Edgar Filing: PORTLAND GENERAL ELECTRIC CO /OR/

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

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 April 30, 2009 is 75,130,568 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	28

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	48

Item 4.	Controls and Procedures.	49

PART II – OTHER INFORMATION		49

Item 1.	Legal Proceedings.	49

Item 1A.	Risk Factors.	50

Item 6.	Exhibits.	50

SIGNATURE		51

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:


Abbreviation or Acronym		Definition
AFDC		Allowance for funds used during construction
Biglow Canyon		Biglow Canyon Wind Farm
Boardman		Boardman coal plant
BPA		Bonneville Power Administration
CERS		California Energy Resources Scheduling
Colstrip		Colstrip Units 3 and 4 coal plant
DEQ		Oregon Department of Environmental Quality
EITF		Emerging Issues Task Force of the Financial Accounting Standards Board
EPA		U.S. Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRP		Integrated Resource Plan
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

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 March 31,
	2009			2008
Revenues	$	485		$	471

Operating expenses:
Purchased power and fuel		255			250
Production and distribution		42			39
Administrative and other		45			47
Depreciation and amortization		57			50
Taxes other than income taxes		23			22

Total operating expenses		422			408

Income from operations		63			63

Other income (expense):
Allowance for equity funds used during construction		2			2
Miscellaneous income (expense)		(3	)		(3	)

Other expense, net		(1	)		(1	)
Interest expense		25			23

Income before income taxes		37			39
Income taxes		13			11

Net income		24			28

Add: net losses attributable to the noncontrolling interests		7			-

Net income attributable to Portland General Electric Company	$	31		$	28


Weighted-average shares outstanding (in thousands):
Basic		65,521			62,530

Diluted		65,607			62,571

Earnings per share - basic and diluted	$	0.47		$	0.44


Dividends declared per common share	$	0.245		$	0.235

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)


	March 31, 2009		December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	47	$	10
Accounts receivable, net		168		168
Unbilled revenues		77		96
Assets from price risk management activities - current		51		31
Inventories, at average cost		72		71
Margin deposits		205		189
Current deferred income taxes		28		17
Regulatory assets - current		235		194
Other current assets		57		44

Total current assets		940		820
Electric utility plant, net		3,440		3,301
Non-qualified benefit plan trust		41		46
Nuclear decommissioning trust		46		46
Regulatory assets - noncurrent		679		631
Other noncurrent assets		41		45

Total assets	$	5,187	$	4,889

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)


	March 31, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	256		$	217
Liabilities from price risk management activities - current		286			225
Regulatory liabilities - current		72			43
Short-term debt		-			203
Current portion of long-term debt		149			142
Other current liabilities		76			59

Total current liabilities		839			889
Long-term debt, net of current portion		1,287			1,164
Liabilities from price risk management activities - noncurrent		243			201
Regulatory liabilities - noncurrent		613			640
Deferred income taxes		327			304
Unfunded status of pension and postretirement plans		174			174
Non-qualified benefit plan liabilities		93			91
Other noncurrent liabilities		74			72

Total liabilities		3,650			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 March 31, 2009 and December 31, 2008		-			-
Common stock, no par value, 80,000,000 shares authorized; 75,130,568 and 62,575,257 shares issued and outstanding as of March 31, 2009 and December 31, 2008, respectively		829			659
Accumulated other comprehensive loss		(5	)		(5	)
Retained earnings		713			700

Total Portland General Electric Company shareholders’ equity		1,537			1,354
Noncontrolling interests’ equity		-			-

Total shareholders’ equity		1,537			1,354

Total liabilities and shareholders’ equity	$	5,187		$	4,889

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Three Months Ended March 31,
	2009			2008
Cash flows from operating activities:
Net income	$	24		$	28
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		57			50
Increase (decrease) in net liabilities (assets) from price risk management activities		87			(141	)
Regulatory deferral - price risk management activities		(87	)		141
Deferred income taxes		11			10
Senate Bill 408 deferrals		(6	)		3
Allowance for equity funds used during construction		(2	)		(2	)
Power cost deferrals		(5	)		-
Other non-cash income and expenses, net		9			11
Changes in working capital:
(Increase) decrease in margin deposits		(16	)		22
Decrease in receivables		19			-
Increase (decrease) in payables		(35	)		13
Other working capital items, net		(21	)		(13	)
Other, net		5			(5	)

Net cash provided by operating activities		40			117

Cash flows from investing activities:
Capital expenditures		(91	)		(71	)
Sales of nuclear decommissioning trust securities		7			7
Purchases of nuclear decommissioning trust securities		(7	)		(6	)
Insurance proceeds		-			3
Other, net		-			(1	)

Net cash used in investing activities		(91	)		(68	)

Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		170			-
Proceeds from issuance of long-term debt, net of issuance costs		129			-
Payments on long-term debt		-			(56	)
Borrowings on revolving credit facilities		82			-
Noncontrolling interests’ cash contributions		7			-
Payments on revolving credit facilities		(213	)		-
Payments on short-term debt, net		(72	)		-
Dividends paid		(15	)		(15	)

Net cash provided by (used in) financing activities		88			(71	)

Change in cash and cash equivalents		37			(22	)
Cash and cash equivalents, beginning of period		10			73

Cash and cash equivalents, end of period	$	47		$	51

Supplemental cash flow information is as follows:
Cash paid during the period for
Interest, net of amounts capitalized	$	13		$	12
Non-cash investing and financing activities:
Accrued capital additions		104			71
Accrued dividends payable		18			15

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power and fuel marketers located throughout the western United States. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. The Company served 814,058 retail customers as of March 31, 2009.

As of March 31, 2009, PGE had 2,718 employees, with 871 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (Local 125). Such agreements cover 836 employees for the five-year period ended February 28, 2009 and 35 employees for the five-year period ending August 1, 2011. PGE is in negotiation with Local 125 for a new agreement to replace the one that expired February 28, 2009. This agreement remains in effect following the expiration date unless either party gives at least 60 days’ written notice of termination. Neither party has given written notice to terminate.

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 months ended March 31, 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.

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 historically have all been classified as current, as well as its Regulatory assets and liabilities, which historically have 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. As a result of the preceding reclassifications, current deferred income taxes in the amount 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 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 152-2). SFAS 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not modify any currently existing accounting pronouncements. PGE’s nonfinancial liabilities include asset retirement obligations (AROs), which are accounted for in accordance with SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143), are initially measured at fair value. In subsequent reporting periods, AROs are not measured at fair value. The application of SFAS 157 is not required for recurring measurement of nonfinancial liabilities accounted for pursuant to SFAS 143 as amounts are only measured at fair value in the initial period and not in subsequent reporting periods. The adoption of SFAS 157 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 and (2) establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. SFAS 160 shall be applied prospectively, with the exception of the presentation and disclosure requirements, which shall be applied retrospectively for all periods presented. Any noncontrolling interest resulting from the consolidation of a less-than-wholly-owned subsidiary beginning January 1, 2009 is accounted for in accordance with SFAS 160. The adoption of SFAS 160 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 interest”, in PGE’s consolidated balance sheet and consolidated statement of income.

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 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 presented shall be adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1. The adoption of FSP EITF 03-6-1 did not have an 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 is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On April 9, 2009, the FASB issued 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. FSP FAS 107-1 and APB 28-1 is effective for interim and annual reporting periods ending after June 15, 2009, with earlier application permitted. The adoption of FSP FAS 107-1 and APB 28-1 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 March 31, 2009 and $4 million as of December 31, 2008.

