PGE is restricted, without prior OPUC approval, from making any dividend distributions to Enron that would reduce PGE's common equity capital below 48% of total capitalization. 

* Includes long-term debt, preferred stock subject to mandatory redemption requirements, long-term capital lease     obligations, and commercial paper to be refinanced.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PGE maintains varying levels of short-term debt, primarily in the form of commercial paper, which serves as the primary form of daily liquidity. In 2000, monthly balances ranged from $16 million to $278 million. PGE has two committed borrowing facilities: a $150 million facility maturing in July 2003 and a $100 million facility maturing in July 2001. Both facilities are used as backup for PGE's commercial paper facility.

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

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

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

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

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

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

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

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

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Articles of Incorporation and the Indenture securing its First Mortgage Bonds. As of December 31, 2000, PGE has the capability to issue preferred stock and additional First Mortgage Bonds in amounts sufficient to meet its capital requirements. 

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

PGE has long-term power contracts with four hydro projects on the mid-Columbia River providing capability of approximately 650 MW, and has also relied increasingly upon short-term purchases to meet its energy needs. The Company anticipates that an active wholesale market and generating capacity within the Western Systems Coordinating Council should provide wholesale energy to supplement its generation and purchases under existing firm power contracts.

Early forecasts for 2001 indicate hydro conditions approximating only 63% of normal, compared to 92% of normal last year. Efforts to restore salmon runs on the Columbia and Snake rivers may additionally reduce the amount of water available for generation, which could affect the availability and price of purchased power. Additional factors that could affect the availability and price of purchased power include weather conditions in the Northwest during winter months and in the Southwest during summer months, as well as the performance of major generating facilities in both regions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes accounting and reporting standards requiring that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

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

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

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although PGE believes that its expectations are based on reasonable assumptions, it can give no assurance that its expectations will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include political developments affecting federal and state regulatory agencies, the pace of electric industry deregulation in Oregon and in the United States, environmental regulations, changes in the cost of power, and adverse weather conditions during the periods covered by the forward-looking statements.

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

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

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

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

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

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

PGE assessed its internal control system as of December 31, 2000, 1999 and 1998, relative to current standards of control criteria. Based upon this assessment, management believes that its system of internal controls was adequate during the periods to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition.

Arthur Andersen LLP was engaged to audit the financial statements of PGE and issue reports thereon. Their audits included developing an overall understanding of PGE's accounting systems, procedures and internal controls and conducting tests and other auditing procedures sufficient to support their opinion on the financial statements. Arthur Andersen LLP was also engaged to examine and report on management's assertion about the effectiveness of PGE's system of internal controls over financial reporting and the protection of assets against unauthorized acquisition, use or disposition. The Reports of Independent Public Accountants appear in this report.

The adequacy of PGE's financial controls and the accounting principles employed in financial reporting are under the general oversight of the Audit Committee of Enron's Board of Directors. No member of this committee is an officer or employee of Enron or PGE. The independent public accountants have direct access to the Audit Committee, and they meet with the committee from time to time, with and without financial management present, to discuss accounting, auditing and financial reporting matters.

We have examined management's assertion that the system of internal control of Portland General Electric Company and its subsidiaries as of December 31, 2000, 1999 and 1998 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition, included in the accompanying report on Management's Responsibility for Financial Reporting. Management is responsible for maintaining effective internal control over the reliability of the financial statements and the protection of assets against unauthorized acquisition, use or disposition. Our responsibility is to express an opinion on management's assertion based on our examination.

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

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

In our opinion, management's assertion that the system of internal control of Portland General Electric Company and its subsidiaries as of December 31, 2000, 1999, and 1998 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition is fairly stated, in all material respects, based upon current standards of control criteria.

Arthur Andersen LLP

Portland, Oregon

January 26, 2001

We have audited the accompanying consolidated balance sheets of Portland General Electric Company (an Oregon corporation), and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, retained earnings and cash flow for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

Arthur Andersen LLP

Portland, Oregon

January 26, 2001

(except with respect to the matter discussed in

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

Portland General Electric Company and Subsidiaries