PORTLAND GENERAL ELECTRIC CO /OR/, 10-Q, 2000-08-10

PORTLAND GENERAL ELECTRIC CO /OR/
10-Q, 2000-08-10
ELECTRIC SERVICES

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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 June 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 July 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				2

Part I. Financial Information
	Item 1. Financial Statements

		Consolidated Income Statement		3
		Consolidated Statement of Retained Earnings		3
		Consolidated Balance Sheet		4
		Consolidated Statement of Cash Flows		5
		Notes to Consolidated Financial Statements		6

	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			9

Part II. Other Information

	Item 1. Legal Proceedings			22
	Item 6. Exhibits and Reports on Form 8-K			22
	Signature Page			23

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 June 30,													Six Months Ended June 30,
			2000							1999						2000				1999
		(Millions of Dollars)

Operating Revenues		$	430	$				294			$				827			$			593

Operating Expenses
	Purchased power and fuel		251						122						453						225
	Production and distribution		33						31						59						61
	Administrative and other		34						29						69						51
	Depreciation and amortization		38						40						77						79
	Taxes other than income taxes		15						14						33						31
	Income taxes		18						18						44						48
			389						254						735						495

Net Operating Income			41						40						92						98

Other Income (Deductions)
	Miscellaneous		3						2						7						6
	Income taxes		-						-						1						2
			3						2						8						8

Interest Charges
	Interest on long-term debt and other		16						14						31						31
	Interest on short-term borrowings		3						2						5						4
			19						16						36						35

Net Income			25						26						64						71

Preferred Dividend Requirement			-						1						1						2

Income Available for Common Stock		$	25		$				25			$			63			$			69

Consolidated Statement of Retained Earnings (Unaudited)

		Three Months Ended June 30,												Six Months Ended June 30,
			2000			1999							2000						1999
		(Millions of Dollars)

Balance at Beginning of Period		$	419		$		380				$			401			$			356
Net Income			25				26							64							71
			444				406							465							427

Dividends Declared
	Common stock		20				20							40							40
	Preferred stock		-				1							1							2
			20				21							41							42
Balance at End of Period		$	424		$		385				$			424				$			385

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

Portland General Electric Company and Subsidiaries Consolidated Balance Sheet (Unaudited)

				June 30,		December 31,
				2000		1999
				(Millions of Dollars)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes Construction work in progress of
	$67 and $44)		$	3,357	$	3,295
	Accumulated depreciation			(1,486)		(1,430)
				1,871		1,865

Other Property and Investments
	Contract termination receivable			71		85
	Receivable from parent			84		89
	Nuclear decommissioning trust, at market value			38		42
	Corporate owned life insurance			91		85
	Miscellaneous			17		17
				301		318
Current Assets
	Cash and cash equivalents			5		-
	Accounts and notes receivable			171		140
	Unbilled and accrued revenues			39		49
	Assets from price risk management activities			177		-
	Inventories, at average cost			34		37
	Prepayments and other			49		41
				475		267
Deferred Charges
	Unamortized regulatory assets			677		691
	Miscellaneous			22		26
				699		717
			$	3,346	$	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			424		401
	Cumulative preferred stock
		Subject to mandatory redemption		30		30
	Long-term obligations			846		701
				1,940		1,772
Current Liabilities
	Long-term debt due within one year			7		32
	Short-term borrowings			138		266
	Accounts payable and other accruals			176		167
	Liabilities from price risk management activities			161		-
	Accrued interest			14		11
	Dividends payable			1		1
	Accrued taxes			23		12
				520		489
Other
	Deferred income taxes			342		351
	Deferred investment tax credits			33		36
	Trojan decommissioning and transition costs			237		234
	Unamortized regulatory liabilities			181		197
	Miscellaneous			93		88
				886		906
			$	3,346	$	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)
				Six Months Ended
				June 30,
				2000		1999
				(Millions of Dollars)

Cash Flows From Operating Activities:
	Reconciliation of net income to net cash provided by
	operating activities
	Net income		$	64	$	71
	Non-cash items included in net income:
		Depreciation and amortization		77		79
		Deferred income taxes		(5)		(4)
		Net assets from price risk management activities		(16)		-
		Other		9		7
	Changes in working capital:
		(Increase) Decrease in receivables		(21)		32
		Increase (Decrease) in payables		23		(46)
		Other working capital items - net		(5)		(9)
	Other - net			10		(16)
Net Cash Provided by Operating Activities				136		114