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


	Three Months Ended March 31,
	2009			2008
Balance at beginning of period	$	4		$	5
Provision		2			1
Amounts written off, less recoveries		(1	)		(1	)

Balance at end of period	$	5		$	5

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.

Electric Utility Plant, Net

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


	March 31, 2009			December 31, 2008
Electric utility plant	$	5,099		$	5,066
Construction work in progress		422			284

Total cost		5,521			5,350
Less: accumulated depreciation and amortization		(2,081	)		(2,049	)

Electric utility plant, net	$	3,440		$	3,301

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $113 million and $109 million as of March 31, 2009 and December 31, 2008, respectively. Amortization expense related to intangible assets was $4 million for each of the three month periods ended March 31, 2009 and 2008.

Regulatory Assets and Liabilities

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


	March 31, 2009				December 31, 2008
	Current		Noncurrent		Current		Noncurrent
Regulatory Assets:
Price risk management	$	235	$	239	$	194	$	193
Pension and other postretirement plans		-		232		-		232
Deferred income taxes		-		87		-		88
Boardman power cost deferral		-		35		-		34
Debt reacquisition costs		-		28		-		28
Utility rate treatment of income taxes		-		18		-		17
Other		-		40		-		39

Total regulatory assets	$	235	$	679	$	194	$	631

Regulatory liabilities:
Asset retirement removal costs	$	-	$	505	$	-	$	494
Utility rate treatment of income taxes		23		14		24		19
Trojan refund liability		35		-		-		34
Power Cost Adjustment Mechanism		14		-		19		-
Residential Exchange Program		-		10		-		12
Asset retirement obligations		-		27		-		26
Trojan ISFSI pollution control tax credits		-		18		-		17
Other		-		39		-		38

Total regulatory liabilities	$	72	$	613	$	43	$	640

Included in Other regulatory assets and liabilities above are amounts related to PGE’s Decoupling Mechanism, which became effective on February 1, 2009, pursuant to approval by the OPUC. An approximate $0.8 million regulatory asset has been recorded to reflect results of the Sales Normalization Adjustment component of the mechanism, which reflects the difference between actual weather adjusted usage by residential and small non-residential customers and that projected in the Company’s most recent general rate case. An approximate $0.3 million regulatory liability has been recorded to reflect results of the ROE Refund component of the mechanism, which reduces PGE’s allowed return on equity (from 10.1% to 10.0%) to reflect a reduction in the Company’s risk associated with the Decoupling Mechanism. The net impact of the mechanism (approximately $0.5 million in the first quarter of 2009) is included within Revenues on the condensed consolidated statement of income.

Credit Facilities

PGE has two unsecured revolving credit facilities with two separate groups of banks with substantially similar terms and an aggregate borrowing capacity of $495 million. The $370 million Credit Facility

permits both borrowings and the issuance of standby letters of credit and is scheduled to expire as follows: $10 million in July 2012 and $360 million in July 2013. The $125 million Short-term Credit Facility permits borrowings but does not provide for the issuance of letters of credit and is scheduled to expire December 4, 2009. 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 March 31, 2009, PGE was in compliance with this covenant.

The Company has a $400 million 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 the credit facilities.

As of March 31, 2009, PGE had issued $223 million in letters of credit under the credit facilities, and had no commercial paper outstanding and no borrowings. As of March 31, 2009, the aggregate unused available credit under the credit facilities was $272 million.

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

Pension and Other Postretirement Benefits

The following table provides the components of net periodic benefit cost (benefit) for the three months ended March 31 (in millions):


	Defined Benefit Pension Plan						Other Postretirement Benefits				Non-Qualified Benefit Plans
	2009			2008			2009		2008		2009		2008
Service cost	$	3		$	3		$	1	$	-	$	-	$	-
Interest cost		8			7			1		1		1		-
Expected return on
plan assets		(11	)		(11	)		-		-		-		-

Net periodic benefit
cost (benefit)	$	-		$	(1	)	$	2	$	1	$	1	$	-

Due to a recent ruling by the Internal Revenue Service regarding pension funding requirements, PGE currently expects to make a contribution to its defined pension plan in an amount of up to $12 million in 2010.

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

SFAS 157 prescribes a fair value hierarchy to prioritize the inputs to valuation techniques used to measure fair value into three broad levels. These 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 SFAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

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 March 31, 2009
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust *	$	28	$	18	$	-	$	46
Non-qualified benefit plan trust		22		-		-		22
Assets from price risk management activities *		-		53		2		55

	$	50	$	71	$	2	$	123

Liabilities - Liabilities from price risk management activities *	$	-	$	357	$	172	$	529


	As of December 31, 2008
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust *	$	27	$	19	$	-	$	46
Non-qualified benefit plan trust		26		-		-		26
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 and, accordingly, gains and losses are deferred pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), and included in Regulatory assets or Regulatory liabilities as appropriate.

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

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 subject to SFAS 157. Assets and liabilities from price risk management activities represent derivative transactions entered into by PGE to manage its exposure to commodity price risk and minimize net power costs for service to the Company’s retail customers and may consist of forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil.

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 March 31,
	2009			2008
Balance as of beginning of period	$	(123	)	$	1
Net realized and unrealized gains (losses)		(51	)		37
Purchases and issuances, net		4			1
Net transfers out of Level 3		-			-

Balance as of end of period	$	(170	)	$	39

Net realized and unrealized gains (losses) included in Purchased power and fuel expense in the condensed consolidated statements of income for the three months ended March 31, 2009 and 2008, in the amount of $(45) million and $34 million, respectively, have been fully offset by the effects of regulatory accounting pursuant to SFAS 71.

NOTE 4: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generating resources combined with wholesale market transactions, 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 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 under SFAS 133 or may use derivative instruments as economic hedges. PGE does not engage in trading activities for non-retail purposes.

As of March 31, 2009, PGE’s net volume related to its Price risk management assets and liabilities resulting from its derivative activities, which are expected to deliver or settle at various dates through 2013, was as follows (in millions):


Type		Volume
Commodity:
Electricity		12 MWh
Natural gas		113 Decatherms
Foreign exchange		$5 Canadian

In connection with the adoption of SFAS 161, PGE reconsidered the presentation of its Price risk management assets and liabilities, which historically have been classified as current. For additional information, see Reclassifications in Note 1. As of March 31, 2009, PGE’s Price risk management assets and liabilities resulting from its derivative activities, offset by SFAS 71 regulatory accounting, consist of the following (in millions):


	Asset Derivatives 2009			Liability Derivatives 2009
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Derivatives not designated as hedging instruments under SFAS 133:
Commodity contracts:
Electricty	Current assets	$	42	Current liabilities	$	167
Natural gas	Current assets		9	Current liabilities		118
Foreign exchange contracts	Current assets		-	Current liabilities		1

Total current derivative activity			51			286

Commodity contracts:
Electricity	Noncurrent assets		1	Noncurrent liabilities		97
Natural gas	Noncurrent assets		3	Noncurrent liabilities		146

Total long-term derivative activity			4			243

Total derivatives not designated as hedging instruments under SFAS 133		$	55		$	529

Total derivatives		$	55		$	529

Changes in the fair value of derivative instruments prior to settlement that do not qualify for either the normal purchases and normal sales exception or for hedge accounting are recorded on a net basis in Purchased power and fuel expense in the statement of income. For derivative instruments that are physically settled, sales are recorded in Revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel expense. PGE records the non-physical settlement of electricity derivative instruments on a net basis in Purchased power and fuel expense.

