Portland General Electric (POR) 10-Q 2009 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period endedSeptember 30, 2009 or

¨ 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).    ¨  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 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 26, 2009 is 75,191,682 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009

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	7
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 4.	Controls and Procedures	60
	PART II – OTHER INFORMATION	61
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	62
Item 6.	Exhibits	62
SIGNATURE		63

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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym	Definition
AFDC	Allowance for funds used during construction
ASC	Accounting Standards Codification
Biglow Canyon	Biglow Canyon Wind Farm
Boardman	Boardman coal plant
CERS	California Energy Resources Scheduling
Colstrip	Colstrip Units 3 and 4 coal plant
DEQ	Oregon Department of Environmental Quality
EITF	Emerging Issues Task Force of the Financial Accounting Standards Board
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
IRP	Integrated Resource Plan
kV	Kilovolt = one thousand volts of electricity
MW	Megawatts
MWa	Average megawatts
MWh	Megawatt hours
NVPC	Net Variable Power Costs
OPUC	Public Utility Commission of Oregon
PCAM	Power Cost Adjustment Mechanism
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

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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,
	2009			2008			2009			2008
Revenues	$	445		$	400		$	1,319		$	1,296
Operating expenses:
Purchased power and fuel		225			217			664			652
Production and distribution		42			40			127			125
Administrative and other		43			48			134			142
Depreciation and amortization		53			54			160			154
Taxes other than income taxes		20			20			64			63
Total operating expenses		383			379			1,149			1,136
Income from operations		62			21			170			160
Other income (expense):
Allowance for equity funds used during construction		5			3			13			7
Miscellaneous income (expense), net		5			(4	)		6			(6	)
Other income (expense), net		10			(1	)		19			1
Interest expense		25			21			76			67
Income (loss) before income tax expense (benefit)		47			(1	)		113			94
Income tax expense (benefit)		16			(1	)		32			27
Net income		31			-			81			67
Less: net loss attributable to noncontrolling interests		(1	)		-			(6	)		-
Net income attributable to Portland GeneralElectric Company	$	32		$	-		$	87		$	67
Weighted-average shares outstanding (in thousands):
Basic		75,182			62,554			71,980			62,539
Diluted		75,223			62,607			72,057			62,589
Earnings per share - basic and diluted	$	0.43		$	-		$	1.21		$	1.08
Dividends declared per common share	$	0.255		$	0.245		$	0.755		$	0.725

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)

	September 30, 2009		December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	46	$	10
Accounts receivable, net		137		168
Unbilled revenues		66		96
Assets from price risk management activities - current		22		31
Inventories		72		71
Margin deposits		86		189
Current deferred income taxes		92		17
Regulatory assets - current		200		194
Other current assets		44		44
Total current assets		765		820
Electric utility plant, net		3,800		3,301
Non-qualified benefit plan trust		48		46
Nuclear decommissioning trust		49		46
Regulatory assets - noncurrent		534		631
Other noncurrent assets		56		45
Total assets	$	5,252	$	4,889

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)

	September 30, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	206		$	217
Liabilities from price risk management activities - current		187			225
Regulatory liabilities - current		57			43
Short-term debt		-			203
Current portion of long-term debt		186			142
Other current liabilities		111			59
Total current liabilities		747			889
Long-term debt, net of current portion		1,408			1,164
Liabilities from price risk management activities - noncurrent		133			201
Regulatory liabilities - noncurrent		658			640
Noncurrent deferred income taxes		408			304
Unfunded status of pension and postretirement plans		177			174
Non-qualified benefit plan liabilities		94			91
Other noncurrent liabilities		72			72
Total liabilities		3,697			3,535
Commitments and contingencies (see notes)
Shareholders’ equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2009 and December 31, 2008		-			-
Common stock, no par value, 160,000,000 shares authorized; 75,191,682 and 62,575,257 shares issued and outstanding as of September 30, 2009 and December 31, 2008, respectively		829			659
Accumulated other comprehensive loss		(5	)		(5	)
Retained earnings		730			700
Total Portland General Electric Company shareholders’ equity		1,554			1,354
Noncontrolling interests’ equity		1			-
Total shareholders’ equity		1,555			1,354
Total liabilities and shareholders’ equity	$	5,252		$	4,889

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
Cash flows from operating activities:
Net income	$	81		$	67
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		160			154
Increase (decrease) in net liabilities (assets) from price risk management activities		(94	)		139
Regulatory deferral - price risk management activities		94			(139	)
Deferred income taxes		23			9
Allowance for equity funds used during construction		(13	)		(7	)
Power cost deferrals		(13	)		2
Unrealized (gains) losses on non-qualified benefit plan trust assets		(7	)		9
Trojan refund liability		3			33
Other non-cash income and expenses, net		10			21
Changes in working capital:
(Increase) decrease in margin deposits		103			(120	)
Decrease in receivables		61			66
Decrease in payables		(51	)		(10	)
Other working capital items, net		15			7
Other, net		5			(9	)
Net cash provided by operating activities		377			222
Cash flows from investing activities:
Capital expenditures		(544	)		(281	)
Sales of nuclear decommissioning trust securities		30			23
Purchases of nuclear decommissioning trust securities		(31	)		(20	)
Insurance proceeds received		-			3
Other, net		(1	)		(2	)
Net cash used in investing activities		(546	)		(277	)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs	$	170		$	-
Proceeds from issuance of long-term debt		430			50
Debt issuance costs		(4	)		-
Payments on long-term debt		(142	)		(56	)
Borrowings on revolving credit facilities		82			11
Payments on revolving credit facilities		(213	)		-
Borrowings (payments) on short-term debt, net		(72	)		27
Dividends paid		(53	)		(45	)
Noncontrolling interests’ cash contributions		7			-
Net cash provided by (used in) financing activities		205			(13	)
Change in cash and cash equivalents		36			(68	)
Cash and cash equivalents, beginning of period		10			73
Cash and cash equivalents, end of period	$	46		$	5
Supplemental cash flow information is as follows:
Cash paid during the period for:
Interest, net of amounts capitalized	$	46		$	49
Income taxes		-			8
Non-cash investing and financing activities:
Accrued capital additions		73			19
Accrued dividends payable		19			15
Former parent’s capital contribution of Oregon tax credits		-			13

See accompanying notes to condensed consolidated financial statements.

8

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 818,395 retail customers as of September 30, 2009.

As of September 30, 2009, PGE had 2,717 employees, with 889 employees covered under two agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. One agreement, which covers 854 employees for the three-year period ending February 28, 2012, was ratified in the third quarter of 2009. The other agreement covers 35 employees at the Company’s Coyote Springs generating plant for the five-year period ending August 1, 2011.

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 footnote 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, 2009 and 2008 is unaudited; however, such information 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, interim financial results do not necessarily represent those to be expected for the year. The financial information as of December 31, 2008 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2008, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 25, 2009, and should be read in conjunction with such consolidated financial statements.

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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

During the first quarter of 2009, PGE reconsidered the presentation of its Price risk management assets and liabilities, which previously had all been classified as current, as well as its Regulatory assets and liabilities, which previously had all been classified as noncurrent. The Company determined it was preferable to present such assets and liabilities as either current or noncurrent based on the expected settlement dates of the underlying contracts for Price risk management assets and liabilities and the timing of amortization or the timing of the collection or refund of the respective Regulatory asset or liability. To conform to the 2009 presentation, certain reclassifications have been made to the December 31, 2008 condensed consolidated balance sheet. These reclassifications include the presentation of noncurrent Price risk management assets of $8 million (included in Other noncurrent assets) and noncurrent Price risk management liabilities of $201 million, all of which were previously classified as current, and current portion of Regulatory assets of $194 million and current portion of Regulatory liabilities of $43 million, all of which were previously classified as noncurrent. Deferred taxes associated with these Price risk management assets and liabilities and Regulatory assets and liabilities were also reclassified to current or noncurrent, as appropriate. As a result of the preceding reclassifications, current deferred income taxes of $134 million included in the December 31, 2008 condensed consolidated balance sheet have been reclassified as a reduction of Deferred income tax liabilities to conform to the 2009 presentation.

Recent Accounting Pronouncements

Adopted Accounting Pronouncements

On September 30, 2009, PGE adopted Statement of Financial Accounting Standards No. (SFAS) 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles - a replacement of FASB Statement No. 162 (SFAS 168). SFAS 168 modifies the U.S. generally accepted accounting principles (GAAP) hierarchy created by SFAS 162 by establishing only two levels of GAAP: authoritative and nonauthoritative. SFAS 168, which was codified within ASC 105,Generally Accepted Accounting Principles, establishes theFASB Accounting Standards Codification(ASC or Codification) as the single source of authoritative U.S. accounting and reporting standards, except for rules and interpretive releases of the SEC under authority of the federal securities laws, which are sources of authoritative GAAP for SEC registrants. All existing accounting standard documents are superseded and all other accounting literature not included in the Codification is considered nonauthoritative. Accordingly, this report and all subsequent public filings will reference the Codification as the sole source of authoritative literature. As the Codification does not change current GAAP, the adoption of SFAS 168 had no material impact on the Company’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On January 1, 2009, PGE adopted Statement of Financial Accounting Standards No. (SFAS) 157,Fair Value Measurements(SFAS 157), for nonfinancial assets and liabilities, in accordance with FASB Staff Position No. (FSP) 157-2,Effective Date of FASB Statement No. 157(FSP FAS 157-2). SFAS 157, as amended by FSP 157-2, was codified within ASC 820,Fair Value Measurements and Disclosures(ASC 820), upon the adoption of SFAS 168. ASC 820 defines fair value, establishes criteria to be considered

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when measuring fair value and expands disclosures about fair value measurements; it does not modify any currently existing accounting pronouncements. PGE’s nonfinancial liabilities include asset retirement obligations (AROs), which are accounted for in accordance with ASC 360,Property, Plant, and Equipment(ASC 360), and are initially measured at fair value. In subsequent reporting periods, AROs are not measured at fair value. The application of ASC 820 is not required for recurring measurement of nonfinancial liabilities accounted for pursuant to ASC 360 as amounts are only measured at fair value in the initial period and not in subsequent reporting periods. The adoption of FSP FAS 157-2, which was codified within ASC 820 for nonfinancial assets and liabilities, had no impact on the Company’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On January 1, 2009, PGE adopted SFAS 160,Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No 51 (SFAS 160), which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary, as well as the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the deconsolidated 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) continues to allocate to a noncontrolling interest its share of losses if ever that attribution results in a deficit noncontrolling interest balance. SFAS 160 is to be applied prospectively, with the exception of the presentation and disclosure requirements, which are to be applied retrospectively for all periods presented. Beginning January 1, 2009, any noncontrolling interests resulting from the consolidation of a less-than-wholly-owned subsidiary are accounted for in accordance with SFAS 160. The adoption of SFAS 160, which was codified within ASC 810,Consolidation, upon the adoption of SFAS 168, did not have a material impact on PGE’s consolidated financial position or consolidated results of operation. However, it did have an impact on the presentation of noncontrolling interests, formerly known as “minority interests”, in PGE’s consolidated financial position, consolidated results of operation, and consolidated cash flows.

On January 1, 2009, PGE adopted SFAS 161,Disclosures about Derivative Instruments and Hedging Activities(SFAS 161), which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The adoption of SFAS 161, which was codified within ASC 815,Derivatives and Hedging, upon the adoption of SFAS 168, did not have an impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On January 1, 2009, PGE adopted FSP EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), which 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. All prior period earnings per share data is required to be adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1. The adoption of FSP EITF 03-6-1, which was codified within ASC 260,Earnings per Share, upon the adoption of SFAS 168, had no impact on PGE’s earnings per share.

On June 30, 2009, PGE adopted SFAS 165,Subsequent Events (SFAS 165), which provides guidance on the recognition and disclosure of events that occur after the balance sheet date but before financial statements are issued. The adoption of SFAS 165, which was codified within ASC 855,Subsequent Events, upon the adoption of SFAS 168, had no impact on PGE’s consolidated financial position,

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consolidated results of operation, or consolidated cash flows. PGE considered events through October 28, 2009, for purposes of determining whether any event warranted recognition or disclosure in its interim financial statements as of and for the three and nine month periods ended September 30, 2009.