Cash Flows From Investing Activities:
	Capital expenditures			(77)		(60)
	Other - net			(5)		(4)
Net Cash Used in Investing Activities				(82)		(64)

Cash Flows From Financing Activities:
	Repayment of long-term debt			(30)		(27)
	Net increase (decrease) in short-term borrowings			(128)		52
	Issuance of long-term debt			150		-
	Dividends paid			(41)		(41)
	Repayment of loans on corporate owned life insurance			-		(32)
	Other - net			-		(1)
Net Cash Used in Financing Activities				(49)		(49)

Increase in Cash and Cash Equivalents				5		1
Cash and Cash Equivalents, Beginning of Period				-		4
Cash and Cash Equivalents, End of Period			$	5	$	5

Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	31	$	29
		Income taxes		36		77

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 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 Utility Reform Project and the Citizens Utility Board, 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 the referendum will appear on the November 2000 ballot. The Oregon Supreme Court has stated it will hold its review of the Court of Appeals decision in abeyance until after the election.

At June 30, 2000, PGE's after-tax Trojan plant investment was $143 million. PGE is presently collecting annual revenues of approximately $18 million, representing a return on its undepreciated investment. Revenue amounts reflecting a recovery of a return on the Trojan investment decline through the recovery period, which ends in the year 2011.

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 half 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 half of 2000, a $16.1 million net gain on electricity trading contracts was recorded, including $11.2 million in the second quarter of the year. In addition, a $0.2 million net loss on natural gas swaps has been recorded, including a $0.1 million gain in the second 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.

Management's Discussion and Analysis of Financial

Condition and Results of Operations

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 June 30

PGE earned $25 million during the second quarter of 2000, $1 million lower than in the second quarter of 1999. Increased revenues were offset by increased power costs, other operating expenses, and interest charges.

Total operating revenues increased $136 million (46%) compared to the second quarter of 1999, largely due to a significant increase in wholesale energy sales and prices. Wholesale revenues increased $121 million (from $62 million to $183 million), as PGE sold on the wholesale market excess power purchased; wholesale sales increased 61% at average prices that increased 83%. Retail revenues increased $14 million (6%) from last year's second quarter due primarily to higher prices for increased industrial energy sales. Industrial energy sales rose 12% 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 slightly as increased sales to commercial and industrial customers were largely offset by decreased residential sales caused by warmer weather during the quarter. Total retail customers increased by about 15,000 (2%) from June 30 of last year.

Megawatt-Hours Sold (thousands)

	2000	1999
Retail	4,484	4,447
Wholesale	4,909	3,053

Purchased power and fuel costs increased $129 million (106%) from last year's second quarter, primarily due to significantly higher power prices and wholesale load. Higher regional power and gas market prices increased the average cost of firm power purchases by 49%; combined with a 39% increase in power purchases, increased combustion turbine generation, and reduced hydro production, PGE's average variable power cost increased almost 74%. Partially offsetting the cost of purchased power and fuel was an approximate $11 million unrealized net gain on electricity trading contracts and natural gas swaps recorded in this year's second quarter (see Note 3, Price Risk Management, in the Notes to Financial Statements for further information).

Total generation decreased 11% with decreased coal and hydro production partially offset by increased production at the Company's combustion turbine generating plants. Generation at the Boardman coal plant decreased 33% from last year due to the plant's maintenance and turbine overhaul closure that extended from May 15 through June 30. Decreased coal-fired generation at both Colstrip and Centralia (sold in late-1999) combined to reduce total Company generation from 28% to 20% of PGE's total system requirement during the second quarter.

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

	2000		1999	2000	1999
Generation	1,967		2,201	14.5	8.7
Firm Purchases	7,175		4,776	25.0	16.8
Spot Purchases	628		836	74.6	18.5
Total Send-Out	9,770		7,813	26.9*	15.5*

(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation, and taxes) increased $7 million (12%). Expenses in last year's second quarter were reduced by the effect of the non-recurring capitalization of approximately $4 million in Year 2000 remediation expenses incurred in the first half of the year. In addition, increased expenses were incurred this year for the overhaul of the Boardman plant's turbine generators and for administrative expenses, including Enron overhead costs.

Depreciation and amortization expense decreased $2 million (5%) due to lower amortization of regulatory assets and increased gains on property sales.

Taxes other than income taxes increased $1 million primarily due to increased state property taxes, caused largely by higher assessed values.

Interest charges increased $3 million (19%) due primarily to the March 2000 issuance of $150 million of 7.875% unsecured notes.

