Edgar Filing: PORTLAND GENERAL ELECTRIC CO /OR/

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

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

incorporation or organization)

(I.R.S. Employer

Identification No.)

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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. x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


		Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨		Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Number of shares of common stock outstanding as of October 24, 2008 is 62,557,928 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

TABLE OF CONTENTS


Definitions		3

	PART I – FINANCIAL INFORMATION	4

Item 1.	Financial Statements.	4

	Condensed Consolidated Statements of Income	4

	Condensed Consolidated Balance Sheets	5

	Condensed Consolidated Statements of Cash Flows	6

	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	51

Item 4.	Controls and Procedures.	52

	PART II – OTHER INFORMATION	53

Item 1.	Legal Proceedings.	53

Item 1A.	Risk Factors.	54

Item 6.	Exhibits.	55

SIGNATURE		56

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:


Abbreviation or Acronym		Definition
AFDC		Allowance for funds used during construction
Beaver		Beaver generating plant
Biglow Canyon		Biglow Canyon Wind Farm
Boardman		Boardman coal plant
BPA		Bonneville Power Administration
CERS		California Energy Resources Scheduling
Colstrip		Colstrip Units 3 and 4 coal plant
CUB		Citizens’ Utility Board
DEQ		Oregon Department of Environmental Quality
EITF		Emerging Issues Task Force of the Financial Accounting Standards Board
EPA		U.S. Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
Financial Statements		Condensed Consolidated Financial Statements of Portland General Electric Company included in Part I, Item 1 of this report
IRP		Integrated Resource Plan
ISFSI		Independent Spent Fuel Storage Installation
MW		Megawatt
MWa		Average megawatts
MWh		Megawatt hour
NVPC		Net Variable Power Costs
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
Port Westward		Port Westward generating plant
SB 408		Oregon Senate Bill 408
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards (issued by the Financial Accounting Standards Board)
Trojan		Trojan Nuclear Plant
URP		Utility Reform Project

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

(Unaudited)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Revenues, net	$	400		$	435	$	1,296		$	1,273

Operating expenses:
Purchased power and fuel		217			242		652			620
Production and distribution		40			36		125			109
Administrative and other		48			46		142			136
Depreciation and amortization		54			46		154			134
Taxes other than income taxes		20			20		63			60

Total operating expenses		379			390		1,136			1,059

Income from operations		21			45		160			214

Other income (expense):
Allowance for equity funds used during construction		3			4		7			13
Miscellaneous income (expense), net		(4	)		2		(6	)		10

Other income (expense), net		(1	)		6		1			23
Interest expense		21			19		67			54

Income (loss) before income tax expense (benefit)		(1	)		32		94			183
Income tax expense (benefit)		(1	)		12		27			62

Net income	$	-		$	20	$	67		$	121


Weighted-average shares outstanding (in thousands):
Basic		62,554			62,516		62,539			62,509

Diluted		62,607			62,542		62,589			62,534

Earnings per share - basic and diluted	$	-		$	0.32	$	1.08		$	1.93


Dividends declared per share	$	0.245		$	0.235	$	0.725		$	0.695

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

(Unaudited)


	September 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	5		$	73
Accounts and notes receivable, net		142			178
Margin deposits		145			28
Assets from price risk management activities		70			64
Inventories, at average cost		69			64
Deferred income taxes		68			12
Unbilled revenues		62			92
Other current assets		66			27

Total current assets		627			538
Electric utility plant, net		3,236			3,066
Non-qualified benefit plan trust		56			69
Nuclear decommissioning trust		45			46
Regulatory assets		427			304
Other noncurrent assets		84			85

Total assets	$	4,475		$	4,108


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	194		$	227
Liabilities from price risk management activities		246			101
Current portion of long-term debt		142			-
Accrued taxes		54			23
Short-term borrowings		38			-
Other current liabilities		47			40

Total current liabilities		721			391
Long-term debt, net of current portion		1,164			1,313
Regulatory liabilities		666			574
Deferred income taxes		342			279
Non-qualified benefit plan liabilities		89			86
Accumulated asset retirement obligations		80			91
Other noncurrent liabilities		59			58

Total liabilities		3,121			2,792
Commitments and contingencies (see notes)
Shareholders’ equity:
Common stock, no par value, 80,000,000 shares authorized; 62,557,928 and 62,529,787 shares issued and outstanding as of September 30, 2008 and December 31, 2007, respectively		662			646
Accumulated other comprehensive loss		(4	)		(4	)
Retained earnings		696			674

Total shareholders’ equity		1,354			1,316

Total liabilities and shareholders’ equity	$	4,475		$	4,108

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Nine Months Ended September 30,
	2008			2007
Cash flows from operating activities:
Net income	$	67		$	121
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		154			134
Net assets from price risk management activities		139			(16	)
Regulatory deferral - price risk management activities		(139	)		16
Trojan refund liability		33			-
Deferred income taxes		9			20
Non-qualified benefit plan trust (gain) loss		9			(6	)
Senate Bill 408 deferrals		2			(9	)
Allowance for equity funds used during construction		(7	)		(13	)
Power cost deferrals		2			(10	)
Other non-cash income and expenses, net		19			1
Changes in working capital:
Net margin deposit activity		(120	)		7
Decrease in receivables		66			29
Increase (decrease) in payables		(10	)		41
Other working capital items, net		7			(15	)
Other, net		(9	)		(9	)

Net cash provided by operating activities		222			291

Cash flows from investing activities:
Capital expenditures		(281	)		(351	)
Sales of nuclear decommissioning trust securities		23			17
Purchases of nuclear decommissioning trust securities		(20	)		(19	)
Insurance proceeds received		3			-
Other, net		(2	)		2

Net cash used in investing activities		(277	)		(351	)

Cash flows from financing activities:
Payments on long-term debt		(56	)		(71	)
Proceeds from issuance of long-term debt		50			306
Short-term borrowings (payments), net		38			(81	)
Dividends paid		(45	)		(43	)
Debt issuance costs		-			(3	)

Net cash provided by (used in) financing activities		(13	)		108

Increase (decrease) in cash and cash equivalents		(68	)		48
Cash and cash equivalents, beginning of period		73			12

Cash and cash equivalents, end of period	$	5		$	60

Supplemental cash flow information is as follows:
Cash paid during the period for:
Interest, net of amounts capitalized	$	49		$	37
Income taxes		8			30
Non-cash investing and financing activities:
Accrued capital additions		19			33
Accrued dividends payable		15			15
Former parent’s capital contribution of Oregon tax credits		13			-

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power and fuel marketers located throughout the western United States. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. The Company served approximately 814,000 retail customers as of September 30, 2008.

As of September 30, 2008, PGE had 2,726 employees, with 884 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (the Union). Such agreements cover 851 and 33 employees for the five-year periods ending February 28, 2009 and August 1, 2011, respectively. The Company is currently in negotiations with the Union to develop a new agreement to replace the agreement that expires February 28, 2009.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein for the three and nine month periods ended September 30, 2008 and 2007 is unaudited. Such information, however, reflects all adjustments, consisting of normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated results of operations and condensed consolidated cash flows of the Company for these interim periods. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, interim financial results do not necessarily represent those to be expected for the year. The financial information as of December 31, 2007 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2007, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 27, 2008, and should be read in conjunction with such consolidated financial statements.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of contingent liabilities, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

Reclassifications

Certain reclassifications have been made to the 2007 financial information to conform to the 2008 presentation. These reclassifications include (1) the presentation of income tax expense as one caption in the condensed consolidated statements of income for the three and nine month periods ended September 30, 2007, which was previously reported as a separate line within operating expenses and other income (deductions), and (2) the inclusion of long-term debt of $1,313 million in total liabilities in the condensed consolidated balance sheet as of December 31, 2007, which was previously reported in total capitalization. For the three months ended September 30, 2007, income tax expense of $10 million and $2 million was previously reported in operating expenses and other income (deductions), respectively. For the nine months ended September 30, 2007, income tax expense of $59 million and $3 million was previously reported in operating expenses and other income (deductions), respectively.

Recent Accounting Pronouncements

Adopted Accounting Pronouncements

On January 1, 2008, PGE adopted Statement of Financial Accounting Standards No. (SFAS) 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. In February 2008, Financial Accounting Standards Board (FASB) Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2) was issued. FSP 157-2 delays the adoption of SFAS 157 for nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, or January 1, 2009 for PGE. SFAS 157 does not modify any currently existing accounting pronouncements. PGE applies fair value measurements to certain assets and liabilities, including assets and liabilities from price risk management activities. The adoption of SFAS 157 did not have a material impact on the Company’s consolidated financial position or consolidated results of operations. PGE is in the process of determining whether the adoption of FSP 157-2 will have a material impact on its financial statements. For additional information, see Note 3.

On September 30, 2008, PGE adopted FASB Staff Position No. SFAS 157-3, Determining the Fair Value of a Financial Asset in a Market That Is Not Active (FSP 157-3), which clarifies the application of SFAS 157 in an inactive market and provides an illustrative example to demonstrate how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP 157-3 was issued on October 10, 2008 and is effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of FSP 157-3 had no impact on the Company’s financial statements.

On January 1, 2008, PGE adopted SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS 159), which allows eligible financial assets and liabilities to be measured at fair value that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item are reported in earnings at each reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the Company elects for similar types of assets and liabilities. The Company elected not to measure eligible financial assets and liabilities at fair value that were not otherwise measured at fair value. The adoption of SFAS 159 had no impact on PGE’s financial statements.

On January 1, 2008, PGE adopted FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (FSP FIN 39-1), which permits reporting entities to offset the receivable or payable recognized for

derivative instruments that have been offset under a master netting arrangement. FSP FIN 39-1 requires financial statement disclosure of a reporting entity’s accounting policy (to offset or not to offset), as well as amounts recognized for the right to reclaim cash collateral, or the obligation to return cash collateral, that have been offset against net derivative positions. PGE elects to continue to not offset its exposures under master netting arrangements in accordance with FSP FIN 39-1, and therefore elects not to offset any fair value amounts recognized for the right to claim cash collateral or the obligation to return cash collateral against its derivative positions. The adoption of FSP FIN 39-1 had no impact on PGE’s financial statements.

On January 1, 2008, PGE adopted Emerging Issues Task Force (EITF) Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11), which was ratified by the EITF on June 27, 2007. EITF 06-11 clarifies how an entity should recognize the income tax benefit received on dividends that are (1) paid to employees holding equity-classified nonvested shares and (2) charged to retained earnings under SFAS 123R, Share-Based Payment. EITF 06-11 is applied prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years. The adoption of EITF 06-11 had no impact on PGE’s financial statements.

New Accounting Pronouncements

SFAS 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51 (SFAS 160), was issued in December 2007 and amends Accounting Research Bulletin No. 51, Consolidated Financial Statements. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also (1) changes the way the consolidated income statement is presented, by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, (2) establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation, and (3) changes the way the consolidated income statement is presented. SFAS 160 shall be applied prospectively, with the exception of the presentation and disclosure requirements, and is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. Any noncontrolling interests resulting from the consolidation of a less than wholly-owned subsidiary beginning January 1, 2009 will be accounted for in accordance with SFAS 160. PGE estimates that the adoption of SFAS 160 will not have a material impact on its financial statements.

In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161), which requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for annual and interim periods beginning after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will have no impact on PGE’s financial statements.

In June 2008, FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), was issued and addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in SFAS 128, Earnings per Share. FSP EITF 03-6-1 is

effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period earnings per share data presented shall be adjusted retrospectively to conform to the provisions of this FASB Staff Position. Early application is not permitted. The adoption of FSP EITF 03-6-1 will not have a material impact on PGE’s financial statements.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts and Notes Receivable, Net

Accounts and notes receivable is net of an allowance for uncollectible accounts of $4 million and $5 million as of September 30, 2008 and December 31, 2007, respectively.

The following is the activity in the allowance for uncollectible accounts (in millions):


	Nine Months Ended September 30,
	2008			2007
Balance at beginning of period	$	5		$	45
Increase (decrease) in provision		5			(35	)
Amounts written off, less recoveries		(6	)		(5	)

Balance at end of period	$	4		$	5

Inventories

Inventories consist of fuel and materials and supplies, all of which are considered finished goods, for use in operations or for the maintenance of the Company’s generating plants and transmission and distribution facilities.

Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):


	September 30, 2008			December 31, 2007
Electric utility plant	$	5,004		$	4,898
Construction work in progress		270			126

Total cost		5,274			5,024
Less: accumulated depreciation and amortization		(2,038	)		(1,958	)

Electric utility plant, net	$	3,236		$	3,066

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $107 million and $96 million as of September 30, 2008 and December 31, 2007, respectively. Amortization expense related to intangible assets was $4 million for the three month periods ended September 30, 2008 and 2007, and $11 million for the nine month periods ended September 30, 2008 and 2007.

Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):


	September 30, 2008		December 31, 2007
Regulatory assets:
Price risk management	$	176	$	37
Income taxes recoverable		87		87
Pension and other postretirement plans		55		57
Boardman power cost deferral		33		31
Debt reacquisition costs		29		28
Oregon Senate Bill 408		16		16
Trojan decommissioning costs		12		16
Other		19		32

Total regulatory assets	$	427	$	304

Regulatory liabilities:
Accumulated asset retirement removal costs	$	486	$	451
Oregon Senate Bill 408		46		42
Trojan refund liability (see Note 7 - Contingencies)		33		-
Asset retirement obligations		27		28
Power Cost Adjustment Mechanism		18		16
Trojan ISFSI pollution control tax credits		16		13
Residential Exchange Program		14		-
Other		26		24

Total regulatory liabilities	$	666	$	574

Credit Facility and Debt

Credit Facility

PGE has a $400 million unsecured revolving credit facility (Credit Facility) with a group of eight banks. The Credit Facility is available to the Company for borrowings for general corporate purposes and the issuance of standby letters of credit, as well as for supporting the Company’s commercial paper program, under which it may issue commercial paper for terms of up to 270 days. The commercial paper program requires the Company to maintain unused revolving credit capacity at least equal to the amount of commercial paper issued. The Credit Facility allows PGE to borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the Credit Facility. The Credit Facility provides that all outstanding loans mature on the termination date of the Credit Facility, provided that annually such date may be extended for an additional year for those lenders who agree to an extension. On June 13, 2008, PGE received approval from seven of the eight banks in the Credit Facility to extend the termination date for an additional year. As a result, a total of $390 million was extended for an additional year to July 2013. The remaining $10 million continues to have a termination date of July 2012.

On September 15, 2008, Lehman Brothers Holdings, Inc., the parent company of Lehman Brothers Bank, FSB (Lehman), filed for protection under Chapter 11 of the U.S. Bankruptcy Code. At that time, Lehman represented $55 million, or approximately 14%, of the Credit Facility. In October 2008, $25 million of

Lehman’s $55 million share of the Credit Facility was reassigned to Sumitomo Mitsui Banking Corporation (Sumitomo). The Company is in discussions with another financial institution for reassignment of the remaining $30 million of Lehman’s share.

In October 2008, Wells Fargo & Company (Wells Fargo) announced the proposed acquisition of Wachovia Corporation (Wachovia). Wells Fargo and Wachovia each participate in the Credit Facility, with Wells Fargo representing $55 million, or 14%, and Wachovia representing $70 million, or 18%, of the Credit Facility. It is not expected that the proposed merger of Wells Fargo and Wachovia will have an impact on the Company’s ability to access funds available to it under the Credit Facility. The proposed merger is expected to close during the fourth quarter of 2008.

The Credit Facility requires annual fees based on PGE’s unsecured credit rating, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the Credit Facility agreement, to 65% of total capitalization. As of September 30, 2008, PGE was in compliance with this covenant.

As of September 30, 2008, PGE had $27 million of commercial paper outstanding and borrowings of $11 million under the Credit Facility, the total of which is classified as Short-term borrowings on the condensed consolidated balance sheet. The Company also had issued $37 million in letters of credit, with $270 million of remaining borrowing capacity available. As of October 24, 2008, PGE had $179 million borrowing capacity under its Credit Facility.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), PGE is authorized to issue short-term debt, including commercial paper, in an amount not to exceed $550 million outstanding at any one time, over the two-year period February 7, 2008 through February 6, 2010.

Long-term Debt

During 2008, PGE repurchased and retired $50 million of its 5.279% series First Mortgage Bonds due April 1, 2013 and issued $50 million of 4.45% series First Mortgage Bonds due April 1, 2013. Additionally, the Company repurchased $5.8 million of its Port of Morrow variable rate pollution control revenue bonds due December 1, 2031.

The current interest rate and interest period expire May 1, 2009 on $142 million of Pollution Control Revenue Bonds (Bonds), consisting of $23 million issued through the Port of Morrow, Oregon, and $119 million issued through the City of Forsyth, Montana. PGE is required under the terms of these Bonds to redeem the entire principal amount of the Bonds at a redemption price equal to 100% of the principal amount plus accrued interest on May 1, 2009. PGE has the option to have the Bonds remarketed beginning May 1, 2009 and can choose a new interest rate period that would be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of the remarketing. The Bonds are currently secured by a pledge of PGE First Mortgage Bonds. The Bonds could be remarketed as unsecured obligations of PGE or may be backed by PGE First Mortgage Bonds depending on market conditions. The Bonds are classified under the Current portion of long-term debt in the condensed consolidated balance sheet as of September 30, 2008.

Pension and Other Postretirement Benefits

The following table provides the components of net periodic benefit cost for the three months ended September 30 (in millions):


	Defined Benefit Pension Plan						Non-Qualified Benefit Plans				Other Benefits
	2008			2007			2008		2007		2008		2007
Service cost	$	3		$	3		$	-	$	-	$	-	$	-
Interest cost		8			7			-		-		1		1
Expected return on plan assets		(11	)		(11	)		-		-		-		-
Amortization of transition assets		-			-			-		1		-		-
Amortization of prior service cost		-			1			-		-		-		-
Amortization of net actuarial loss		-			1			1		-		-		-

Net periodic benefit cost	$	-		$	1		$	1	$	1	$	1	$	1

The following table provides the components of net periodic benefit cost (income) for the nine months ended September 30 (in millions):


	Defined Benefit Pension Plan						Non-Qualified Benefit Plans				Other Benefits
	2008			2007			2008		2007		2008			2007
Service cost	$	9		$	9		$	-	$	-	$	1		$	1
Interest cost		23			21			1		1		3			3
Expected return on plan assets		(33	)		(32	)		-		-		(1	)		-
Amortization of transition assets		-			-			-		1		-			-
Amortization of prior service cost		-			1			-		-		1			-
Amortization of net actuarial loss		-			3			1		-		-			-

Net periodic benefit cost (income)	$	(1	)	$	2		$	2	$	2	$	4		$	4

Management periodically reviews the reasonableness of the assumptions underlying the annual actuarial estimates.

NOTE 3: FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Company adopted SFAS 157, which requires, among other things, enhanced disclosures about assets and liabilities carried at fair value on a recurring basis. Pursuant to FSP 157-2, PGE will adopt SFAS 157 with respect to its nonfinancial assets and liabilities, which include asset retirement obligations, on January 1, 2009.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. However, as permitted under SFAS 157, PGE utilizes a mid-market pricing convention, the mid-point price between bid and ask prices, as a practical expedient for valuing the majority of its financial instruments.

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2-Pricing inputs are other than quoted market prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter (OTC) forwards and swaps.

Level 3-Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

The Company’s financial assets and liabilities whose fair values were accounted for on a recurring basis are as follows by level within the fair value hierarchy (in millions):


	As of September 30, 2008
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust *	$	45	$	-	$	-	$	45
Non-qualified benefit plan trust		34		1		-		35
Assets from price risk management activities *		-		39		31		70

	$	79	$	40	$	31	$	150

Liabilities - Liabilities from price risk management activities *	$	-	$	153	$	93	$	246

* Activities are subject to regulation and, accordingly, gains and losses are deferred pursuant to SFAS 71 and included in regulatory assets or regulatory liabilities as appropriate.

Nuclear decommissioning trust assets reflect the assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) and consist of fixed

income securities. Changes in the fair value of decommissioning trust assets are deferred to the balance sheet pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation. Non-qualified benefit plan trust reflects the assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and consist primarily of marketable securities. While fluctuations in the fair value of the non-qualified benefit plan assets are recorded in current earnings, a portion of the change in assets value representing the cash surrender value is excluded from the table above as it is not subject to SFAS 157. Assets and liabilities from price risk management activities represent derivative transactions entered into by PGE to manage its exposure to commodity price risk and minimize net power costs for service to the Company’s retail customers and may consist of forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas.

As a result of continued turbulence in capital markets into October 2008, the fair values of financial assets classified as Level 1 have sustained additional decreases in fair value. From September 30, 2008 through October 24, 2008, the fair value of assets held by the Non-qualified benefit plan trust have decreased approximately $7 million.

Changes in the fair value of assets and liabilities from price risk management activities classified as Level 3 in the fair value hierarchy were as follows (in millions):


	Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
Beginning balance	$	170		$	1
Net realized and unrealized losses		(208	)		(9	)
Purchases and issuances, net		(23	)		(52	)
Net transfers out of Level 3		(1	)		(2	)

Ending balance	$	(62	)	$	(62	)

Net realized and unrealized losses included in Purchased power and fuel in the condensed consolidated statements of income, which includes $236 million and $60 million in net unrealized losses for the three and nine month periods ended September 30, 2008, respectively, have been fully offset by the effects of regulatory accounting pursuant to SFAS 71.

NOTE 4: EARNINGS PER SHARE

Components of basic and diluted earnings per share were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
Numerator (in millions):
Net income available for common shareholders	$	-	$	20	$	67	$	121


Denominator (in thousands):
Weighted-average common shares outstanding - basic		62,554		62,516		62,539		62,509
Dilutive effect of restricted stock units and employee stock purchase plan shares		53		26		50		25

Weighted-average common shares outstanding - diluted		62,607		62,542		62,589		62,534


Earnings per share - basic and diluted	$	-	$	0.32	$	1.08	$	1.93

Unvested performance stock units and related dividend equivalent rights are not included in the computation of dilutive securities because vesting of these instruments is dependent upon the attainment of specific goals during three-year performance periods.

Basic and diluted earnings per share amounts are calculated based on actual amounts. Accordingly, basic and diluted earnings per share amounts as presented in the table above and on the condensed consolidated statements of income may not necessarily recalculate based on the rounded amounts presented for both net income and weighted-average shares outstanding.

NOTE 5: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such activities include power and natural gas purchases and sales resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. PGE utilizes derivative instruments, which may include forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas, in its retail electric utility activities to manage its exposure to commodity price risk and to minimize net power costs. Under SFAS 133, derivative instruments are recorded at estimated fair value on the balance sheet as an asset or liability unless they qualify for the normal purchase, normal sale exception, with changes in estimated fair value recognized currently in earnings, unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows gains and losses on a derivative instrument to be recorded in comprehensive income until they can offset the related results on the hedged item in net income. The derivative instruments entered into to manage the Company’s future retail resource requirements are subject to regulation; accordingly, the unrealized gains and losses are deferred pursuant to SFAS 71 in both net income and comprehensive income.

PGE has affirmed its ongoing policy election pursuant to FASB Interpretation No. (FIN) 39, Offsetting of Amounts Related to Certain Contracts, not to net on the balance sheet the positive and negative exposures resulting from derivative instruments entered into with counterparties where a master netting arrangement exists, as allowed under FIN 39.

Most of PGE’s wholesale sales have been to utilities and power marketers and have been predominantly short-term. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions are referred to as “book outs.” Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations and physically delivered is recorded in Wholesale sales and Purchased power and fuel expense.

Changes in the fair value of retail derivative instruments prior to settlement that do not qualify for either the normal purchases and normal sales exception or for hedge accounting are recorded on a net basis in Purchased power and fuel expense. For derivative instruments that are physically settled, sales are recorded in Revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel expense. PGE records the non-physical settlement of electricity derivative activities on a net basis in Purchased power and fuel expense, in accordance with EITF 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, as none of PGE’s derivative activities are executed for trading purposes.

Net unrealized gains (losses) from derivative activities recorded in net income, fully offset by the recognition of SFAS 71 regulatory assets or liabilities, were as follows (in millions):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net unrealized gains (losses)	$	(549	)	$	(18	)	$	(137	)	$	16
SFAS 71 regulatory asset (liability)		549			18			137			(16	)

Net unrealized gains (losses)	$	-		$	-		$	-		$	-

In 2007, PGE elected to discontinue hedge accounting for the Company’s remaining outstanding derivatives designated as cash flow hedges, in accordance with SFAS 133, which did not have a material impact on the Company’s consolidated financial position or consolidated results of operations. Net unrealized gains of $2 million, substantially all of which the Company estimates will be reclassified into earnings within the next twelve months, are fully offset by SFAS 71 regulatory accounting, with the balance to settle over the next 36 months. These net unrealized gains, fully offset by SFAS 71 regulatory accounting, are included in Accumulated other comprehensive loss in the condensed consolidated balance sheet as of September 30, 2008.