On June 30, 2009, PGE adopted FSP FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments,which requires disclosures about the fair value of financial instruments in interim financial statements as well as in annual financial statements. The adoption of this new pronouncement, which was codified within ASC 825,Financial Instruments, upon the adoption of SFAS 168, had no impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On June 30, 2009, PGE adopted FSP FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4), which requires, among other things, the disclosure in interim and annual periods (1) the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period, and (2) quantitative disclosures about the fair value measurements separately for each major category of assets and liabilities measured at fair value on a recurring basis. The adoption of FSP FAS 157-4, which was codified within ASC 820 upon the adoption of SFAS 168, had no impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

New Accounting Pronouncements

On December 30, 2008, the FASB issued FSP FAS 132(R)-1,Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1), which requires enhanced annual disclosures about plan assets of an employer’s defined benefit pension or other postretirement plans. FSP FAS 132(R)-1 is effective for financial statements for fiscal years ending after December 15, 2009, with earlier application permitted. Upon initial application, the provisions of this FSP are not required for earlier periods that are presented for comparative purposes. The adoption of FSP FAS 132(R)-1, which was codified within ASC 715,Compensation - Retirement Benefits, upon the adoption of SFAS 168, is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On June 12, 2009, the FASB issued SFAS 167,Amendments to FASB Interpretation No. 46(R) (SFAS 167), a revision of FIN 46(R) that changes how a company determines when a variable interest entity (VIE) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. SFAS 167 requires a company to provide additional disclosures about its involvement with variable interest entities and what any significant change in risk exposure does to that involvement. A company will also be required to disclose how its involvement with a VIE affects the company’s performance. SFAS 167 is effective for fiscal years beginning after November 15, 2009. Earlier application is prohibited. PGE is in the process of determining what impact, if any, that the adoption of SFAS 167, as codified within ASC 810,Consolidation, upon the adoption of SFAS 168, will have on its consolidated financial position, consolidated results of operation, or consolidated cash flows.

On August 28, 2009, the FASB issued Accounting Standards Update (ASU) 2009-05,Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value. This Update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of certain alternative valuation techniques, as outlined in the Update. ASU 2009-05 is effective for financial statements for

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interim and annual periods beginning after August 28, 2009, with earlier application permitted. The adoption of ASU 2009-05, as codified within ASC 820, did not have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On September 30, 2009, the FASB issued ASU 2009-12,Fair Value Measurements and Disclosures (Topic 820) - Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). Amendments in this Update provide additional guidance related to measuring the fair value of certain alternative investments. This Update permits, in certain situations, a reporting entity to use the net asset value per share as a practical expedient to measure the fair value of these certain alternative investments. The ASU also requires disclosure by major category of investment about the attributes of the investments, such as the nature of any restrictions on the investor’s ability to redeem its investments at the measurement date. ASU 2009-12 is effective for interim and annual periods ending after December 15, 2009, with early application permitted. The adoption of ASU 2009-12, as codified within ASC 820, is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $5 million as of September 30, 2009 and $4 million as of December 31, 2008.

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

	Nine Months Ended September 30,
	2009			2008
Balance as of beginning of period	$	4		$	5
Provision		7			5
Amounts written off, less recoveries		(6	)		(6	)
Balance as of end of period	$	5		$	4

Inventories

Inventories consist primarily of materials, supplies, and fuel. Materials and supplies inventories, used in operations, maintenance, and capital activities, are recorded at average cost. Fuel inventories, which may include natural gas, oil, and coal used in the Company’s generating plants, are recorded at the lower of average cost or market.

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Electric Utility Plant, Net

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

	September 30, 2009			December 31, 2008
Electric utility plant	$	5,513		$	5,066
Construction work in progress		411			284
Total cost		5,924			5,350
Less: accumulated depreciation and amortization		(2,124	)		(2,049	)
Electric utility plant, net	$	3,800		$	3,301

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $118 million and $109 million as of September 30, 2009 and December 31, 2008, respectively. Amortization expense related to intangible assets was $4 million for the three months ended September 30, 2009 and 2008, and $12 million and $11 million for the nine months ended September 30, 2009 and 2008, respectively.

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Regulatory Assets and Liabilities

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

	September 30, 2009				December 31, 2008
	Current		Noncurrent		Current		Noncurrent
Regulatory Assets:
Price risk management	$	165	$	128	$	194	$	193
Pension and other postretirement plans		-		230		-		232
Deferred income taxes		-		91		-		88
Boardman power cost deferral		-		36		-		34
Debt reacquisition costs		-		26		-		28
Utility rate treatment of income taxes		12		-		-		17
Other		23		23		-		39
Total regulatory assets	$	200	$	534	$	194	$	631
Regulatory liabilities:
Asset retirement removal costs	$	-	$	529	$	-	$	494
Utility rate treatment of income taxes		15		21		24		19
Trojan refund liability		36		-		-		34
Power Cost Adjustment Mechanism		6		-		19		-
Asset retirement obligations		-		29		-		26
Trojan ISFSI pollution control tax credits		-		19		-		17
Other		-		60		-		50
Total regulatory liabilities	$	57	$	658	$	43	$	640

Credit Facilities

PGE has the following unsecured revolving credit facilities:

• A $370 million credit facility with a group of banks, of which $10 million is currently scheduled to terminate in July 2012 and $360 million in July 2013;

• A $125 million credit facility with a group of banks, which is currently scheduled to terminate in December 2009; and

• A $30 million credit facility with a bank, which is currently scheduled to terminate in June 2012.

Pursuant to the individual terms of the agreements, these facilities may be used for borrowings for general corporate purposes and as backup for commercial paper borrowings. The $370 million and $30 million credit facilities also permit the issuance of standby letters of credit. The credit facility agreements contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreements, to 65% of total capitalization. As of September 30, 2009, PGE was in compliance with this covenant.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under its credit facilities.

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Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue up to $550 million of short-term debt, including commercial paper, through February 6, 2010.

As of September 30, 2009, PGE had $190 million in letters of credit outstanding under the credit facilities, and had no borrowings or commercial paper outstanding. As of September 30, 2009, the aggregate amount of unused available credit under the credit facilities was $335 million.

Long-term Debt

During 2009, PGE has issued the following first mortgage bonds:

• On January 15, 2009, $67 million of 6.8% Series due January 15, 2016, with interest paid semi-annually on January 15th and July 15th;

• On January 15, 2009, $63 million of 6.5% Series due January 15, 2014, with interest paid semi-annually on January 15th and July 15th; and

• On April 16, 2009, $300 million of 6.1% Series due April 15, 2019, with interest paid semi-annually on April 15th and October 15th.

First mortgage bonds are secured by a first mortgage lien on substantially all utility property, other than expressly excepted property, and may be redeemed at the Company’s option upon 30 days notice to holders, in whole or in part, at a redemption price equal to the greater of (i) 100% of the principal amount of the bonds to be redeemed or (ii) the present value of the remaining principal and interest payments due on the bonds discounted at a rate of treasuries plus 50 basis points.

On May 1, 2009, PGE purchased three series of its outstanding Pollution Control Bonds in the amount of $142 million. These instruments are backed by first mortgage bonds. Although these Pollution Control Bonds are currently owned by PGE, the first mortgage bonds that back them reduce the amount of first mortgage bonds available to the Company for issuance.

On September 30, 2009, PGE entered into an agreement with certain institutional buyers in the private placement market to sell an aggregate of $150 million of 5.43% Series First Mortgage Bonds, which mature May 3, 2040. These bonds are expected to be issued on or about November 3, 2009.

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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						Other Postretirement Benefits					Non-Qualified Benefit Plans
	2009			2008			2009			2008		2009		2008
Service cost	$	3		$	3		$	-		$	-	$	-	$	-
Interest cost		7			8			1			1		-		-
Expected return on plan assets		(11	)		(11	)		(1	)		-		-		-
Amortization of prior service cost		1			-			1			-		-		-
Amortization of net actuarial loss		-			-			-			-		1		1
Net periodic benefit cost	$	-		$	-		$	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						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2009			2008			2009			2008			2009		2008
Service cost	$	9		$	9		$	1		$	1		$	-	$	-
Interest cost		23			23			3			3			1		1
Expected return on plan assets		(33	)		(33	)		(1	)		(1	)		-		-
Amortization of prior service cost		1			-			1			1			-		-
Amortization of net gain		-			-			1			-			-		-
Amortization of net actuarial loss		-			-			-			-			1		1
Net periodic benefit cost (income)	$	-		$	(1	)	$	5		$	4		$	2	$	2

PGE currently expects no contributions to its defined benefit pension plan in 2009 and 2010, but estimates that it will be required to make contributions of approximately $40 million in 2011, $19 million in 2012, and $16 million in 2013.

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of financial instruments, both assets and liabilities recognized and not recognized in PGE’s condensed consolidated balance sheet, for which it is practicable to estimate fair value is as follows as of September 30, 2009 and December 31, 2008:

• The fair value of cash and cash equivalents and short-term debt approximate their carrying amounts due to the short-term nature of these balances;

• Derivative instruments are recorded at fair value and are based on published market indices as adjusted for other market factors such as location pricing differences or internally developed models;

• Certain trust assets, consisting of money market funds and fixed income securities included in the Nuclear decommissioning trust and marketable securities included in the Non-qualified benefit plan trust, are recorded at fair value and are based on quoted market prices; and

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• The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of September 30, 2009, the estimated aggregate fair value of PGE’s long-term debt was $1,742 million, compared to its $1,594 million carrying amount. As of December 31, 2008, the estimated aggregate fair value of PGE’s long-term debt was $1,286 million, compared to its $1,306 million carrying amount.

A fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

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 reporting 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 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 fair value measurement and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

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The Company’s assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):

	As of September 30, 2009
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust *:
Cash equivalents:
Cash	$	29	$	-	$	-	$	29
U.S. treasury securities		7		-		-		7
Debt securities:
Corporate debt securities		-		6		-		6
Mortgage-backed securities		-		5		-		5
Other		-		2		-		2
Non-qualified benefit plan trust:
Equity securities		22		-		-		22
Debt securities - mutual funds		4		-		-		4
Assets from price risk management activities *		-		26		1		27
	$	62	$	39	$	1	$	102
Liabilities - Liabilities from price risk management activities *	$	-	$	171	$	149	$	320
	As of December 31, 2008
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust *:
Cash	$	27	$	-	$	-	$	27
Debt securities:
Mortgage-backed securities		-		7		-		7
Corporate debt securities		-		4		-		4
Municipal securities		-		4		-		4
Other		-		4		-		4
Non-qualified benefit plan trust:
Equity securities		23		-		-		23
Debt securities - mutual funds		3		-		-		3
Assets from price risk management activities *		-		33		6		39
	$	53	$	52	$	6	$	111
Liabilities - Liabilities from price risk management activities *	$	-	$	297	$	129	$	426

* Activities are subject to regulation, with certain gains and losses deferred for future recovery from, or refund to, retail customers and included in Regulatory assets or Regulatory liabilities, as appropriate.

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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.

Nuclear decommissioning trust assets reflect the assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation and consist of money market funds and fixed income securities. 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. These assets also include investments recorded at cash surrender value, which are excluded from the table above as they are not measured at fair value.

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, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil. PGE applies a market based approach to the fair value measurement of its derivative transactions. Inputs into the valuation of derivative activities include forward commodity and foreign exchange pricing, interest rates, volatility and correlation. PGE utilizes the Black-Scholes and Monte Carlo pricing models for commodity option contracts. Forward pricing, which employs the mid-point of the market’s bid-ask spread, is derived using observed transactions in active markets, as well as historical experience as a participant in those markets, and nonbinding broker quotes. Interest rates used to calculate the present value of derivative valuations incorporate PGE’s borrowing ability. PGE considers the creditworthiness of its counterparties when determining the appropriateness of a particular transaction’s assigned Level in the fair value hierarchy.