During the three months ended March 31, 2009, net realized and unrealized losses on derivative transactions were recognized in the statement of income as follows (in millions):


Derivatives not designated as hedging instruments under SFAS 133	Location of net loss recognized in Earnings on derivative activities	Net loss recognized in income on derivative activities *
Commodity contracts:
Electricity	Purchased power and fuel expense	$	81
Natural Gas	Purchased power and fuel expense		88

*	Amounts are offset by SFAS 71 regulatory accounting.

The following table indicates the year in which the net unrealized loss recorded as of March 31, 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	$	97	$	107	$	13	$	4	$	-	$	221
Natural gas		93		69		39		36		15		252
Foreign exchange contracts		1		-		-		-		-		1

Net unrealized loss	$	191	$	176	$	52	$	40	$	15	$	474

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 based on total portfolio positions with each counterparty, which can be in the form of cash or letters of credit.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2009 was $383 million. As of March 31, 2009, the Company had $233 million in collateral posted associated with such liability positions, which consisted of $36 million in cash, classified as Margin deposits on the condensed consolidated balance sheet, and $197 million in 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 March 31, 2009, the collateral requirement would have been $347 million, an increase of $114 million.

At March 31, 2009, contracts with five different counterparties represent approximately 86% and 69% of PGE’s Price risk management assets and liabilities, respectively. Two counterparties represent 50% and 15% each of Price risk management assets, with two different counterparties representing 30% and 16% of Price risk management liabilities. No other counterparty represents more than 10% of the Price risk management assets and liabilities.

See Note 3 for additional information concerning the determination of fair value for the Company’s Price risk management assets and liabilities.

NOTE 5: EARNINGS PER SHARE

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


	Three Months Ended March 31,
	2009		2008
Numerator (in millions):
Net income atributable to Portland General Electric
Company common shareholders	$	31	$	28


Denominator (in thousands):
Weighted-average common shares outstanding - basic		65,521		62,530
Dilutive effect of restricted stock units and employee stock purchase plan shares		86		41

Weighted-average common shares outstanding - diluted		65,607		62,571


Earnings per share - basic and diluted	$	0.47	$	0.44

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

NOTE 6: SHAREHOLDERS’ EQUITY

The activity in shareholders’ equity during the three months ended March 31, 2009 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 stock units	77,811		-		-			-			-
Noncontrolling interest capital contributions	-		-		-			-			7
Dividends declared								(18	)
Net income (loss)	-		-		-			31			(7	)

Balances as of March 31, 2009	75,130,568	$	829	$	(5	)	$	713		$	-


Balances as of January 1, 2008	62,529,787	$	646	$	(4	)	$	674		$	-
Vesting of restricted stock units	2,445		-		-			-			-
Stock based compensation	-		1		-			-			-
Dividends declared								(15	)
Net income	-		-		-			28			-

Balances as of March 31, 2008	62,532,232	$	647	$	(4	)	$	687		$	-

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

NOTE 7: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):


	Three Months Ended March 31,
	2009			2008
Net income	$	24		$	28
Unrealized gains (losses) on cash flow hedges:
Reclassification to net income for contract settlements, net of taxes		1			-
Reclassification of unrealized losses to SFAS 71 regulatory asset, net of taxes		(1	)		-

Total unrealized gains on cash flow hedges		-			-

Comprehensive income		24			28
Add: comprehensive losses attributable to the noncontrolling interests		7			-

Comprehensive income attributable to Portland General Electric Company	$	31		$	28

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, including decommissioning, in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

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

Settlement of Court Proceedings on OPUC Authority. In 2000, while the petitions for review of the 1998 Oregon Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE’s recovery of, and return on, its investment in the Trojan plant. The URP did not participate in the settlement, 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 the following issues:

•

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 $33.1 million to certain customers. The refund relates to the unamortized Trojan balance on September 30, 2000, as discussed below.

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

•

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

•

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

The OPUC examined the rates in effect for the period April 1, 1995 through September 30, 2000 and determined what rates during this period would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. The OPUC ruled that $15.4 million, plus interest at 9.6% from September 30, 2000, should be refunded to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The $15.4 million amount, plus accrued interest, results in a total refund of $33.1 million as of September 30, 2008. The order also provides that the total refund amount will accrue interest at 9.6% from October 1, 2008 until all refunds are issued to customers. The full text of OPUC Order No. 08-487 is available on its Internet website at www.puc.state.or.us. The URP and the plaintiffs in the class actions described below have separately appealed the order to the Oregon Court of Appeals.

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.

On January 24, 2009, the URP and the plaintiffs in the class actions described below filed a motion with the Court of Appeals requesting a stay of the refund pending final disposition of their appeal of the September 30, 2008 OPUC order. On February 2, 2009, the OPUC suspended the refund requirements pending the decision of the Court of Appeals on the motion requesting a stay. On February 24, 2009, the Court of Appeals denied the motion. On March 19, 2009, the OPUC issued an order that reset and restarted the refund mechanism as outlined in the September 30, 2008 order. Based on the OPUC orders, PGE is moving forward with refunds to customers, which are anticipated to occur during late 2009. In late April 2009, the URP and the plaintiffs in the class actions separately appealed the March 19, 2009 order to the Oregon Court of Appeals.

Class Actions. In a separate legal proceeding, two class action suits were filed in Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million plus interest for the Current Class and $70 million plus interest for the Former Class, as a result of the inclusion of a return on investment of Trojan in the prices PGE charged its customers.

On December 14, 2004, the judge granted the Class Action Plaintiffs’ motion for Class Certification and Partial Summary Judgment and denied PGE’s motion for Summary Judgment. On March 3, 2005 and March 29, 2005, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial judge to dismiss the complaints or to show cause why they should not be dismissed, and seeking to overturn the Class Certification.

On August 31, 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions for Alternative Writ of Mandamus, abating the class action proceedings until the OPUC responded with respect to certain issues on remand to the 2003 Remand (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1995 through October 2000. The Oregon Supreme Court further stated that if the OPUC 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 December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest Refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and did not rule on the FERC’s ultimate decision to deny refunds. Two requests for rehearing were filed with the court. On April 9, 2009, the Ninth Circuit denied the 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.

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 the Pacific Northwest, and if so, how such refunds would be calculated. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of 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 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 considers amortization of the deferral. PGE understands that the OPUC will consider the potential impact of the deferral on PGE’s earnings over a relevant 12-month period, which will include the Deferral Period.

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

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

Management cannot predict the ultimate outcome of this matter. However, based on the information currently known to management, it believes this matter will not have a material adverse effect on PGE’s financial condition, results of 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 August 2009 for the Company to respond. In March 2009, the EPA sent General Notice Letters to seven additional PRPs.

The EPA will determine the boundaries of the site at the conclusion of the RI/FS in a Record of Decision, expected in 2010. The EPA will document its findings in the Record of Decision 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.

The OPUC has approved the deferral, for later ratemaking treatment, of incremental investigation and remediation costs related to the Portland Harbor site, effective March 31, 2008. Ratemaking treatment will be determined in a future regulatory proceeding that includes both a prudency review with respect to the costs incurred and a regulated earnings test. As a result, there can be no assurance that recovery of all of these costs will be granted.