The following table reflects derivative activities from cash flow hedges recorded in comprehensive income, before taxes (in millions):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Other unrealized holding net losses arising during the period	$	-		$	(5	)	$	-		$	(5	)
Reclassification to net income for contract settlements		2			2			2			(5	)
Reclassification of unrealized (gains) losses to SFAS 71 regulatory asset		(2	)		3			(2	)		10

Net unrealized gains (losses)	$	-		$	-		$	-		$	-

NOTE 6: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income	$	-		$	20		$	67		$	121
Unrealized gains (losses) on cash flow hedges:
Other unrealized holding losses arising during the period, net of taxes of $2 in 2007		-			(3	)		-			(3	)
Reclassification to net income for contract settlements, net of taxes of ($1) for the three months ended September 30, 2007, and ($1) and $2 for the nine months ended September 30, 2008 and 2007, respectively		1			1			1			(3	)
Reclassification of unrealized (gains) losses to SFAS 71 regulatory asset (liability), net of taxes of $1 and ($1) for the three months ended September 30, 2008 and 2007, respectively, and $1 and ($4) for the nine months ended September 30, 2008 and 2007, respectively		(1	)		2			(1	)		6

Total unrealized gains (losses) on cash flow hedges		-			-			-			-

Pension and other postretirement plans’ funded position, net of taxes of ($1) for the three months ended September 30, 2007 and for the nine months ended September 30, 2008 and 2007		-			1			1			1
Reclassification of defined benefit pension plan and other benefits to SFAS 71 regulatory asset, net of taxes of $1 for the three months ended September 30, 2007 and for the nine months ended September 30, 2008 and 2007		-			(1	)		(1	)		(1	)

Comprehensive income	$	-		$	20		$	67		$	121

NOTE 7: CONTINGENCIES

Legal Matters

Trojan Investment Recovery

Background. In 1993, PGE closed the Trojan Nuclear Plant as part of the Company’s least cost planning process. PGE sought full recovery of, and a rate of return on, its Trojan plant costs, including decommissioning, in a general rate case filing with the Public Utility Commission of Oregon (OPUC). In 1995, the OPUC issued a general rate order which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Court Proceedings on OPUC Authority to Grant Recovery of Return on Trojan Investment. Numerous challenges, appeals and reviews were subsequently filed in the Marion County Circuit Court (Circuit Court), the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The primary plaintiffs in the litigation were the Citizens’ Utility Board (CUB) and the Utility Reform Project (URP). The Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC’s authorization of PGE’s recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and URP each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. On November 19, 2002, the Oregon Supreme Court dismissed the petitions for review. As a result, the 1998 Oregon Court of Appeals opinion stands and the case was remanded to the OPUC (1998 Remand).

Settlement of Court Proceedings on OPUC Authority. In 2000, while the petitions for review of the 1998 Oregon Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE’s recovery of, and return on, its investment in the Trojan plant. The URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining credit due customers under terms of the 1997 merger of the Company’s parent corporation at the time (Portland General Corporation) with Enron Corp. The settlement also allowed PGE recovery of approximately $47 million in income tax benefits related to the Trojan investment which had flowed through to customers in prior years; such amount was recovered from PGE customers by the end of 2006. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan is no longer included in prices charged to customers, either through a return of or a return on that investment. Authorized collection of Trojan decommissioning costs is unaffected by the settlement agreements or the OPUC orders.

Challenge to Settlement of Court Proceeding. URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC’s September 2000 order. In March 2002, the OPUC issued an order (2002 Order) denying all of URP’s challenges, and approving the accounting and ratemaking elements of the 2000 settlement. URP appealed the 2002 Order to the Circuit Court. On November 7, 2003, the Circuit Court issued an opinion remanding the case to the OPUC for action to reduce prices or order refunds (2003 Remand). The opinion did not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC appealed the 2003 Remand to the Oregon Court of Appeals. On October 10, 2007, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration because the 2002 Order was based, in part, on an incorrect understanding of Section 757.225 of the Oregon Revised Statutes. The Oregon Court of Appeals also vacated the 2003 Remand finding error in the Circuit Court’s specific instructions to the OPUC to revise the rate structure.

Remand of 2002 Order. As a result of the Oregon Court of Appeals remand of the 2002 Order, the OPUC considered the following issues:

•

What prices would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment; and

•

Whether the OPUC has authority to engage in retroactive ratemaking.

On September 30, 2008, the OPUC issued an order that requires PGE to refund $33.1 million to certain customers. The refund relates to the unamortized Trojan balance on September 30, 2000, as discussed below.

In the order, the OPUC also made the following findings:

•

The OPUC has authority to order a utility to issue refunds under certain limited circumstances; and

•

PGE’s rates that were in effect for the period April 1, 1995 through September 30, 2000 were just and reasonable.

The OPUC examined the rates in effect for the period April 1, 1995 through September 30, 2000 and determined what rates during this period would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. The OPUC removed the previously allowed return on the Company’s Trojan investment during the period, reduced the recovery period from 17 to 10 years, and revised certain other assumptions, all of which reduced the recoverable balance as of September 30, 2000 from $180.5 million to $165.1 million. The OPUC ruled that the difference of $15.4 million, plus interest at 9.6% from September 30, 2000, should be refunded to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The $15.4 million amount, plus accrued interest, results in a total refund of $33.1 million as of September 30, 2008. The order also provides that the total refund amount will accrue interest at 9.6% from October 1, 2008 until all refunds are issued to customers. The Company expects the refunds to customers to occur by mid-2009.

As a result of this order, PGE recorded, as a regulatory liability, the total refund due to customers of $33.1 million, which reduced 2008 revenues. The URP and the plaintiffs in the class actions described below have separately appealed the order to the Oregon Court of Appeals. PGE is continuing to review and evaluate the order along with the subsequent appeals. The full text of OPUC Order No. 08-487 is available on its Internet website at www.puc.state.or.us.

Class Actions. In a separate legal proceeding, two class action suits were filed in Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million plus interest for the Current Class and $70 million plus interest for the Former Class, as a result of the inclusion of a return on investment of Trojan in the prices PGE charges its customers. On December 14, 2004, the judge granted the Class Action Plaintiffs’ motion for Class Certification and Partial Summary Judgment and denied PGE’s motion for Summary Judgment. On March 3, 2005 and March 29, 2005, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial judge to dismiss the complaints or to show cause why they should not be dismissed, and seeking to overturn the Class Certification. On August 31, 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions for Alternative Writ of Mandamus, abating the class action proceedings until the OPUC responds to the 2003 Remand (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1995 through October 2000. The Oregon Supreme Court further stated that if the OPUC determines that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part, but if the OPUC determines that it cannot provide a remedy, and that decision becomes final, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings.

On October 5, 2006, the Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions, but inviting motions to lift the abatement after one year. On October 17, 2007, the plaintiffs filed a motion to lift the abatement. A hearing on this motion was held on April 10, 2008. At the hearing, the Circuit Court declined to lift the abatement. The Circuit Court has encouraged the parties to attempt to agree on steps that might be taken in preparation for a trial in the event the Circuit Court lifts the abatement following the OPUC order issued on September 30, 2008. On June 3, 2008, the Circuit Court scheduled a status conference for October 15, 2008 and set a tentative trial date for April 2009. At the October 15, 2008 status conference, the Circuit Court set a schedule for the filing of briefs on the plaintiffs’ motion to lift the abatement. The schedule calls for the completion of briefing by November 25, 2008 and oral argument on January 12, 2009.

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

Regulatory Matters

Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal from the Rosebud Mine in Montana under a Coal Supply Agreement and a Transportation Agreement with owners of Colstrip Units 3 and 4 coal plant (Colstrip), in which PGE has a 20% ownership interest. In 2002 and 2003, WECO received two orders from the Office of Minerals Revenue Management of the U.S. Department of the Interior (USDI) which asserted underpayment of royalties and taxes by WECO related to transportation of coal from the mine to Colstrip during the period October 1991 through December 2001. In late September 2006, WECO received an additional order from the Office of Minerals Revenue Management to report and pay additional royalties for the period January 2002 through December 2004. WECO has appealed the 2002 and 2003 orders and filed a Complaint for Declaratory and Injunctive Relief with the U.S. District Court for the District of Columbia challenging the decision of the Interior Board of Land Appeals to deny the appeal. In May 2005, WECO received a “Preliminary Assessment Notice” from the Montana Department of Revenue (MDOR), asserting claims similar to those of the USDI.

In October 2008, PGE and the other owners of Colstrip agreed with WECO to pay a portion of the taxes and royalties that WECO is required to pay to the MDOR and the USDI for both past and future periods. On October 23, 2008, WECO entered into an agreement with MDOR that settles all claims for years prior to 2008 and establishes a method for calculating taxes and royalties for subsequent periods. Management believes that PGE’s share of WECO’s obligation to pay royalties, taxes and interest to the USDI and MDOR for periods through September 30, 2008 would range from $2 million to $3 million. As of September 30, 2008, PGE has accrued $2.2 million related to this matter. The October 2008 agreements have not changed the Company’s assessment of its exposure for past periods.

PGE estimates that the Company’s share of royalties, taxes and interest for future periods will be approximately $0.2 million per year. The Company anticipates that amounts relating to future periods would be recovered through the ratemaking process. The Company will evaluate the likelihood of recovery through the ratemaking process of amounts relating to past periods. However, there can be no assurance that recovery of any amounts relating to past periods, if pursued, would be granted.

Refunds on Wholesale Market Transactions

Pacific Northwest Refund Proceeding. On July 25, 2001, the FERC called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest Refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and declined to rule on the merits of the FERC’s ultimate decision to deny refunds. Two requests for rehearing have been filed with the court, with a decision now pending.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, (California Refund case) et seq., approved by the FERC on May 17, 2007, resolves all claims as between PGE and the California parties named in the settlement as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001, but does not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The Lockyer Case. In a separate but potentially related action, in 2002, the California Attorney General filed a complaint (the Lockyer case) with the FERC against various sellers in the wholesale power market, alleging that the FERC’s authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. Upon appeal of the FERC’s refusal to order refunds pursuant to the complaint, the Ninth Circuit remanded the case for further proceedings at the FERC to determine whether refunds should be ordered due to failure of parties to file correct and timely quarterly reports. PGE settled the Lockyer case with the California Attorney General and other California parties as part of its previously reported comprehensive settlement of the California Refund and related cases, which settlement became effective on May 17, 2007.

On December 10, 2007, the California Attorney General and others filed with the FERC a motion to suspend any Lockyer remand proceedings until the court issues mandates in the California Refund case and Pacific Northwest Refund proceeding on the basis that all three cases include similar parties and similar issues. They indicated their intent to file a motion to consolidate all three cases upon remand of the two that remain pending rehearing before the Ninth Circuit.

On March 21, 2008, the FERC issued an order on remand (Remand Order) that denied the California parties’ motion to suspend the Lockyer remand proceedings and set the case for further proceedings. On

April 15, 2008, pursuant to a request for clarification filed by parties, including PGE, who had previously settled the Lockyer case with the California Attorney General and other California parties, the FERC issued an order that dismissed PGE from the Lockyer remand proceeding, which relates solely to California markets.

On October 6, 2008, the FERC denied a request for rehearing of the Remand Order, insofar as certain California Parties had requested that the remand proceedings be expanded to include issues beyond those raised by the inaccurate or untimely filing of quarterly transaction reports. On October 14, 2008, the California Attorney General and other California parties appealed the Remand Order and the order on rehearing to the Ninth Circuit Court of Appeals. PGE’s dismissal from the remand proceedings was not appealed and has become final.

Although PGE is no longer a party to the Lockyer remand proceedings, future consolidation of the Lockyer case with the Pacific Northwest Refund proceeding, on remand, could increase the Company’s potential liability in the Pacific Northwest proceeding by extending the period for which other parties are requesting refunds back to May 1, 2000, or earlier.

Management cannot predict the outcome of the Pacific Northwest Refund proceeding or Lockyer remand, if it is ever consolidated with the Pacific Northwest Refund proceeding, or whether the FERC will order refunds in the Pacific Northwest, and if so, how such refunds would be calculated. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

Complaint and Application for Deferral – Income Taxes

On October 5, 2005, the URP and Ken Lewis (together, the Complainants) filed a Complaint and an Application for Deferred Accounting with the OPUC alleging that, since the September 2, 2005 effective date of Oregon Senate Bill 408 (SB 408), PGE’s rates were not just and reasonable and were in violation of SB 408 because they contained approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any governmental entity. The Complaint and Application for Deferred Accounting requested that the OPUC order the creation of a deferred account for all amounts charged to customers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes. PGE contended that no adjustment for taxes may be made prior to the January 1, 2006 effective date of the automatic adjustment clause included in SB 408.