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,						Nine Months Ended September 30,
	2009			2008			2009			2008
Balance as of beginning of period	$	(156	)	$	170		$	(123	)	$	1
Net realized and unrealized gains (losses)		10			(208	)		(24	)		(9	)
Purchases, issuances, and settlements, net		-			(23	)		1			(52	)
Net transfers out of Level 3		(2	)		(1	)		(2	)		(2	)
Balance as of end of period	$	(148	)	$	(62	)	$	(148	)	$	(62	)

Net realized and unrealized gains (losses) are recorded in Purchased power and fuel expense in the condensed consolidated statements of income and include $10 million and $(236) million for the three months ended September 30, 2009 and 2008, respectively, and ($27) million and ($60) million for the nine months ended September 30, 2009 and 2008, respectively, of Level 3 net unrealized gains (losses) that have been fully offset by the effects of regulatory accounting.

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NOTE 4: PRICE RISK MANAGEMENT

PGE obtains power from both its own generating resources and from the wholesale market. The Company 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 existing long-term wholesale contracts. Such activities include power purchases and sales resulting from economic dispatch decisions for its own generation. As a result of this ongoing business activity, PGE is exposed to commodity price risk and, to a limited extent, foreign currency exchange rate risk. PGE utilizes derivative instruments, which may include forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil, in its retail electric utility activities to manage its exposure to commodity price risk and foreign exchange rate risk, mitigate the effects of market fluctuations, and minimize net power costs for service to its retail customers. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not engage in trading activities for non-retail purposes.

Assets and liabilities resulting from PGE’s derivative activities are classified as assets or liabilities from price risk management activities, respectively, in the Company’s condensed consolidated balance sheets.

As of September 30, 2009, net volumes related to PGE’s Assets and Liabilities from price risk management activities, which are expected to deliver or settle at various dates through 2013, were as follows (in millions):

Type	Volume
Commodity:
Electricity	13     MWh
Natural gas	114    Decatherms
Foreign exchange	$4   Canadian

As of September 30, 2009, PGE’s Assets and Liabilities resulting from its derivative activities, offset by regulatory accounting, consist of the following (in millions):

	Asset Derivatives				Liability Derivatives
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
Derivatives not designated as hedging instruments:
Commodity contracts:
Electricty	Current assets	$	13		Current liabilities	$	104
Natural gas	Current assets		9		Current liabilities		83
Total current derivative activity			22				187
Commodity contracts:
Electricity	Noncurrent assets		4		Noncurrent liabilities		30
Natural gas	Noncurrent assets		1		Noncurrent liabilities		103
Total long-term derivative activity			5	*			133
Total derivatives not designated as hedging instruments		$	27			$	320
Total derivatives		$	27			$	320

* The noncurrent asset derivative balance of $5 million is included in Other noncurrent assets on the condensed consolidated balance sheet.

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Changes in the fair value of derivative instruments prior to settlement that do not qualify for the normal purchases and normal sales exception, or for hedge accounting, are recorded on a net basis in Purchased power and fuel expense in the statement of income. Net realized and unrealized gains (losses) on derivative transactions were recognized in the statement of income for the periods presented (in millions):

Derivatives not designated as hedging instruments	Location of net gain (loss) recognized in net income on derivative activities	Net gain (loss) recognized in net income on derivative activities *
		Three Months Ended September 30, 2009		Nine Months Ended September 30, 2009
Commodity contracts:
Electricity	Purchased power and fuel expense	$	17	$	(52	)
Natural Gas	Purchased power and fuel expense		14		(69	)
Oil	Purchased power and fuel expense		-		(1	)

* Unrealized gains and losses and certain realized gains and losses are offset by regulatory accounting. Of the net gain (loss) recognized in net income for the three and nine month periods ended September 30, 2009, $31 and ($110), respectively, has been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of September 30, 2009 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2009 *		2010		2011		2012		2013		Total
Commodity contracts:
Electricity	$	25	$	78	$	11	$	3	$	-	$	117
Natural gas		35		57		31		37		16		176
Net unrealized loss	$	60	$	135	$	42	$	40	$	16	$	293

* Represents the period from October 1, 2009 to December 31, 2009.

The Company’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each counterparty.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of September 30, 2009 was $250 million. As of September 30, 2009, the Company had $170 million in collateral posted associated with such liability positions, which consisted entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered by a dual agency downgrade to below investment grade at September 30, 2009, the additional cash collateral requirement would have been $230 million.

At September 30, 2009, contracts with four different counterparties represent approximately 89% and 41% of PGE’s Assets and Liabilities from price risk management activities, respectively. Two different counterparties represent 76% and 13% of Assets from price risk management activities, with two different counterparties representing 25% and 16% of Liabilities from price risk management activities. No other counterparty represents more than 10% of the Assets and Liabilities from price risk management activities.

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See Note 3 for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

NOTE 5: EARNINGS PER SHARE

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	32	$	-	$	87	$	67
Denominator (in thousands):
Weighted-average common shares outstanding - basic		75,182		62,554		71,980		62,539
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares		41		53		77		50
Weighted-average common shares outstanding - diluted		75,223		62,607		72,057		62,589
Earnings per share - basic and diluted	$	0.43	$	-	$	1.21	$	1.08

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 three-year performance periods.

Basic and diluted earnings per share amounts are calculated based on actual amounts rather than the rounded amounts presented in the table above and on the condensed consolidated statements of income. Accordingly, calculations using the rounded amounts presented for net income and weighted-average shares outstanding may yield results that vary slightly from the earnings per share amounts in the table above.

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NOTE 6: SHAREHOLDERS’ EQUITY

On May 13, 2009, the shareholders approved an increase in the number of shares of common stock authorized to 160,000,000 shares.

The activity in shareholders’ equity during the nine months ended September 30, 2009 and 2008 was as follows (dollars in millions):

	Portland General Electric Company Shareholders’ Equity
	Common Stock			Accumulated Other Comprehensive			Retained			Noncontrolling Interests’
	Shares	Amount		Loss			Earnings			Equity
Balances as of January 1, 2009	62,575,257	$	659	$	(5	)	$	700		$	-
Issuance of common stock, net of issuance costs of $6 *	12,477,500		170		-			-			-
Vesting of restricted and performance stock units	124,019		-		-			-			-
Issuance of shares pursuant to employee stock purchase plan	14,906		-		-			-			-
Noncontrolling interest capital contributions	-		-		-			-			7
Dividends declared	-		-		-			(57	)		-
Net income (loss)	-		-		-			87			(6	)
Balances as of September 30, 2009	75,191,682	$	829	$	(5	)	$	730		$	1
Balances as of January 1, 2008	62,529,787	$	646	$	(4	)	$	674		$	-
Vesting of restricted stock units	16,989		-		-			-			-
Issuance of shares pursuant to employee stock purchase plan	11,152		-		-			-			-
Former parent capital contribution	-		13		-			-			-
Stock based compensation	-		3		-			-			-
Dividends declared	-		-		-			(45	)		-
Net income	-		-		-			67			-
Balances as of September 30, 2008	62,557,928	$	662	$	(4	)	$	696		$	-

* Issuance costs, including a return on the unamortized balance, are included in rates over 10 years, beginning January 1, 2009.

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NOTE 7: COMPREHENSIVE INCOME

Comprehensive income is as follows for the three months ended September 30 (in millions):

	2009			2008
Net income	$	31		$	-
Unrealized gains (losses) on cash flow hedges:
Reclassification to net income for contract settlements, net of taxesof $0 in 2009 and 2008		-			1
Reclassification of unrealized gains to a regulatory liability, net of taxes of $0 in 2009 and $1 in 2008		-			(1	)
Total unrealized gains (losses) on cash flow hedges		-			-
Pension and other postretirement plans’ funded position, net of taxes of $1 in 2009 and $0 in 2008		2			-
Reclassification of defined benefit pension plan and other benefits to a regulatory asset, net of taxes of ($1) in 2009 and $0 in 2008		(2	)		-
Comprehensive income		31			-
Less: comprehensive loss attributable to noncontrolling interests		(1	)		-
Comprehensive income attributable to Portland General Electric Company	$	32		$	-

Comprehensive income is as follows for the nine months ended September 30 (in millions):

	2009			2008
Net income	$	81		$	67
Unrealized gains (losses) on cash flow hedges:
Reclassification to net income for contract settlements, net of taxesof $0 in 2009 and $(1) in 2008		-			1
Reclassification of unrealized gains to a regulatory liability, net of taxes of $0 in 2009 and $1 in 2008		-			(1	)
Total unrealized gains (losses) on cash flow hedges		-			-
Pension and other postretirement plans’ funded position, net of taxes of $0 in 2009 and ($1) in 2008		3			1
Reclassification of defined benefit pension plan and other benefits to a regulatory asset, net of taxes of $0 in 2009 and $1 in 2008		(3	)		(1	)
Comprehensive income		81			67
Less: comprehensive losses attributable to noncontrolling interests		(6	)		-
Comprehensive income attributable to Portland General Electric Company	$	87		$	67

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NOTE 8: 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 in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs.

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, which upheld the OPUC’s authorization of PGE’s recovery of the Trojan investment, but stated that the OPUC did not have the authority to allow PGE to recover a return on the Trojan investment and remanded the case to the OPUC.

Settlement of Court Proceedings on OPUC Authority. In 2000, 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, which was approved by the OPUC in September 2000. The settlement 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.

Challenge to Settlement of Court Proceeding. The 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 the URP’s challenges, and approving the accounting and ratemaking elements of the 2000 settlement. On October 10, 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration.

Remand of 2002 Order. As a result of the Oregon Court of Appeals remand of the 2002 Order, the OPUC considered whether the OPUC has authority to engage in retroactive ratemaking and what prices would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. On September 30, 2008, the OPUC issued an order that requires PGE to refund $15.4 million, plus interest at 9.6% from September 30, 2000, to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. 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 URP and the plaintiffs in the class actions described below have separately appealed the order to the Oregon Court of Appeals.

The $15.4 million amount, plus accrued interest, resulted in a total refund of $33.1 million as of September 30, 2008. As a result of the September 30, 2008 order, PGE recorded, as a regulatory liability, the total refund due to customers of $33.1 million, which reduced 2008 revenues.

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 (the Class Action Plaintiffs). The cases seek to represent PGE customers during the period from April 1, 1995 to October 1, 2000. The suits seek damages of $260 million plus interest as a result of the inclusion of a return on investment of Trojan in the prices PGE charged its customers.

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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 responded with respect to the 2002 Order (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 1, 1995 through October 1, 2000. The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court further stated that, if the OPUC determined that it cannot provide a remedy, 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. On February 10, 2009, the Circuit Court judge denied the plaintiffs’ motion to lift the abatement.

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 operation and cash flows for a future reporting period.

Regulatory Matters

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 June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. Parties appealed various aspects of the FERC order 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

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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 did not rule on the FERC’s ultimate decision to deny refunds. After denying requests for rehearing, the Ninth Circuit on April 16, 2009 issued a mandate giving immediate effect to its August 24, 2007 order remanding the case to the FERC.

Since issuance of the mandate, certain parties proposing refunds have filed pleadings with the FERC suggesting procedures on remand, attempting to initiate new proceedings, and containing additional evidence that they assert shows market-wide manipulation that justifies refunds from early in 2000. Parties opposing refunds, including PGE, have filed various pleadings that contest allegations of market-wide manipulation and urge the FERC to reaffirm, with a more detailed explanation of its consideration of market manipulation claims, its previous decision not to initiate proceedings to order refunds.

On September 4, 2009, various parties, including PGE, filed a petition for a writ of certiorari with the U.S. Supreme Court requesting that the Supreme Court review the decision of the Ninth Circuit in the Pacific Northwest Refund proceeding. The petition asserts, among other things, that the Ninth Circuit erred by interfering with certain FERC decisions that other circuit courts have held are within the FERC’s discretion.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95,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.

Management cannot predict the outcome of the Pacific Northwest Refund proceeding, or whether the FERC will order refunds in this proceeding, 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 operation and cash flows in future reporting periods.

Complaint and Application for Deferral – Income Taxes

On October 5, 2005, the URP and another party (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.