2000 Compared to 1999 for the Six Months Ended June 30

PGE earned $64 million during the six months ended June 30, 2000, compared to earnings of $71 million in 1999. An increase in operating revenues was more than offset by increased power costs and other operating expenses during the period.

Total operating revenues increased $234 million (39%) compared to the first half of 1999, largely due to a significant increase in wholesale energy sales and prices. Wholesale revenues increased $209 million (from $87 million to $296 million), as PGE sold on the wholesale market excess power purchased; wholesale sales increased 109% at average prices that increased 63%. Retail revenues increased $22 million (4%) from last year due primarily to higher prices and increased industrial energy sales. Industrial energy sales rose 14% as large paper, chemical, high tech, and metals manufacturers increased their energy use; prices averaged 12% 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 2.7% as increased sales to commercial and industrial 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 15,000 (2%) from June 30 of last year. Other operating revenues increased $3 million (26%) due largely to increased sales of natural gas in excess of generation requirements.

Megawatt-Hours Sold (thousands)

	2000	1999
Retail	9,886	9,625
Wholesale	9,190	4,391

Purchased power and fuel costs increased $228 million (101%) 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 44%; combined with a 46% increase in power purchases, increased combustion turbine generation, and reduced hydro production, PGE's average variable power cost increased about 57%. Partially offsetting the cost of purchased power and fuel was an approximate $16 million unrealized net gain on electricity trading contracts and natural gas swaps recorded during the first half of this year (see Note 3, Price Risk Management, in the Notes to Financial Statements for further information).

Company generation increased 11%, with a significant increase in combustion turbine plant generation partially offset by decreases in both coal-fired and hydro generation. Total generation decreased from 32% to 26% of PGE's total system requirement during the first half of the year.

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

		2000	1999	2000	1999
Generation		5,089	4,604	13.1	8.4
Firm Purchases		13,367	7,981	24.2	16.8
Spot Purchases		1,292	2,033	49.4	16.4
Total Send-Out		19,748	14,618	23.8*	15.2*

(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation, and taxes) increased $16 million (14%). Expenses in last year's first half were reduced by the effect of a non-recurring reduction in employee benefit accruals resulting from negotiated changes to union pension and Retirement Savings Plan enhancements. In addition, the Company in this year's first half wrote off $2.4 million of deferred costs related to the proposed sale of its 20% interest in Units 3 and 4 of the Colstrip power plant, approval of which was denied by the OPUC. Other increases include a combined $2.8 million increase in insurance claim provisions and employee health insurance costs, the $1.2 million overhaul of the Boardman plant's turbine generators, and increased administrative expenses, including Enron overhead costs.

Taxes other than income taxes increased $2 million (6%) due to increased payroll taxes and property taxes, caused primarily by higher assessed values. Income taxes decreased $4 million (8%) primarily because of a decrease in taxable income for the first half of the year.

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 $136 million in this year's first half compared to $114 million in the same period last year. The increase is due primarily to reduced payments for power purchases and income taxes, partially offset by a reduction in payments received for wholesale power sales (reflected in changes in accounts payable and accounts receivable). Reflected within "Other-net" is the accounting effect of significantly reduced major maintenance expenditures at the Coyote Springs combustion turbine generating plant, and a reduction in refunds related to reduced Oregon excise taxes and customer savings under certain energy efficiency programs, as directed by the OPUC.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities, as well as continued energy efficiency program expenditures. Capital expenditures of $77 million through June 30, 2000, were primarily for the expansion and improvement of PGE's distribution system to support the addition of new 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. During the first half of 2000, the Company issued $150 million of 7.875% unsecured notes maturing in 2010 and reduced its short-term commercial paper by $128 million. Issuance expenses on the newly-issued notes and payment of conservation bonds are reflected in "Repayment of long-term debt". The Company paid $40 million in common stock dividends to its parent and $1 million in preferred stock dividends during the first half 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 June 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 expected to close in late 2000. 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. 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.

On July 26, 2000, the FERC directed Sierra to provide, within 30 days, additional information, including further data and analysis on the effect of the proposed acquisition on competition in the western United States. 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. PGE testimony has been filed with the OPUC and proceedings are continuing; a settlement conference is scheduled on August 9 and 10 and a hearing is scheduled on August 30.

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. Incentives for the divestiture of generation assets are authorized, 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 the expectation that rules enabling utilities to develop tariffs will be adopted in August 2000. PGE is participating in this rulemaking process. Additional rulemakings regarding non-tariff-related items are also expected. PGE expects to file its restructuring plan, including associated tariffs, in time to allow for direct access by October 1, 2001. 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 June 30, 2000, such costs total approximately $0.2 million.