On August 14, 2007, the OPUC issued an order granting the Application for Deferred Accounting for the period from October 5, 2005 through December 31, 2005 (Deferral Period). The OPUC’s order also dismissed the Complaint, without prejudice, on grounds that it was superfluous to the Complainants’ request for deferred accounting. The order required that PGE calculate the amounts applicable to the Deferral Period, along with calculations of PGE’s earnings and the effect of the deferral on the Company’s return on equity. The order also provided that the OPUC would review PGE’s earnings at the time it considers amortization of the deferral. PGE understands that the OPUC will consider the potential impact of the deferral on PGE’s earnings over a relevant 12-month period, which will include the Deferral Period.

On December 1, 2007, PGE filed its report as required by the OPUC. In the report, PGE determined that (i) the amount of any deferral would be between zero and $26.6 million; (ii) a relevant 12-month period would be the 12-month period ended September 30, 2006; and (iii) PGE’s earnings over such period would preclude any refund. The OPUC has indicated that it will determine whether any necessary rate adjustment should be made to amortize the deferral granted in its August 14, 2007 order.

On October 15, 2007, PGE filed a petition for judicial review with the Oregon Court of Appeals, seeking review of the OPUC’s August 14, 2007 order. The Court of Appeals has granted PGE’s request to stay the proceedings pending an OPUC order in the matter.

Management cannot predict the ultimate outcome of this matter. However, based on the information currently known to management, it believes this matter will not have a material adverse effect on PGE’s financial condition, results of operations or cash flows.

FERC Investigation

In May 2008, PGE received a notice of a preliminary non-public investigation from the FERC Division of Investigations concerning PGE’s compliance with its Open Access Transmission Tariff. The investigation involves certain issues identified during an audit by FERC staff.

Management cannot predict the final outcome of the investigation or what actions, if any, the FERC will take or require the Company to take. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

Environmental Matters

Portland Harbor

Since 1973, PGE has operated the Harborton Substation on land owned by the Company located near the Willamette River. A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a 5.5 mile segment of the river, known as the Portland Harbor Superfund Site, revealed significant contamination of sediments within the harbor. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act.

The Portland Harbor Superfund Site is currently undergoing a remedial investigation and feasibility study (RI/FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several Potentially Responsible Parties (PRPs), not including PGE. In the AOC, the EPA determined the site for purposes of the RI/FS to be a segment of the river approximately 10 miles in length.

On January 22, 2008, PGE received a Section 104(e) Information Request from the EPA requiring the Company to provide information concerning its properties in or near the Portland Harbor Superfund Site being examined in the RI/FS, as well as several miles beyond that segment. PGE’s response is now due by the end of January 2009.

The boundaries of the site for remediation purposes will be determined at the conclusion of the RI/FS in a Record of Decision, in which the EPA documents its findings and selects a preferred cleanup alternative.

Sufficient information is currently not available to determine the total cost of any required investigation or remediation of the Portland Harbor or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

PGE has filed an application with the OPUC requesting deferred accounting, for later ratemaking treatment, of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Portland Harbor site. However, there can be no assurance that any recovery of these costs will be granted.

Harbor Oil

Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company’s power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil is also utilized by other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site that impacted an approximate two acre area. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyls, have been detected at the site. On September 29, 2003, Harbor Oil was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for RI/FS from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter started a period for the PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance an RI/FS of the Harbor Oil site. On May 31, 2007, an Administrative Order on Compliance was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site. The EPA has approved an RI/FS work plan. On-site sampling was completed during the second quarter of 2008.

Sufficient information is currently not available to determine the total cost of investigation and remediation of the Harbor Oil site or the liability of the PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

PGE has filed an application with the OPUC requesting deferred accounting, for later ratemaking treatment, of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Harbor Oil site. However, there can be no assurance that any recovery of these costs will be granted.

Other Matters

PGE is subject to other regulatory and legal proceedings that arise from time to time in the ordinary course of its business, which may result in adverse judgments against the Company. Although management currently believes that resolving such matters will not have a material adverse effect on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties and management’s view of these matters may change in the future.

NOTE 8: GUARANTEES

PGE enters into financial and power purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise in connection with the transactions contemplated by these agreements. Generally, these indemnification provisions do not set a maximum obligation amount and therefore, the aggregate maximum amount of PGE’s obligations under these agreements cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities. Based on PGE’s historical experience and the evaluation of the specific indemnities, management believes the likelihood that PGE would be required to perform, or otherwise incur any significant losses, is remote.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements relate to expectations, beliefs, plans, objectives for future operations, assumptions, business prospects, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “should,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” or similar expressions are intended to identify such forward-looking statements.

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

In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

•

governmental policies and regulatory audits, investigations, and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, transmission of electricity, recovery of Net Variable Power Costs (NVPC) and capital investments, and current or prospective wholesale and retail competition;

•

capital market conditions, including availability of capital and interest rate fluctuations, as well as changes in PGE’s credit ratings, which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;

•

the outcome of legal and regulatory proceedings and issues, including the proceedings related to the Trojan investment recovery, the Pacific Northwest Refund proceeding, and the Portland Harbor investigation described in Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements;

•

unseasonable weather and other natural phenomena, which, in addition to affecting PGE’s customers’ demand for power, could have a serious impact on PGE’s ability and cost to procure adequate supplies of fuel or power to serve its customers;

•

operational factors affecting PGE’s power generation facilities, including outages, unplanned forced outages, hydro conditions, wind conditions, and disruption of fuel supply;

•

wholesale energy prices and their impact on the availability and price of wholesale power in the western United States;

•

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

•

future laws, regulations, and proceedings that could increase the Company’s costs or affect the operations of the Company’s thermal generating plants by imposing requirements for additional pollution control equipment or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, to mitigate carbon dioxide, mercury, and other emissions;

•

the effectiveness of PGE’s risk management policies and procedures and the creditworthiness of customers and counterparties;

•

the failure to complete major generating plants on schedule and within budget;

•

the effects of Oregon law related to utility rate treatment of income taxes (SB 408), which may result in earnings volatility and adverse effects on results of operations;

•

the outcome of efforts to relicense the Company’s hydroelectric projects, as required by the FERC;

•

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

•

the effects of global warming or climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or affect its operations;

•

new federal, state, and local laws that could have adverse effects on operating results;

•

employee workforce factors, including aging, potential strikes, work stoppages, and the loss of key executives;

•

general political, economic, and financial market conditions;

•

natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind, and fire;

•

acts of war or terrorism;

•

financial or regulatory accounting principles or policies imposed by governing bodies; and

•

other factors identified elsewhere in this report and other PGE filings with the Securities and Exchange Commission, including those factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008, as supplemented by Part II, Item 1A of this Quarterly Report on Form 10-Q.

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

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, its Annual Report on Form 10-K for the year ended December 31, 2007, and other periodic and current reports filed with the SEC.

Current Market Conditions - Turbulent capital market conditions during the third and early fourth quarter of 2008 have adversely affected both access to capital and the cost of capital in global markets. PGE is assessing the impact of these market conditions on its operations, which include, but are not limited to, the following:

•

Impacts on the Company’s plans to issue capital stock or debt - PGE has estimated capital expenditure requirements of approximately $760 million in 2009 and $470 million in 2010 in addition to long-term debt maturities of $142 million in 2009 and $186 million in 2010. Although the current market conditions have made access to capital more difficult, PGE believes it continues to have the ability to obtain funding for its capital requirements. Further, the Company’s borrowing costs, including increases resulting from current and future market conditions, are expected to be recoverable in customer prices.

•

Valuation of Investments -

PGE sponsors a pension plan. The fair market value of investments held by the pension trust has recently decreased substantially. Pursuant to the Pension Protection Act of 2006, PGE is legally obligated to maintain a certain funding level with respect to the pension plan. The required funding level is determined annually based on certain actuarial assumptions and the valuation of the assets held by the pension trust. If market conditions do not improve, PGE may be required to fund an unfunded position of the pension plan in the near term.

Non-qualified benefit plan assets, which include marketable securities, are held in trusts to cover PGE’s obligations under its non-qualified benefit plans. Fluctuations in the fair market value of the non-qualified benefit plan assets are recorded in current earnings.

Nuclear decommissioning trust assets reflect the assets held in trust to cover general decommissioning costs and operation of the ISFSI and consist of fixed income securities. Changes in the fair value of decommissioning trust assets are deferred to the balance sheet pursuant to SFAS 71.

•

Other Demands on Liquidity - During October 2008, PGE was required to provide increased margin deposits pursuant to existing purchased power and natural gas agreements. These margin deposits are required primarily because of decreases in the mark-to-market value of PGE’s outstanding contracts. If wholesale power and natural gas prices continue to decline, PGE may be required to provide additional margin deposits.

For additional information with respect to these and other matters, see “Liquidity and Capital Resources” in this Item and Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Customers - During the nine months ended September 30, 2008, PGE served an average of 811,000 retail customers compared to 799,000 during the comparable period of 2007, an increase of 1.5%. This customer growth, along with generally cooler weather in 2008, resulted in a 3% increase in retail energy deliveries relative to 2007. On a weather adjusted basis, retail energy deliveries increased 1.5% from the comparable period of 2007.

A slow-down in the state’s economy, including a sustained decline in the housing market, continued through the third quarter of 2008. Oregon’s unemployment rate rose from 5.2% for 2007 to 5.8% through

September 2008, compared to the national jobless rate of 5.4%. Despite the slow-down, Oregon had a 0.3% payroll growth compared to a national growth of 0.1% during the nine months ended September 30, 2008. PGE projects an approximate 1.5% increase in weather adjusted energy deliveries for 2008, with higher use by industrial customers projected during the last quarter of the year. PGE currently projects an approximate 1.9% increase in weather adjusted energy deliveries for 2009.

Regulatory review of the Company’s general rate case and proposed tariffs, filed with the OPUC in late February 2008, is continuing under procedural schedules that currently provide for new rates to become effective on January 1, 2009. PGE’s initial filing proposed an 8.9% average price increase related to higher purchased power and fuel costs, increased investment in utility plant, and higher operating expenses. Due to projections of increased costs of purchased power and fuel for the Company’s thermal generating plants subsequent to the initial filing, PGE has filed power cost updates reflecting additional projected power costs. PGE, OPUC staff, and interveners have reached stipulations on several items, including the method of determining estimated power costs and the cost of capital. The cost of capital stipulation provides for a debt-to-equity capital structure of 50/50 and a return on equity of 10.1%. The stipulated items and the power cost updates filed to date would result in a proposed average price increase of approximately 10%, consisting of increased revenue requirements of approximately $104 million for NVPC and $57 million for other costs. Certain customer credits, including those related to 2007 results of the Company’s Power Cost Adjustment Mechanism (PCAM), are expected to reduce the average price increase to approximately 8.4% effective January 1, 2009. The proposed increases remain subject to change until a final decision is made by the OPUC, which is expected in late December. Estimated 2009 NVPC will be updated in November 2008 according to a procedural schedule established by the OPUC. Additional information regarding PGE’s general rate case filing, including copies of direct testimony and exhibits, is available on the Company’s Internet website at www.portlandgeneral.com. Information may also be obtained on the OPUC Internet website at www.puc.state.or.us.

Installation of a limited number of new smart meters has begun as part of the smart meter project’s acceptance testing phase, with the remaining meters to be installed by the end of 2010 for residential and commercial customers. PGE expects the project to provide improved services as well as operational efficiencies and cost savings. A new tariff, effective from June 1, 2008 through December 31, 2010, provides for recovery of costs related to this project, including the net book value of existing meters, during this period.

Power Supply - PGE utilizes its own generating resources and wholesale market purchases to meet the energy and capacity needs of its customers. The Company’s generating plants provided approximately 60% of its retail load requirement during the nine months ended September 30, 2008, compared to 52% in the comparable period of 2007, primarily due to the addition of Port Westward and Biglow Canyon Phase I to the Company’s generation portfolio in June and December 2007, respectively. Current forecasts indicate near normal regional hydro conditions for 2008.

On August 15, 2008, PGE set a new all-time net system load “summer peak” (3,743 MW), driven by unusually warm weather and increased air conditioning demand, surpassing the previous record (3,706 MW) set on June 24, 2006. The Company’s all-time high net system load peak (4,073 MW) occurred in December 1998.

In March 2008, PGE executed agreements to purchase 141 wind turbines for Phases II and III of Biglow Canyon, and in July 2008, the Company entered into contracts for the related construction contracts. Construction of Phase II has begun, with completion expected by the end of 2009. Phase III is expected to be completed by the end of 2010. Total cost of the two phases is expected to be $730 million to $770 million, including allowance for funds used during construction (AFDC). The two phases will have a combined installed capacity of approximately 324 MW, further increasing the diversity of the Company’s generating resource portfolio while minimizing related environmental impacts. For further information regarding estimated future capital expenditures, see “Capital Requirements” in “Liquidity and Capital Resources” in this Item 2.