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 considered amortization of the deferral.

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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; and (ii) PGE’s earnings over the twelve-month period ended September 30, 2006 would preclude any refund.

On August 18, 2009, the OPUC issued an order that denied amortization of any deferral in this matter, based on a review of PGE’s earnings over the 12-month period ended September 30, 2006. On October 16, 2009, plaintiffs filed an appeal of the August 18, 2009 order with the Oregon Court of Appeals.

Management cannot predict the ultimate outcome of this matter. However, management believes this matter will not have a material adverse effect on PGE’s financial condition, results of operation 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 operation and cash flows in future reporting periods.

Environmental Matters

Portland Harbor

A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a segment of the Willamette River known as the Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included this segment on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site and listed sixty-nine Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river.

The Portland Harbor 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 PRPs, not including PGE. In the AOC, the EPA determined that the RI/FS would focus on a segment of the river approximately 5.7 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 segment of the river being examined in the RI/FS, as well as several miles beyond that 5.7 mile segment. PGE has requested, and the EPA granted, an extension until October 30, 2009 for the Company to respond. During 2009, the EPA sent General Notice Letters to 15 additional PRPs.

The EPA will determine the boundaries of the site at the conclusion of the RI/FS in a Record of Decision, now expected in 2012, in which it will document its findings and select 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 site 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 operation and cash flows in future reporting periods.

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The OPUC issued an order authorizing the deferral, for later ratemaking treatment, of incremental investigation and remediation costs related to the Portland Harbor site incurred during the twelve-month period ended March 31, 2009. As of September 30, 2009, the Company had not deferred any costs related to Portland Harbor. The OPUC is considering PGE’s request for a second twelve-month deferral period beginning April 1, 2009. Ratemaking treatment of any costs which may be deferred would be determined in a future regulatory proceeding that includes both a prudency review with respect to the costs incurred and a regulated earnings test. Accordingly, there can be no assurance that recovery of such costs would 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 continues to be 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. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyls, have been detected at the site. On September 29, 2003, the Harbor Oil facility was included on the 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. On May 31, 2007, an Administrative Order on Consent 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 commenced in 2008 and has yet to be completed.

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. Management believes that the outcome of this matter 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 operation and cash flows in future reporting periods.

The OPUC issued an order authorizing the deferral, 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 incurred during the twelve-month period ended March 31, 2009. As of September 30, 2009, the Company had not deferred any costs related to Harbor Oil. The OPUC is considering PGE’s request for a second twelve-month deferral period beginning April 1, 2009. Ratemaking treatment of any costs which may be deferred would be determined in a future regulatory proceeding that includes both a prudency review with respect to the costs incurred and a regulated earnings test. Accordingly, there can be no assurance that recovery of such costs would be granted.

Other Matters

PGE is subject to other regulatory, environmental, 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 resolution of such matters will not have a material adverse effect on its financial position, results of operation, or cash flows, these matters are subject to inherent uncertainties and management’s view of these matters may change in the future.

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NOTE 9: GUARANTEES

PGE enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on PGE’s historical experience and the evaluation of the specific indemnities. As of September 30, 2009, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

NOTE 10: VARIABLE INTEREST ENTITIES

PGE has determined that its interest in two VIEs, as outlined below, will absorb the majority of the expected variability generated by the entities. Accordingly, the VIEs are consolidated with the Company’s condensed consolidated financial statements. Both entities are limited liability companies (LLCs) and were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating and financing photovoltaic solar power facilities located on real property owned by third parties and selling the energy generated by the facilities. Photovoltaic solar power facilities give rise to certain tax benefits, which flow through to the members of the LLCs. PGE is the Managing Member in each of the LLCs, representing less than a 1% equity interest in each entity, and a financial institution is the Investor Member, representing more than a 99% equity interest in each entity.

Determining whether PGE is the primary beneficiary of a VIE is complex, subjective and requires the use of judgments and assumptions. Significant judgments and assumptions made by PGE in determining that it is the primary beneficiary of these LLCs include the following: (1) based on projections prepared in accordance with the operating agreement, PGE will absorb a majority of the expected losses of the LLCs; (2) PGE expects to own 100% of the LLCs shortly after five years have elapsed, at which time the facilities will have approximately 75% of their estimated useful life remaining; and (3) PGE has the expertise to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements.

During 2009, impairment losses of $5 million, which are classified in Depreciation and amortization expense, were recognized on the photovoltaic solar power facilities held by the LLCs. Based on PGE’s intent to ultimately acquire 100% of the LLCs and the fact that the capitalized cost of the photovoltaic solar power facilities exceeded the undiscounted cash flows of the facilities over their estimated useful lives, an impairment analysis was performed at the time each facility was completed. Immediately following the completion of the photovoltaic solar power facilities, impairment losses were recognized on these assets. The impairment losses were equal to the excess of the carrying amount over the estimated fair value of these photovoltaic solar power facilities. Estimated fair value was determined using the discounted cash flow method, assuming a discount rate (after taxes) of approximately 7%, which is PGE’s allowed rate of return, and estimated useful life of 20 to 25 years. The new cost basis of these photovoltaic solar power facilities is amortized over their remaining estimated useful lives. The valuation technique used to measure fair value of the photovoltaic solar power facilities at the impairment date is considered Level 3 in the fair value hierarchy, as described in Note 3.

As noted above, PGE has consolidated the LLCs even though it has less than a 1% ownership interest in the LLCs. The participating members are allocated their proportionate share of the LLCs’ net losses based on the respective members’ ownership percent. Accordingly, the majority of the impairment losses are attributable to the “noncontrolling interests” through the Net losses attributable to noncontrolling interests in PGE’s condensed consolidated statement of income for the nine months ended September 30, 2009.

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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, but not limited to, 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 power costs and capital investments, and current or prospective wholesale and retail competition;

• the outcome of legal and regulatory proceedings and issues including, but not limited to, the proceedings related to the Trojan Investment Recovery, the Pacific Northwest Refund proceeding, the Portland Harbor investigation, and other matters described in Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements;

• the continuing effects of the economic downturn in the state of Oregon, the United States and other parts of the world, including reductions in demand for electricity, sale of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers and elevated levels of uncollectible customer accounts;

• capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper and the availability and cost of capital, 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 repayments of maturing debt;

• unseasonable or extreme weather and other natural phenomena, which in addition to affecting PGE’s customers’ demand for power, could significantly affect PGE’s ability and cost to procure adequate supplies of fuel or power to serve its customers, and could increase PGE’s costs to maintain its generating facilities and transmission and distribution system;

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• operational factors affecting PGE’s power generation facilities, including forced outages, hydro conditions, wind conditions, and disruption of fuel supply, which may cause the Company to incur replacement power costs or repair costs;

• wholesale prices for natural gas, coal, oil, and other fuels and their impact on the availability and price of wholesale power in the western United States;

• declines in wholesale power and natural gas prices, which would require the Company to issue additional letters of credit or post additional cash as collateral to counterparties pursuant to existing purchased power and natural gas agreements;

• changes in 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, in order to mitigate carbon dioxide, mercury, and other gas emissions;

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

• the failure to complete capital projects on schedule and within budget;

• the effects of Oregon law related to utility rate treatment of income taxes, which may result in earnings volatility and adversely affect PGE’s results of operation;

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

• declines in the market prices of equity securities held by, and increased funding requirements for, defined benefit pension plans and other benefit plans;

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

• the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely 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 transitions in senior management;

• 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; and

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• financial or regulatory accounting principles or policies imposed by governing bodies.

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 as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2008, and other periodic and current reports filed with the SEC.

Future Energy Resource Strategy - In September 2009, PGE issued a draft Integrated Resource Plan (IRP) for public review that outlines the Company’s proposed action plan to meet the electricity needs of its customers through 2020. A final IRP will be filed with the OPUC in November 2009. The action plan in the draft IRP includes continued emphasis on energy efficiency, new natural gas-fired generating facilities, increased transmission capacity, reductions in Boardman emissions, and continued focus on renewable energy resources to meet Oregon’s Renewable Energy Standard, while maintaining reasonable pricing and minimizing risk. If the action plan is acknowledged by the OPUC as filed, its execution will have a broad and significant impact on the Company’s capital requirements, financing activities, power supply portfolio, and regulatory processes. For further information, see “Liquidity and Capital Resources” in this Item 2.

Capital and Financing - PGE’s recent and near term capital requirements are related primarily to the following major projects and debt maturities:

• Construction of Biglow Canyon Phase II (completed in August 2009 at a cost of approximately $320 million), and Phase III (expected to be completed in the third quarter of 2010), the smart meter project, and ongoing capital expenditures for the upgrade, replacement, and expansion of transmission, distribution and generation infrastructure. Capital expenditures are expected to approximate $732 million in 2009 and $545 million in 2010;

• The purchase of $142 million of Pollution Control Bonds in May 2009; and

• The maturity of $186 million of long-term debt in 2010.

To fund these projects and debt maturities, the Company has executed the following transactions:

• The issuance of $130 million of first mortgage bonds in January 2009;

• The issuance of 12,477,500 shares of common stock in March 2009 for net proceeds of $170 million;

• The issuance of $300 million of first mortgage bonds in an April 2009 public offering.

• In addition, in September 2009, the Company entered into an agreement to sell $150 million of 5.43% Series First Mortgage Bonds in the private placement market, with the bonds expected to be issued in early November 2009.

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PGE maintains liquidity through revolving credit facilities, with the ability to issue letters of credit and access the commercial paper market. As of September 30, 2009, the unused available credit under the credit facilities was $335 million. In addition, PGE expects cash from operations to be approximately $420 million in 2009 and $475 million in 2010 and anticipates issuing approximately $250 million of additional debt securities in 2010.

As of September 30, 2009, PGE had posted a total of $256 million of collateral with counterparties in connection with its price risk management activities. Provided that market prices remain unchanged, the Company anticipates that approximately 35% of the posted collateral would no longer be required by the end of 2009 as the related contracts are settled, with another 47% expected to roll off by the end of 2010.

Customers and Demand - During the nine months ended September 30, 2009, PGE served an average of 815,626 retail customers compared to 810,861 during the nine months ended September 30, 2008, an increase of 0.6%. Despite this customer growth, retail energy deliveries declined 4% in the first nine months of 2009 compared to the same period in 2008. Residential deliveries decreased 0.8% and industrial and commercial deliveries, including those to direct access customers, decreased 6.2%. The Company believes that these decreases reflect the impact of the continuing recession.

PGE expects that weather adjusted retail energy deliveries for 2009 will be approximately 2.5% less than in 2008. Based on the expectation of a modest economic recovery in 2010, the Company estimates that energy deliveries in 2010 will increase approximately 1.6% from projected 2009 weather adjusted deliveries.

As indicated below, seasonally adjusted unemployment rates for the United States, the state of Oregon, and the Portland/Salem metropolitan area for the first three quarters of 2009 were higher than for the corresponding periods of 2008, with rates for both Oregon and the Portland/Salem area exceeding the national averages. The majority of the Company’s service territory lies within the Portland/Salem metropolitan area.

Seasonally Adjusted Unemployment Rates

	United States		Oregon		Portland/ Salem
2009
1st quarter average	8.1	%	10.8	%	9.9	%
2nd quarter average	9.3		12.0		11.8
3rd quarter average	9.6		11.8		11.4
Avg for year-to-date	9.0		11.5		11.0
2008
1st quarter average	4.9	%	5.4	%	5.1	%
2nd quarter average	5.3		5.7		5.4
3rd quarter average	6.0		6.5		6.2
Avg for year-to-date	5.4		5.9		5.6
4th quarter average	6.8		7.8		7.7
Avg for the year	5.8		6.4		6.1

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Wholesale Markets -PGE utilizes sales of excess energy capacity in the wholesale market to optimize its power supply portfolio and obtain reasonably priced power for its customers. Continued low market prices for natural gas, with the resulting impact on wholesale electricity prices in the western United States, has contributed to a substantial decrease in PGE’s wholesale revenues in 2009 compared to 2008.

