SEC Filing | Portland General Electric Company

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Portland General Electric Company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2000

[ ]

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

THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from ________________ to _______________

Commission File Number 1-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Oregon		93-0256820
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

121 SW Salmon Street, Portland, Oregon 97204

(Address of principal executive offices) (zip code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of October 31, 2000: 42,758,877 shares of Common Stock, $3.75 par value. (All shares are owned by Enron Corp.)

Table of Contents

Page

Number

Definitions

Part I. Financial Information

Item 1. Financial Statements

Consolidated Statement of Income

Consolidated Statement of Retained Earnings

Consolidated Balance Sheet

Consolidated Statement of Cash Flows

Notes to Consolidated Financial Statements

Item 2. Management's Discussion and Analysis of

Financial Condition and Results of Operations

Part II. Other Information

Item 1. Legal Proceedings

Item 6. Exhibits and Reports on Form 8-K

Signature Page

Definitions

BPA

Bonneville Power Administration

DEQ

Department of Environmental Quality

Enron

Enron Corp.

EPA

Environmental Protection Agency

FERC

Federal Energy Regulatory Commission

KWh

Kilowatt-Hour

Mill

One tenth of one cent

MWh

Megawatt-hour

OPUC or the Commission

Oregon Public Utility Commission

PGE or the Company

Portland General Electric Company

Trojan

Trojan Nuclear Plant

Part I

Portland General Electric Company and Subsidiaries Consolidated Income Statement (Unaudited)

			Three Months Ended September 30,				Nine Months Ended September 30,
			2000		1999		2000		1999
			(Millions of Dollars)
Operating Revenues		$	728	$	408	$	1,555	$	1,001

Operating Expenses
	Purchased power and fuel		523		245		976		470
	Production and distribution		31		29		90		90
	Administrative and other		36		28		105		79
	Depreciation and amortization		39		36		116		115
	Taxes other than income taxes		19		16		52		47
	Income taxes		27		15		71		63
			675		369		1,410		864

Net Operating Income			53		39		145		137

Other Income (Deductions)
	Miscellaneous		(5)		1		2		7
	Income taxes		2		-		3		2
			(3)		1		5		9

Interest Charges
	Interest on long-term debt and other		16		14		47		45
	Interest on short-term borrowings		2		2		7		6
			18		16		54		51

Net Income			32		24		96		95

Preferred Dividend Requirement			1		-		2		2

Income Available for Common Stock		$	31	$	24	$	94	$	93

Consolidated Statement of Retained Earnings (Unaudited)
			Three Months Ended September 30,				Nine Months Ended September 30,
			2000		1999		2000		1999
			(Millions of Dollars)
Balance at Beginning of Period		$	424	$	385	$	401	$	356
Net Income			32		24		96		95
			456		409		497		451

Dividends Declared
	Common stock		20		20		60		60
	Preferred stock		1		-		2		2
			21		20		62		62

Balance at End of Period		$	435	$	389	$	435	$	389


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

Portland General Electric Company and Subsidiaries Consolidated Balance Sheet (Unaudited)
				September 30,		December 31,
				2000		1999
				(Millions of Dollars)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes Construction Work in Progress of
	$62 and $44)		$	3,367	$	3,295
	Accumulated depreciation and amortization			(1,507)		(1,430)
				1,860		1,865

Other Property and Investments
	Contract termination receivable			65		85
	Receivable from parent			82		89
	Nuclear decommissioning trust, at market value			35		42
	Corporate owned life insurance			90		85
	Miscellaneous			18		17
				290		318
Current Assets
	Cash and cash equivalents			5		-
	Accounts and notes receivable			244		140
	Unbilled and accrued revenues			44		49
	Assets from price risk management activities			68		-
	Inventories, at average cost			31		37
	Prepayments and other			69		41
				461		267
Deferred Charges
	Unamortized regulatory assets			493		691
	Miscellaneous			21		26
				514		717
			$	3,125	$	3,167
Capitalization and Liabilities
Capitalization
	Common stock equity
		Common stock, $3.75 par value per share, 100,000,000
		shares authorized; 42,758,877 shares outstanding	$	160	$	160
		Other paid-in capital - net		480		480
	Retained earnings			435		401
	Cumulative preferred stock
		Subject to mandatory redemption		30		30
	Long-term obligations			800		701
				1,905		1,772
Current Liabilities
	Long-term debt due within one year			53		32
	Short-term borrowings			92		266
	Accounts payable and other accruals			251		167
	Liabilities from price risk management activities			51		-
	Accrued interest			16		11
	Dividends payable			1		1
	Accrued taxes			39		12
				503		489
Other
	Deferred income taxes			352		351
	Deferred investment tax credits			27		36
	Trojan decommissioning and transition costs			228		234
	Unamortized regulatory liabilities			16		197
	Miscellaneous			94		88
				717		906
			$	3,125	$	3,167