In April 2008, PGE issued a request for proposals for 218 MWa of renewable energy resources and identified an initial short list of bidders in September 2008. Such resources, which are in addition to Biglow Canyon, are required to become available between 2009 and 2014. The Company expects to identify a final short list by the end of the year and then begin negotiations.

As requested by the OPUC, PGE is currently preparing additional long-term analysis to address resource decisions beyond 2012, which the Company plans to include in a revised Integrated Resource Plan (IRP) to be filed by October 2009. PGE expects the updated and revised IRP to further define the Company’s future energy and capacity needs.

In an effort to secure additional renewable energy resources, the Company invested in its first photovoltaic solar power project during the third quarter of 2008 through a limited liability company. The project is located on property owned by the Oregon Department of Transportation, with a total cost estimated at approximately $1.3 million and an installed capacity of approximately 104 kW. On October 2, 2008, the Company invested in, through another limited liability company, an additional photovoltaic solar power project located on the rooftops of three distribution warehouses. The total cost of this facility is estimated at approximately $7.4 million, with an installed capacity of approximately 1,095 kW. Both of these projects are expected to be placed in service by December 31, 2008. Although PGE’s initial interest in each of these limited liability companies is less than 5%, PGE is the managing member and will operate both facilities pursuant to an operating agreement with the investor member. PGE expects to consolidate both entities pursuant to FASB Interpretation No. 46R, Consolidation of Variable Interest Entities.

Legal, Regulatory and Environmental Matters - On September 30, 2008, the OPUC issued an order in the matter of recovery of PGE’s investment in Trojan. The order requires PGE to refund $33.1 million to customers who received service during the period October 1, 2000 through September 30, 2001. For further information, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

In November 2007, PGE proposed to the Oregon Department of Environmental Quality (DEQ) controls that would address emissions from the Boardman coal plant. In August 2008, the DEQ issued a preliminary proposal that would require the installation of even more stringent emission controls, under a phased-in approach. For further discussion of this matter, see Air Quality Standards, in “Capital Requirements” under “Liquidity and Capital Resources” in this Item 2.

PGE is a party to other proceedings whose ultimate outcome could have a material impact on the results of operations and cash flows in future reporting periods. These include matters related to:

—

claims for refunds related to wholesale energy sales in the Pacific Northwest during 2000 - 2001;

—

an audit and subsequent investigation by the FERC related to the Company’s compliance with its Open Access Transmission Tariff; and

—

an investigation by the EPA of the Portland Harbor Superfund Site.

For further information regarding the above and other matters, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

Recent and pending rate actions include, but are not limited to, the following:

—

A 6.3% average price decrease for residential and small farm customers, effective April 15, 2008, related to an agreement between PGE and Bonneville Power Administration (BPA) that temporarily restored federal hydropower benefits under the Residential Exchange Program administered by the BPA. The majority of such benefits, approximately $43 million, are expected to be refunded by the end of 2008. In September 2008, PGE and BPA entered into an agreement that will provide approximately $50 million in benefits over the period October 1, 2008 through September 30, 2009. Such benefits will be credited to eligible customers beginning in January 2009.

—

A 1.4% average price decrease, effective June 1, 2008, for refunds to retail customers of taxes pursuant to SB 408 related to the 2006 reporting year. Such refunds, in the amount of $37.2 million plus interest, will take place over an approximate two-year period.

—

An approximate 1% average price increase, effective June 1, 2008, for costs related to energy efficiency measures that enable customers to reduce their energy use.

—

A 0.8% average price increase, effective June 1, 2008, related to the smart meter project.

—

The collection of deferred replacement power costs related to the outage of Boardman from late 2005 through early 2006 ($26.4 million plus $7.1 million of accrued interest through September 30, 2008). PGE has proposed that this be offset by certain credits due to customers, with no price impact anticipated. PGE’s request is subject to both a prudence review with respect to the outage and to a regulated earnings test. An OPUC decision and order on this matter is expected in late 2008 or the first half of 2009.

—

An approximate $18 million refund to customers, including accrued interest, related to the 2007 application of PGE’s PCAM. The Company has requested that such amount, which is subject to review by the OPUC, be refunded over a one-year period beginning January 1, 2009.

—

A proposed average price increase of approximately 10%, subject to revision later this year based on projected 2009 NVPC and final resolution of the general rate case, to be effective January 1, 2009, as previously described.

Critical Accounting Policies

PGE’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008.

Results of Operations

The following table contains certain financial information for the periods presented (dollars in millions):


	Three Months Ended September 30,									Nine Months Ended September 30,
	2008					2007				2008					2007
	Amount			As % of Rev		Amount		As % of Rev		Amount			As % of Rev		Amount		As % of Rev
Revenues, net	$	400		100	%	$	435	100	%	$	1,296		100	%	$	1,273	100	%
Operating expenses:
Purchased power and fuel		217		54			242	56			652		50			620	49
Production and distribution		40		10			36	8			125		10			109	9
Administrative and other		48		12			46	11			142		11			136	11
Depreciation and amortization		54		14			46	11			154		12			134	11
Taxes other than income taxes		20		5			20	5			63		5			60	5

Total operating expenses		379		95			390	90			1,136		88			1,059	83

Income from operations		21		5			45	10			160		12			214	17
Other income (expense):
Allowance for equity funds used during construction		3		1			4	1			7		1			13	1
Miscellaneous, net		(4	)	(1	)		2	-			(6	)	-			10	1

Other income (expense), net		(1	)	-			6	1			1		-			23	2
Interest expense		21		5			19	4			67		5			54	4

Income (loss) before income tax expense (benefit)		(1	)	-			32	7			94		7			183	14
Income tax expense (benefit)		(1	)	-			12	3			27		2			62	5

Net income	$	-		-	%	$	20	5	%	$	67		5	%	$	121	10	%

Percentages may not add due to rounding.

Net income was zero for the third quarter of 2008 compared to $20 million, or $0.32 per diluted share, for the third quarter of 2007. The decrease was due primarily to a $20 million after-tax provision for the future refund to customers of an amount ordered by the OPUC in September 2008, related to the Trojan order. Also contributing to the decrease in net income was the $7 million after-tax impact of an increase in estimated customer refunds pursuant to SB 408, primarily due to the Trojan refund order, and a $3 million after-tax impact of a decline in the fair market value of non-qualified benefit plan trust assets. Such results were partially offset by a 3% increase in retail energy deliveries and reduced power costs. In the third quarter of 2008, the Company’s power costs were reduced by $6 million related to results of the PCAM, while power costs in the third quarter of 2007 increased $12 million related to the PCAM.

Net income for the nine months ended September 30, 2008 was $67 million, or $1.08 per diluted share, compared to $121 million, or $1.93 per diluted share, for the nine months ended September 30, 2007. The decrease was due primarily to a $20 million after-tax provision in September 2008 for a future refund to customers related to the Trojan order, the $13 million after-tax impact of the deferral in 2007 of a portion of Boardman replacement power costs (including accrued interest) for potential future recovery (as approved by the OPUC), and higher operating expenses. Also contributing to the decrease in net income was a $10 million after-tax impact of adjustments related to SB 408, with a $7 million customer refund recorded in 2008 and a $10 million collection recorded in 2007. In addition, there was a $9 million after-tax impact of a decline in the fair market value of non-qualified benefit plan assets and a favorable $4 million after-tax impact in 2007 for the settlement between PGE and certain California parties related to wholesale energy transactions in the western energy markets during 2000-2001. Such results were partially offset by a 3% increase in retail energy deliveries. The Company’s power costs increased $1 million and $15 million for the first nine months of 2008 and 2007, respectively, related to results of the PCAM.

Third Quarter of 2008 Compared to the Third Quarter of 2007

Revenues, energy sold and delivered (based in megawatt hours), and retail customers are comprised of the following:


	Three Months Ended September 30,
	2008					2007
	Amount			Percent of Total		Amount			Percent of Total
Revenues (dollars in millions):
Retail sales:
Residential	$	155		39	%	$	160		37	%
Commercial		156		39			157		36
Industrial		42		11			41		9

Total retail sales		353		88			358		82
Trojan refund liability		(33	)	(8	)		-		-
Other retail revenues		11		3			7		2
Direct access customers		(3	)	(1	)		(3	)	(1	)

Total retail revenues		328		82			362		83
Wholesale revenues		61		15			68		16
Other operating revenues		11		3			5		1

Revenues, net	$	400		100	%	$	435		100	%


Energy sold and delivered (MWhs in thousands):
Retail energy sales:
Residential		1,643		28	%		1,602		27	%
Commercial		1,909		33			1,910		32
Industrial		649		11			632		11

Total retail energy sales		4,201		73			4,144		70
Delivery to direct access customers		636		11			567		10

Total retail energy deliveries		4,837		84			4,711		79
Wholesale sales		942		16			1,221		21

Total energy sold and delivered		5,779		100	%		5,932		100	%

Percentages may not add due to rounding.


	As of September 30,
	2008	2007
Retail customers:
Residential	711,963	703,272
Commercial	102,162	100,110
Industrial	267	257

Total retail customers	814,392	803,639

Demand for electricity by residential and commercial customers is significantly affected by weather. Heating degree-days, an indication of the likelihood that customers will use heating, and cooling degree-days, an indication of the likelihood that customers will use air conditioning, are generally used to measure the effect of weather on the demand for electricity. The following table indicates the number of heating and cooling degree-days for the months indicated, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:


	Heating		Cooling
	2008	2007	2008	2007
July	6	-	134	184
August	17	7	169	114
September	57	116	73	46

3rd quarter	80	123	376	344

15-year average for the quarter	82	82	385	385

Total revenues decreased $35 million, or 8%, in the third quarter of 2008 compared to the third quarter of 2007 as a result of the following factors:

Total retail revenues decreased $34 million, or 9%, due primarily to the accrual of refunds to customers in the amount of $33.1 million pursuant to the OPUC order issued September 30, 2008 related to various Trojan matters. Total retail revenues were also affected by the following decrease:

^¡

A $12 million decrease related to SB 408, largely due to an estimated refund due to customers of $6 million recorded in the third quarter of 2008, resulting primarily from the Trojan order, compared to an estimated collection from customers of $5 million recorded in the third quarter of 2007.

Partially offsetting the above decreases were the following increases:

^¡

A $5 million increase resulting from a 2% increase in average price, which was driven by price increases for the Company’s smart meter project and recovery of Biglow Canyon Phase I, partially offset by a price decrease for changes in forecasted 2008 power and fuel costs; and

^¡

A $5 million increase resulting from a 3% increase in total retail energy deliveries, primarily due to an increase of 1.4% in the average number of customers served during the third quarter of 2008, relative to the third quarter of 2007.

Wholesale revenues result from sales of electricity to utilities and power marketers which are made in conjunction with the Company’s efforts to secure reasonably priced power for its retail customers, manage risk and administer its current long-term wholesale contracts. Such sales can vary significantly between periods. During the third quarter of 2008, wholesale revenues decreased $7 million, or 10%, compared to the third quarter of 2007, due to the net effect of the following:

^¡

A $16 million decrease resulting from a 23% decrease in wholesale energy sales volume; partially offset by

^¡

A $9 million increase resulting from a 17% increase in average price, due to higher natural gas prices.

Other operating revenues increased $6 million due primarily to the sale of fuel oil in 2008. Pursuant to an assessment of reliability requirements, PGE reduced oil inventory levels at its Beaver generating plant.

Purchased power and fuel expense in the third quarter of 2008 decreased $25 million, or 10%, from the third quarter of 2007. Information about PGE’s total system load and retail load requirement for the periods presented is as follows (in thousands of MWhs):


	Three Months Ended September 30,
	2008		2007
Generation	2,928		3,265
Term purchases	1,966		1,984
Spot purchases	527		397

Total system load	5,421		5,646
Less: wholesale sales	(942	)	(1,221	)

Retail load requirement	4,479		4,425

The average variable power cost of the above total system loads was $41.11 and $40.94 per MWh in the third quarter of 2008 and 2007, respectively. Averages exclude the effect of amounts related to regulatory power cost deferrals and wholesale credit provisions.

The decrease in Purchased power and fuel expense was due primarily to the net effect of the following factors:

—

A $50 million decrease related to settled natural gas swap agreements entered into in conjunction with PGE’s management of its NVPC, due to an increase in natural gas prices. These agreements are among those financial instruments in the Company’s diversified power supply portfolio used to manage market risk, with activities reflected in Wholesale revenues, Purchased power and fuel expense, and Other operating revenues;

—

An $18 million decrease related to application of the Company’s PCAM. As a result of an increase in projected customer refunds under SB 408 (due primarily to the impact of the OPUC’s September 2008 Trojan order), the Company is not expected to achieve a sufficient return on equity in 2008 that would allow for refunds under the PCAM. Accordingly, an approximate $6 million refund provision, recorded in the first half of 2008, was reversed in the third quarter, with a corresponding reduction in power costs. In the third quarter of 2007, PGE recorded a $12 million regulatory liability, with a corresponding increase in power costs.