Harbor Oil

Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company’s power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil 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 federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for RI/FS from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter started a period for the PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance an RI/FS of the Harbor Oil site. On May 31, 2007, an Administrative Order on 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 has approved 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, effective March 31, 2008. Ratemaking treatment will be determined in a future regulatory proceeding that includes both a prudency review with respect to the costs incurred and a regulated earnings test. As a result, there can be no assurance that recovery of all of these costs will be granted.

Other Matters

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

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 March 31, 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 indemnifications. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnifications.

NOTE 10: VARIABLE INTEREST ENTITIES

Pursuant to FIN 46(R), Variable Interest Entities (FIN46(R)), PGE has determined it is the primary beneficiary of two variable interest entities (VIEs). 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. PGE is the Managing Member in each of the LLCs, representing less than 1% equity interest in each entity, and a financial institution is the Investor Member, representing more than 99% equity interest in each entity. As the primary beneficiary, PGE consolidates the VIEs pursuant to FIN 46(R).

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 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 the first quarter of 2009, impairment losses of $7 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, with the new cost basis of these photovoltaic solar power facilities amortized over their remaining estimated useful lives.

As noted above, PGE has consolidated the LLCs pursuant to FIN 46(R) 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, which are included in the net losses of the LLCs, are attributable to the “noncontrolling interests” through the Net loss attributable to the noncontrolling interests in PGE’s condensed consolidated statement of income for the three months ended March 31, 2009.

NOTE 11: SUBSEQUENT EVENT

On April 16, 2009, PGE issued $300 million of 6.10% Series First Mortgage Bonds (the Bonds), which are due April 15, 2019. Interest is paid semi-annually at 6.10% per annum on April 15 and October 15, beginning October 15, 2009. The 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 at any time and from time to time, in whole or in part. The net proceeds from the sale of the Bonds will be used for general corporate purposes, including funding capital expenditures, and the repurchase of Pollution Control Bonds in the amount of $142 million, which occurred on May 1, 2009.

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 ongoing deterioration of the economies of the state of Oregon, the United States and other parts of the world, including reductions in demand for electricity, impaired financial soundness of vendors and service providers and elevated levels of uncollectible customer accounts;

•

capital market conditions, including the recent credit crisis, interest rate volatility, severe 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 have a serious impact on 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;

•

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

•

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

•

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

•

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

•

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 the transitions in senior management, including the recent retirement and replacement of PGE’s Chief Executive Officer and hiring of a new Chief Financial Officer;

•

general political, economic, and financial market conditions;

•

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

•

acts of war or terrorism;

•

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

•

declines in the market prices for equity securities and increased funding requirements for defined benefit pension plans and other benefit plans; and

•

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.

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.

Capital and Financing - PGE has undertaken projects that will require significant capital spending in 2009 and 2010, and has near term debt maturities which will require capital resources, as follows:

•

The Company expects to spend $723 million in 2009 and $522 million in 2010 for capital projects. The majority of these amounts relate to Biglow Canyon Phases II and III, the smart meter project, and ongoing capital expenditures;

•

On May 1, 2009, the Company refinanced $142 million of Pollution Control Bonds; and

•

$186 million of the Company’s long-term debt will mature in 2010.

Funding for these projects and debt maturities includes:

•

In January 2009, the Company issued $130 million of First Mortgage Bonds;

•

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

•

On April 16, 2009, the Company issued $300 million in First Mortgage Bonds in a public offering, in part to repurchase the $142 million of its Pollution Control Bonds for which the interest rate and interest period expired May 1, 2009;

•

In 2009, cash provided by operations is expected to be approximately $410 million; and

•

Through 2010, the Company anticipates issuing a total of approximately $375 million of additional debt, a portion of which will be used to replace $186 million of long-term debt that matures in 2010.

Liquidity - PGE maintains liquidity through revolving credit facilities totaling $495 million and access to the commercial paper market. As of March 31, 2009, the unused available credit under the credit facilities is $272 million, with $279 million available as of April 30, 2009.

The decline in power and natural gas prices in the latter half of 2008 has required the Company to post considerable collateral with counterparties in the form of cash or letters of credit, in connection with its price risk management activities. These cash deposits, which are classified as Margin deposits on PGE’s condensed consolidated balance sheet, are based on contract terms and commodity prices and can vary from period to period. As of March 31, 2009, PGE had posted a total of $409 million of collateral with these counterparties, consisting of $205 million in cash and $204 million in letters of credit, $44 million of which was affiliated with master netting agreements. Provided market prices remain unchanged from March 31, 2009, the Company anticipates that approximately 45% of the current collateral deposits would no longer be required by the end of 2009 as the related contracts are settled, and another 45% are expected to roll off by the end of 2010. The Company has an additional $19 million of letters of credit outstanding under its credit facilities that are not related to price risk management activities.

Management believes that, as of March 31, 2009, the availability of its credit facilities, the expected ability to issue long-term debt and equity securities, and cash generated from operations will provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements.

Customers - During the first quarter of 2009, PGE served an average of 813,031 retail customers compared to 807,144 during the first quarter of 2008, an increase of 0.7%. Despite this customer growth and generally cooler weather in 2009, retail energy deliveries decreased 3.1% in the first quarter of 2009 relative to 2008, due to lower customer demand. In 2009, a “decoupling mechanism” was approved by the OPUC to help mitigate the effects on the Company of conservation efforts made by customers. For further information on this mechanism, see “Decoupling Mechanism” under Legal, Regulatory, and Environmental Matters in this section.

A slow-down in Oregon’s economy continued into the first quarter of 2009. Seasonally adjusted unemployment rates for the United States, the state of Oregon, and the Portland /Salem metropolitan area, which incorporates the majority of the Company’s service territory, are reflected in the table below.


	United States		Oregon		Portland/ Salem
2009
January	7.6	%	9.8	%	9.1	%
February	8.1		10.7		9.6
March	8.5		12.1		11.2

Avg for quarter	8.1	%	10.9	%	10.0	%


2008
January	4.9	%	5.3	%	5.0	%
February	4.8		5.4		5.0
March	5.1		5.5		5.2

Avg for quarter	4.9	%	5.4	%	5.1	%

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 64% of its retail load requirement during the first quarter of 2009, compared to 66% in the first quarter of 2008. Generation from PGE’s hydroelectric plants provided approximately 10% of the Company’s retail load requirement during the first quarters of both 2009 and 2008. Current forecasts indicate slightly below normal regional hydro conditions for 2009.

PGE has a 20% ownership interest in Units 3 and 4 of the Colstrip coal plant, located in southeastern Montana, with each of the units providing approximately six percent (148 MW) of the Company’s total generating capability. During the scheduled 2009 maintenance outage of Unit 4, which began on March 28, two turbine rotors were found to be damaged, with both sent to the manufacturer for repair. It is currently estimated that such repairs will extend the outage by 8 to 10 weeks, with Unit 4 expected to return to service in late July 2009. In addition to the Company’s share of repair costs, it is expected that PGE will incur incremental power costs to replace the output of Unit 4 during its extended outage. The total cost for repairs has not yet been determined. Incremental replacement power costs are estimated to range from $2 million to $3 million through July 2009.

Legal, Regulatory and Environmental Matters - In December 2008, the DEQ issued a proposed plan that would require the installation of emission controls at Boardman under a phased-in approach. For further discussion of this matter, see Boardman emissions controls, in “Capital Requirements” under “Liquidity and Capital Resources” in this Item 2.