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

Portland General Electric Company and Subsidiaries Consolidated Statement of Cash Flows (Unaudited)
				Nine Months Ended
				September 30,
				2000		1999
				(Millions of Dollars)
Cash Flows From Operating Activities:
	Reconciliation of net income to net cash provided by
		operating activities
	Net Income		$	96	$	95
	Non-cash items included in net income:
		Depreciation and amortization		116		115
		Deferred income taxes		(8)		(4)
		Net assets from price risk management activities		(17)		-
		Other non-cash (income) and expenses		7		(10)
	Changes in working capital:
		Increase in receivables		(99)		(11)
		Increase in payables		116		50
		Other working capital items - net		(22)		(28)
	Other - net			12		(6)
Net Cash Provided by Operating Activities				201		201

Cash Flows From Investing Activities:
	Capital expenditures			(109)		(133)
	Proceeds from sales of assets			27		-
	Other - net			2		16
Net Cash Used in Investing Activities				(80)		(117)

Cash Flows From Financing Activities:
	Repayment of long-term debt			(30)		(109)
	Net increase (decrease) in short-term borrowings			(174)		107
	Issuance of long-term debt			150		-
	Dividends paid			(62)		(42)
	Repayment of loans on corporate owned life insurance			-		(32)
	Other - net			-		1
Net Cash Used in Financing Activities				(116)		(75)

Increase in Cash and Cash Equivalents				5		9
Cash and Cash Equivalents, Beginning of Period				-		4
Cash and Cash Equivalents, End of Period			$	5	$	13


Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	47	$	41
		Income taxes		80		90


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

Notes to Consolidated Financial Statements

(Unaudited)

Note 1 - Principles of Interim Statements

The interim financial statements have been prepared by PGE and, in the opinion of management, reflect all material adjustments which are necessary for a fair statement of results for the interim period presented. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods based on the estimates of operating time expired, benefit received or activity associated with the interim period. Accordingly, such costs are subject to year-end adjustment. It is PGE's opinion that, when the interim statements are read in conjunction with the 1999 Annual Report on Form 10-K, the disclosures are adequate to make the information presented not misleading.

Reclassifications - Certain amounts in prior years have been reclassified to conform to current year presentation.

Note 2 - Legal Matters

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

The Court of Appeals decision was a result of combined appeals from earlier circuit court rulings. In April 1996, a Marion County Circuit Court judge ruled that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan, contradicting a November 1994 ruling from the same court upholding the OPUC's authority. The 1996 ruling was the result of an appeal of PGE's 1995 general rate order, which granted PGE recovery of, and a return on, 87% of its remaining investment in Trojan.

On August 26, 1998, PGE and the OPUC filed petitions for review with the Oregon Supreme Court, supported by amicus briefs filed by three other major utilities seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's return on its undepreciated investment in Trojan. Also on August 26, 1998, the Utility Reform Project (URP) filed a petition for review with the Oregon Supreme Court seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's recovery of its undepreciated investment in Trojan.

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

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

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

In August 2000, PGE entered into settlement agreements with CUB and the staff of the OPUC of the litigation related to PGE's recovery of its investment in the Trojan plant. Under the agreements, CUB agreed to withdraw from the litigation and support the settlement as the means to resolve the Trojan litigation. The OPUC approved the accounting and ratemaking elements of the settlement on September 29, 2000. As a result of these approvals, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return on or a return of that investment. On October 30, 2000, the URP filed a complaint with the OPUC, challenging PGE's application for approval of the accounting and ratemaking elements of the settlement and requesting a hearing.