Under the PCAM, the Company can adjust future prices to reflect a portion of the difference between each year’s forecasted power costs included in customer prices and actual power costs to the extent that such difference exceeds a pre-determined “deadband” which, for 2008, ranges from $14 million below, to $28 million above, baseline power costs. Any regulatory asset or liability arising from the application of the PCAM is adjusted for the results of a regulated earnings test, with final determination of any customer refund or collection to be determined by the OPUC through a public filing and review;

—

A $30 million increase in the cost of purchased power, resulting primarily from a 27% increase in the average cost; and

—

A $11 million increase in the cost of natural gas-fired production, as a 55% increase in the average cost of natural gas was only partially offset by a 24% reduction in generation, resulting from the economic displacement of gas-fired generation with less expensive power purchases.

Sources of Energy - The following table indicates that portion of PGE’s total load requirement met with each listed source for the periods presented:


	Three Months Ended September 30,
	2008		2007
Generation:
Thermal	45	%	52	%
Hydro	6		6
Wind	2		-

Total generation	53	%	58	%

Purchased power:
Term purchases	24	%	22	%
Spot purchases	13		13
Mid-Columbia hydro projects	10		7

Total purchases	47	%	42	%

Total load requirement	100	%	100	%

Generation at PGE’s thermal plants decreased by 16% from the third quarter of 2007 as the result of a reduction in total system load and the increased economic displacement of both Beaver and Coyote at certain times during 2008. Energy from hydro resources in the third quarter of 2008 decreased 2% from the third quarter of 2007. A 14% increase in Company-owned hydro production, resulting from higher stream flows, was more than offset by an 8% reduction in energy received under long-term purchase power agreements from hydro facilities on the mid-Columbia River.

Regional hydro conditions in 2008 have been near normal. Volumetric water supply data for the Pacific Northwest is prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies. The following is the final forecast (issued July 8, 2008) of the April-to-September 2008 runoff compared to the actual runoff for 2007 (as a percentage of normal):


Location	2008 Forecast		2007 Actual
Columbia River at The Dalles, Oregon	101	%	97	%
Mid-Columbia River at Grand Coulee, Washington	102	%	102	%
Clackamas River	163	%	100	%
Deschutes River at Benham Falls	101	%	91	%

Production and distribution expense increased $4 million, or 11%, in the third quarter of 2008 compared to the third quarter of 2007. The increase is due primarily to an increase of $2 million in overhead and underground line maintenance costs, including tree trimming, and a $1 million increase in operating costs at Biglow Canyon Phase I, which was completed in December 2007.

Administrative and other expense increased $2 million, or 4%, in the third quarter of 2008 compared to the third quarter of 2007, primarily due to an increase in the provision for uncollectible accounts and increased legal and regulatory fees.

Depreciation and amortization expense increased $8 million, or 17%, in the third quarter of 2008 compared to the third quarter of 2007. Of the total increase, $4 million is related to higher distribution

plant balances and accelerated depreciation on existing meters which are being replaced as part of the Company’s smart meter project, and $3 million is related to the new Biglow Canyon Phase I project, which was placed in service in December 2007.

Other income decreased $7 million in the third quarter of 2008 compared to the third quarter of 2007. The decrease is primarily due to a decline in the fair market value of non-qualified benefit plan assets. During the third quarter of 2008, losses of approximately $4 million were recorded on the assets, compared to gains of approximately $1 million in the third quarter of 2007.

Interest expense increased $2 million, or 11%, in the third quarter of 2008 compared to the third quarter of 2007 due primarily to a higher level of short- and long-term debt outstanding during 2008. During the third quarter of 2008, the average balance of short- and long-term debt outstanding was $1,325 million, compared to $1,173 million for the third quarter of 2007.

Income tax expense (benefit) was ($1) million in the third quarter of 2008 compared to $12 million in the third quarter of 2007. The change in income tax expense (benefit) is primarily the result of lower taxable income and an increase of $1 million in federal energy tax credits generated from the operation of Biglow Canyon Phase I in the third quarter of 2008.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Revenues and energy sold and delivered (based in megawatt hours) is comprised of the following:


	Nine Months Ended September 30,
	2008					2007
	Amount			Percent of Total		Amount			Percent of Total
Revenues (dollars in millions):
Retail sales:
Residential	$	559		43	%	$	501		39	%
Commercial		450		35			440		35
Industrial		119		9			119		9

Total retail sales		1,128		87			1,060		83
Trojan refund liability		(33	)	(3	)		-		-
Other retail revenues		20		2			54		4
Direct access customers		(7	)	(1	)		(9	)	(1	)

Total retail revenues		1,108		85			1,105		87
Wholesale revenues		153		12			149		12
Other operating revenues		35		3			19		1

Revenues, net	$	1,296		100	%	$	1,273		100	%


Energy sold and delivered (MWhs in thousands):
Retail energy sales:
Residential		5,765		33	%		5,504		31	%
Commercial		5,439		31			5,442		31
Industrial		1,857		11			1,875		11

Total retail energy sales		13,061		75			12,821		73
Delivery to direct access customers		1,825		11			1,612		9

Total retail energy deliveries		14,886		86			14,433		82
Wholesale sales		2,429		14			3,161		18

Total energy sold and delivered		17,315		100	%		17,594		100	%

Percentages may not add due to rounding.

The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:


	Heating		Cooling
	2008	2007	2008	2007
1st Quarter	1,981	1,852	-	-
2nd Quarter	860	698	98	56
3rd Quarter	80	123	376	344

Year-to-date	2,921	2,673	474	400

15-year average for the year-to-date	2,586	2,586	452	452

Total revenues increased $23 million, or 2%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 as a result of the following factors:

Total retail revenues increased $3 million due primarily to:

^¡

A $28 million increase resulting from a 2% increase in average price, which was driven by price increases for the Company’s smart meter project and recovery of Port Westward and Biglow Canyon Phase I; and

^¡

A $21 million increase resulting from a 3% increase in total retail energy deliveries, due to more extreme weather conditions in 2008, as indicated in the above table, and a 1.4% increase in the average number of customers served during the first nine months of 2008 relative to the first nine months of 2007.

Largely offsetting the above increases were the following decreases:

^¡

A $33.1 million accrual of refunds to customers pursuant to the OPUC order issued September 30, 2008 related to various Trojan matters;

^¡

An $17 million decrease related to SB 408, with an estimated refund due to customers of $7 million recorded in 2008, compared to an estimated collection from customers of $10 million recorded in 2007.

On a weather adjusted basis, retail energy deliveries increased 1.5% for the nine months ended September 30, 2008, with deliveries to residential, commercial, and industrial customers increasing by 1.7%, 0.4%, and 3.0% respectively. PGE projects an approximate 1.5% increase in total weather adjusted energy deliveries for 2008, with higher use by industrial customers projected during the last quarter of the year offset by lower residential and commercial use.

Other retail revenues for the nine month periods ended September 30, 2008 and 2007 include $20 million and $42 million, respectively, in customer credits under the Residential Exchange Program administered by the BPA, with such amounts fully offset within Retail sales to residential and commercial customers. As a result of a decision by the Ninth Circuit, the BPA suspended such benefits in May 2007. In April 2008, benefits were temporarily restored under an Interim Relief agreement with the BPA. The resumption of customer credits, as approved by the OPUC, resulted in an average price reduction of approximately 6.3% for residential and small farm customers, effective April 15, 2008.

Wholesale revenues increased $4 million, or 3%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 due to the net effect of the following:

^¡

A $39 million increase resulting from a 34% increase in average price, caused by both higher natural gas prices and lower hydro availability; partially offset by

^¡

A $35 million decrease resulting from a 23% reduction in wholesale energy sales volume.

Other operating revenues increased $16 million, or 84%, due to sales of fuel oil from the Company’s Beaver generating plant in 2008, which resulted in a gain of $11 million.

Purchased power and fuel expense for the nine months ended September 30, 2008 increased $32 million, or 5%, from the comparable period of 2007. Information about PGE’s total system load and retail load requirement for the periods presented is as follows (in thousands of MWhs):


	Nine Months Ended September 30,
	2008		2007
Generation	8,386		7,176
Term purchases	6,790		8,709
Spot purchases	1,191		1,014

Total system load	16,367		16,899
Less: wholesale sales	(2,429	)	(3,161	)

Retail load requirement	13,938		13,738

The average variable power cost of the above total system loads was $39.79 and $37.39 per MWh in the first nine months of 2008 and 2007, respectively, an increase of 6%. Averages exclude the effect of amounts related to regulatory power cost deferrals and wholesale credit provisions.

The increase in Purchased power and fuel expense was due to the net effect of the following factors:

—

A $99 million increase in the cost of thermal production, due primarily to a 39% increase in the average cost of natural gas and a 41% increase in gas-fired generation with the completion of Port Westward in June 2007;

—

A $20 million increase related to the deferral of excess Boardman power costs in the first quarter of 2007, which were incurred in late 2005 and early 2006;

—

A $5 million increase due to a reduction in the Company’s wholesale credit reserve in the first quarter of 2007, primarily as a result of a settlement with certain California parties involving transactions in 2000-2001;

—

A $46 million decrease in the cost of purchased power, due primarily to an 18% decrease in purchases, related to increases in thermal and wind generation resulting from the addition of Port Westward and Biglow Canyon Phase I to the Company’s generation portfolio;

—

A $37 million decrease related to settled natural gas swap agreements entered into in conjunction with PGE’s management of its net power costs, due to increased natural gas prices; and

—

A $14 million decrease in the estimated amount recorded for potential future refund to customers under the PCAM.

Sources of Energy - The following table indicates that portion of PGE’s total load requirement met with each listed source for the periods presented:


	Nine Months Ended September 30,
	2008		2007
Generation:
Thermal	41	%	35	%
Hydro	9		8
Wind	2		-

Total generation	52	%	43	%

Purchased power:
Term purchases	26	%	35	%
Spot purchases	7		6
Mid-Columbia hydro projects	15		16

Total purchases	48	%	57	%

Total load requirement	100	%	100	%

Generation at PGE thermal plants increased by 14% in the first nine months of 2008 compared to the first nine months of 2007, due primarily to the addition of Port Westward in June 2007. Wind generation from Biglow Canyon Phase I comprised 4% of the Company’s total generation in the first nine months of 2008. These new generating resources have resulted in reduced reliance on power purchases in the wholesale market.

Energy from hydro resources in the first nine months of 2008 decreased 4% from the comparable period of 2007. A 6% increase in Company-owned hydro production, resulting from higher stream flows, was more than offset by a 10% reduction in energy received under long-term purchase power agreements from hydro facilities on the mid-Columbia River.

Production and distribution expense increased $16 million, or 15%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. The increase is due primarily to the following:

•

A $7 million increase in operating costs at the Company’s generating facilities, including Port Westward, which was completed in June 2007, and Biglow Canyon Phase I, which was completed in December 2007;

•

A $4 million increase in distribution labor, contractor and tree trimming costs; and

•

A $3 million increase resulting from increased repairs and maintenance expenses incurred on the Boardman and Beaver plants in connection with scheduled maintenance activities.

Administrative and other expense increased $6 million, or 4%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to an increase in legal settlement expense, higher employee benefit expenses and an increase in the provision for uncollectible accounts.

Depreciation and amortization expense increased $20 million, or 15%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. The increase is primarily due to the following:

•

A $14 million increase related to capital plant additions, primarily Port Westward and Biglow Canyon Phase I, which were placed in service in June 2007 and December 2007, respectively; and

•

A $4 million increase related to accelerated depreciation of existing meters that are being replaced as part of the Company’s smart meter project.

Taxes other than income taxes increased $3 million, or 5%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. The increase is due primarily to higher property taxes and city franchise fees resulting from increases in assessed values and retail revenues, respectively.

Other income decreased $22 million, or 96%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. The decrease is primarily due to the following:

•

A $15 million decrease in income from non-qualified benefit plan trust assets resulting from the recognition of a $9 million decline in the fair market value of the plan assets during the nine months ended September 30, 2008, compared to a $6 million increase in the fair market value in the comparable period of 2007;

•

A $6 million decrease in the allowance for equity funds used during construction, which resulted from lower construction work in progress balances during the first nine months of 2008 due to the completion of both Port Westward and Biglow Canyon Phase I in 2007; and

•

A decrease in interest income on regulatory assets.