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

—

Ongoing matters related to the recovery of the Company’s investment in its closed Trojan plant;

—

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

—

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

—

Investigation of the Portland Harbor site.

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 Nuclear Plant, PGE plans to issue refund checks to certain customers totaling $33.1 million, plus accrued interest ($1.6 million as of March 31, 2009), beginning in October 2009. Such refunds are expected to be completed by the end of 2009.

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

—

Boardman Deferral Amortization - On October 9, 2007, PGE filed a request with the OPUC to amortize the deferral of $26.4 million of replacement power costs, plus accrued interest ($8.5 million as of March 31, 2009), associated with the forced outage of Boardman from November 18, 2005 through February 5, 2006. In its filing, the Company 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. Management cannot predict the ultimate outcome of this proceeding.

—

Utility Rate Treatment of Income Taxes (SB 408) - Each year, PGE files a report with the OPUC by October 15 reporting the amount of taxes paid by the Company for the preceding year as well as the amount of taxes authorized to be collected in rates. The report is reviewed as part of a formal process, with the OPUC expected to issue an order within 180 days after the filing of the report. 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 ($2.3 million as of March 31, 2009). Pursuant to the OPUC rules, collections from customers will begin June 1, 2009. PGE is expected to file its report for the 2008 reporting year by October 15, 2009.

—

Power Costs - Under PGE’s Annual Power Cost Update Tariff, customer prices are adjusted annually to reflect the latest forecast of net variable power costs for the following year. As required, the Company’s initial forecast of 2010 power costs was submitted to the OPUC on April 1, 2009. Such forecast will be updated during the year and will be finalized in November. Based upon the final forecast, new prices, as approved by the OPUC, will become effective January 1, 2010.

—

Renewable Resources - Pursuant to a renewable adjustment clause mechanism (RAC), PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in rates until the next annual RAC filing. On April 1, 2009, the Company submitted its initial filing under the RAC. The filing includes three renewable projects - Biglow Canyon Phase II and two solar projects. The filing requests approximately $41 million in revenue requirements, 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 $15 million for 2010 and included in the Company’s Annual Power Cost Update (described above). The related cost and benefit amounts to be included in rates will be updated by December 1, 2009, with new rates to become effective on January 1, 2010.

—

Selective Water Withdrawal System - Under a stipulation in PGE’s general rate case proceeding, the Company removed from requested rates recovery of its investment in the Selective Water Withdrawal System at the Pelton/Round Butte generating facility. However, the stipulation also provided for a process to recover the cost of this system through a separate proceeding, which is currently in process. On April 14, 2009, the Company filed a motion with the OPUC requesting that the procedural schedule be suspended as a result of a recently encountered delay in construction. Although PGE anticipates rate recovery of this system, its completion, which was expected in the second quarter of 2009, is now expected to be delayed by at least four months. PGE’s initial filing in this matter requested an annual revenue increase of $12.9 million related to this project.

—

Decoupling Mechanism - Pursuant to authorization contained in the final order in PGE’s general rate case, the Company filed with the OPUC on January 30, 2009 an application to defer, for later ratemaking treatment, potential revenues associated with a new decoupling mechanism as well as revenues associated with a return on equity (ROE) refund. The decoupling mechanism is intended to allow recovery of reduced earnings resulting from a reduction in sales of electricity resulting from customers’ energy efficiency and conservation efforts. It would be implemented under a new two-year tariff that includes a Sales Normalization Adjustment, for residential and small non-residential customers, and a Nonresidential Lost Revenue Recovery, for large non-residential customers with loads less than 1 MWa. The ROE refund, estimated at approximately $1.9 million annually, would reduce PGE’s allowed ROE from 10.1%, as approved by the OPUC in the Company’s latest general rate proceeding, to 10.0%, and is intended to reflect an assumed reduction in the Company’s risk associated with the decoupling mechanism.

The American Recovery and Reinvestment Act of 2009 - On February 17, 2009, the American Recovery and Reinvestment Act of 2009 (the Act) was enacted. The Act includes provisions for several enhanced tax benefits, many of which are favorable to renewable energy projects such as PGE’s Biglow Canyon Wind Farm. In particular, the Production Tax Credit (PTC) was extended for wind farms from 2009 through 2012 and in lieu of the PTC, a company may elect Investment Tax Credit (ITC) or Treasury Department Grants, meeting certain criteria.

Based on PGE’s preliminary assessment of current provisions of the Act, the Company believes that it may qualify for the Treasury Department Grant option in amounts ranging from $60 million to $90 million in 2009 and $80 million to $110 million in 2010, related to its construction of Phases II and III of the Biglow Canyon Wind Farm project, based on current project schedules. PGE is also considering opportunities under the Act that would provide funding for smart grid projects, vehicle electrification, and research relating to potential carbon capture projects.

PGE’s assessment of its options under the Act are preliminary and still under review and analysis by the Company. The availability of any such grants under the Act and the Company’s final determination of whether to seek such grants or other benefits under the Act are subject to various other factors, including the promulgation of regulations under the Act and the clarification of regulatory treatment of grant funds under the Act. Accordingly, there is no assurance that PGE will either seek or receive any grants or other benefits under the Act.

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.

Results of Operations

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


	Three Months Ended March 31,
	2009					2008
	Amount			% of Revenues		Amount			% of Revenues
Revenues	$	485		100	%	$	471		100	%
Operating expenses:
Purchased power and fuel		255		52			250		53
Production and distribution		42		9			39		8
Administrative and other		45		9			47		10
Depreciation and amortization		57		12			50		11
Taxes other than income taxes		23		5			22		5

Total operating expenses		422		87			408		87

Income from operations		63		13			63		13
Other income (expense):
Allowance for equity funds used during construction		2		-			2		-
Miscellaneous expense		(3	)	-			(3	)	-

Other expense, net		(1	)	-			(1	)	-
Interest expense		25		5			23		5

Income before income taxes		37		8			39		8
Income taxes		13		3			11		2

Net income		24		5			28		6
Add: net losses attributable to the noncontrolling interests		7		1			-		-

Net income attributable to Portland General Electric Company	$	31		6	%	$	28		6	%

Net income attributable to Portland General Electric Company was $31 million, or $0.47 per diluted share, for the first quarter of 2009 compared to $28 million, or $0.44 per diluted share, for the first quarter of 2008. The effect of increased prices in the first quarter 2009, as authorized by the OPUC, was substantially offset by a reduction in energy sales, higher power costs, and increases in other operating expenses. The effect of estimated customer collections related to SB 408, recorded in the first quarter of 2009, also contributed to the increase.

