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.

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.

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 r eorganization 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 o f the stock purchase agreement.

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

          Income Taxes

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 c ause 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.

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.

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 po wer 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.

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.

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 Com pany'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.

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 a nd 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.

PGE's current credit ratings are as follows:

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

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

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

PGE 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 pay ments 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.

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 proc ess.

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) I ssue 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.

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 provision s against certain receivable balances due from Enron companies in bankruptcy. For further information, see Note 12, Related Party Transactions, and Note 16, Enron Bankruptcy, in the Notes to Financial Statements.

PGE trading activities utilize electricity forward and option contracts 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):

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.

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.

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 (N EIL).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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).

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.

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

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.

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

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

Gains and losses from 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.

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.

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):

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

PGE is exposed to credit risk in its 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.

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.

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.

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.

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 

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.

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

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.

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 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.

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 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 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.

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):

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.

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

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.

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.

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.

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 payi ng 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.

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 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 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.

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

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.

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).

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):