTION 2.05. Certain Exceptions to Sections 2.06 and 2.10 of the Mortgage. Notwithstanding the provisions of Section 2.06 or Section 2.10 of the Mortgage, the Company shall not be required (a) to issue, register, discharge from registration, exchange or register the transfer of any Bond of the 2002 Second Series for a period of fifteen (15) days next preceding any selection by the Trustee of Bonds of the 2002 Second Series to be redeemed or (b) to register, discharge from registration, exchange or register the permitted transfer of any Bond of the 2002 Second Series so selected for redemption in its entirety or (c) to exchange or register the permitted transfer of any portion of a Bond of the 2002 Second Series which portion has been so selected for redemption.

        SECTION 2.06. Reference to Minimum Provision for Depreciation in Certificate of Available Additions. So long as any Bonds of the 2002 Second Series remain outstanding, all references to the minimum provision for depreciation in the form of certificate of available additions set forth in Section 3.03 of the Mortgage shall be included in any certificate of available additions filed with the Trustee, but whenever Bonds of the 2002 Second Series shall no longer be outstanding, all references to such minimum provisions for depreciation may be omitted from any such certificate.

        SECTION 2.07. Collection of Indebtedness. The Company covenants that if

        (1)     default is made in the payment of any interest on any Bond of the 2002 Second Series when such interest becomes due and payable and such default continues for a period of 30 days, or

        (2)     default is made in the payment of the principal of any Bond of the 2002 Second Series at the Maturity thereof,

the Company will, upon demand of the Trustee, pay to it, for the benefit of the registered holders of such Bonds of the 2002 Second Series, the whole amount then due and payable on such Bonds of the 2002 Second Series for principal and interest and, to the extent that payment of such interest shall be legally enforceable, interest on any overdue principal and on any overdue interest, at the rate or rates prescribed therefore in such Bonds of the 2002 Second Series, and, in addition thereto, such further amount as shall be sufficient to cover the costs and expenses of collection, including the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, and any other amounts due the Trustee under the Mortgage.

        SECTION 2.08. Duration of Article Two. This Article shall be of force and effect only so long as any Bonds of the 2002 Second Series are outstanding.

ARTICLE THREE.
TRUSTEE.

        SECTION 3.01. Duties of Trustee. The Trustee hereby accepts the trust hereby created.  The Trustee undertakes, prior to the occurrence of an event of default and after the curing of all events of default which may have occurred, to perform such duties and only such duties as are specifically set forth in the Original Indenture as heretofore and hereby supplemented and modified, on and subject to the terms and conditions set forth in the Original Indenture as so supplemented and modified, and in case of the occurrence of an event of default (which has not been cured) to exercise such of the rights and powers vested in it by the Original Indenture as so supplemented and modified, and to use the same degree of care and skill in their exercise, as a prudent man would exercise or use under the circumstances in the conduct of his own affairs.

        The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the Bonds of the 2002 Second Series issued hereunder or the due execution thereof by the Company.  The Trustee shall be under no obligation or duty with respect to the filing, registration or recording of this Supplemental Indenture or the re-filing, re-registration or re-recording thereof. The recitals of fact contained herein or in the Bonds of the 2002 Second Series (other than the Trustee's authentication certificate) shall be taken as the statements solely of the Company, and the Trustee assumes no responsibility for the correctness thereof.

ARTICLE FOUR.
MISCELLANEOUS PROVISIONS.

        SECTION 4.01. Date of this Supplemental Indenture. Although this Supplemental Indenture, for convenience and for the purpose of reference, is dated December 14, 2001, the actual date of execution by the Company and by the Trustee is as indicated by their respective acknowledgments hereto annexed.

        SECTION 4.02. Relation to Original Indenture. This Supplemental Indenture is executed and shall be construed as an indenture supplemental to the Original Indenture as heretofore supplemented and modified, and as supplemented and modified hereby, the Original Indenture as heretofore supplemented and modified is in all respects ratified and confirmed, and the Original Indenture as heretofore and hereby supplemented and modified shall be read, taken and construed as one and the same instrument. All terms used in this Supplemental Indenture shall be taken to have the same meaning as in the Original Indenture except in cases where the context clearly indicates otherwise.

        SECTION 4.03. Invalid, Illegal or Unenforceable Provisions. In case any one or more of the provisions contained in this Supplemental Indenture or in the Bonds of the 2002 Second Series shall for any reason be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provisions of this Supplemental Indenture, but this Supplemental Indenture shall be construed as if such invalid or illegal or unenforceable provision had never been contained herein.