Revenues and average number of retail customers consist of the following (dollars in millions):


	Three Months Ended March 31,
	2009					2008
	Amount			% of Total		Amount			% of Total
Revenues:
Retail sales:
Residential	$	233		48	%	$	235		50	%
Commercial		149		31			149		32
Industrial		42		8			38		8

Total retail sales		424		87			422		90
Direct access customers		(1	)	-			(2	)	-
Other retail revenues		29		6			(3	)	(1	)

Total retail revenues		452		93			417		89
Wholesale revenues		28		6			48		10
Other operating revenues		5		1			6		1

Total revenues	$	485		100	%	$	471		100	%


Average number of retail customers:
Residential		713,747		88	%		709,132		88	%
Commercial		98,771		12			97,397		12
Industrial		249		-			215		-
Direct access		264		-			400		-

Total retail customers		813,031		100	%		807,144		100	%

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


	Three Months Ended March 31,
	2009				2008
Energy sold and delivered:
Retail energy sales:
Residential	2,351		40	%	2,358		39	%
Commercial	1,733		30		1,791		29
Industrial	604		10		568		9

Total retail energy sales	4,688		80		4,717		77
Delivery to direct access customers	450		8		587		10

Total retail energy deliveries	5,138		88		5,304		87
Wholesale sales	709		12		806		13

Total energy sold and delivered	5,847		100	%	6,110		100	%


Sources of energy:
Generation:
Thermal	2,645		46	%	2,743		47	%
Hydro	504		9		504		9
Wind	68		1		82		1

Total generation	3,217		56		3,329		57

Purchased power:
Term purchases	1,640		28		1,511		26
Purchased hydro	681		12		725		12
Spot purchases	220		4		306		5

Total purchased power	2,541		44		2,542		43

Total system load	5,758		100	%	5,871		100	%

Less: wholesale sales	(709	)			(806	)

Retail load requirement	5,049				5,065

Revenues increased $14 million, or 3%, in the first quarter of 2009 compared to the first quarter of 2008 as a result of the following factors:

Total retail revenues increased $35 million, or 8%, due primarily to:

^¡

A $35 million increase resulting from an 8% increase in average price, which was driven by the price increases approved by the OPUC pursuant to the Company’s 2009 General Rate Case and became effective January 1, 2009;

^¡

A $3 million increase related to SB 408, primarily due to a $2 million customer refund recorded in the first quarter of 2008. In the first quarter of 2009, PGE provided refunds to customers related to 2006 and recorded a nominal estimated collection from customers for the first quarter of 2009, all of which was substantially offset by the amortization of the regulatory liability related to SB 408 for 2006; partially offset by

^¡

A $3 million decrease resulting from a decrease of approximately 3% in total retail energy deliveries resulting from the continuing economic slowdown. Partially offsetting this decrease was an increase in the average number of customers served of 0.7% and cooler weather, as indicated in the table below; and

^¡

A $3 million decrease related to supplemental tariffs, which is fully offset in Depreciation and amortization expense.

Heating degree-days is an indication of the likelihood that customers will use heating and is used to measure the effect of weather on the demand for electricity. During the first quarter of 2009, the heating degree-days increased 2.1% compared to the first quarter of 2008. The following table indicates the number of heating degree-days for the months shown, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:


	Heating Degree-days
	2009	2008
January	767	805
February	656	578
March	599	598

1st quarter	2,022	1,981

15-year average for the quarter	1,831	1,831

On a weather adjusted basis, retail energy deliveries decreased 1.3% in the first quarter of 2009 compared to the first quarter of 2008, with deliveries to residential, commercial, and industrial customers increasing (decreasing) by (1.2)%, (2.3)%, and 0.1%, respectively. PGE projects that weather adjusted energy deliveries will decrease approximately 0.9% in 2009 relative to 2008.

Other retail revenues for the first quarter of 2009 include $27 million of customer credits and refunds related to the following, all of which are fully offset within Retail sales:

^¡

$16 million related to the Residential Exchange Program administered by the BPA. As a result of a decision by the Ninth Circuit, the BPA suspended such benefits in May 2007. In April 2008, benefits were temporarily restored under an Interim Relief agreement with the BPA. The resumption of customer credits, as approved by the OPUC, resulted in an average price reduction of approximately 6.3% for residential and small farm customers, effective April 15, 2008;

^¡

$6 million related to the results of SB 408 for the year 2006. Customer refunds, totaling $37 million (plus interest), began June 1, 2008 and will continue over an approximate two-year period; and

^¡

$5 million related to results of the PCAM for the year 2007. Customer refunds, totaling $16 million (plus interest), began January 1, 2009 and will continue over a one-year period.

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 current long-term wholesale contracts. Such sales can vary significantly period to period. Wholesale revenues decreased $20 million, or 42%, in the first quarter of 2009 compared to the first quarter of 2008 due to the net effect of the following:

^¡

A $15 million decrease related to a 35% decline in average price, driven by lower natural gas and electricity prices; and

^¡

A $5 million decrease related to a 12% decline in wholesale energy sales.

Purchased power and fuel expense increased $5 million, or 2%, in the first quarter of 2009 compared to the first quarter of 2008. The increase was due primarily to the net effect of the following factors:

—

A $73 million increase in the cost of settled electric and natural gas financial contracts entered into in conjunction with PGE’s management of its net power costs. These contracts are among those financial instruments in the Company’s diversified power supply portfolio used to manage market risk, with activities reflected in Wholesale revenues, Purchased power and fuel expense, and Other operating revenues;

—

A $37 million decrease in the cost of purchased power, related primarily to lower prices for natural gas and electricity; and

—

A $31 million decrease in the cost of thermal production, due to a 30% reduction in natural gas prices and a 4% reduction in generation resulting from economic dispatch decisions.

The average variable cost of PGE’s total system load was $44.42 per MWh in the first quarter of 2009 compared to $42.63 per MWh in the first quarter of 2008, an increase of 4%.

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’s NVPC for the first quarter of 2009 was above the baseline, the difference between forecast and baseline NVPC for the year 2009 is below the established deadband threshold. Under the regulated earnings test of the PCAM, however, PGE is not expected to achieve a sufficient return on equity in 2009 that would allow for future refunds; accordingly, no amount was recorded for refund to retail customers as of March 31, 2009.

Current forecasts indicate that regional hydro conditions in 2009 will be slightly below normal levels. 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 April 23, 2009) compared to the actual runoffs for 2008 (as a percentage of normal):


Location	2009 Forecast		2008 Actual
Columbia River at The Dalles, Oregon	87	%	101	%
Mid-Columbia River at Grand Coulee, Washington	90		102
Clackamas River	107		163
Deschutes River	95		101

Production and distribution expense increased $3 million, or 8%, in the first quarter of 2009 compared to the first quarter of 2008, primarily due to increased repair and restoration activities related to the December 2008 snow and ice storm and January and March 2009 wind storms.

Administrative and other expense decreased $2 million, or 4%, in the first quarter of 2009 compared to the first quarter of 2008, primarily due to a decrease in legal settlement expense of $3 million, partially offset by an increase in employee benefit costs of $1 million.

Depreciation and amortization expense increased $7 million, or 14%, in the first quarter of 2009 compared to the first quarter of 2008 primarily due to the following offsetting factors:

•

A $7 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”; and

•

A $3 million increase related to accelerated depreciation of existing customer meters that are being replaced as part of the Company’s smart meter project; partially offset by

•

A $3 million decrease related to the amortization of regulatory liabilities (fully offset in Retail sales).

Taxes other than income taxes increased $1 million, or 5%, in the first quarter of 2009 compared to the first quarter of 2008 primarily due to an increase in payroll tax expense driven by higher employee salaries and wages.

Other expense, net in the first quarter of 2009 was unchanged from the first quarter of 2008 due to the net effect of the following:

•

A $2 million decrease in miscellaneous interest income, including $1 million related to lower money market account balances during the first quarter of 2009;

•

A $1 million increase in income from non-qualified benefit plan trust assets, resulting from a $3 million decline in the fair value of the plan assets in 2009 compared to a $4 million decline in the first quarter of 2008; and

•

A $1 million increase in the allowance for equity funds used during construction as a result of higher construction work in progress balances in 2009 related to Biglow Canyon Phases II and III and the Selective Water Withdrawal project.