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 53% of its retail load requirement during the first nine months of 2009, compared to 60% during the corresponding period of 2008. The decrease was primarily related to the following extended maintenance outages:

• Colstrip Unit 4 is one of the Company’s coal-fired thermal generating resources, providing approximately 6% (148 MW) of the Company’s total generating capability. In connection with the scheduled maintenance outage of Colstrip Unit 4 in March 2009, two turbine rotors were found to be damaged, with both sent to the manufacturer for repair. Colstrip Unit 4 is expected to be back online and generating power by mid-November 2009.PGE’s incremental replacement power costs were approximately $8 million through September 30, 2009, with an additional $4 million expected in the fourth quarter of 2009. The Company’s share of repair costs is currently estimated at approximately $2 million.

• Boardman is one of the Company’s coal-fired thermal generating resources, providing approximately 15% (374 MW) of the Company’s total generating capability. In connection with the scheduled maintenance outage of Boardman in May 2009, its outage was extended through mid-August 2009 due to required contractor repairs to remedy high generator rotor vibrations. PGE’s incremental replacement power costs were approximately $4 million. The Company’s share of repair costs was not material.

Availability of the plants PGE operates (excludes Colstrip) approximated 86% during the first nine months of 2009, compared to 88% during the same period of 2008. The availability of Colstrip approximated 64% during the first nine months of 2009, compared to 96% during the same period of 2008. Although generation from PGE’s hydroelectric plants provided approximately 10% of the Company’s retail load requirement during the first nine months of both 2009 and 2008, hydro generation decreased 4% in 2009 compared to 2008.

Biglow Canyon Phase II, a 149 MW wind project, was completed in August 2009, with completion of Phase III, a 175 MW project, expected in the third quarter of 2010. These important additions to PGE’s generation portfolio are major steps in helping to meet Oregon’s Renewable Energy Standard (RES). Wind generation in the first nine months of 2009, which increased 21% from the comparable period of 2008, provided 3% of PGE’s retail load requirement. Information regarding cost recovery of the project is included in “Renewable Resources” below.

Legal, Regulatory and Environmental Matters -PGE is a party to certain 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:

• Recovery of the Company’s investment in its closed Trojan plant;

• Claims for refunds related to wholesale energy sales during 2000 - 2001 in the Pacific Northwest Refund proceeding;

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

• Investigation of environmental matters at Portland Harbor.

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For further information regarding the above and other matters, see Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

Pursuant to an order issued by the OPUC in September 2008, related to litigation involving the closed Trojan facility, PGE plans to issue refund checks to certain customers totaling $33.1 million, plus accrued interest ($3.3 million as of September 30, 2009), beginning in October 2009. Such refunds are expected to be completed by the end of 2009.

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

• Boardman Deferral Amortization - In October 2007, PGE filed a request with the OPUC to amortize the deferral of $26.4 million of replacement power costs, plus accrued interest ($9.9 million as of September 30, 2009), associated with the forced outage of Boardman from November 18, 2005 through February 5, 2006. In its filing, PGE proposed that the amortization be offset with certain credits due to customers, with no price impact anticipated. PGE’s request is subject to a regulatory proceeding that provides for both a prudency review with respect to the outage and to a regulated earnings test. A decision by the OPUC is pending.

• Utility Rate Treatment of Income Taxes (SB 408) - On April 10, 2009, the OPUC issued its order on the 2007 reporting year authorizing PGE to collect from customers $14.7 million plus accrued interest. In accordance with the OPUC rules, collections from customers began June 1, 2009 and will continue over a one-year period. On October 15, 2009, PGE filed its report for the 2008 reporting year with the OPUC for review, with total estimated customer refunds of approximately $9 million (excluding interest), which would begin June 1, 2010. As of September 30, 2009, the Company has recorded an estimated $9 million customer refund related to the 2009 reporting year.

On August 18, 2009, the OPUC issued an order that denied amortization of any deferral related to the application of SB 408 for the period October 5, 2005 through December 31, 2005, based on a review of PGE’s earnings over the twelve month period ended September 30, 2006. On October 16, 2009, plaintiffs filed an appeal of the August 18, 2009 OPUC order with the Oregon Court of Appeals.

• Power Costs - Under PGE’s Annual Power Cost Update Tariff, the Company’s latest forecast of 2010 power costs was submitted to the OPUC in late September 2009. The forecast includes the effects of lower natural gas prices and wholesale power costs, as well as the lower cost of wind generation, and projects an approximate 4% overall decrease in retail customer prices. Such forecast will be updated and finalized in November, with new prices, as approved by the OPUC, effective on January 1, 2010.

• Renewable Resources - On April 1, 2009, the Company submitted to the OPUC its initial filing under the renewable adjustment clause mechanism. The filing includes three renewable projects - Biglow Canyon Phase II and two solar projects. The filing requests approximately $41 million in revenue requirements, or a 2.4% overall increase in retail customer prices, consisting of approximately $6 million to be deferred in 2009 and a $35 million increase in the Company’s 2010 revenue requirement. These amounts will be partially offset by related power cost savings, currently estimated at about $17 million for 2010 and included in the Company’s Annual Power Cost Update Tariff (described above). The related cost and benefit amounts will be updated by December 1, 2009 and included in new prices that become effective on January 1, 2010.

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The net impact of customer price adjustments related to Power Costs and Renewable Resources is currently estimated to result in an approximate 1.7% overall price decrease, to be allocated among all retail customer classes. Actual price changes will become effective on January 1, 2010.

• Selective Water Withdrawal System - In a stipulation in PGE’s most recent general rate case, the OPUC provided for a process to recover the cost of the Company’s investment in the Selective Water Withdrawal System at the Pelton/Round Butte generating plant, which is designed to restore fish passage on the upper portion of the Deschutes River. As a result of a delay in construction, the procedural schedule in this matter has been delayed, with an OPUC decision now expected by March 31, 2010. Completion of the project, initially planned for the second quarter of 2009, is now expected in late 2009 or early in 2010. PGE’s filing in this matter requested an annual revenue increase of $12.9 million related to this project.

• Decoupling Mechanism - Pursuant to OPUC authorization in PGE’s most recent general rate case, the Company is deferring, for later ratemaking treatment, amounts associated with a new decoupling mechanism. The mechanism provides for recovery of reduced revenues resulting from a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. It also provides for customer refunds if weather adjusted use per customer exceeds that approved in the rate case. As weather adjusted loads for the first nine months of 2009 exceeded those approved in the rate case, PGE accrued a refund to customers of approximately $4 million related to the decoupling mechanism, which is included as a reduction in Revenues.

PGE periodically evaluates the need to align its general price structure to sufficiently cover its operating costs and provide a reasonable rate of return. The Company currently plans to file a general rate case in early 2010, based on a 2011 test year, with new prices to be effective beginning in January 2011.

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, 2008, filed with the SEC on February 25, 2009.

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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,
	2009					2008					2009					2008
	Amount			As % of Rev		Amount			As % of Rev		Amount			As % of Rev		Amount			As % of Rev
Revenues	$	445		100	%	$	400		100	%	$	1,319		100	%	$	1,296		100	%
Operating expenses:
Purchased power and fuel		225		51			217		54			664		50			652		50
Production and distribution		42		9			40		10			127		10			125		10
Administrative and other		43		10			48		12			134		10			142		11
Depreciation and amortization		53		12			54		14			160		12			154		12
Taxes other than income taxes		20		4			20		5			64		5			63		5
Total operating expenses		383		86			379		95			1,149		87			1,136		88
Income from operations		62		14			21		5			170		13			160		12
Other income (expense):
Allowance for equity funds used during construction		5		1			3		1			13		1			7		1
Miscellaneous income (expense), net		5		1			(4	)	(1	)		6		-			(6	)	(1	)
Other income (expense), net		10		2			(1	)	-			19		1			1		-
Interest expense		25		6			21		5			76		6			67		5
Income (loss) before income tax expense (benefit)		47		10			(1	)	-			113		8			94		7
Income tax expense (benefit)		16		3			(1	)	-			32		2			27		2
Net income		31		7			-		-			81		6			67		5
Less: net loss attributable to noncontrolling interests		(1	)	-			-		-			(6	)	-			-		-
Net income attributable toPortland GeneralElectric Company	$	32		7	%	$	-		-	%	$	87		6	%	$	67		5	%

Net income attributable to Portland General Electric Company was $32 million, or $0.43 per diluted share, for the third quarter of 2009 compared to zero for the third quarter of 2008. The increase in net income was due primarily to the net effect of the following (net of income taxes):

• A $20 million increase from a refund due to customers, recorded in September 2008, related to settlement of certain Trojan matters; and

• A $6 million increase resulting from an increase in the fair market value of non-qualified benefit plan trust assets.

Operating results were also affected by higher retail prices and lower employee benefit expenses in 2009, partially offset by a 2% decrease in retail energy deliveries (driven by an 11% decrease in industrial customer deliveries), higher power costs (due in part to extended outages at Colstrip and Boardman), and the sale of excess power (initially acquired to meet retail load) into low-priced wholesale markets.

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Net income attributable to Portland General Electric Company was $87 million, or $1.21 per diluted share, for the nine months ended September 30, 2009 compared to $67 million, or $1.08 per diluted share, for the nine months ended September 30, 2008. The increase in net income was due primarily to the net effect of the following (net of income taxes):

• A $20 million increase from a refund due to customers, recorded in September 2008, related to the settlement of certain Trojan matters;

• A $10 million increase resulting from an increase in the fair market value of non-qualified benefit plan trust assets; and

• A $7 million decrease related to gains realized on the sale of fuel oil in 2008.

Operating results were also affected by higher retail prices and lower employee benefit expenses, partially offset by a 4% decrease in retail energy deliveries, higher power costs (due in part to extended outages at Colstrip and Boardman and lower hydro availability), and the sale of excess power into low-priced wholesale markets.

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Third Quarter of 2009 Compared to the Third Quarter of 2008

Revenues, energy sold and delivered (based in megawatt hours), and average number of retail customers consist of the following:

	Three Months Ended September 30,
	2009				2008
	Amount		% of Total		Amount			% of Total
Revenues (dollars in millions):
Retail sales:
Residential	$	173	39	%	$	155		39	%
Commercial		165	37			156		39
Industrial		44	10			42		10
Total retail sales		382	86			353		88
Direct access customers		1	-			(3	)	(1	)
Other retail revenues		19	4			(22	)	(5	)
Total retail revenues		402	90			328		82
Wholesale revenues		36	8			61		15
Other operating revenues		7	2			11		3
Total revenues	$	445	100	%	$	400		100	%
Energy sold and delivered (MWh in thousands):
Retail energy sales:
Residential		1,719	30	%		1,643		29	%
Commercial		1,916	34			1,909		33
Industrial		610	11			649		11
Total retail energy sales		4,245	75			4,201		73
Delivery to direct access customers:
Commercial		112	2			152		3
Industrial		393	7			484		8
Total retail energy deliveries		4,750	84			4,837		84
Wholesale sales		877	16			942		16
Total energy sold and delivered		5,627	100	%		5,779		100	%
Average number of retail customers:
Residential		714,320	87	%		711,619		87	%
Commercial		102,744	13			101,718		13
Industrial		254	-			219		-
Direct access		253	-			425		-
Average retail customers		817,571	100	%		813,981		100	%

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Revenues increased $45 million, or 11%, in the third quarter of 2009 compared to the third quarter of 2008 as a result of the net effect of the items discussed below.