Interest expense increased $13 million, or 24%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. The increase is due primarily to a higher average outstanding balance of long-term debt resulting from the issuance of First Mortgage Bonds during the last seven months of 2007, partially offset by a lower average outstanding balance of commercial paper. During the first nine months of 2008, the average outstanding balance of short- and long-term debt was $1,329 million, compared to $1,161 million for the first nine months of 2007, which resulted in an increase to interest expense of approximately $10 million. Additionally, the credit to interest expense for AFDC decreased $3 million as a result of lower construction work in progress balances during the first nine months of 2008 compared to the first nine months of 2007.

Income tax expense decreased $35 million for the nine months ended September 30, 2008, with an effective tax rate of 29%, compared to the nine months ended September 30, 2007, with an effective tax rate of 34%. These decreases are primarily the result of lower taxable income and an increase of $5 million in federal energy tax credits generated from the operation of Biglow Canyon Phase I in 2008.

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s projected capital cash requirements, excluding AFDC, for the years indicated (in millions):


	2008		2009			2010		2011		2012
Capital expenditures	$	222	$	240			$225-$245		$240-$260		$250-$270
Biglow Canyon Phase II		75		234			-		-		-
Biglow Canyon Phase III		23		180			185		-		-
Hydro licensing and construction		59		25					$40 - $60
Smart meter project		19		79			31		-		-
Boardman emissions controls ⁽¹⁾		3		2				$	295 - $335

Total capital expenditures	$	401	$	760


Long-term debt maturities	$	-	$	142	⁽²⁾	$	186	$	-	$	100

(1)	Represents 80% of estimated total costs, which assumes the Purchaser does not exercise certain rights pursuant to existing agreements. See Air Quality Standards below.

(2)	For further information, see “Credit Facility and Debt” in Note 2, Balance Sheet Components, in the Notes to Condensed Consolidated Financial Statements.

Capital Expenditures - Consists of upgrades to and replacement of transmission, distribution and generation infrastructure, as well as new customer connections.

Biglow Canyon - In 2008, PGE entered into various agreements for the construction of Phases II and III of the project. The estimated total cost of Phases II and III is $730 million to $770 million, including AFDC of approximately $40 million, with Phases II and III expected to be completed by the end of 2009 and 2010, respectively.

Hydro licensing and construction - As required under the 50-year license that the FERC issued to PGE in 2004 for its Pelton/Round Butte project on the Deschutes River, PGE began construction of a selective water withdrawal system in late 2007 in an effort to restore fish passage on the upper portion of the river. The system will collect juvenile salmon and steelhead, allowing them to bypass the dam when migrating to the Pacific Ocean, and will regulate downstream water temperature. The system is expected to be completed in 2009. Amounts presented in the table above represent PGE’s portion of the estimated total cost to complete the project, as well as other relicensing costs.

The Company filed an application with the FERC in 2004 to relicense the Clackamas River hydroelectric projects. A settlement agreement, resolving most of the issues raised in the relicensing proceeding and providing for a 45-year license term, was signed by the thirty-three participating parties in March 2006 and was submitted to the FERC for review and approval. In June 2008, PGE filed an application with the DEQ proposing final resolution to the remaining lower Clackamas River temperature issues. Pending issuance of the new license, the project will operate under annual licenses issued by the FERC. It is expected that the DEQ will complete its water quality certification process in 2009 and the FERC will issue a new license for the Clackamas River projects in 2010.

In October 2002, PGE entered into an agreement with state and federal agencies, conservation groups, and others regarding removal of the Company’s 22 MW Bull Run hydroelectric project located in the Sandy River basin. During the second quarter of 2008, the project ceased generation, as planned. The project is currently being decommissioned and project facilities are being removed consistent with the May 2004 FERC Surrender Order.

Smart meter project - PGE plans to install approximately 850,000 new customer meters that will enable two-way remote communications with the Company. In May 2008, the OPUC approved PGE’s smart meter project. Approximately 16,000 new meters are being installed as part of the project’s acceptance testing phase, with the remaining meters to be installed starting in 2009 through 2010. PGE expects the smart meter project to provide improved services, operational efficiencies, and a reduction in future operating expenses.

Air Quality Standards - The Boardman and Beaver generating plants are subject to EPA’s Regional Haze Regulations, which may require installation of retrofit controls to achieve visibility improvement in several federally protected areas.

In November 2007, the Company submitted a Best Available Retrofit Technology (BART) Determination to the DEQ for Boardman that stated the BART for Boardman is a combination of New Low NOx Burners, Modified Over Fire Air System, Selective Non-Catalytic Reduction (SNCR), and Semi-dry Flue Gas Desulphurization. PGE has also proposed to meet requirements of the Oregon Utility Mercury Rule through a Mercury Sorbent Injection System to be installed in conjunction with BART controls. The total cost for these controls is estimated to be in the range of $360 million to $470 million (100% of total costs, excluding AFDC, in nominal dollars). PGE has no commitments in place at this time, and cautions that the cost estimates are preliminary and subject to change.

In the third quarter of 2008, the DEQ issued a preliminary proposal that would require the installation of controls at the Boardman plant in three phases. The first phase would require installation of controls for oxides of nitrogen (NOx) as required under the Clean Air Act with estimated completion in 2011. The second phase would address mercury and sulfur dioxide removal using a semi dry scrubber and bag house, with estimated completion 2014. The DEQ proposes that these first two phases would meet federal requirements for installing BART. The third phase would require the installation of Selective Catalytic Reduction (SCR) for additional NOx control with estimated completion in 2017. The DEQ proposes that the third phase would meet reasonable progress requirements towards haze emission reduction goals. PGE estimates that the DEQ proposal would cost between $507 million and $686 million (100% of total costs, excluding AFDC, in nominal dollars). The DEQ proposal is open for comment and public input. A draft rule is expected to be issued in December 2008. The Oregon Environmental Quality Commission is expected to adopt a rule in April 2009 after appropriate public process has been completed. The rule will be submitted to EPA for approval as part of the Oregon Regional Haze State Implementation Plan (SIP). The company expects EPA to issue a decision on the SIP in early 2010.

PGE continues to believe that the retrofit controls proposed in its November 2007 BART filing will adequately address emission concerns at Boardman. As the regulatory requirements are clarified by the relevant agencies and the related costs more closely estimated, the Company will further evaluate the economic prudence of these expenditures. In doing so, the Company will also consider additional costs such as taxes, emission fees and other costs that may be imposed under any future laws related to climate change, as well as the Company’s ability to recover these costs through the ratemaking process. Such additional costs, as well as any requirement to install SCR controls, could require an investment in excess of what the plant can economically support. The ultimate impact that the above regulatory requirements and emission controls will have on future operations, costs, or generating capacity of the Company’s thermal generating plants is not yet determinable and will be evaluated through the IRP process.

In 1985, PGE entered into a sale transaction in which it sold an undivided 15% interest in Boardman and a 10.714% undivided interest in the Pacific Northwest Intertie (Intertie) transmission line (jointly, the Boardman Assets) to a third party financial institution (Purchaser). The Purchaser leased the Boardman Assets to a lessee (Lessee) unrelated to PGE or the Purchaser. The term of the lease ends on December 31, 2013. Concurrently with the sale, PGE assigned to the Lessee certain agreements for the sale of power and transmission services from Boardman and the Intertie (P&T Agreements) to a regulated electric utility (Utility) unrelated to PGE, the Purchaser, or the Lessee. The payments by the Utility under the P&T Agreements generally cover the payment obligations of the Lessee under the lease, but do not cover all capital expenditures and are not expected to cover a material portion of the costs relating to the controls for the Boardman generating plant. The Purchaser has certain rights to participate in the financing of the portion of the total cost attributable to its interest. As a result of these agreements, PGE’s share of the total cost for the emission controls on the Boardman generating plant is expected to be 80% if the Purchaser does not exercise its rights under the agreements to finance the portion of the total cost attributable to its interest. At the expiration of the lease, and in certain other circumstances, PGE has an option to repurchase the Boardman Assets.

In April 2008, PGE submitted an application for a modification of its Beaver generating plant operating permit, pursuant to the BART process. The proposed permit modifications would restrict the use of oil to fuel the Beaver generating plant to reduce emissions below the BART threshold. The operational restrictions would not impact the plant’s capacity to burn natural gas.

Emergency Economic Stabilization Act of 2008

In response to the recent turmoil in the capital markets, the Emergency Economic Stabilization Act of 2008 (EESA) was enacted on October 1, 2008. In addition to a $700 billion financial rescue package, the EESA includes several other provisions of interest to PGE and its customers. These include, but are not limited to: the extension of the renewables production tax credit; extension and expansion of solar investment tax credit and energy efficiency incentives; accelerated depreciation for smart meters; a new plug-in vehicle credit; and extension of research and development tax credits. PGE is in the process of determining the impact that the EESA will have on its operations.

Liquidity

PGE’s access to short-term debt markets, including revolving credit from banks, provides necessary liquidity to support the Company’s current operating activities, including the purchase of electricity and fuel for the generation of electricity. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, as well as debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposits related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

PGE has an unsecured $400 million revolving credit facility with a group of banks that supplements operating cash flow and provides a primary source of liquidity. The Credit Facility is available to the Company for borrowings for general corporate purposes and the issuance of standby letters of credit, as well as for supporting the Company’s commercial paper program, under which it may issue commercial paper for terms of up to 270 days. The commercial paper program requires the Company to maintain unused revolving credit capacity at least equal to the amount of commercial paper issued. In June 2008, PGE extended the maturity on $390 million of the facility to July 2013, with the remaining $10 million maturing in July 2012.

On September 15, 2008, Lehman’s parent company, Lehman Brothers Holdings, Inc., filed for protection under Chapter 11 of the U.S. Bankruptcy Code. At that time, Lehman represented $55 million, or approximately 14%, of the Credit Facility. In October 2008, $25 million of Lehman’s $55 million share of the Credit Facility was reassigned to Sumitomo. The Company is in discussions with another financial institution for reassignment of the remaining $30 million of Lehman’s share.

In October 2008, Wells Fargo announced the proposed acquisition of Wachovia. Wells Fargo and Wachovia each participate in the Credit Facility, with Wells Fargo representing $55 million, or 14%, and Wachovia representing $70 million, or 18%, of the Credit Facility. It is not expected that the proposed merger of Wells Fargo and Wachovia will have an impact on the Company’s ability to access funds available to it pursuant to the Credit Facility. The proposed merger is expected to close during the fourth quarter of 2008.

As of September 30, 2008, the Company has financial assets of $31 million and financial liabilities of $93 million included in the Level 3 category pursuant to SFAS 157. See Note 3, Financial Instruments, in the Notes to Condensed Consolidated Financial Statements. These financial instruments are recorded at fair value and may consist of forward, swap and option contracts for electricity and natural gas and futures contracts for natural gas. Fair value of all forward, swap and futures contracts is calculated using internally developed forward price curves based on observed daily market activity and conditions. These forward curves are compared to non-binding quotes received from various brokers and validated against actual transactions executed just prior to and after the balance sheet date for contracts that deliver within 24 months. Forward pricing for contracts that deliver subsequent to 24 months from the balance sheet date is not currently validated, and those contracts receive the Level 3 categorization. Creditworthiness and counterparty exposure is continually monitored and any adjustments deemed necessary are made to fair value measurements across all SFAS 157 levels. For option contracts, fair value is calculated using standard financial models that utilize interest rate and price curves, time to expiration, and internally developed price volatility and correlation curves. Any change in the assumptions used to determine fair value of these financial instruments, including market conditions which can vary significantly depending on the weather and the economy, would not have an impact on the financial condition or results of operations of the Company as changes in the fair value of these financial instruments are fully offset by the effects of regulatory accounting pursuant to SFAS 71.

PGE’s cash flows were as follows (in millions):


	Nine Months Ended September 30,
	2008			2007
Cash and cash equivalents at January 1	$	73		$	12
Net cash provided by (used in):
Operating activities		222			291
Investing activities		(277	)		(351	)
Financing activities		(13	)		108

Net change in cash and cash equivalents		(68	)		48

Cash and cash equivalents at September 30	$	5		$	60

Net cash provided by operating activities decreased $69 million in the first nine months of 2008 compared to the first nine months of 2007. This decrease is primarily due to the net effect of the following factors:

—

A $127 million decrease related to higher margin deposit requirements with certain wholesale customers and brokers, driven primarily by power and natural gas price decreases, as discussed below;

—

A $28 million decrease resulting from a 2007 cash settlement from the California Power Exchange, related to wholesale energy transactions in 2000-2001;

—

A $12 million decrease as the result of higher interest payments in 2008;

—

A $7 million decrease resulting from higher payments for power and fuel purchases;

—

A $63 million increase in cash received from retail sales of electricity;

—

A $24 million increase related to the Residential Exchange Program; and

—

A $22 million increase resulting from reduced income tax payments in 2008.