Interest expense increased $2 million, or 9%, in the first quarter of 2009 compared to the first quarter of 2008. The increase is due primarily to the following offsetting factors:

•

A $3 million increase resulting from an increase in the average balance of short- and long-term debt outstanding during the first quarter of 2009 compared to the first quarter of 2008. In January 2009, PGE issued $130 million of First Mortgage Bonds, increasing the average balance outstanding of long-term debt to $1,372 million in the first quarter of 2009, compared to $1,285 million in the first quarter of 2008. Additionally, average balances outstanding under short-term borrowing arrangements were higher in the first quarter of 2009 compared to the first quarter of 2008, primarily driven by increased collateral requirements pursuant to the Company’s price risk management activities; partially offset by

•

A $1 million increase in the credit to interest expense for the allowance for funds used during construction driven by higher construction work in progress balances during the first quarter of 2009 compared to the first quarter of 2008. The higher construction work in progress balances were driven by the construction of Biglow Canyon Phases II and III and the Selective Water Withdrawal capital project.

Income taxes increased $2 million in the first quarter of 2009, with an effective tax rate of 29.5%, compared to the first quarter of 2008, with an effective tax rate of 28.2%. The effective tax rate for the first quarter of 2009 was calculated using income before income taxes of $37 million plus the net losses attributable to the noncontrolling interests of $7 million, for income before income taxes attributable to the Company of $44 million, which compares to income before income taxes of $39 million for the first quarter of 2008. These increases are primarily driven by higher taxable income in 2009 relative to 2008.

Net losses attributable to the noncontrolling interests of $7 million represents the noncontrolling interests’ portion of the net losses 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 above.

Liquidity and Capital Resources

Capital Requirements

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


	2009		2010		2011		2012		2013
Ongoing capital expenditures	$	226	$	223		$215 - $235		$245 - $265		$240 - $260
Biglow Canyon Phase II		230		-		-		-		-
Biglow Canyon Phase III		176		201		-		-		-
Hydro licensing and construction		26		17		$65 - $85
Smart meter project		63		56		-		-		-
Boardman emissions controls *		2		25		$255 - $295

Total capital expenditures	$	723	$	522


Long-term debt maturities	$	142	$	186	$	-	$	100	$	100

* Represents 80% of estimated total costs. For further explanation see “Boardman emissions controls” below.

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 - Both phases are currently under construction, with the estimated total cost of Phase II at $326 million, including $10 million of AFDC, and Phase III at $433 million, including $27 million of AFDC. Phases II and III are expected to be completed by the end of 2009 and 2010, respectively, with installed capacities of 149 MW and 175 MW, respectively.

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 will regulate downstream water temperature. Completion of the system, at a total cost of approximately $105 million to $110 million, is expected in 2009. PGE’s portion of the costs is expected to be approximately $80 million, including AFDC.

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. In June 2008, PGE filed an application with the DEQ proposing final resolution of the remaining lower Clackamas River temperature issues. Pending issuance of the new license, the project will operate under annual licenses issued by the FERC. It is expected that the DEQ will complete its water quality certification process in 2009 and the FERC will issue a new license for the Clackamas River projects in 2010.

Smart meter project - PGE began to install approximately 850,000 new customer meters during the second quarter 2009 that will enable two-way remote communication with the Company. Approximately 25,000 new smart meters have been installed within the Company’s service area, including 15,000 as part of the project’s systems acceptance testing phase, which is now completed. It is expected that about 400,000 smart meters will be installed by the end of 2009, with the remainder to be installed in 2010. PGE estimates the capital cost of the smart meter project will range from $130 million to $135 million. The project is expected to provide improved services, operational efficiencies, and a reduction in future operating expenses.

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 emission sources that has indicated that the Boardman generating plant may cause or contribute to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination.

In December 2008, the DEQ issued a proposed plan 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) as required under the Clean Air Act, 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. The DEQ proposes that these first two phases would meet federal requirements for installing BART. The third phase would require the installation of Selective Catalytic Reduction for additional NO_x control, with estimated completion by 2017. The DEQ proposes that the third phase would meet requirements for reasonable progress towards haze emission reduction goals. PGE estimates that the DEQ proposed plan would cost between $575 million and $640 million (100% of total costs, excluding AFDC, in nominal dollars). PGE has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change.

The comment and public input period for the DEQ proposed plan has closed. PGE has commented with an alternative BART/Reasonable Progress proposal that would allow for decision points along the DEQ timeline to provide flexibility to achieve the best economic and environmental outcomes for customers on future controls at those points. The OEQC is expected to adopt a rule in June 2009. The rule will be 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 early 2010.

Additional costs such as taxes, emission fees, and other future costs that may be imposed under any future laws related to climate change, combined with any expenditures for controls, could constitute an investment in excess of what the plant can economically support. The ultimate impact that the above regulatory requirements and emission controls will have on future operations, costs, or generating capacity of the Company’s thermal generating plants is not yet determinable and will be evaluated as part of the Company’s integrated resource planning process. PGE will seek recovery of its costs through the ratemaking process.

Further capital needs, not included in the table above, could include those related to the following:

•

Additional resource requirements identified in the Company’s pending Integrated Resource Plan (IRP), expected to be filed with the OPUC by late 2009. The IRP, which describes the Company’s energy supply strategy, will address resource requirements through the year 2020. Such requirements are expected to be met by additional resources that could include purchase power agreements of various durations, new facilities to help meet base load and capacity requirements, the expansion of energy efficiency programs, and additional renewable resources.

Potential new energy resources the Company is considering include natural gas facilities at Boardman, to help meet additional base load requirements estimated at 300-500 MW, and at Port Westward, for additional peak load requirements estimated at 100-200 MW. Following OPUC acknowledgement of the Company’s IRP, these and other potential resources would be included in a formal bidding process.

•

New renewable resources identified in the Company’s 2007 IRP. The OPUC directed PGE to seek proposals for up to 218 MWa of new renewable resources, to be in service by the end of 2014. PGE is currently negotiating with a short list of bidders that responded to the Company’s Request for Proposal.

•

The Company is also exploring its options with respect to a 200-mile, 500 kV transmission project referred to as Southern Crossing, which would help to meet growing demand and provide improved system reliability while reducing payments to third party transmission providers. The Company is working closely with other utilities and the WECC to coordinate the project. The total cost of Southern Crossing is estimated to range from $600 million to $750 million (current dollars, excluding AFDC).

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.

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


	Three Months Ended March 31,
	2009			2008
Cash and cash equivalents, beginning of period	$	10		$	73
Net cash provided by (used in):
Operating activities		40			117
Investing activities		(91	)		(68	)
Financing activities		88			(71	)

Net change in cash and cash equivalents		37			(22	)

Cash and cash equivalents, end of period	$	47		$	51

Net cash provided by operating activities - The $77 million decrease in cash provided by operating activities in the first quarter of 2009 compared to the first quarter of 2008 was primarily attributable to the following:

—

A $38 million decrease related to higher margin deposit requirements with certain wholesale customers and brokers, driven primarily by lower power and natural gas prices;

—

An $18 million decrease resulting from higher payments for power and fuel purchases in the first quarter of 2009;

—

A $6 million decrease related to payments for the December 2008 storm;

—

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

—

A $4 million decrease in cash received from retail sales of electricity.