Total retail revenues increased $74 million, or 23%, in the third quarter of 2009 compared to the third quarter of 2008 primarily due to the net effect of the following:

• A $33 million increase resulting from the accrual of customer refunds in the third quarter of 2008 pursuant to the OPUC order related to various Trojan matters, which is included in Other retail revenues;

• A $29 million increase resulting from higher average prices, primarily driven by the price increases approved by the OPUC pursuant to the Company’s 2009 General Rate Case which became effective January 1, 2009;

• A $6 million increase related to SB 408, with a $0.5 million customer refund recorded in the third quarter of 2009, as compared to a $6 million customer refund recorded in the third quarter of 2008. Such amounts are included within Other retail revenues;

• A $4 million increase related to a 1% increase in total retail energy sales, which is primarily due to a 5% increase in residential energy sales, driven by hotter weather in the third quarter of 2009, offset by a 6% decrease in industrial energy sales. When combined with industrial customers who purchase their energy from Electricity Service Suppliers (direct access customers), total energy deliveries to industrial customers decreased 11% from the third quarter of 2008. Decreased demand from industrial customers during the third quarter of 2009 compared to the third quarter of 2008 was driven by the continued effect of the recession and a large contributor to the 2% decrease in total retail energy deliveries;

• A $4 million increase resulting from the accrual of amounts due from customers related to Biglow Canyon Phase II, pursuant to PGE’s Renewable Adjustment Clause tariff, which is included in Other retail revenues. PGE expects a collection from customers of approximately $7 million related to 2009, which will be collected over one year and reflected in customer prices beginning January 1, 2010; and

• A $2 million decrease related to the decoupling mechanism, which went into effect on February 1, 2009 and is included in Other retail revenues. For further information on the decoupling mechanism, see “Legal, Regulatory and Environmental Matters” in “Overview” of this Item 2.

Heating and cooling degree-days are an indication of the likelihood that customers will use heating and cooling, respectively, and is used to measure the effect of weather on the demand for electricity. During the third quarter of 2009, cooling degree-days increased 43%. On July 29, 2009, the Company set a new all-time “summer peak” net system load of 3,949 MW during a heat wave, surpassing the previous summer peak set in August 2008. The following table indicates the actual number of heating and cooling degree-days for the months presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

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	Heating Degree-days		Cooling Degree-days
	2009	2008	2009	2008
July	7	6	281	134
August	11	17	170	169
September	45	57	86	73
3rd quarter	63	80	537	376
15-year average for the quarter	80	82	394	385

On a weather adjusted basis, retail energy deliveries decreased 5.0% in the third quarter of 2009 compared to the third quarter of 2008, with deliveries to residential, commercial, and industrial customers increasing (decreasing) by 1.5%, (4.3)%, and (15.8)%, respectively. Driven by the continuing recession, several industrial customers have taken measures that have significantly reduced energy use.

In addition to those items listed above as “included in Other retail revenues,” Other retail revenues also includes certain customer credits and refunds that are fully offset within Retail sales, therefore having no impact to total Retail revenues. These consist primarily of the following:

• A $4 million increase related to the PCAM for the year 2007. Customer refunds related to the PCAM for 2007, totaling $17 million (plus interest), began January 1, 2009 and continue over approximately one year; and

• A $4 million decrease related to SB 408 for the years 2007 and 2006. Customer collections related to SB 408 for 2007, totaling $15 million (plus interest) began June 1, 2009 and continue over approximately one year. Customer refunds related to SB 408 for 2006, totaling $37 million (plus interest), began June 1, 2008 and continue over approximately two years.

Wholesale revenues decreased $25 million, or 41%, in the third quarter of 2009 compared to the third quarter of 2008, driven by a 37% decrease in average price and a 7% decrease in wholesale energy sales volume. Wholesale revenues result from sales of electricity to utilities and power marketers, which are made in conjunction with the Company’s effort to secure reasonably priced power for its retail customers, manage risk, and administer its long-term wholesale contracts. Such sales can vary significantly period to period. During the third quarter of 2009, PGE sold electricity originally intended to meet forecasted retail load into a continuing depressed market.

Other operating revenues decreased $4 million, or 36%, in the third quarter of 2009 compared to the third quarter of 2008, due largely to $5 million of fuel oil sales from the Company’s Beaver generating plant in 2008. Such sales resulted in realized gains of $4 million in the third quarter of 2008.

Purchased power and fuel expense increased $8 million, or 4%, in the third quarter of 2009 compared to the third quarter of 2008. Such expense includes the cost of power purchased and fuel used to generate electricity required to meet PGE’s retail load requirement. Also included is the cost of settled electric and natural gas financial contracts. The increase was due primarily to the net effect of the following:

• A $26 million increase in the cost of generation was driven by a 32% increase in the average cost of such generation. Based on economic dispatch decisions, PGE increased operation of its natural gas-fired plants during the third quarter of 2009, driving a 44% increase in natural gas-fired generation compared to the third quarter of 2008, while extended outages during the third quarter of 2009 at Colstrip and Boardman reduced overall generation from the Company’s coal-fired generation compared to the third quarter of 2008. This shift in lower-cost coal-fired generation to

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higher-cost natural gas-fired generation during the third quarter of 2009 resulted in the 32% increase in the average cost of generation relative to the third quarter of 2008;

• A $6 million increase related to the PCAM, reflecting the effect of a third quarter 2008 reversal of an estimated customer refund recorded in the first half of the year. No amount was recorded in the third quarter of 2009;

• A $25 million, or 18%, decrease in the cost of purchased power was driven by a decrease in market prices. An increase in the volume of power purchased resulting from the outages at Colstrip and Boardman in the third quarter of 2009 was more than offset by the increased operation of PGE’s natural gas-fired plants, which reduced the Company’s reliance on power purchases. This resulted in the volume of power purchases in the third quarter of 2009 approximating that in the third quarter of 2008.

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PGE’s sources of energy (based in MWh) for the periods presented are as follows (MWh in thousands):

	Three Months Ended September 30,
	2009				2008
Generation:
Thermal:
Natural gas	1,671		31	%	1,160		21	%
Coal	718		13		1,311		24
Hydro	327		6		357		7
Wind	190		4		100		2
Total generation	2,906		54		2,928		54
Purchased power:
Term purchases	890		16		1,286		24
Purchased hydro	571		11		680		12
Spot purchases	1,029		19		527		10
Total purchased power	2,490		46		2,493		46
Total system load	5,396		100	%	5,421		100	%
Less: wholesale sales	(877	)			(942	)
Retail load requirement	4,519				4,479

Retail load requirement increased 1% from the third quarter of 2008. The impact of warmer weather in the third quarter of 2009 was largely offset by reduced energy sales to industrial customers as a result of the continued economic slowdown. The average variable cost of PGE’s total system load was $41.54 per MWh in the third quarter of 2009 compared to $41.11 per MWh in the third quarter of 2008, an increase of 1%.

Under the PCAM, the Company can adjust future prices to reflect a portion of the difference between each year’s forecasted NVPC included in customer prices (the baseline) and actual NVPC, to the extent that such difference exceeds a pre-determined “deadband.” For 2009, the deadband ranges from approximately $15 million below, to $30 million above, the baseline NVPC. Although PGE expects that actual NVPC for 2009 will be above the baseline, the difference between actual and baseline NVPC is expected to be within the established deadband; accordingly, no customer refund or collection has been recorded as of September 30, 2009.

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Regional hydro conditions for 2009 are expected to be below normal levels. During the third quarter of 2009, PGE-owned hydro production and energy received under contracts with mid-Columbia River projects were down 8% and 16%, respectively, from the third quarter of 2008. Volumetric water supply forecasts for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies. The following indicates the forecast of the April-to-September 2009 runoff (issued July 8, 2009) compared to the actual runoffs for the same period of 2008 (as a percentage of normal):

Location	2009 Forecast		2008 Actual
Columbia River at The Dalles, Oregon	85	%	99	%
Mid-Columbia River at Grand Coulee, Washington	80		98
Clackamas River	122		157
Deschutes River	92		112

Production and distribution expense increased $2 million, or 5%, in the third quarter of 2009 compared to the third quarter of 2008. Higher operating and maintenance costs at PGE’s generating plants, including those related to the Company’s new Biglow Canyon Phase II wind project, were partially offset by a reduction in distribution related expenses.

Administrative and other expense decreased $5 million, or 10%, in the third quarter of 2009 compared to the third quarter of 2008, primarily due to a decrease in incentive compensation. This decrease was partially offset by an increase in pension costs.

Depreciation and amortization expense decreased $1 million, or 2%, in the third quarter of 2009 compared to the third quarter of 2008. A decrease related to the recovery of certain regulatory assets (fully offset in Retail sales) was partially offset by an increase in depreciation related to Biglow Canyon Phase II and other capital additions in 2009.

Other income (expense), net increased $11 million in the third quarter of 2009 compared to the third quarter of 2008, primarily due to the following:

• A $9 million increase in income from non-qualified benefit plan trust assets, resulting from a $5 million increase in the fair value of the plan assets in the third quarter of 2009 compared to a $4 million decrease in the third quarter of 2008; and

• A $2 million increase in the allowance for equity funds used during construction as a result of higher construction work in progress balances in 2009 related primarily to Biglow Canyon Phases II and III.

Interest expense increased $4 million, or 19%, in the third quarter of 2009 compared to the third quarter of 2008. The increase is primarily due to the net effect of the following:

• A $6 million increase resulting from a higher average long-term debt balance in the third quarter of 2009 compared to the third quarter of 2008. In January and April 2009, PGE issued $130 million and $300 million, respectively, of first mortgage bonds, increasing the average debt balance to $1,594 million in the third quarter of 2009, compared to $1,306 million in the third quarter of 2008; and

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• A $2 million decrease due to a higher credit to interest expense for the allowance for funds used during construction, resulting from higher construction work in progress balances during the third quarter of 2009, related primarily to the construction of Biglow Canyon Phases II and III.

Income tax expensewas $16 million in the third quarter of 2009, compared to a benefit of $1 million in the third quarter of 2008. The increase in income taxes is largely due to an increase in pretax earnings. Additionally, in July of 2009, Oregon’s corporate tax rate was increased retroactive to January 1, 2009. As a result of this increase, PGE’s income taxes increased $3 million in the third quarter of 2009. This tax increase was largely offset by an increase in federal and state tax credits of $3 million.

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Nine Months Ended September 30, 2009 Compared to the Nine Months Ended September 30, 2008

Revenues, energy sold and delivered (based in megawatt hours), and average number of retail customers consist of the following:

	Nine Months Ended September 30,
	2009				2008
	Amount		% of Total		Amount			% of Total
Revenues(dollars in millions):
Retail sales:
Residential	$	574	44	%	$	559		43	%
Commercial		463	35			450		35
Industrial		125	9			119		9
Total retail sales		1,162	88			1,128		87
Direct access customers		-	-			(7	)	(1	)
Other retail revenues		52	4			(13	)	(1	)
Total retail revenues		1,214	92			1,108		85
Wholesale revenues		85	6			153		12
Other operating revenues		20	2			35		3
Total revenues	$	1,319	100	%	$	1,296		100	%
Energy sold and delivered(MWh in thousands):
Retail energy sales:
Residential		5,716	35	%		5,765		33	%
Commercial		5,367	32			5,439		31
Industrial		1,772	11			1,857		11
Total retail energy sales		12,855	78			13,061		75
Delivery to direct access customers:
Commercial		299	2			456		3
Industrial		1,120	6			1,369		8
Total retail energy deliveries		14,274	86			14,886		86
Wholesale sales		2,274	14			2,429		14
Total energy sold and delivered		16,548	100	%		17,315		100	%
Average number of retail customers:
Residential		714,125	88	%		710,446		88	%
Commercial		100,995	12			99,783		12
Industrial		252	-			217		-
Direct access		254	-			415		-
Average retail customers		815,626	100	%		810,861		100	%

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Revenues increased $23 million, or 2%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 as a result of the net effect of the items discussed below.

Total retail revenues increased $106 million, or 10%, due primarily to:

• A $95 million increase resulting from higher average prices, driven primarily by OPUC-approved price increases in PGE’s most recent general rate case, which became effective January 1, 2009;

• A $33 million increase resulting from the accrual of customer refunds in the third quarter of 2008 pursuant to the OPUC order related to various Trojan matters, which is included in Other retail revenues;

• A $7 million increase resulting from a reduction in transition adjustment credits provided to Direct Access customers. These credits are provided for under Oregon’s electricity restructuring law and are based on the difference between the cost and market value of PGE’s power supply;

• An $18 million decrease driven by a 2% decline in total retail energy sales to residential, commercial, and industrial customers, which resulted from the continued economic slowdown in 2009;

• A $7 million decrease related to the recovery of certain regulatory assets, which is fully offset in Depreciation and amortization expense; and

• A $4 million decrease related to the decoupling mechanism, which went into effect on February 1, 2009 and is included in Other retail revenues.