During the nine months ended September 30, 2008, PGE’s net assets from price risk management activities decreased $139 million. These derivative instruments are recorded at their estimated fair value (“mark-to-market”), as discussed in Note 3, Financial Instruments, in the Notes to the Condensed Consolidated Financial Statements. During the first nine months of 2008, the commodities market experienced significant volatility which resulted in, among other things, decreased market prices for purchased power and natural gas in the third quarter. Pursuant to regulatory accounting under SFAS 71, the mark-to-market of PGE’s derivative instruments is deferred and, accordingly, the Company’s net regulatory liability related to price risk management decreased $139 million, with no impact to the statement of operations.

A significant portion of cash provided by operations consists of depreciation and amortization of electric utility plant, which is recovered in prices with no current direct cash outlay as it represents the recovery of prior investments. PGE estimates recovery of such charges to approximate $208 million in 2008. Combined with all other sources, cash provided by operations is estimated to approximate $370 million in 2008.

Net cash used in investing activities decreased $74 million in the first nine months of 2008 compared to the first nine months of 2007. This decrease is primarily due to the net effect of the following factors:

—

An $82 million decrease in expenditures for the Biglow Canyon project;

—

A $28 million increase in expenditures for the Pelton/Round Butte selective water withdrawal system;

—

A $27 million decrease in construction costs for Port Westward, which was completed in June 2007; and

—

Insurance proceeds of $3 million received in 2008 related to storm damage to substations in 2006.

See “Capital Requirements” section above for further information.

Net cash flows used in financing activities increased $121 million in the first nine months of 2008 compared to the first nine months of 2007. Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. PGE relies on cash from operations, the issuance of commercial paper, borrowings under its revolving credit facility, and long-term financing activities to support such requirements. During the first nine months of 2008, net cash used in financing activities consisted of the repayment of long-term debt of $56 million and the payment of dividends of $45 million, partially offset by $38 million of net short-term debt borrowings. PGE also issued $50 million of long-term debt in the first nine months of 2008. During the same period of 2007, net cash flow from financing activities consisted primarily of the issuance of long-term debt of $306 million, partially offset by the net repayment of $81 million of short-term debt, the repayment of long-term debt of $71 million, and the payment of $43 million in dividends.

Dividends on Common Stock

While the Company expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deem relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

Common stock dividends declared during 2008 consist of the following:


Declaration Date	Record Date	Payment Date	Dividends Declared per Share
February 20, 2008	March 25, 2008	April 15, 2008	$	0.235
May 7, 2008	June 25, 2008	July 15, 2008		0.245
August 6, 2008	September 25, 2008	October 15, 2008		0.245
October 29, 2008	December 26, 2008	January 15, 2009		0.245

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital financing between now and 2010 at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, alternatives available to investors, and the condition of the capital markets. The Company’s ability to obtain and renew such financing depends on its credit ratings as well as its access to capital markets, both generally and for electric utilities in particular. Despite the recent turmoil in the capital markets, management believes that the availability of funds under the Credit Facility, as well as the expected ability to increase short-term credit capacity and to issue long-term debt and equity securities, would provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. Management believes that PGE continues to have access to these markets, although the cost of borrowing for all companies,

including PGE, has increased due to the recent problems in the capital markets. The Company anticipates issuing a total of approximately $230 million of equity and $300 million of new long-term debt in late 2008 or in 2009, subject to market conditions and availability of capital. Furthermore, the Company expects to remarket $142 million of tax-exempt bonds, which have a mandatory tender date of May 1, 2009.

PGE’s financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company’s financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were 50.2% and 50.0% as of September 30, 2008 and December 31, 2007, respectively.

For further information regarding PGE’s Credit Facility and debt financing activities, see “Credit Facility and Debt” in Note 2, Balance Sheet Components, in the Notes to Condensed Consolidated Financial Statements.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). PGE’s current credit ratings and outlook are as follows:


	Moody’s	S&P
First Mortgage Bonds	Baa1	A
Senior unsecured debt	Baa2	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to provide additional performance assurance collateral. On September 30, 2008, PGE had provided approximately $167 million of collateral, consisting of $144 million in cash and $23 million in letters of credit, none of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of September 30, 2008, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $75 million and decreases to approximately $39 million by December 31, 2008. The approximate amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $122 million and decreases to approximately $70 million by December 31, 2008.

PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade.

The issuance of additional First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Company’s Amended and Restated Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on September 30, 2008 it could issue up to approximately $640 million of additional First Mortgage Bonds under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust. Any issuances would be subject to market conditions and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust on the basis of property additions, bond credits, and/or deposits of cash.

PGE’s Credit Facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. As of September 30, 2008, the Company’s consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 49.8%.

Off Balance Sheet Arrangements

PGE has no off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on its consolidated financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Contractual Obligations

PGE’s contractual obligations for 2008 and beyond are included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008. Obligations for 2008 and beyond have not changed materially except as presented below. As of September 30, 2008, PGE has the following additional purchase commitments (in millions):


	Payments Due
	2008 *		2009		2010		2011		2012		There- after		Total
Purchase obligations	$	-	$	350	$	170	$	6	$	3	$	-	$	529
Electricity purchases		36		110		4		-		-		-		150
Natural gas agreements		21		21		19		16		-		-		77
Coal and transportation agreements		-		18		13		10		-		-		41

	$	57	$	499	$	206	$	32	$	3	$	-	$	797

* Represents the period from October 1, 2008 through December 31, 2008.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

The Company is subject to various market risks which include commodity price risk, credit risk, foreign currency exchange rate risk, and interest rate risk. There have been no material changes to market risks affecting the Company set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008, except as presented below.

Due to the recent activity in the credit markets, PGE has assessed the exposure and creditworthiness of the wholesale counterparties associated with major financial institutions. At September 30, 2008, no material changes or allowances were required due to estimated performance risk or credit risk of the parties to each contract. However, on September 15, 2008, Lehman Brothers Holdings Inc. (LBHI), along with certain subsidiaries, filed a petition to initiate bankruptcy proceedings under Chapter 11 of the U.S. Bankruptcy Code. The Company had a minor net wholesale commodity position with a wholly-owned subsidiary of LBHI; the outcome of which will not have a material adverse impact on the financial condition or the results of operations for future reporting periods.

The following table presents the credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. As of September 30, 2008, PGE’s credit risk exposure for commodity activities and their subsequent maturity is as follows (dollars in millions):


	Credit Risk Before Collateral		As % of Total		Credit Collateral		Maturity of Credit Risk Exposure
	Credit Risk Before Collateral		As % of Total		Credit Collateral		2008 *		2009		2010		2011		2012		There- after
Externally rated:
Investment grade	$	80	100	%	$	46	$	11	$	10	$	16	$	15	$	15	$	13
Non-investment grade		-	-			1		-		-		-		-		-		-
Internally rated:
Investment grade		-	-			-		-		-		-		-		-		-

Total	$	80	100	%	$	47	$	11	$	10	$	16	$	15	$	15	$	13

* Represents the period from October 1, 2008 through December 31, 2008.

As of September 30, 2008, there was no posted collateral subject to be returned to a counterparty that is affiliated with master netting arrangements. Posted collateral may be in the form of cash or letters of credit and may represent prepayment.

Item 4.

Controls and Procedures.

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2008, these disclosure controls and procedures were effective at the reasonable assurance level to ensure that information required to be disclosed by PGE in reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There have been no changes in the Company’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings.

For further information regarding legal proceedings, see PGE’s Legal Proceedings set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008 and subsequent Quarterly Reports on Form 10-Q.

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, Public Utility Commission of Oregon Docket Nos. DR10, UE 88, and UM 989, Marion County Oregon Circuit Court, Case No. 94C-10417, the Court of Appeals of the State of Oregon, the Oregon Supreme Court, Case No. SC S45653.

On September 30, 2008, the OPUC issued an order that requires PGE to refund $33.1 million to customers. The refund relates to the unamortized Trojan balance on September 30, 2000, as discussed below.

In the order, the OPUC also made the following findings:

—

The OPUC has authority to order a utility to issue refunds under certain limited circumstances; and

—

PGE’s rates that were in effect for the period April 1, 1995 through September 30, 2000 were just and reasonable.

The OPUC examined the rates in effect for the period April 1, 1995 through September 30, 2000 and determined what rates during this period would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. The OPUC removed the previously allowed return on the Company’s Trojan investment during the period, reduced the recovery period from 17 to 10 years, and revised certain other assumptions, all of which reduced the recoverable balance as of September 30, 2000 from $180.5 million to $165.1 million. The OPUC ruled that the difference of $15.4 million, plus interest at 9.6% from September 30, 2000, should be refunded to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The $15.4 million amount, plus accrued interest results in a total refund of $33.1 million as of September 30, 2008. The order also provides that the total refund amount will earn interest at 9.6% from October 1, 2008 until all refunds are issued to customers. The Company expects the refunds to customers to occur by mid-2009.

On October 22, 2008, the URP and the class action plaintiffs in the Dreyer case (see below) separately appealed this order to the Oregon Court of Appeals. PGE is continuing to review and evaluate the order along with the subsequent appeals.

Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court, Case No. 03C 10639; and Morgan v. Portland General Electric Company, Marion County Circuit Court, Case No. 03C 10640.

At a status conference on October 15, 2008, the Circuit Court set a schedule for the filing of briefs on the plaintiffs’ motion to lift the abatement. The schedule calls for the completion of briefing by November 25, 2008 and oral argument on January 12, 2009.

Sierra Club et al. v. Portland General Electric Company, U.S. District Court for the District of Oregon, Case No. CV 08-1136-HA.

On January 15, 2008, plaintiffs sent PGE a sixty-day notice of intent to sue for alleged violations of the federal Clean Air Act (CAA), Oregon’s State Implementation Plan (SIP) at PGE’s Boardman Coal Plant, and the Plant’s CAA Title V permit. On September 30, 2008, the plaintiffs sued PGE for these and additional alleged violations of various environmental related regulations.

The plaintiffs are seeking injunctive relief that includes permanently enjoining PGE from operating the Boardman Coal Plant except in accordance with the CAA, Oregon’s SIP, and the Plant’s Title V Permit. In addition, plaintiffs are seeking civil penalties against PGE including $27,500 per day per alleged violation for violations occurring before March 15, 2004 and $32,500 per day per alleged violation occurring thereafter. The total amount of monetary penalties and damages asserted in the complaint cannot be determined with certainty. However, based solely on the complaint, the Company estimates that the amount is approximately $60 million. The Company believes that it has strong defenses to the plaintiffs’ claims and intends to vigorously defend against this lawsuit.

Item 1A.

Risk Factors.

The following risk factors supplement PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27:

The current capital and credit market conditions may adversely affect the Company’s access to capital and cost of capital.

Access to capital markets is important to PGE’s ability to operate and the Company expects to issue both debt and equity in late 2008 or in 2009 in order to fund capital projects. In October 2008, the general economic and capital market conditions in the United States and other parts of the world have deteriorated significantly and have adversely affected access to capital and increased the cost of capital. If these conditions continue or become worse, the Company’s future cost of debt and equity capital and the Company’s future access to capital markets could be adversely affected.

The current economic downturn may impair the financial soundness of vendors, service providers and customers, which could adversely affect the Company’s business operations.

As a result of the current economic downturn, increases in energy costs and macro-economic challenges currently affecting the economy of the United States and other parts of the world, the Company’s vendors and service providers may experience serious cash flow problems and, as a result, may be unable to perform under existing contracts or may significantly increase their prices or reduce their output or performance on future contracts.

Furthermore, if customers are not successful in generating sufficient revenue or are precluded from securing financing, they may not be able to pay, or may delay payment of, accounts receivable that are owed to the Company. Any inability of current and/or future customers to pay the Company for its products may adversely affect the Company’s earnings and cash flow.

Item 6.

Exhibits.


3.1		Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 3, 2006).

3.2		Fifth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 8, 2007).

31.1		Certification of Chief Executive Officer.

31.2		Certification of Chief Financial Officer.

32		Certifications of Chief Executive Officer and Chief Financial Officer.

Certain instruments defining the rights of holders of other long-term debt of the Company are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.

SIGNATURE

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 thereunto duly authorized.


	PORTLAND GENERAL ELECTRIC COMPANY
	(Registrant)

Date: October 30, 2008	By:	/s/ James J. Piro
		James J. Piro
		Executive Vice President, Finance, Chief Financial Officer and Treasurer
		(duly authorized officer and principal financial officer)