With CUB's withdrawal from the litigation, the URP is the one remaining significant adverse party in the litigation. The URP has indicated it plans to continue to challenge the March 1995 OPUC order allowing PGE recovery of its investment in Trojan. The Oregon Supreme Court had indicated it will hold its review of the Court of Appeals decision in abeyance until after the election referenced above. PGE has requested the Oregon Supreme Court to continue to hold its review in abeyance pending resolution of the URP's October 30, 2000 complaint described above, and plans after that matter is resolved to request the Oregon Supreme Court to determine that the entire matter is now moot.

The settlement agreements and OPUC order provided for removal from PGE's balance sheet of the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consist of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining obligation due PGE customers under terms of the Enron/PGC merger. After offsetting the investment in Trojan with these credits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed in the third quarter of 2000.

Collection of ongoing decommissioning costs at Trojan is not affected by the settlement agreements or the September 29, 2000, OPUC order.

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

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

Note 3 - Price Risk Management

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

Unrealized gains and losses from newly originated contracts and the impact of price movements are recorded within "Purchased power and fuel" on the Income Statement. In the first nine months of 2000, a $17.8 million net gain on electricity trading contracts was recorded, including $1.7 million in the third quarter of the year. In addition, a $1.1 million net loss on natural gas swaps has been recorded, including a $0.9 million loss in the third quarter of the year.

Note 4 - Credit Facilities and Debt

On March 8, 2000, PGE issued $150 million of 7.875% unsecured notes maturing in 2010. On July 27, 2000, PGE completed a $250 million committed credit facility with a group of commercial banks. The new facility consists of two separate agreements, a three-year $150 million facility and a 364-day $100 million facility. The new credit facility, which replaced the Company's separate $200 million and $100 million revolving credit facilities, will be used as backup for commercial paper and borrowings from commercial banks under uncommitted lines of credit, and will serve as the Company's primary source of liquidity. There are no changes to current debt covenants or other restrictions.

Note 5 - Subsequent Event

In connection with the termination of PGE's membership in Nuclear Electric Insurance Limited related to the Trojan plant, the Company will receive a terminating distribution of approximately $34 million. The OPUC has ordered that PGE customers shall receive 55% and PGE will retain 45% of such distribution. The customers' pre-tax share, approximately $19 million, will be deferred pending disposition by the OPUC, with interest accrued at the Company's authorized rate of return. PGE's pre-tax share of the total distribution, approximately $15 million, will be recorded as Other Income in the fourth quarter of 2000.

Management's Discussion and Analysis of Financial

Condition and Results of Operation

Results of Operations

The following review of PGE's results of operations should be read in conjunction with the Consolidated Financial Statements.

Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and fuel costs, quarterly operating earnings are not necessarily indicative of results to be expected for calendar year 2000.

PGE does not have a fuel adjustment clause as part of its retail rate structure; therefore, changes in fuel and purchased power expenses are reflected currently in earnings.

2000 Compared to 1999 for the Three Months Ended September 30

PGE earned $32 million during the third quarter of 2000 compared to earnings of $24 million in 1999. The increase was primarily due to increased revenues, partially offset by higher costs for purchased power and fuel and increases in other operating expenses.

Total operating revenues increased $320 million (78%) compared to the third quarter of 1999, due largely to a significant increase in the price of energy sold in the wholesale market, caused by increased demand for higher priced power (for further information see "Power Supply" in the Financial and Operating Outlook section). Wholesale revenues increased $300 million (from $166 million to $466 million), as PGE sold on the wholesale market excess power purchased; wholesale sales volume increased 16% at average prices that increased 142%. Retail revenues increased $20 million (9%) from last year's third quarter due primarily to higher prices for increased industrial energy sales and an approximate $5 million increase related to increased energy savings achieved under certain energy efficiency programs, as filed and approved by the OPUC. Industrial energy sales rose 7% as large paper, chemical, high tech, and metals manufacturers increased their energy use; prices averaged 13% higher than last year due to higher prices indexed to the cost of power. Overall retail energy sales rose 2%, with 7% higher industrial sales partially offset by smaller increases in residential and commercial sales. The average number of retail customers during the third quarter was approximately 11,000 higher than in last year's third quarter.