Power Cost Rate Adjustment

In August 2000, PGE plans to file with the OPUC a request to increase authorized rates to recover the increased costs of purchased power and fuel. The amount of such adjustment would be based upon the effect of power cost increases on the Company. It is proposed that such adjustment become effective beginning January 1, 2001, and extend until new general rates become effective on or about October 1, 2001.

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales grew by 3.8% for the six months ended June 30, 2000, compared to the same period last year. Manufacturing sector energy sales increased 11.2% as large paper, chemical, high tech, and metals manufacturers significantly increased their energy usage. Commercial sales growth remains strong at 3.6% over last year. Sales to residential customers, however, decreased 0.7% in the first half of the year. PGE forecasts retail energy sales growth of approximately 3% in 2000.

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, along with a continuation of benefits to PGE's residential and small farm customers through at least the June 2001 termination of the agreement. Through June 30, 2000, PGE has received approximately $33.7 million in payments, with the remaining $0.8 million to be received by September 2000. Such exchange benefits continue to be passed directly to PGE's customers in the form of price adjustments contained in OPUC-approved tariffs.

Power Supply

Hydro conditions in the region are below normal this year, with current projections forecasting the January-to-July runoff at 92% of normal, compared to 116% of normal last year. A significant 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 and current hydro conditions are favorable, efforts to restore salmon may continue to reduce the amount of water available for generation. PGE's base of hydro and thermal generating capacity and the electric generating capability in the Western U.S. provide PGE the flexibility needed to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers.

Asset Sales

Pursuant to the voter-approved annexation 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 have entered into definitive agreements, which are subject to approval by the OPUC. On February 24, 2000, PGE filed for Commission approval two proposed Service Territory Transfer Agreements, and on April 10, 2000, the Company filed a proposed Asset Purchase Agreement. Issues related to the proposed transfer and sale were addressed pursuant to an OPUC-established schedule, which included a public hearing in June 2000. In an order issued in early August 2000, the OPUC approved the proposed agreements.

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 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 will also require approval of the OPUC.

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. Upon completion of the sale, PGE will own 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 its 50% 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 LLP and operated by PGE under a 15-year operations and maintenance contract. The net gain on the sale, approximately $10.6 million, is anticipated to be 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 the undepreciated balance of its 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 a petition for review with the Oregon Supreme Court, supported by amicus briefs filed by three other major utilities seeking review of that portion of the Oregon Court of Appeals decision relating to PGE's return on its undepreciated investment in Trojan.

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

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. 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 agrees 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 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 investigation 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 half 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 value at risk, which measures the potential impact of market movements over a given time interval. Value at risk remains at an immaterial level at June 30, 2000.

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, PGE and five other regional utilities have signed an agreement to study the formation of a for-profit Independent Transmission Company (ITC) that would manage the transmission assets of the participating companies. The proposed ITC could own, lease or maintain high-voltage transmission lines, increasing efficiency and reliability. It would join other transmission owners as members of RTO West, a non-profit Independent System Operator (ISO), which would control transmission operations and pricing in an eight-state western region.

A Regional Representative Group (RRG), comprised of industry, governmental agencies, consumer and environmental representatives, the region 's major jurisdictional utilities and BPA, has been formed to address issues and recommend approaches to the successful formation of an RTO. Participating utilities are required to file their proposal with the FERC by October 15, 2000.

As the Pacific Northwest faces potential transmission congestion in the future, a large ITC could more quickly implement decisions to add new facilities. PGE believes the development of an ITC would bring benefits to both the Company and its customers as cost and service efficiencies are created through larger scale operations.

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". SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) 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 either the income statement or the Statement of Shareholders' Equity and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

In June 1999, the FASB issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. A company may implement SFAS No. 133 as of the beginning of any fiscal quarter after issuance; however, the statement cannot be applied retroactively. PGE does not plan to effect the early adoption of SFAS No. 133, as important interpretations regarding implementation continue to be made. In June 2000, the FASB - issued SFAS No. 138, which amended certain guidance within SFAS No. 133. PGE believes that SFAS No. 133 (as amended) will not have a material impact on its accounting for price risk management activities but has not yet quantified the effect on its hedging activities or physical based contracts.

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.

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.

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

None.

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)

August 9, 2000	By:	/s/ Mary K. Turina
		Mary K. Turina Vice President, Finance Chief Financial Officer and Treasurer

August 9, 2000	By:	/s/ Kirk M. Stevens
		Kirk M. Stevens Controller and Assistant Treasurer