        SECTION 4.04. Counterparts. This Supplemental Indenture may be executed in any number of counterparts, and each of such counterparts shall for all purposes be deemed to be an original, and all such counterparts, or as many of them as the Company and the Trustee shall preserve undestroyed, shall together constitute but one and the same instrument.

        SECTION 4.05. Conflicting Provision. If any provision of this Supplemental Indenture conflicts with another provision of the Mortgage required to be included in indentures qualified under the Trust Indenture Act of 1939 (as enacted prior to the date of this Supplemental Indenture) by any of the provisions of said Act, such required provision shall control.

        IN WITNESS WHEREOF, Portland General Electric Company has caused this Supplemental Indenture to be signed in its corporate name by its President or one of its Senior Vice Presidents or one of its Vice Presidents and its corporate seal to be hereunto affixed and attested by its Secretary or one of its Assistant Secretaries, and in token of its acceptance of the trusts created hereunder, HSBC Bank USA has caused this Supplemental Indenture to be signed in its corporate name by one of its Vice Presidents or one of its Assistant Vice Presidents or one of its Corporate Trust Officers and its corporate seal to be hereunto affixed and attested by one of its Corporate Trust Officers, all as of the day and year first above written.

                                                                                      PORTLAND GENERAL ELECTRIC COMPANY

 

                                                                                     By:                                                                            

                                                                                     Name:

                                                                                     Title:

Attest:

                                                                        

Title:                                                                 

(Seal)

                                                                                        HSBC BANK USA

 

                                                                                        By:                                                                       

                                                                                         Name:

                                                                                         Title:

                                                                                                                                                                                                                                          

                                                                                       

Attest:                                                              

Title:                                                                

(Seal)

 

 

State of Oregon           )

                                   )

County of Multnomah  )

 

 

        The foregoing instrument was acknowledged before me on this          day of December by                                             , a                                          of PORTLAND GENERAL ELECTRIC COMPANY, an Oregon corporation, on behalf of said corporation.

 

                                                                                                                                                          

                                                                                                 Notary Public for Oregon

                                                                                                 My Commission Expires                     

[NOTARIAL SEAL]

 

State of New York          )

                                       )

County of _________     )

 

The foregoing instrument was acknowledged before me on this          day of December by ________________________, a(an) ______________ of HSBC BANK USA, a New York banking corporation and trust company, on behalf of said corporation.

 

                                                                                                                                                           

                                                                                                  Notary Public, State of New York

                                                                                                                    No.             

                                                                                                   My Commission Expires                     

[NOTARIAL SEAL]

 

State of Oregon            ) 

                                    )

County of Multnomah   )

 

                            and                             , a                                 and                                                          , respectively, of PORTLAND GENERAL ELECTRIC COMPANY, an Oregon corporation, the mortgagor in the foregoing mortgage named, being first duly sworn, on oath depose and say that they are the officers above named of said corporation and that this affidavit is made for and on its behalf by authority of its Board of Directors and that the aforesaid mortgage is made by said mortgagor in good faith, and without any design to hinder, delay or defraud creditors.

            Subscribed and sworn to before me this           day of December.

 

                                                                                                                                                                  

                                                                                                     Notary Public for Oregon

                                                                                                     My Commission Expires                         

[NOTARIAL SEAL]

 

POWER OF ATTORNEY

PORTLAND GENERAL ELECTRIC COMPANY

 

 

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by Portland General Electric Company of its Annual Report on Form 10-K for the year ended December 31, 2001, with the Securities and Exchange Commission, the undersigned director of the Company hereby constitute and appoint Douglas R. Nichols and Kirk M. Stevens, 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 April 11, 2002.

 

 

/s/ Stanley C. Horton                        

     Stanley C. Horton

AGENDA ITEM (7)(d)(ii)

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 2001 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

        RESOLVED FURTHER, that Douglas R. Nichols and Kirk M. Stevens (the "Authorized Officers"), individually, are hereby appointed as attorney-in-fact for the members of this Board of Directors as authorized by the Power of Attorney executed this day and each are authorized and directed to execute on behalf of the Board of Directors and file the final Form 10-K with the SEC; and

        RESOLVED FURTHER, that the Form 10-K shall be executed on behalf of the members of this Board of Directors 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

        RESOLVED FURTHER, that the Authorized Officers of the Company, and its 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; and

        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 the Company in connection with the foregoing matters are hereby ratified, confirmed, and adopted by the Company.

 

Dated effective as of April 11, 2002.

                                                                                        /s/ Peggy Y. Fowler                                       

                                                                                             Peggy Y. Fowler

 

                                                                                        /s/ Stanley C. Horton                                      

                                                                                             Stanley C. Horton

 

        /s/ James J. Piro                                              

                                                                                             James J. Piro