Megawatt-Hours Sold (thousands)

	2000	1999
Retail	4,657	4,553
Wholesale	5,703	4,921

Purchased power and fuel costs increased $278 million (113%) from last year's third quarter, primarily due to significantly higher prices and an increase in wholesale load. Higher regional power and gas market prices increased the average cost of firm power purchases by 65%. Combined with an almost five-fold increase in the average price of secondary power and the replacement of low-cost hydro with combustion turbine generation, PGE's average variable power cost increased almost 98% in the third quarter.

Total generation increased 11%; with significantly increased production at the Company's combustion turbine generating plants partially offset by reduced coal and hydro production. Company generation comprised 27% of PGE's total system requirement during the third quarter of both 1999 and 2000.

Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)

	2000	1999	2000	1999
Generation	2,934	2,648	15.1	10.1
Firm Purchases	6,745	6,028	50.1	30.3
Spot Purchases	1,065	1,155	126.6	22.0
Total Send-Out	10,744	9,831	48.8*	24.7*

(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation, and taxes) increased $10 million (18%). Expenses in last year's third quarter were reduced by the effect of the non-recurring capitalization of approximately $2 million of Year 2000 remediation expenses incurred in the first three quarters of the year. In addition, a $2 million contract termination settlement with an Oregon electric cooperative recorded in this year's third quarter; this amount was deferred, in accordance with an accounting order from the OPUC, and offset within Depreciation and amortization expense. Increased expenses were also incurred this year for the overhaul of the Boardman coal plant's turbine generators and for administrative expenses, including Enron overhead costs.

Depreciation and amortization expense increased $3 million (8%) due primarily to normal capital additions.

Taxes other than income taxes increased $3 million (19%) due to increased state property taxes, caused largely by higher assessed values, and higher payroll taxes. Taxes on operating income increased $12 million due primarily to an approximate 63% increase in taxable income in the third quarter.

Other Income decreased $4 million due primarily to the write-off of the Company's remaining investment in the Trojan plant as part of a settlement agreement. For further information, see "Trojan Investment Recovery" in the Financial and Operating Outlook section.

Interest charges increased $2 million (13%), 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. For further information, see "Cash Flow - Financing Activities".

2000 Compared to 1999 for the Nine Months Ended September 30

PGE earned $96 million during the nine months ended September 30, 2000, compared to earnings of $95 million in 1999. Increased operating revenues were largely offset by increased power costs and other operating expenses during the period.

Total operating revenues increased $554 million (55%) compared to the first nine months of 1999, largely due to a significant increase in wholesale energy prices and sales. Wholesale revenues increased $509 million (from $253 million to $762 million), as PGE sold on the wholesale market excess power purchased; wholesale sales increased 60% at average prices that increased 89%. Retail revenues increased $43 million as large paper, chemical, high tech, and metals manufacturers increased their energy use; prices averaged 5% higher than last year due to higher prices for customers whose power prices are indexed to the market cost of power. Overall retail energy sales increased 2.6% as increased sales to industrial and commercial customers were partially offset by decreased residential sales caused by warmer weather during the first half of the year. Total retail customers increased by about 7,800 (1%) from September 30 of last year; such increase includes the offsetting effect of the loss of approximately 7,400 customers who were transferred to two public utility districts upon the sale of a portion of PGE's service territory (for further information see "Asset Sales" in the Financial and Operating Outlook section). Other operating revenues increased $2 million (14%) due largely to increased sales of natural gas in excess of generation requirements.

Megawatt-Hours Sold (thousands)

	2000	1999
Retail	14,543	14,178
Wholesale	14,893	9,312

Purchased power and fuel costs increased $506 million (108%) due to significantly higher power prices combined with higher wholesale load. Higher regional power and gas market prices increased the average cost of firm power purchases by 46%; combined with a 31% increase in power purchases, increased combustion turbine generation, and reduced hydro production, PGE's average variable power cost increased almost 71%. Partially offsetting the cost of purchased power and fuel was an approximate $17 million unrealized net gain on electricity trading contracts and natural gas swaps recorded during the first nine months of this year (see Note 3, Price Risk Management, in the Notes to Financial Statements for further information).