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 $218 million in 2009. Combined with all other sources, cash provided by operations is estimated to be approximately $410 million in 2009, including the reduction of approximately 34% of those margin deposits held by certain wholesale customers and brokers as of March 31, 2009. 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 $23 million increase in cash used in investing activities in the first quarter of 2009 compared to the first quarter of 2008 was primarily attributable to a $21 million increase in construction costs related to Biglow Canyon Phases II and III and a $3 million increase in expenditures for the smart metering 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 $88 million in the first quarter of 2009 compared to net cash used of $71 million in the first quarter of 2008. PGE relies on cash from operations, the issuance of commercial paper, borrowings under its revolving credit facility, and long-term financing activities to support such requirements. During the first quarter of 2009, net cash provided by financing activities primarily consisted of the issuance of common stock for net proceeds of $170 million, proceeds from the issuance of long-term debt of $130 million, partially offset by the repayment of short-term borrowings of $203 million and the payment of dividends of $15 million. Financing activities in the first quarter of 2009 also included the receipt of $7 million in cash contributions from noncontrolling interests in the solar projects. During the first quarter of 2008, net cash used in financing activities consisted of the repayment of long-term debt of $56 million and the payment of dividends of $15 million.

Dividends on Common Stock

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

During the first quarter of 2009, the Board of Directors declared a dividend of $0.245 per common share, amounting to total dividends declared of $18 million, which were paid on April 15, 2009 to shareholders of record on March 25, 2009.

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. PGE has two unsecured revolving credit facilities with groups of banks which provide an aggregate maximum amount available to the Company of $495 million. These two facilities provide for borrowings of up to $370 million and $125 million, respectively. The credit facilities are currently scheduled to terminate as follows: $125 million in December 2009, $10 million in July 2012 and $360 million in July 2013. 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 general corporate purposes or as backup for commercial paper borrowings. The $370 million facility permits

borrowings or the issuance of standby letters of credit and the $125 million facility permits borrowing only. As of March 31, 2009, PGE had no outstanding borrowings or commercial paper issued and had $223 million in outstanding letters of credit under the credit facilities. As of March 31, 2009, the unused available credit under the credit facilities is $272 million, with $279 million available as of April 30, 2009.

In January 2009, PGE issued $130 million of First Mortgage Bonds in two series. One series is for $67 million to mature January 15, 2016 at a fixed rate of 6.80%. The second series is for $63 million to mature on January 15, 2014 at a fixed rate of 6.50%. As of March 31, 2009, the total long-term debt outstanding was $1,437 million. On April 16, 2009, PGE issued $300 million of 6.10% Series First Mortgage Bonds, which mature April 15, 2019. As of April 30, 2009, total long-term debt outstanding was $1,737 million. The Company used a portion of the proceeds from the April 16 bond issuance to refinance $142 million of its Pollution Control Bonds on May 1, 2009.

In March 2009, PGE issued 12,477,500 shares of common stock for net proceeds of $170 million. The proceeds 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 the credit facilities, the expected ability to issue long-term debt and equity securities, and cash generated from operations will 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. Through 2010, the Company anticipates issuing a total of approximately $375 million of debt, part of which will be used to fund debt maturities of $186 million in 2010.

PGE’s financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company’s financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were 51.7% and 47.3% as of March 31, 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	Baa1	A
Senior unsecured debt	Baa2	BBB+
Commercial paper	Prime-2	A-2
Outlook	Positive	Negative

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 March 31, 2009, PGE had posted approximately $409 million of collateral with these counterparties, consisting of $205 million in cash and $204 million in letters of credit, $44 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 March 31, 2009, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $150 million and decreases to approximately $53 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 $210 million at March 31, 2009 and decreases to approximately $84 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 estimated that on March 31, 2009 it could issue up to approximately $599 million of additional First Mortgage Bonds under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, and subsequently issued $300 million in First Mortgage Bonds on April 16, 2009. 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 March 31, 2009, the Company’s debt ratio, as calculated under the credit agreements, was 48.3%.

Off-Balance Sheet Arrangements

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

Contractual Obligations

PGE’s contractual obligations for 2009 and beyond are included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009. Obligations for 2009 and beyond, as set forth in Part II, Item 7 of the 2008 Form 10-K, have not changed materially as of March 31, 2009, except as presented below (in millions):


	Payments Due
	2009 *		2010		2011		2012		2013		There- after		Total
Long-term debt	$	-	$	-	$	-	$	-	$	-	$	130	$	130
Interest on long-term debt		6		9		9		9		9		9		51
Electricity purchases		10		61		-		-		-		-		71
Natural gas agreements		7		-		-		-		-		-		7

Total	$	23	$	70	$	9	$	9	$	9	$	139	$	259

* Represents the period from April 1, 2009 through December 31, 2009.

Due to a recent ruling by the Internal Revenue Service regarding pension funding requirements, approximately $11 million of the $23 million funding disclosed as due in 2010 in the Company’s 2008 Annual Report on Form 10-K for pension plan contributions has been deferred to subsequent years.

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, except as noted below.

The following table presents the credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. As of March 31, 2009, PGE’s credit risk exposure for commodity activities and their subsequent maturity is as follows (dollars in millions):


	Credit Risk						Maturity of Credit Risk Exposure
	Before Collateral		As % of Total		Credit Collateral		2009 *		2010		2011		2012		2013		There- after
Externally rated:
Investment grade	$	17	89	%	$	5	$	-	$	-	$	3	$	4	$	4	$	6
Non-investment grade		2	11	%		1		2		-		-		-		-		-

Total	$	19	100	%	$	6	$	2	$	-	$	3	$	4	$	4	$	6

* Represents the period from April 1, 2009 through December 31, 2009.

As of March 31, 2009, there was no posted collateral subject to be returned to a counterparty that is affiliated with master netting arrangements.

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 March 31, 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.

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.

Citizens’ Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O’Neill v. Public Utility Commission of Oregon, Public Utility Commission of Oregon Docket Nos. DR 10, UE 88, and UM 989, Marion County Oregon Circuit Court, Case No. 94C-10417, the Court of Appeals of the State of Oregon, the Oregon Supreme Court, Case No. SC S45653.

On January 24, 2009, counsel for the URP and the Class Action Plaintiffs in the Dreyer proceeding filed a motion with the Oregon Court of Appeals requesting a stay of the refund process pending final disposition of their October 22, 2008 appeal of the September 30, 2008 OPUC order.

On February 2, 2009, the OPUC issued an order that suspended the refund process pending the Court of Appeals decision on the motion requesting a stay. On February 24, 2009, the Court of Appeals denied the motion.

On March 19, 2009, the OPUC issued an order that reset and restarted the refund mechanism as outlined in the September 30, 2008 order. In late April 2009, the URP and the plaintiffs in the class action proceedings separately appealed the March 19, 2009 order to the Oregon Court of Appeals.

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

On October 5, 2006, the Circuit Court issued an Order of Abatement, in response to the August 31, 2006 ruling of the Oregon Supreme Court, abating the class actions, but invited 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.

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. Two requests for rehearing were filed with the court and on April 9, 2009, the Ninth Circuit issued an order that denied the 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.

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

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

4.1		Sixty-first Supplemental Indenture dated January 15, 2009 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed January 16, 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.

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: May 4, 2009	By:	/s/ Maria M. Pope
		Maria M. Pope
		Senior Vice President, Chief Financial Officer, and Treasurer
		(duly authorized officer and principal financial officer)