During the nine months ended September 30, 2009, heating degree-days decreased 9% compared to the same period of 2008. Cooling degree-days increased 32% from the comparable period of the prior year and were 35% greater than the 15-year average. 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 Degree-days		Cooling Degree-days
	2009	2008	2009	2008
1st Quarter	2,022	1,981	-	-
2nd Quarter	578	860	90	98
3rd Quarter	63	80	537	376
Year-to-date	2,663	2,921	627	474
15-year average for the year-to-date	2,594	2,586	465	452

On a weather adjusted basis, retail energy deliveries decreased 3.1% during the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, with deliveries to residential, commercial, and industrial customers increasing (decreasing) by 0.3%, (3.4)%, and (8.6)%, respectively. Economic shutdowns by some large industrial customers have curtailed retail energy deliveries during 2009.

In addition to those items listed above as “included in Other retail revenues,” Other retail revenues includes certain customer credits and refunds that are fully offset in Retail sales, therefore having no impact to total Retail revenues. These consist primarily of the following items:

• A $19 million increase related to the resumption of customer credits pursuant to the Residential Exchange Program administered by the Bonneville Power Administration, which resulted in an average price reduction of approximately 6.3% for residential and small farm customers, effective April 15, 2008;

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• A $14 million increase, reflecting customer refunds related to results of the 2007 PCAM, which are being made over a one-year period that began January 1, 2009; and

• A $5 million increase related to net customer refunds under SB 408 for the 2006 and 2007 reporting years.

Wholesale revenues decreased $68 million, or 44%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 due to the net effect of the following:

• A $58 million decrease related to a 41% decline in average price, driven by lower natural gas and electricity prices; and

• A $10 million decrease related to a 6% decline in wholesale energy sales.

Other operating revenues decreased $15 million, or 43%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, as the result of fuel oil sales from the Company’s Beaver generating plant in 2008. Such sales resulted in realized gains of $11 million.

Purchased power and fuel expense increased $12 million, or 2%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The increase was due primarily to the net effect of the following:

• A $42 million, or 11%, increase in the cost of purchased power, resulting primarily from increased purchases required to replace the output of Colstrip and Boardman, as discussed below; and

• A $30 million, or 12%, decrease in the cost of generation. The overall decrease resulted primarily from a 17% reduction in generation due to extended maintenance and repair outages at Colstrip and Boardman and an 8% decrease in the average cost of natural gas-fired generation.

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PGE’s sources of energy (based in MWh) for the periods presented are as follows (MWh in thousands):

	Nine Months Ended September 30,
	2009				2008
Generation:
Thermal:
Natural gas	3,100		19	%	3,097		19	%
Coal	2,435		15		3,549		21
Hydro	1,366		9		1,422		9
Wind	384		3		318		2
Total generation	7,285		46		8,386		51
Purchased power:
Term purchases	5,132		32		4,383		27
Purchased hydro	2,187		14		2,407		15
Spot purchases	1,376		8		1,191		7
Total purchased power	8,695		54		7,981		49
Total system load	15,980		100	%	16,367		100	%
Less: wholesale sales	(2,274	)			(2,429	)
Retail load requirement	13,706				13,938

Retail load requirement decreased 2% from 2008 primarily due to the continued economic slowdown. The average variable cost of PGE’s total system load was $41.55 per MWh for the nine months ended September 30, 2009 compared to $39.79 per MWh for the nine months ended September 30, 2008, an increase of 4%.

Generation from hydro resources represented 26% and 27% of PGE’s retail load requirement during the nine months ended September 30, 2009 and 2008, respectively. Due to a reduction in hydro availability, PGE-owned hydro production and energy received under contracts from mid-Columbia River projects were down 4% and 9%, respectively, during the nine months ended September 30, 2009 compared to the same period of 2008.

Production and distribution expense increased $2 million, or 2%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to the net effect of the following:

• A $4 million increase for repair and restoration activities, related primarily to 2009 wind storms;

• A $3 million increase in maintenance costs at Colstrip Unit 4, consisting of those related to an extended overhaul and the repair of damaged turbine rotors in 2009;

• A $2 million escalation increase in the long-term service agreement for the Company’s Coyote Springs natural gas-fired generating plant;

• A $1 million increase resulting from a reserve established for the cost of certain environmental remediation activities;

• A $6 million decrease related to the deferral of certain plant maintenance costs at Boardman, Beaver, and Colstrip. As authorized by the OPUC in PGE’s most recent general rate case, certain maintenance costs that exceed those covered in current prices are deferred and amortized over ten years, beginning in 2009; and

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• A $2 million decrease in maintenance outage expenses at Boardman as compared to the first nine months of 2008.

Administrative and other expense decreased $8 million, or 6%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to the net effect of the following:

• An $8 million decrease in incentive compensation;

• A $3 million decrease in legal settlement expense;

• A $1 million decrease in customer support expenses; and

• A $4 increase in employee benefit expenses, related primarily to pension and medical costs.

Depreciation and amortization expense increased $6 million, or 4%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to the net effect of the following:

• A $5 million increase related to impairment losses recognized on photovoltaic solar power facilities, the majority of which was allocated to noncontrolling interests through the Net losses attributable to the noncontrolling interests. For additional information, see Note 10 to the condensed consolidated financial statements included in Item 1 - “Financial Statements”;

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

• A $5 million increase related to capital additions in 2009; and

• An $8 million decrease related primarily to the 2008 recovery of certain regulatory assets (fully offset in Retail sales).

Other income (expense), net increased $18 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to the net effect of the following:

• A $16 million increase in income from non-qualified benefit plan trust assets, resulting from a $7 million increase in the fair value of the plan assets in the first nine months of 2009 compared to a $9 million decrease in the comparable period of 2008;

• A $6 million increase in the allowance for equity funds used during construction as a result of higher construction work in progress balances in 2009, related primarily to Biglow Canyon Phases II and III; and

• A $4 million decrease in miscellaneous income, including $2 million resulting from lower rates on lower average money market account balances.

Interest expense increased $9 million, or 13%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to the net effect of the following:

• A $12 million increase resulting from a higher average long-term debt balance during the first nine months of 2009 compared to the first nine months of 2008, related primarily to capital requirements associated with generation construction. In January and April 2009, PGE issued $130 million and $300 million, respectively, of first mortgage bonds, increasing the average outstanding long-term debt balance to $1,450 million during the first nine months of 2009, compared to $1,310 million in the first nine months of 2008;

• A $2 million increase in fees related to PGE’s credit facilities; and

• A $5 million decrease resulting from an increase in the allowance for funds used during construction, related primarily to the construction of Biglow Canyon Phases II and III.

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Income tax expenseincreased $5 million for the nine months ended September 30, 2009, with an effective tax rate of 28.3%, compared to the same period of 2008, with an effective tax rate of 28.7%. The effective tax rates for both 2009 and 2008 differ from the expected statutory rate due to federal and state tax credits, the majority of which consist of production tax credits. The decrease in the effective tax rate in 2009 compared to 2008 is largely the result of an increase in these tax credits of $5 million, partially offset by a $3 million increase in income taxes driven by a newly enacted state tax rate.

Net loss attributable to noncontrolling interestsof $6 million represents the noncontrolling interests’ portion of the net loss of PGE’s less-than-wholly-owned subsidiaries, the majority of which consists of the impairment losses recognized on the photovoltaic solar power facilities, discussed previously in Depreciation and amortization.

Liquidity and Capital Resources

Capital Requirements

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

	2009		2010		2011		2012		2013
Ongoing capital expenditures	$	235	$	245		$230 - $250		$245 - $265		$240 - $260
Biglow Canyon Phase II		230		-	-			-		-
Biglow Canyon Phase III		175		200	-			-		-
Hydro licensing and construction		30		25		$55 - $75
Smart meter project		60		60	-			-		-
Boardman emissions controls *		2		15		$210 - $250
Total capital expenditures	$	732	$	545
Long-term debt maturities	$	142	$	186	$                  -		$	100	$	100

* Represents 80% of estimated total costs.

Ongoing capital expenditures - Consists of upgrades to and replacement of transmission, distribution and generation infrastructure, as well as new customer connections.

Biglow Canyon Phases II and III - Construction of Phase II, with an installed capacity of 149 MW, was completed in August 2009. Total cost of the project through September 2009 was approximately $320 million, including $12 million of AFDC. Construction of Phase III, which will have an installed capacity of 175 MW, is continuing, with completion expected in the third quarter of 2010. The estimated total cost of Phase III is $426 million, including $23 million of AFDC.

Hydro licensing and construction - As required under the 50-year license that the FERC issued to PGE in 2005 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 is designed to collect juvenile salmon and steelhead, allowing them to bypass the dam when migrating to the Pacific Ocean, and regulate downstream water temperature. As a result of a delay in construction, completion of the system, initially planned for the second quarter of 2009, is now expected in late 2009 or early in 2010. The total cost is estimated at $105 million to $110 million, with PGE’s portion estimated at $80 million to $85 million, including AFDC.

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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 licensing 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. Pending issuance of the new license, the project is operating under annual licenses issued by the FERC. PGE anticipates that the FERC will issue a decision on approval of a new license for the Clackamas River projects in 2010.

Smart meter project - Installation of approximately 850,000 customer smart meters is continuing, with approximately 300,000 installed through October 20, 2009. It is expected that about 400,000 new meters will be installed by the end of 2009, with the remainder to be installed in 2010. The project, which will enable two-way remote communication, is expected to provide improved services, operational efficiencies, and a reduction in future operating expenses. The capital cost of the smart meter project is estimated to range from $130 million to $135 million, excluding AFDC.

Boardman emissions controls - In accordance with federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ conducted an assessment of emissions sources which indicated that Boardman contributes to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination, as required under the Clean Air Act.

In June 2009, the OEQC adopted a rule that would require the installation of controls at Boardman in three phases. The first phase would require installation of controls for nitrogen oxides (NO_x), with estimated completion by 2011. The second phase would address mercury and sulfur dioxide removal using a semi-dry scrubber and bag house, with estimated completion by 2014. These first two phases would meet federal requirements for installing BART. The third phase, which would require the installation of Selective Catalytic Reduction for additional NO_x control, with estimated completion by 2017, would meet requirements for reasonable progress towards haze emissions reduction goals. The OEQC rule has been submitted to the EPA for approval as part of the Oregon Regional Haze State Implementation Plan (SIP). The Company expects the EPA to issue a decision on the SIP in 2010.

Based on requirements outlined in the OEQC’s rule and current market conditions for air quality equipment, PGE estimates that the approximate cost of the controls required by the OEQC rule would be between $520 million and $560 million (100% of total costs, excluding AFDC). The Company has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. PGE will continue to seek recovery of its costs through the ratemaking process.

PGE believes that, based upon the expected cost and risks relating to (i) carbon dioxide emissions, (ii) replacement generation, (iii) coal and natural gas, and (iv) emissions controls required to meet the OEQC’s rule, the long-term continued operation of Boardman will best meet the economic and reliability interests of its customers. Accordingly, given the options provided by the OEQC of either ceasing operation of Boardman or installing controls and continuing operations, PGE has proposed to continue operation of Boardman with the addition of the controls called for in the OEQC rule as part of the Company’s IRP action plan discussed below.

Integrated Resource Plan - Further capital needs could include those described in the Company’s draft IRP, which was issued for public comment in September 2009. The final IRP, which will be filed with the OPUC in November 2009, will describe the Company’s action plan through the year 2020, with particular emphasis on energy efficiency programs and the acquisition of supply and transmission resources to meet the Company’s annual average energy shortfall by 2015.