Company generation increased 11%, with an almost two-fold increase in combustion turbine plant generation partially offset by reduced coal-fired and hydro production. Total generation decreased from 30% to 26% of PGE's total system requirement during the first nine months of the year.

Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)

	2000	1999	2000	1999
Generation	8,023	7,252	13.8	9.0
Firm Purchases	20,112	14,009	32.9	22.6
Spot Purchases	2,357	3,188	84.3	18.4
Total Send-Out	30,492	24,449	32.6*	19.1*

(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation, and taxes) increased $26 million (15%). Expenses in last year's first nine months 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 and by the non-recurring capitalization of $2 million in Year 2000 remediation expenses. In 2000, the Company recorded a $2.4 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 in its recently filed restructuring plan, the Company seeks rate recovery of certain costs associated with this proposed sale.). Other increases include $3.2 million in insurance claim provisions and employee health insurance costs, higher administrative expenses, including Enron overhead costs, and a $2 million contract termination settlement with an Oregon electric cooperative was recorded in this year's third quarter; this amount was deferred, in accordance with an accounting order from the OPUC, and offset within Depreciation and amortization expense.

Taxes other than income taxes increased $5 million (11%) due to increased payroll taxes and property taxes, caused primarily by higher assessed values. Taxes on operating income increased $8 million (13%) primarily because of an increase in taxable income for the first nine months of the year.

Interest charges increased $3 million (6%), 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. For further information, see "Cash Flow - Financing Activities".

Cash Flow

Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE. Supplemental cash is obtained from external borrowings, as needed.

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

Cash provided by operating activities totaled $201 million in this year's first nine months, the same as last year. Large increases in both accounts receivable and accounts payable are largely due to increased wholesale activity. Included in "Other non-cash income and expenses" is a reduction in customer refunds related to Oregon excise taxes and to customer savings under certain energy efficiency programs, as directed by the OPUC. Increases in "Other working capital items" and in "Other - net" are primarily due to the effect of reduced coal and material purchases this year, and to the effect of reduced major maintenance expenditures at the Coyote Springs combustion turbine generating plant.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. Energy efficiency program expenditures, included in "Other - net", total approximately $5 million during the first nine months of the year; beginning October 1, 2000, such expenditures will be expensed as incurred (for further information, see "Energy Efficiency" in the Financial and Operating Outlook section). Capital expenditures of $109 million through September 30, 2000 were primarily for the expansion and improvement of PGE's distribution system and to support both new and existing customers within PGE's service territory. In 1999, expenditures of $133 million included the approximate $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 of its Coyote Springs combustion turbine generating plant (for further information, see "Asset Sales" in the Financial and Operating Outlook section).

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. During the first nine months of 2000, the Company issued $150 million of 7.875% unsecured notes maturing in 2010 and, with other funds, reduced its short-term commercial paper by $174 million. In addition, the Company repaid $25 million in matured First Mortgage Bonds; issuance expenses on the newly-issued notes and payment of conservation bonds, totaling $7 million, are also reflected in "Repayment of long-term debt". The Company paid $60 million in common stock dividends to its parent and $2 million in preferred stock dividends during the first nine months of 2000. On July 27, 2000, PGE completed a $250 million committed credit facility with a group of commercial banks (see Note 4, Credit Facilities and Debt, in the Notes to Financial Statements for further information).

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 September 30, 2000, PGE has the capability to issue preferred stock and additional First Mortgage Bonds in amounts sufficient to meet its capital requirements.

Financial and Operating Outlook

Proposed Acquisition

On November 8, 1999, Enron announced that it had entered into a purchase and sale agreement to sell PGE to Sierra Pacific Resources (Sierra) for $2.1 billion, comprised of $2.02 billion in cash and the assumption of Enron's approximately $80 million merger payment obligation. Sierra will also assume approximately $1 billion in PGE debt and preferred stock. The proposed transaction, which is subject to regulatory approval, is now expected to close in early 2001. On January 18, 2000, Sierra filed with the OPUC an application to acquire PGE. On February 3, 2000, Sierra filed with the SEC an application to acquire PGE and also to become a registered public utility holding company; a decision is expected in the first quarter of 2001. On March 3, 2000, Sierra filed with the FERC and the U.S. Department of Justice a request for approval of its acquisition of PGE; the Department of Justice investigation has concluded with no action taken.

On July 26, 2000, the FERC directed Sierra to provide additional information, including further data and analysis on the effect of the proposed acquisition on competition in the western United States; a decision is expected in the fourth quarter of this year. On July 27, 2000, the Nuclear Regulatory Commission (NRC) approved the proposed acquisition, concluding that it will not impede PGE's decommissioning work at the Trojan Nuclear Plant. 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 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 FERC approves changes caused by implementation of a Regional Transmission Organization. In addition, the settlement agreement includes a $95 million customer rate credit 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.

Restructuring

On July 23, 1999, Oregon's governor signed into law State Senate Bill SB1149 that provides all industrial and commercial customers of investor-owned utilities in the state direct access to competing energy suppliers no later than October 1, 2001. Residential customers will be able to purchase electricity from a "portfolio" of rate options that will include a cost-of-service rate, a new renewable resource rate, and a market-based rate. 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.

In October 1999, the OPUC began a series of workshops designed to discuss the issues associated with SB1149 and to develop administrative rules for implementation of the law. In February 2000, the OPUC began its formal rulemaking process, with PGE and other parties participating. On September 28, 2000, the Commission 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. Development of additional rules regarding non-tariff-related items, including code of conduct issues, is continuing and is expected to be completed by year-end.

PGE filed its restructuring plan, including associated tariffs, 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 largely offset by benefits from the Bonneville Power Administration. Business customers will have the option to purchase power on the open market. As provided in SB1149, an additional three percent "public purpose" surcharge will be assessed customers to fund the state's energy efficiency, renewable resource and low-income weatherization programs. 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 September 30, 2000, such costs total approximately $2.4 million.

Power Cost Rate Increase

On August 16, 2000, PGE filed with the OPUC a request to increase authorized rates by an average of approximately 13.5% to recover the increased costs of purchased power and fuel. The adjustment is based upon the effect of 2001 power cost increases on the Company. It is proposed that the adjustment become effective beginning January 1, 2001, and extend until new general rates, as proposed in the SB1149 restructuring plan, become effective on or about October 1, 2001. Settlement discussions have been held with the OPUC and other interested parties, but no agreement has yet been reached. The Company is continuing to explore its available options to obtain rate relief by the beginning of 2001.

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales grew by 3.4% for the nine months ended September 30, 2000, compared to the same period last year. Manufacturing sector energy sales increased 9.3% as large paper, chemical, high tech, and metals manufacturers significantly increased their energy use. Commercial sales growth remains strong at 3.2% over last year. Sales to residential customers, however, decreased 0.6% in the first nine months of the year. PGE forecasts retail energy sales growth of approximately 3% in 2000. (The accompanying graph excludes the effect of the transfer of approximately 6,375 residential and 1,025 commercial/industrial customers to two public utility districts in the third quarter of 2000, pursuant to the sale of a portion of PGE's service territory).

Retail Competition

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

An initiative petition was filed in February 2000 by a local political committee, which is attempting to amend the charter of the City of Portland to require the city's acquisition of privately owned electricity distribution systems and facilities within its boundaries under certain circumstances on or before December 31, 2002. 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, the Court ruled against PGE in this matter. The Company plans to appeal this decision.

Resource Plan

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

On November 1, 2000, PGE filed with the OPUC its Resource Plan. Under the plan, PGE proposes to retain almost all of its resources, selling only its 20 percent 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 April 1, 2001.

Residential Exchange Program

The September 1998 Residential Exchange Termination Agreement with the Bonneville Power Administration provided for a total of $34.5 million in BPA payments to PGE over two years, with benefits to PGE's residential and small farm customers to continue through the June 2001 termination of the Agreement. At September 30, 2000, PGE has received the entire amount provided for under the Agreement, with benefits continuing to PGE's customers in the form of price adjustments contained in OPUC-approved tariffs.