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PGE’s proposed action plan contained in the draft IRP includes the following:

• Acquisition of 214 MWa of energy efficiency through continuation of Energy Trust of Oregon programs, with funding to be provided from the existing public purpose charge and through enabling legislation included in Oregon’s Renewable Energy Standard;

• An additional 122 MWa of wind or other renewable resources necessary to meet requirements of Oregon’s Renewable Energy Standard by 2015;

• New natural gas generation facilities to help meet additional base load requirements estimated at 300-500 MW;

• Natural gas generation facilities to meet additional peak load requirements estimated at up to 200 MW;

• A 200-mile, 500 kV transmission project that would help meet growing demand by interconnecting new and existing energy resources in eastern Oregon to the Company’s service territory. PGE is working with other utilities and the Western Electricity Coordinating Council to coordinate the project and is currently exploring possible routes. The total cost of the Cascade Crossing Transmission Project is estimated to range from $610 million to $825 million (current dollars, excluding AFDC), depending on whether a single circuit or double circuit line is constructed; and

• The addition of emissions controls at Boardman, as discussed above.

The Company plans to conduct formal bidding processes in 2010 to acquire some of the resource needs identified in the action plan as acknowledged by the OPUC. PGE plans to include self-build options in the request for proposal processes with respect to the renewable resources and the two natural gas plants indicated above.

Liquidity

PGE’s access to short-term debt markets provides necessary liquidity to support the Company’s current operating activities, including power and fuel purchases. 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.

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

	Nine Months Ended September 30,
	2009			2008
Cash and cash equivalents, beginning of period	$	10		$	73
Net cash provided by (used in):
Operating activities		377			222
Investing activities		(546	)		(277	)
Financing activities		205			(13	)
Net change in cash and cash equivalents		36			(68	)
Cash and cash equivalents, end of period	$	46		$	5

Net cash provided by operating activities - The $155 million increase in cash provided by operating activities for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 was primarily attributable to the net effect of the following:

• A $223 million increase related to an overall decrease in margin deposit requirements with certain wholesale customers and brokers, driven primarily by recent increases in the forward market prices of power and natural gas;

• A $52 million increase in cash received from retail sales of electricity, driven by higher prices;

• An $8 million increase due to lower income tax payments;

• A $103 million decrease resulting from higher payments for power and fuel purchases in 2009;

• A $15 million decrease due to payments received in 2008 from the sales of fuel oil;

• A $5 million decrease resulting from higher payments for payroll taxes and other employee benefits; and

• A $5 million decrease due to higher payments in 2009 for Biglow II and III warranty and availability guarantee payments.

A significant portion of cash provided by operations consists of the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates recovery of such charges will approximate $215 million in 2009 and $225 million in 2010. Combined with all other sources, cash provided by operations is estimated to be approximately $420 million in 2009 and $475 million in 2010, including reductions in margin deposits held by certain wholesale customers and brokers of $87 million in 2009 and $55 million in 2010. The estimated reduction of such margin deposits is based on both the timing of contract settlements and projected future energy prices.

Net cash used in investing activities -The $269 million increase in cash used in investing activities for the nine months ended September 30, 2009 relative to the comparable period of 2008 was primarily attributable to a $251 million increase in construction costs related to Biglow Canyon Phases II and III and a $28 million increase in expenditures for the smart meter project. These increases were partially offset by an $18 million decrease in expenditures for the Selective Water Withdrawal project. See “Capital Requirements” section above for further information.

Net cash provided by financing activities - Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Net cash provided by such activities was $205 million for the nine months ended September 30, 2009 compared to net cash used of $13 million for the nine months ended September 30, 2008. PGE relies on cash from operations, the issuance of commercial paper, borrowings under its revolving credit facilities, and long-term financing activities to

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support such requirements. During the first nine months of 2009, cash provided by financing activities consisted primarily of net proceeds of $426 million and $170 million from the issuance of long-term debt and common stock, respectively. These issuances were partially offset by the repayment of $142 million of Pollution Control Bonds, $131 million in net payments on revolving credit facilities, $72 million in payments on short-term debt, and $53 million in dividend payments. Financing activities in the first nine months of 2009 also included the receipt of $7 million in cash contributions from noncontrolling interests in the solar projects. During 2008, net cash used in financing activities consisted of $56 million of long-term debt repayments and $45 million in dividend payments, partially offset by $50 million in proceeds from the issuance of long-term debt and $27 million in net short-term borrowings.

Dividends on Common Stock

While PGE 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 2009 consist of the following:

Declaration Date	Record Date	Payment Date	Dividends Declared per Share
February 19, 2009	March 25, 2009	April 15, 2009	$	0.245
May 13, 2009	June 25, 2009	July 15, 2009		0.255
August 5, 2009	September 25, 2009	October 15, 2009		0.255

Debt and Equity Financings

PGE has approval from the FERC to issue short-term debt up to a total of $550 million through February 6, 2010 and currently has the following unsecured revolving credit facilities:

• A $370 million credit facility with a group of banks, with $10 million and $360 million currently scheduled to terminate in July 2012 and July 2013, respectively;

• A $125 million credit facility with a group of banks, currently scheduled to terminate in December 2009; and

• A $30 million credit facility with a bank, currently scheduled to terminate in June 2012.

These credit facilities supplement operating cash flow and provide a primary source of liquidity. Pursuant to the individual terms of the agreements, these facilities may be used for borrowings for general corporate purposes and as backup for commercial paper borrowings. The $370 million and $30 million credit facilities also permit borrowings and the issuance of standby letters of credit. As of September 30, 2009, PGE had no borrowings or commercial paper outstanding and had $190 million of letters of credit outstanding under the credit facilities. As of September 30, 2009, the aggregate unused available credit under the credit facilities was $335 million. The Company intends to seek to replace the $125 million credit facility and may increase the amount of the credit facility to as much as $200 million and extend the term to two or three years.

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Through September 30, 2009, PGE had issued the following first mortgage bonds:

• $130 million in January 2009 in two series. The first series is for $67 million to mature January 15, 2016 at a fixed rate of 6.8%. The second series is for $63 million to mature on January 15, 2014 at a fixed rate of 6.5%; and

• $300 million of 6.1% Series in April 2009, which mature April 15, 2019.

The Company used a portion of the proceeds from the April 2009 bond issuance to purchase $142 million of its Pollution Control Bonds on May 1, 2009. These Pollution Control Bonds are currently owned by the Company and may be remarketed at a later date at the Company’s option. As of September 30, 2009, the total long-term debt outstanding was $1,594 million.

On September 30, 2009, PGE entered into an agreement to sell $150 million of 5.43% Series First Mortgage Bonds that mature on May 3, 2040. These bonds are expected to be issued on or about November 3, 2009.

In March 2009, PGE issued 12,477,500 shares of common stock. The net proceeds of $170 million were used to substantially repay outstanding short-term debt, with the balance to fund capital expenditures and general corporate purposes.

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, and alternatives available to investors. The Company’s ability to obtain and renew such financing depends on its credit ratings, as well as on credit markets, both generally and for electric utilities in particular. Management believes that the availability of PGE’s credit facilities, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. PGE currently expects to issue approximately $250 million of additional debt in 2010, part of which will be used to repay $186 million of debt that matures in 2010.

PGE’s financial objectives include the balancing of debt and equity to maintain an optimum 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 favorable credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were 49.4% and 47.3% as of September 30, 2009 and December 31, 2008, respectively.

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	A3	A
Senior unsecured debt	Baa2	BBB+
Commercial paper	Prime-2	A-2
Outlook	Positive	Negative

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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 its wholesale, commodity and certain transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. These deposits, which are classified as Margin deposits in PGE’s condensed consolidated balance sheet, are based on the contract terms and commodity prices and can vary from period to period. As of September 30, 2009, PGE had posted approximately $256 million of collateral with these counterparties, consisting of $86 million in cash and $170 million in letters of credit, $32 million of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of current energy market prices, and the level of collateral outstanding as of September 30, 2009, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $106 million and decreases to approximately $50 million by December 31, 2009. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $156 million at September 30, 2009 and decreases to approximately $88 million by December 31, 2009.

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 Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have, on September 30, 2009, issued up to approximately $524 million of additional first mortgage bonds, of which $150 million is expected to be issued on or about November 3, 2009. Additional future issuances would be subject to market conditions and amounts could 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 retirements, and/or deposits of cash.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65% of total capitalization (debt ratio). As of September 30, 2009, the Company’s debt ratio, as calculated under the credit agreements, was 50.6%.

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.

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Contractual Obligations

PGE’s contractual obligations for 2009 and beyond are set forth in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009. Such obligations have not changed materially as of September 30, 2009, with the following exceptions:

• In January 2009, PGE issued $130 million of first mortgage bonds, with $67 million at a fixed rate of 6.8%, maturing in January 2016, and $63 million at a fixed rate of 6.5%, maturing in January 2014;

• In April 2009, PGE issued $300 million of 6.1% Series First Mortgage Bonds that mature in April 2019; and

• In September 2009, PGE entered into an agreement to issue $150 million of 5.43% Series First Mortgage Bonds that mature in May 2040. These bonds are expected to be issued on or about November 3, 2009.

PGE currently expects no contributions to its defined benefit pension plan in 2009 and 2010, but estimates that it will be required to make contributions of approximately $40 million in 2011, $19 million in 2012, and $16 million in 2013.

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 from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009.

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, 2009, these disclosure controls and procedures were effective.

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.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

For further information regarding the following 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, 2008, filed with the SEC on February 25, 2009 and Part II, Item 1 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, filed with the SEC on May 4, 2009.

Puget Sound Energy, Inc. v. All Jurisdictional Sellers of Energy and/or Capacity at Wholesale Into Electric Energy and/or Capacity Markets in the Pacific Northwest, Including Parties to the Western System Power Pool Agreement, Federal Energy Regulatory Commission, Docket Nos. EL01-10-000, et seq. (Pacific Northwest Refund proceeding).

On August 24, 2007, the Ninth Circuit issued its decision on appeal, 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 did not rule on the FERC’s ultimate decision to deny refunds. After denying requests for rehearing, on April 16, 2009, the Ninth Circuit issued a mandate giving immediate effect to its August 24, 2007 order remanding the case to the FERC.

Since issuance of the mandate, certain parties proposing refunds have filed pleadings with the FERC suggesting procedures on remand, attempting to initiate new proceedings, and containing additional evidence that they assert shows market-wide manipulation that justifies refunds from early in 2000. Parties opposing refunds, including PGE, have filed various pleadings that contest allegations of market-wide manipulation and urge the FERC to reaffirm, with a more detailed explanation of its consideration of market manipulation claims, its previous decision not to initiate proceedings to order refunds.

On September 4, 2009, various parties, including PGE, filed a petition for a writ of certiorari with the U.S. Supreme Court requesting that the Supreme Court review the decision of the Ninth Circuit in the Pacific Northwest Refund proceeding. The petition asserts that, among other things, the Ninth Circuit erred by interfering with certain FERC decisions that other circuit courts have held are within the FERC’s discretion.

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 Boardman’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 seek injunctive relief that includes permanently enjoining PGE from operating Boardman except in accordance with the CAA, Oregon’s SIP, and Boardman’s Title V Permit. In addition, plaintiffs seek civil penalties against PGE including $27,500 per day per alleged violation for violations occurring

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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.

On September 30, 2009, the District Court ruled on PGE’s motion to dismiss most of the claims. In summary, the court denied PGE’s motion with respect to most of the plaintiffs’ claims. The court granted PGE’s motion with respect to the plaintiffs’ claims alleging that PGE triggered new source performance standards, but denied the motion with respect to the claims alleging violation of federal and state permitting requirements for the construction and subsequent modification of Boardman. The principal claims that remain are (i) that PGE constructed Boardman without complying with the 1974 and 1977 federal pre-construction permitting requirements and (ii) that PGE modified Boardman in the 1990s without complying with Oregon’s pre-construction permitting requirements.

The Company believes that it has strong defenses to the plaintiffs’ claims and intends to vigorously defend against this lawsuit.

Item 1A. Risk Factors.

There have been no material changes to 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, 2008, filed with the SEC on February 25, 2009.

Item 6. Exhibits.

3.1	Second Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed August 3, 2009).
3.2	Sixth 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 May 15, 2009).
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.

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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 28, 2009	By:	/s/ Maria M. Pope
		Maria M. Pope
		Senior Vice President, Chief Financial Officer, and Treasurer
		(duly authorized officer and principal financial officer)

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