On October 31, 2000, PGE and BPA signed a Settlement Agreement that provides for BPA payments totaling approximately $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 such benefits continuing to pass directly to residential and small farm customers. The total amount of such 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.

Power Supply

Hydro conditions in the region are below normal this year. The January-to-July runoff was 92% of normal, compared to 116% of normal last year. A number of salmon species in the Pacific Northwest have been granted or are being evaluated for protection under the federal Endangered Species Act (ESA). Although the impacts to date have been minimal for PGE because current hydro conditions are favorable, efforts to restore salmon will continue to reduce the amount of water available for generation.

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, a reduction in surplus generation, and fish protection flow limits affecting hydro generation, are expected to increase both price and demand pressure on available resources.

Asset Sales

Pursuant to the voter-approved sale of PGE service territory in four Columbia County cities to the Columbia River People's Utility District (CRPUD) and the Clatskanie Public Utility District (CPUD), the parties entered into Service Territory Transfer and Asset Purchase agreements. Following public hearings, the OPUC issued an order on August 2, 2000, approving the proposed agreements; the transfer of service territory and approximately 7,400 PGE customers took place on August 15, 2000.

On April 12, 2000, the Confederated Tribes of Warm Springs (Tribes) and PGE executed an agreement that would result in shared ownership and control of PGE's 408-MW Pelton Round Butte hydroelectric project, which provides about 20% of the Company's power-generating capacity. The agreement with the Tribes, under which PGE would continue to operate the project, provides for increased ownership by the Tribes over a proposed 50-year license period, which PGE and the Tribes will now jointly pursue with the FERC. The proposed sale was approved by the OPUC on August 23, 2000.

On April 13, 2000, PGE received final approval from the FERC to sell 12% of its interest (representing a 10.5% tenancy-in-common share) in the Kelso-Beaver Pipeline to B-R Pipeline for approximately $2.5 million. The proposed sale was previously approved by the OPUC and had received preliminary approval, subject to environmental review, by the FERC. 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.

On July 21, 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 $14.2 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 $10.6 million, has been deferred for future refund to ratepayers.

Trojan Investment Recovery

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

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

With CUB's withdrawal, the URP is the one remaining significant adverse party in the litigation. The URP has indicated it plans to continue to challenge the March 1995 OPUC order allowing PGE recovery of its investment in Trojan. The Oregon Supreme Court had indicated it will hold its review of the Court of Appeals decision in abeyance until after the election referenced above. PGE has requested the Oregon Supreme Court to continue to hold its review in abeyance pending resolution of the URP's October 30, 2000 complaint described above, and plans after that matter is resolved to request the Oregon Supreme Court to determine that the entire matter is now moot.

The settlement agreements and OPUC order provided for removal from PGE's balance sheet of the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consist of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining obligation under terms of the Enron/PGC merger. After offsetting the investment in Trojan with these credits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed in the third quarter of 2000.

Collection of ongoing decommissioning costs at Trojan is not affected by the settlement agreements or the September 29, 2000, OPUC order.

Environmental Matter

A 1997 investigation of a portion of the Willamette River known as the Portland Harbor conducted by a U.S. Environmental Protection Agency (EPA) contractor revealed significant contamination of sediments within the harbor. In September 1999, 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. Based on analytical results from the 1997 study, the EPA is planning to include Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act. While PGE does not believe that it is responsible for any contamination in Portland Harbor, on May 30, 2000, PGE entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" with the DEQ, in which the Company agreed to voluntarily complete a remedial investigation at the Harborton site under terms of the Agreement and Scope of Work. In conjunction with such agreement, PGE has also submitted a pre-remedial investigation work plan for DEQ review and approval. It appears EPA or DEQ may share direct jurisdiction over the Harborton site. Investigations of the site by PGE will occur, with subsequent investigations expected if significant soil or groundwater contamination with a pathway to the river sediments is discovered. Remedial activities, if any, that PGE may ultimately perform with respect to this matter will depend on the results of its investigations.

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

Energy Efficiency

On April 25, 2000, the OPUC approved PGE's application to expense all current Demand Side Management (DSM) program expenditures beginning October 1, 2000. This change in accounting will be accompanied by a 1.18% increase in rates. PGE's unamortized DSM investment prior to implementation of the change will continue to be collected in rates and amortized to expense over a five-year period. The approved change in accounting is in response to SB1149, which encourages a competitive marketplace for energy services and provides for a public service charge to fund conservation measures.

Financial Risk Management

PGE is exposed to market risk arising from the need to purchase power to meet the needs of its retail customers and to purchase fuel for its natural gas fired generating units. The Company uses instruments such as forward contracts, natural gas swaps, and options for the purpose of hedging the impact of market fluctuations on assets, liabilities, production, and other contractual commitments. 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 (see Note 3, Price Risk Management, in the Notes to Financial Statements for further information).

The use of derivative commodity instruments by PGE 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. During the first nine months of 2000, PGE's market risk profile has changed because of increased electricity and natural gas trading activities. However, due to continuing low trading volume limits, 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 September 30, 2000.

RTO West and Proposed Independent Transmission Company

In December 1999, the FERC issued Order No. 2000 in a continued effort to more efficiently manage transmission, create fair pricing policies, and encourage competition by providing equal access to the nation's electric power grids. The order encourages all owners of electricity transmission facilities to join Regional Transmission Organizations (RTOs), to be created and 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 and manage pricing in the Pacific Northwest, Nevada, and parts of neighboring states.

In addition, PGE and five other regional utilities have filed a proposal with the FERC to form an independent transmission company (ITC), to be called TransConnect. The new company would be a member of RTO West and would own or lease the six companies' high voltage transmission systems. TransConnect would be formed to 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.

Other proposed members of TransConnect consist of Avista Corp., Puget Sound Energy, Montana Power, Sierra Pacific Power, and Nevada Power. The proposal, filed on October 15, 2000, is also subject to approval by state regulators and the board of directors of each filing company. It is currently anticipated that RTO West and TransConnect will begin operations no earlier than December 2001.

New Accounting Standard

In June 1998, the Financial Accounting Standards Board 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). PGE does not plan to adopt SFAS No. 133 before January 1, 2001. In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133. As important interpretations regarding implementation continue to be made, PGE has not yet completed the quantification of the impacts of adopting SFAS No. 133 on its financial statements. However, it could increase volatility in earnings and other comprehensive income.

Information Regarding Forward Looking Statements

This Quarterly Report on Form 10-Q includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although PGE believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include, but are not limited to, 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.

Part II

Portland General Electric Company and Subsidiaries

Other Information

Item 1. Legal Proceedings

For further information, see PGE's report on Form 10-K for the year ended December 31, 1999.

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

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

In the November 7, 2000 election, the voters of Oregon voted to reject House Bill 3220, which authorized the OPUC to allow recovery of a return on undepreciated property retired from service.

The Oregon Supreme Court has indicated it will hold in abeyance its review of the June 24, 1998, Court of Appeals decision until after the election referenced above. PGE has requested the Oregon Supreme Court to continue to hold its review in abeyance pending resolution of the URP's complaint described above, and plans after that matter is resolved to request the Oregon Supreme Court to determine that the entire matter is now moot.

For further information, see Note 2, Legal Matters, in the Notes to Financial Statements.

Columbia River People's Utility District v Portland General Electric Company

On April 21, 1999, CRPUD filed a Notice of Appeal. On May 3, 2000, the Ninth Circuit Court of Appeals heard oral arguments on the PUD's appeal challenging the assertion it must pursue its anti-trust claims against PGE at the state level. On July 18, 2000, the Ninth Circuit Court affirmed the March 24, 1999, decision of the Federal District Court's Summary Judgment in favor of PGE.

Portland General Electric Company and Subsidiaries

Other Information

Item 6. Exhibits and Reports on Form 8-K

a. Exhibits

Number Exhibit

27 Financial Data Schedule - UT

(Electronic Filing Only)

b. Reports on Form 8-K

August 23, 2000 - Item 5. Other Events: Legal Matters - Trojan Settlement Agreements

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

November 10, 2000	By:	/s/ James J. Piro
		James J. Piro Vice President Chief Financial Officer and Treasurer

November 10, 2000	By:	/s/ Kirk M. Stevens
		Kirk M. Stevens Controller and Assistant Treasurer